10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

XANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013.

OR

__ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________.

Commission file number   001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

Oklahoma	73-1520922
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
100 West Fifth Street, Tulsa, OK	74103
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code   (918) 588-7000

Securities registered pursuant to Section 12(b) of the Act:

Common stock, par value of $0.01	New York Stock Exchange
(Title of each class)	(Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No__

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __  No X

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes X  No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every

Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes X No __

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one) Large accelerated filer X Accelerated filer __    Non-accelerated filer __    Smaller reporting company __

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes__ No X

Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on June 30, 2013, was $8.1 billion.

On February 19, 2014, the Company had 207,814,086 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 21, 2014, are incorporated by reference in Part III.

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ONEOK, Inc.

2013 ANNUAL REPORT

Part I.		Page No.
Item 1.	Business	5
Item 1A.	Risk Factors	20
Item 1B.	Unresolved Staff Comments	37
Item 2.	Properties	37
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39
Part II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	76
Item 8.	Financial Statements and Supplementary Data	81
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	139
Item 9A.	Controls and Procedures	140
Item 9B.	Other Information	140
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance	140
Item 11.	Executive Compensation	141
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	141
Item 13.	Certain Relationships and Related Transactions, and Director Independence	142
Item 14.	Principal Accounting Fees and Services	142
Part IV.
Item 15.	Exhibits, Financial Statement Schedules	142
Signatures		151

As used in this Annual Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.

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GLOSSARY

The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:

AFUDC	Allowance for funds used during construction
Annual Report	Annual Report on Form 10-K for the year ended December 31, 2013
ASU	Accounting Standards Update
Bbl	Barrels, 1 barrel is equivalent to 42 United States gallons
Bbl/d	Barrels per day
BBtu/d	Billion British thermal units per day
Bcf	Billion cubic feet
Bcf/d	Billion cubic feet per day
Bighorn Gas Gathering	Bighorn Gas Gathering, L.L.C.
Bushton Plant	Bushton Natural Gas Processing and Fractionation Plant
CFTC	Commodities Futures Trading Commission
Clean Air Act	Federal Clean Air Act, as amended
Clean Water Act	Federal Water Pollution Control Act Amendments of 1972, as amended
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOT	United States Department of Transportation
EBITDA	Earnings before interest expense, income taxes, depreciation and amortization
EPA	United States Environmental Protection Agency
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Guardian Pipeline	Guardian Pipeline, L.L.C.
Intermediate Partnership	ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary of ONEOK Partners, L.P.
IRS	Internal Revenue Service
KCC	Kansas Corporation Commission
KDHE	Kansas Department of Health and Environment
LDCs	Local distribution companies
LIBOR	London Interbank Offered Rate
MBbl	Thousand barrels
MBbl/d	Thousand barrels per day
MDth/d	Thousand dekatherms per day
Midwestern Gas Transmission	Midwestern Gas Transmission Company
MMBbl	Million barrels
MMBtu	Million British thermal units
MMBtu/d	Million British thermal units per day
MMcf	Million cubic feet
MMcf/d	Million cubic feet per day
Moody’s	Moody’s Investors Service, Inc.
Natural Gas Act	Natural Gas Act of 1938, as amended
Natural Gas Policy Act	Natural Gas Policy Act of 1978, as amended
NGL products	Marketable natural gas liquid purity products, such as ethane, ethane/propane mix, propane, iso-butane, normal butane and natural gasoline
NGL(s)	Natural gas liquid(s)
Northern Border Pipeline	Northern Border Pipeline Company
NYMEX	New York Mercantile Exchange
NYSE	New York Stock Exchange
OBPI	ONEOK Bushton Processing, L.L.C., formerly ONEOK Bushton Processing, Inc.

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OCC	Oklahoma Corporation Commission
OESC	ONEOK Energy Services Company, L.P.
ONE Gas	ONE Gas, Inc.
ONE Gas Credit Agreement	ONE Gas’ $700 million revolving credit agreement dated December 20, 2013
ONEOK	ONEOK, Inc.
ONEOK Credit Agreement	ONEOK’s $300 million revolving credit agreement dated April 5, 2011, as amended
ONEOK Partners	ONEOK Partners, L.P.
ONEOK Partners Credit Agreement	ONEOK Partners’ $1.7 billion revolving credit agreement dated August 1, 2011, as amended January 31, 2014
ONEOK Partners GP	ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole general partner of ONEOK Partners
OPIS	Oil Price Information Service
OSHA	Occupational Safety and Health Administration
Overland Pass Pipeline Company	Overland Pass Pipeline Company LLC
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
POP	Percent of Proceeds
Quarterly Report(s)	Quarterly Report(s) on Form 10-Q
RRC	Railroad Commission of Texas
S&P	Standard & Poor’s Rating Services
SEC	Securities and Exchange Commission
Securities Act	Securities Act of 1933, as amended
VAR	Value-at-Risk
Viking Gas Transmission	Viking Gas Transmission Company
XBRL	eXtensible Business Reporting Language

The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.  Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations and assumptions will be achieved.  Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A, “Risk Factors,” and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation and “Forward-Looking Statements,” in this Annual Report.

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PART I

ITEM 1.    BUSINESS

GENERAL

We are a diversified energy company and successor to the company founded in 1906 as Oklahoma Natural Gas Company.  We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.”  We are the sole general partner and, as of December 31, 2013, own 41.2 percent of ONEOK Partners (NYSE: OKS), one of the largest publicly traded master limited partnerships. Our goal is to provide management and resources enabling ONEOK Partners to execute its growth strategies and allowing us to grow our dividend. ONEOK Partners applies its core capabilities of gathering, processing, fractionating, transporting, storing, marketing and distributing natural gas and NGLs through the rebundling of services across the energy value chains, primarily through vertical integration, in an effort to provide its customers with premium services at lower costs. ONEOK Partners is a leader in the gathering, processing, storage and transportation of natural gas in the United States.  In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.  At December 31, 2013, our operations included our energy services business, which provides premium natural gas marketing services to its customers across the United States, and our natural gas distribution business, which includes Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service.

EXECUTIVE SUMMARY

In 2013, we announced plans to separate our natural gas distribution business into a standalone publicly traded company and to wind down our energy services business. ONEOK and its subsidiaries will continue to own the entire general partner interest and limited partner interests in ONEOK Partners, which, together, represented a 41.2 percent ownership interest at December 31, 2013, in ONEOK Partners. Following the separation of the natural gas distribution business and the wind down of our energy services business, our cash flows will primarily be derived from the cash distributions we receive from ONEOK Partners associated with our limited partner and general partner interests, including incentive distribution rights. We expect to distribute in the form of dividends the majority of our cash flows in excess of debt service, income taxes and other operating needs. Subject to board approval, we expect to pay higher dividends following the separation of the natural gas distribution business and as ONEOK Partners’ distributions increase.

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 (NYSE: OGS), which was completed on January 31, 2014. ONE Gas consists of ONEOK’s former Natural Gas Distribution segment 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 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 our outstanding commercial paper and to repay approximately $550 million of long-term debt prior to maturity.

ONE Gas is the largest natural gas distributor in Oklahoma and Kansas and the third largest natural gas distributor in Texas, providing service as a regulated public utility to wholesale and retail customers.  ONE Gas’ largest distribution markets are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita and Topeka, Kansas; and Austin and El Paso, Texas.  ONE Gas benefits from rate strategies, including a performance-based rate mechanism in Oklahoma, capital-recovery mechanisms in Kansas and portions of Texas, and cost-of-service adjustments in certain Texas jurisdictions that address investments in rate base and changes in expense. See additional discussion in the “Financial Results and Operating Information” section of our Natural Gas Distribution segment.

Wind-down of Energy Services - As a result of challenging natural gas market industry conditions, in June 2013, we announced an accelerated wind down of our Energy Services segment. Our Energy Services segment no longer fits strategically and has become increasingly smaller on a relative basis because of the market conditions that it has faced and the growth of our other businesses. We will continue to operate our Energy Services segment through the completion of the wind down process that is expected to be completed substantially by March 31, 2014. See additional discussion in the “Financial Results and Operating Information” section of our Energy Services segment.

Market Conditions - Domestic supplies of natural gas, natural gas liquids and crude oil continue to increase from drilling activities focused in crude oil and NGL-rich resource areas. Despite lower commodity prices, North American natural gas production continues to increase at a faster rate than demand, primarily as a result of increased production from

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nonconventional resource areas such as shale areas.  Producers currently receive higher market prices on a heating-value basis for crude oil and NGLs compared with natural gas. As a result, many producers have focused their drilling activity in NGL-rich shale areas throughout the country that produce crude oil and NGL-rich natural gas rather than areas that produce dry natural gas. ONEOK Partners expects continued demand for midstream infrastructure development to be driven by producers who need to connect emerging production with end-use markets where current infrastructure is insufficient or nonexistent.

Additional infrastructure is needed to gather, process, fractionate, store and transport increasing supplies of natural gas and NGLs.  In response to this increased production and demand for NGL products, ONEOK Partners is investing approximately $6.0 billion to $6.4 billion in new capital projects, including approximately $1.2 billion in new projects and acquisitions announced in 2013. These projects are expected to meet the needs of crude oil, NGL and natural gas producers in the Bakken Shale and Three Forks formations in the Williston Basin, the Niobrara Shale, the Cana-Woodford Shale, Woodford Shale, Mississippian Lime and Granite Wash areas, and the need for additional natural gas liquids infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand.  When completed, ONEOK Partners expects these projects to increase volumes in its businesses and generate additional earnings and cash flows, while also increasing commodity-price sensitivity in its natural gas gathering and processing business and fee-based revenues in its natural gas liquids business.

The increased drilling activity and production have resulted in lower NGL prices, as well as reduced price volatility and narrower NGL location and seasonal price differentials for natural gas and NGLs in the markets ONEOK Partners serves. ONEOK Partners expects similar conditions in 2014; however, market conditions may produce periods of higher prices and volatility, as well as wider NGL location and product price differentials. For example, in the fourth quarter 2013, the price of propane increased significantly, and the price differential of propane between the Conway, Kansas, and the Mont Belvieu, Texas, market centers also widened in favor of Conway, Kansas, due to colder than normal weather and lower propane inventory levels. We expect propane prices to remain high through the 2014 winter heating season. Due to success in extracting NGLs, ethane production has increased more rapidly than the petrochemical industry's current capability to consume ethane. ONEOK Partners believes similar market conditions may generally persist until ethylene producers increase their capacity, with the largest number of additions expected to be completed in the next two to four years, to consume additional ethane feedstock volumes through plant modifications and expansions, and the completion of announced new world-scale ethylene capacity.

When economic conditions warrant, certain natural gas processors elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants.  Price differentials between ethane and natural gas resulted in ethane rejection at most of ONEOK Partners’ natural gas processing plants and some of  ONEOK Partners’ natural gas liquids business’ customers’ natural gas processing plants connected to its natural gas liquids gathering system in the Mid-Continent and Rocky Mountain regions during 2013, which reduced natural gas liquids volumes gathered, fractionated and transported in its natural gas liquids business and its results of operations. In the near term, ONEOK Partners expects the ethane oversupply may result in volatile ethane prices.

ONEOK Partners expects 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 ONEOK Partners’ financial results over this period. However, ONEOK Partners’ natural gas liquids business’ 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 ONEOK Partners’ natural gas liquids business. See additional discussion in the “Financial Results and Operating Information” section.

ONEOK Partners also expects narrow NGL price differentials, with periods of volatility for certain NGLs, between the Conway, Kansas, and Mont Belvieu, Texas, market centers to persist as new fractionators and pipelines from the various NGL-rich shale areas throughout the country, including ONEOK Partners’ growth projects discussed below, continue to alleviate constraints affecting NGL prices and location price differentials between the two 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 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. ONEOK Partners’ natural gas liquids business’s capital projects are backed by fee-based supply commitments that ONEOK Partners expects to fill much of its capacity used historically to capture NGL price differentials between the two market centers.

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Other Significant 2013 Events - During 2013, we paid cash dividends of $1.48 per share, an increase of approximately 17 percent from the $1.27 per share paid during 2012.  In January 2014, we declared a dividend of $0.40 per share ($1.60 per share on an annualized basis), an increase of approximately 11 percent from the $0.36 declared in January 2013.

During 2013, ONEOK Partners paid cash distributions to its limited partners of $2.87 per unit, an increase of approximately 11 percent compared with the $2.59 per unit paid during 2012.  In January 2014, ONEOK Partners GP declared a cash distribution to ONEOK Partners’ limited partners of $0.73 per unit ($2.92 per unit on an annualized basis) for the fourth quarter 2013, an increase of approximately 3 percent compared with the $0.71 declared in January 2013.

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 its 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 it 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 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.

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. ONEOK Partners used the proceeds to pay down commercial paper and for general partnership purposes.

In September 2013, ONEOK Partners completed the acquisition for $305 million 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. 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.

During 2013, we relied primarily on operating cash flows, commercial paper and distributions from ONEOK Partners to fund our short-term liquidity and capital requirements. Our cash flow sources and requirements are expected to change significantly following the separation of the natural gas distribution business and the wind down of the energy services business. Our primary source of cash inflows are expected to be distributions from ONEOK Partners, and our primary cash outflows are expected to be dividends to our shareholders. 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 anticipates that its cash flows generated from operations, existing capital resources and ability to obtain financing will enable it to maintain its current and planned levels of operations.  Additionally, ONEOK Partners expects to fund its capital expenditures with proceeds from short- and long-term debt, the issuance of equity and operating cash flows.

In December 2013, we amended the ONEOK Credit Agreement effective upon the separation of our natural gas distribution business on January 31, 2014, which reduced the size of our facility to $300 million from $1.2 billion and extended the maturity to January 2019.

In December 2013, ONEOK Partners amended its Partnership 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. The facility is available to provide liquidity for working capital, capital expenditures and for other general partnership purposes.

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, for more information on our growth projects, results of operations, liquidity and capital resources.

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BUSINESS STRATEGY

Our primary business strategy is to maximize dividend payout while maintaining prudent financial strength and flexibility, with a focus on safe, reliable and environmentally responsible operations for our customers, employees, contractors and the public through the following:

• Provide reliable energy and energy-related services in a safe and environmentally responsible manner to our stakeholders through our ownership in ONEOK Partners - environmental, safety and health issues continue to be a primary focus for us, and our emphasis on personal and process safety has produced improvements in the key indicators we track.  We also continue to look for ways to reduce our environmental impact by conserving resources and utilizing more efficient technologies;

• Maximize dividend payout while maintaining financial strength and flexibility - during 2013, cash dividends paid per share increased 17 percent compared with the prior year. During 2013, ONEOK Partners’ cash distributions increased by 28 cents per unit, an increase of approximately 11 percent compared with 2012; ONEOK Partners announced new capital projects and acquisitions of $1.2 billion, increasing its total growth program to approximately $6.0 billion to $6.4 billion. These projects are expected to meet the needs of NGL and natural gas producers in the Williston Basin, Niobrara Shale, Cana-Woodford Shale, Woodford Shale, Mississippian Lime and Granite Wash areas, and for additional natural gas liquids infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand. When completed, these projects are anticipated to provide additional earnings and cash flows. In 2014, we intend to distribute the majority of our cash flows in excess of debt service, income taxes and other operating needs in the form of dividends. ONEOK Partners’ balance sheet remains strong, and ONEOK Partners will seek to maintain its investment-grade credit ratings; and

• Attract, select, develop and retain a diverse group of employees to support strategy execution - we continue to execute on our recruiting strategy that targets colleges, universities and vocational-technical schools in our operating areas.  We also continue to focus on employee development efforts with our current employees.

NARRATIVE DESCRIPTION OF BUSINESS

At December 31, 2013, we report operations in the following business segments:

• ONEOK Partners;

• Natural Gas Distribution; and

• Energy Services.

ONEOK Partners

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

We own approximately 92.8 million common and Class B limited partner units, and the entire 2 percent general partner interest, which, together, represent a 41.2 percent ownership interest in ONEOK Partners at December 31, 2013.  We receive distributions from ONEOK Partners on our common and Class B units and our 2 percent general partner interest, which includes our incentive distribution rights.  See Note Q of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our incentive distribution rights.

We and ONEOK Partners maintain significant financial and corporate governance separations.  We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners.  To aid in understanding the important business and financial characteristics of our ONEOK Partners segment at December 31, 2013, the following describes its business with reference to its underlying activities.

Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business provides nondiscretionary services to producers that include gathering and processing of natural gas produced from crude oil and natural gas wells.  Unprocessed natural gas is compressed and gathered through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas.  The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users. When the NGLs are separated from the

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unprocessed natural gas at the processing plants, the NGLs are in the form of a mixed, unfractionated NGL stream that is delivered to natural gas liquids gathering pipelines for transportation to natural gas liquids fractionators.

ONEOK Partners gathers and processes natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale, Woodford Shale, Granite Wash area and the Mississippian Lime formation of Oklahoma and Kansas and the Hugoton and Central Kansas Uplift Basins of Kansas.  It also gathers and/or processes natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming, which includes the NGL-rich Frontier, Turner, Sussex and Niobrara Shale formations. ONEOK Partners also gathers coal-bed methane, or dry natural gas, in the Powder River Basin that does not require processing or NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

Revenue from the natural gas gathering and processing business is derived primarily from commodity and fee-based contracts. ONEOK Partners generally gathers and processes natural gas under the following types of contracts:

• POP with fee - These commodity contracts allow ONEOK Partners to retain a percentage of the proceeds from the sale of residue gas, condensate, and/or NGLs and to charge fees for gathering, treating, compressing and processing the producer’s natural gas.  POP with fee contracts expose ONEOK Partners to commodity price and volumetric risks but economically align it with the producer because ONEOK Partners’ benefits from higher commodity prices, reduced costs and improved efficiencies. This type of contract represented approximately 85 percent and 81 percent of contracted volumes for 2013 and 2012, respectively.  There are a variety of factors that directly affect ONEOK Partners, POP margins, including:

– the percentage of proceeds retained by ONEOK Partners that represent NGL, condensate and residue natural gas sales that it receives as payment for the services it provides;

– volumes produced that affects its fee revenue;

– transportation and fractionation costs incurred on the NGLs it retains; and

– the natural gas, crude oil and NGL prices received for its retained products.

• Fee - ONEOK Partners is paid a fee for the services it provides, based on volumes gathered, processed, treated and/or compressed. ONEOK Partners’ fee-based contracts expose it to volumetric risk and represent approximately 15 percent and 19 percent of contracted volumes for 2013 and 2012, respectively.

ONEOK Partners expects its capital projects in its natural gas gathering and processing business will continue to provide additional revenues, earnings and cash flows as they are completed. ONEOK Partners expects its natural gas liquids and natural gas commodity price sensitivity within this business to increase in the future as its capital projects are completed and volumes increase under POP contracts with its customers. ONEOK Partners uses commodity derivative instruments and physical-forward contracts to mitigate its sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for its share of volumes.

Natural gas liquids business - ONEOK Partners’ natural gas liquids business owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL products primarily in Oklahoma, Kansas, Texas and the Rocky Mountain region where it provides nondiscretionary services to producers of NGLs.   ONEOK Partners owns or has an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. ONEOK Partners’ natural gas liquids business also owns FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect its Mid-Continent assets with Midwest markets, including Chicago, Illinois.  The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas Panhandle, which extract unfractionated NGLs from unprocessed natural gas, are connected to its gathering systems.  ONEOK Partners’ natural gas liquids business owns and operates truck- and rail-loading and -unloading facilities that interconnect with its NGL fractionation and pipeline assets.  In April 2013, ONEOK Partners’ natural gas liquids business began transporting unfractionated NGLs from natural gas processing plants in the Williston Basin on its Bakken NGL Pipeline. These unfractionated NGLs previously were transported by rail to ONEOK Partners’ Mid-Continent natural gas liquids fractionation facilities. ONEOK Partners’ natural gas liquids business continues to use its rail terminal facilities in its NGL marketing activities.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline.  The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are separated into NGL products.  These NGL products are then stored or distributed to ONEOK Partners’ natural gas liquids business’ customers, such as petrochemical manufacturers, heating fuel users, ethanol producers, refineries and propane

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distributors.  ONEOK Partners’ natural gas liquids business also purchases NGLs and condensate from third parties, as well as from ONEOK Partners’ natural gas gathering and processing business.

Revenues from the natural gas liquids business are derived primarily from nondiscretionary fee-based services provided to ONEOK Partners’ customers and physical optimization of its natural gas liquids assets. Its fee-based services have increased due primarily to new supply connections, expansion of existing connections and its previously completed capital projects, including the Bakken-NGL Pipeline, Cana-Woodford Shale and Granite Wash projects, and expansion of its NGL fractionation capacity.  The sources of revenue are categorized as exchange services, optimization and marketing, pipeline transportation, isomerization and storage, which are defined as follows:

• Exchange services’ activities - ONEOK Partners primarily gathers, fractionates and treats unfractionated NGLs for a fee, thereby converting them into marketable NGL products that are stored and shipped to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments.

• Optimization and marketing activities - ONEOK Partners utilizes its assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials.  ONEOK Partners transports NGL products between Conway, Kansas and Mont Belvieu, Texas, to capture the location price differentials between the two market centers.  ONEOK Partners’ natural gas liquids storage facilities are also utilized to capture seasonal price variances. A growing portion of its marketing activities serves truck and rail markets.

• Pipeline transportation activities - ONEOK Partners transports unfractionated NGLs, NGL products and refined petroleum products, primarily under its FERC-regulated tariffs.  Tariffs specify the maximum rates ONEOK Partners charges its customers and the general terms and conditions for NGL transportation service on its pipelines.

• Isomerization activities - ONEOK Partners captures the product price differential when normal butane is converted into the more valuable iso-butane at its isomerization unit in Conway, Kansas.  Iso-butane is used in the refining industry to increase the octane of motor gasoline.

• Storage activities - ONEOK Partners storage activities consist primarily of fee-based NGL storage services at its Mid-Continent and Gulf Coast storage facilities.

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

ONEOK Partners’ FERC-regulated interstate natural gas pipeline assets transport natural gas through pipelines in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico.  ONEOK Partners’ intrastate natural gas pipeline assets in Oklahoma transport natural gas through the state and have access to the major natural gas producing areas in the state, including the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime.  ONEOK Partners also has access to the major natural gas producing areas, including the Mississippian Lime formation in south central Kansas.  In Texas, its intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas Panhandle, including the Granite Wash area and the Delaware and Cline producing areas in the Permian Basin, and transport natural gas throughout the western portion of Texas, including the Waha Hub where other pipelines may be accessed for transportation to western markets, the Houston Ship Channel market to the east and the Mid-Continent market to the north. ONEOK Partners owns underground natural gas storage facilities in Oklahoma and Texas that are connected to its intrastate natural gas pipeline assets. ONEOK Partners also has underground natural gas storage facilities in Kansas.

ONEOK Partners’ revenues from its natural gas pipelines are derived typically from fee-based services provided to its customers. Its revenues are generated from the following types of fee-based contracts:

• Firm service - Customers can reserve a fixed quantity of pipeline or storage capacity for the terms of their contract. Under this type of contract, the customer pays a fixed fee for a specified quantity regardless of their actual usage. The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport or store, and/or ONEOK Partners may retain a specified volume of natural gas in-kind for fuel.  Under the firm-service contract, the customer generally is guaranteed access to the capacity they reserve; and

• Interruptible service - Customers with interruptible service transportation and storage agreements may utilize available capacity after firm-service requests are satisfied or on an as-available basis.  Interruptible service customers typically are assessed fees, such as a commodity charge, based on their actual usage, and/or ONEOK Partners may retain a specified volume of natural gas in-kind for fuel.  Under the interruptible service contract, the customer is not guaranteed use of ONEOK Partners’ pipelines and storage facilities unless excess capacity is available.

Market Conditions and Seasonality - Supply - Natural gas, crude oil and NGL supply is affected by producer drilling activity, which is sensitive to commodity prices, drilling rig availability, exploration success, operating capability, the NGL content of

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the natural gas that is produced and processed, access to capital and regulatory control.  Crude oil prices and advances in horizontal drilling and completion technology have had a positive impact on drilling activity in the crude oil and NGL-rich shale and other nonconventional resource areas, providing an offset to the less favorable supply projections in some of the dry natural gas conventional resource areas. Extreme weather conditions can impact the volume of natural gas gathered and processed and NGL volumes gathered, transported and fractionated. Freeze-offs are a phenomenon where water produced from natural gas freezes at the wellhead or within the gathering system. This causes a temporary interruption in the flow of natural gas. This is more prevalent in the Rocky Mountain region where temperatures tend to be colder than in the Mid-Continent region but can occur throughout ONEOK Partners’ systems. All of ONEOK Partners’ operations may be affected by other weather conditions that may cause a loss of electricity or prevent access to certain locations that affect a producer’s ability to complete wells or ONEOK Partners’ ability to connect these wells to its systems.

In the Rocky Mountain region, Williston Basin volumes continue to grow as well connections from drilling completions increase, driven primarily by producer development of Bakken Shale and Three Forks formation crude oil wells, which also produce associated natural gas containing significant quantities of NGLs.  However, ONEOK Partners’ natural gas gathering and processing business has experienced declines in natural gas volumes gathered in the portions of the Powder River Basin that produce dry natural gas.

In the Mid-Continent region, ONEOK Partners has a significant amount of natural gas gathering and processing assets in western Oklahoma and southwest Kansas.  ONEOK Partners expects continued drilling activity in the Cana-Woodford Shale and Granite Wash areas of western Oklahoma and the Mississippian Lime formation of Oklahoma and Kansas to offset the volumetric declines in most conventional wells that supply its natural gas gathering and processing facilities.

NGL supply for ONEOK Partners’ natural gas liquids business depends on the pace of crude oil and natural gas drilling activity by producers, the decline rate of existing production and the NGL content of the natural gas that is produced and processed.  ONEOK Partners’ natural gas liquids business has seen rapid NGL supply growth within its operating footprint as producers continue to aggressively drill in a number of NGL-rich resource areas in the Mid-Continent and Rocky Mountain regions.  ONEOK Partners expects the overall supply of NGLs to continue to increase, as well as demand for its fee-based services, as a result of the development of these resource areas.  Many new natural gas processing plants are being constructed in North Dakota, Wyoming, Oklahoma and the Texas Panhandle to process NGL-rich natural gas being produced in the Williston Basin, Niobrara Shale, Cana-Woodford Shale, Granite Wash, Woodford Shale and the Mississippian Lime areas.  The unfractionated NGLs that ONEOK Partners’ natural gas liquids business transports are gathered primarily from natural gas processing plants in Oklahoma, Kansas, Texas and the Rocky Mountain region.  Its gathering and fractionation operations receive NGLs from a variety of processors and pipelines, including affiliates, located in these regions.

ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses also are affected by operational or market-driven changes that affect the output of natural gas processing plants to which ONEOK Partners’ NGL assets are connected.  The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differentials between ethane and natural gas, has influenced the volume of ethane natural gas processing plants make available to be gathered in ONEOK Partners’ natural gas liquids business. When economic conditions warrant, certain natural gas processors elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants.  Price differentials between ethane and natural gas resulted in ethane rejection at most of ONEOK Partners’ natural gas processing plants and some of  ONEOK Partners’ natural gas liquids business’ customers’ natural gas processing plants connected to its natural gas liquids gathering system in the Mid-Continent and Rocky Mountain regions during 2013, which reduced natural gas liquids volumes gathered, fractionated and transported in its natural gas liquids business and its results of operations.

ONEOK Partners expects 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 the financial results of ONEOK Partners’ natural gas liquids business over this period. However, its integrated natural gas liquids assets enable it to mitigate partially the impact of ethane rejection through minimum volume agreements and its ability to utilize the transportation capacity made available due to ethane rejection to capture additional NGL location price differentials in its optimization activities. In addition, new NGL supply commitments are expected to increase volumes in 2014 through 2016 to mitigate further the impact of ethane rejection on ONEOK Partners’ natural gas liquids business. See additional discussion in the “Financial Results and Operating Information” section in our ONEOK Partners segment.

Natural gas, natural gas liquids and crude oil transportation constraints may also affect the output of natural gas processing plants in total or for specific NGL products in the future.  During 2013, ONEOK Partners’ natural gas liquids business experienced limited reductions of supply related to changes in plant output as a result of transportation constraints.

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ONEOK Partners’ interstate natural gas pipelines access supply from major producing regions in the Mid-Continent, Rocky Mountain, Gulf Coast, the Northeast and Canada. Supply volumes from nontraditional natural gas production areas, such as into the Northeast, may compete with and displace volumes from the Mid-Continent, Rocky Mountains and Canadian supply sources in our markets.

Demand-Demand for natural gas gathering and processing services is aligned typically with the production of natural gas from natural gas resource areas or the associated natural gas from wells drilled in crude oil resource areas.  Gathering and processing are nondiscretionary services that producers require to market their natural gas and NGL production.  As producers continue to develop NGL-rich shale and other resource areas, ONEOK Partners expects demand for its natural gas gathering and processing services to increase.

Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations affect the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, fractionation and distribution services.  Natural gas and propane are subject to weather-related seasonal demand. Other NGL products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as butanes and natural gasoline used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil.  Ethane, propane, normal butane and natural gasoline are used by the petrochemical industry to produce chemical products, such as plastics, rubber and synthetic fibers. Several petrochemical companies announced new plants, plant expansions, additions or enhancements that improve the light-NGL feed capability of their facilities due primarily to the increased supply and attractive price of ethane, compared with crude oil-based alternatives, as a petrochemical feedstock in the United States. The demand is expected to increase significantly in two to four years when the new petrochemical plants are completed. In addition, international demand for propane is expected to continue affecting the NGL market in the future.  ONEOK Partners expects this increase in demand for NGLs will provide opportunities to increase fee-based earnings in its exchange services, storage activities and marketing activities.

Demand for natural gas pipeline transportation service and natural gas storage is related directly to its access to supply and the demand for natural gas in the markets that ONEOK Partners’ natural gas pipelines and storage facilities serve. It is affected by weather, the economy and natural gas and NGL price volatility.  ONEOK Partners’ natural gas pipelines primarily serve end-users, such as local natural gas distribution companies, electric-generation companies, large industrial companies, municipalities and irrigation customers that require natural gas to operate their businesses and generally are not affected by location price differentials. However, narrower location price differentials may affect demand for ONEOK Partners’ services from natural gas marketers as discussed below under “Commodity Prices.”  Demand for ONEOK Partners’ natural gas pipelines services is also affected as coal-fired electric generators are retired and replaced with alternative power generation fuels such as natural gas. Recent EPA regulations on emissions from coal-fired electric-generation plants, including the Maximum Achievable Control Technology Standards and the Mercury and Air Toxics Standards, have increased the demand for natural gas as a fuel for electric generation, as well as related transportation and storage services. The demand for natural gas and related transportation and storage services is expected to increase over the next several years as these regulations continue to be implemented. The effect of weather on ONEOK Partners’ natural gas pipelines operations is discussed below under “Seasonality.” The strength of the economy directly affects manufacturing and industrial companies that consume natural gas.  Commodity price volatility can influence producers’ decisions related to the production of natural gas and the amount of NGLs processed from natural gas.

Commodity Prices - Crude oil, natural gas and NGL prices can be volatile due to changes in market conditions.  Commodity prices can also be affected by demand for products from the petrochemical industry and other consumers, storage injection and withdrawal rates, and available storage capacity.  The increase in natural gas supply from shale gas development has caused natural gas prices to remain low and natural gas location and seasonal price differentials to remain narrow across the regions where ONEOK Partners operates.  However, an increase in crude oil prices and the abundance of NGLs produced from the development of NGL-rich shale resource areas have made producing NGL feedstocks for the petrochemical industry more profitable.  ONEOK Partners is exposed to commodity-price risk in its natural gas gathering and processing business as a result of receiving commodities in exchange for services, primarily on POP contracts, and in its natural gas liquids business from the NGLs it purchases and sells.

The increased drilling activities and production have resulted in lower NGL prices, as well as minimal price volatility and narrower NGL location and seasonal price differentials for natural gas and NGLs in the markets we serve during 2013. We expect similar conditions in 2014; however, market conditions may produce periods of higher prices and volatility, as well as wider NGL location and product price differentials. For example, in the fourth quarter 2013, the price of propane increased significantly, and the price differential of propane between the Conway, Kansas, and the Mont Belvieu, Texas, market centers also widened in favor of Conway, Kansas, due to colder than normal weather and lower propane inventory levels. We expect

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propane prices to remain high through the 2014 winter heating season. The abundance of NGLs produced from the development of shale and other resource areas has made NGL feedstocks to the petrochemical industry less costly.  Ethane production has increased more rapidly than the petrochemical industry's current capability to consume the increase in supplies. This oversupplied situation contributed to low ethane prices in 2013. While petrochemical demand remained strong in 2013 and ethane inventory levels decreased, ONEOK Partners believes the oversupply of ethane may persist until ethylene producers increase their capacity to consume additional ethane feedstock volumes through plant modifications and expansions and the completion of announced new world-scale ethylene capacity. In the near term, ONEOK Partners expects continued ethane price volatility and ethane rejection to balance supply and demand.

ONEOK Partners is also exposed to market risk associated with the location price differentials between receipt and delivery points along its natural gas and natural gas liquids pipelines, also known as location differentials. Its natural gas liquids business is exposed to market risk associated with changes in the price of NGLs; the location differential between the Mid-Continent, Chicago, Illinois, and Gulf Coast regions; and the relative price differential between natural gas, NGLs and individual NGL products, which affect its NGL purchases, sales and margins related to its NGL exchange, storage, transportation and optimization activities.  When natural gas prices are higher relative to NGL prices, NGL production may decline due to ethane rejection, which could negatively affect ONEOK Partners’ exchange services and transportation revenues.  When the NGL location price differential between the Mid-Continent and Gulf Coast market centers is narrow, optimization opportunities and NGL shipments may decline, resulting in a decline in earnings from our NGL optimization and marketing activities. During 2013, strong production and supply 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 resulted in NGL price differentials remaining narrow between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas.  NGL storage revenue may be affected by price volatility and forward pricing of NGL physical contracts versus the price of NGLs on the spot market.

To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, ONEOK Partners uses commodity derivative instruments such as futures, swaps and physical-forward contracts to manage commodity-price risk associated with existing or anticipated purchase and sale agreements, existing physical natural gas or NGLs in storage and location price differentials.

Seasonality -Our ONEOK Partners segment’s products and services are subject to weather-related seasonal demand.  Cold temperatures typically increase demand for natural gas and propane, which are used to heat homes and businesses.  Extreme warm or cold temperatures typically drive demand for natural gas used for natural gas-fired electric generation needed to meet the electricity-generation demand required to heat and cool residential and commercial properties.  Precipitation levels also can impact the demand for natural gas that is used to fuel irrigation activity in the Mid-Continent region and demand for propane used to fuel crop-drying activity.  Demand for butanes and natural gasoline, which are used primarily by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, may also be subject to some variability during seasonal periods when certain government restrictions on motor fuel blending products are in place.  During periods of peak demand for a certain commodity, prices for that product typically increase, which may influence natural gas processing and NGL fractionation decisions. During late 2013, ONEOK Partners’ natural gas liquids business experienced high propane demand for crop drying, international exports and home heating due to colder than normal winter weather.

Competition -ONEOK Partners’ natural gas and natural gas liquids businesses compete directly with other companies for natural gas and NGL supply, markets and services.  Competition for natural gas transportation services continues to increase as new infrastructure projects are completed and the FERC and state regulatory bodies continue to encourage additional competition in the natural gas markets.  Competition is based primarily on fees for services, quality of services provided, current and forward natural gas and NGL prices and proximity to supply areas and markets.  ONEOK Partners believes that the location and integration of its assets enable it to compete effectively.

ONEOK Partners’ natural gas gathering and processing business competes for natural gas supplies with major integrated oil companies, independent exploration and production companies that have gathering and processing assets, pipeline companies and their affiliated marketing companies, national and local natural gas gatherers and processors, and marketers in the Mid-Continent and Rocky Mountain regions. ONEOK Partners’ natural gas liquids business competes with other fractionators, intrastate and interstate pipeline companies, storage providers, gatherers and transporters for NGL supplies in the Rocky Mountain, Mid-Continent and Gulf Coast regions.  The factors that typically affect ONEOK Partners’ ability to compete for natural gas and NGL supply are:

• quality of services provided;

• producer drilling activity;

• the petrochemical industry’s level of capacity utilization and feedstock requirements;

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• products retained and/or fees charged under its contracts;

• current and forward NGL prices;

• location of its assets relative to those of its competitors;

• location of its assets relative to drilling activity;

• proximity to NGL supply areas and markets;

• efficiency and reliability of its operations;

• operating pressures maintained on its gathering systems; and

• receipt and delivery capabilities that exist for natural gas and NGLs in each pipeline system, processing plant, fractionator and storage location.

ONEOK Partners is responding to these factors by making capital investments to access new supply by increasing gathering, processing, fractionation and distribution capacity; increasing storage, withdrawal and injection capabilities; and improving natural gas processing efficiency and reducing operating costs.  ONEOK Partners’ competitors are constructing or have completed new natural gas gathering and processing facilities and natural gas liquids pipelines and fractionators to address the growing natural gas and NGL supply and petrochemical demand.  ONEOK Partners is also evaluating opportunities to maximize earnings and renegotiating low-margin contracts to improve margins and reduce risk. When completed, ONEOK Partners’ growth projects and those of its competitors are expected to alleviate constraints between the Conway, Kansas, and Mont Belvieu, Texas, natural gas liquids market centers. As a result, we expect the narrow location price differentials between the Mid-Continent and Gulf Coast market centers to continue. 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 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 our assets are located. We believe ONEOK Partners’ natural gas gathering and processing, NGL fractionation, pipelines and storage assets are located strategically, connecting diverse supply areas to market centers.

Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act.  Although the FERC has made no specific declaration as to the jurisdictional status of ONEOK Partners’ natural gas processing operations or facilities, ONEOK Partners’ natural gas processing plants are primarily involved in extracting NGLs and, therefore, ONEOK Partners believes its natural gas processing plants are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC.  ONEOK Partners believes its natural gas gathering facilities and operations meet the criteria used by the FERC for nonjurisdictional gathering facility status.  Interstate transmission facilities remain subject to FERC jurisdiction.  The FERC has distinguished historically between these two types of facilities, either interstate or intrastate, on a fact-specific basis.  ONEOK Partners also transports residue gas from its natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act.

Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, in various degrees, the gathering of natural gas in those states.  In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

The operations and revenues of ONEOK Partners’ natural gas liquids pipelines are regulated by various state and federal government agencies.  Its interstate natural gas liquids pipelines are regulated by the FERC, which has authority over the terms and conditions of service and rates, including depreciation and amortization policies, and initiation of service.  In Oklahoma, Kansas and Texas, ONEOK Partners’ intrastate natural gas liquids pipelines that provide common carrier service are subject to the jurisdiction of the OCC, KCC and RRC, respectively.

PHMSA has asserted jurisdiction over certain portions of ONEOK Partners’ natural gas liquids fractionation facilities in Bushton, Kansas, that ONEOK Partners believes are not subject to its jurisdiction. ONEOK Partners has objected to the scope of PHMSA’s jurisdiction and is seeking resolution of this matter. We do not anticipate that the cost of compliance will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

ONEOK Partners’ interstate natural gas pipelines are regulated under the Natural Gas Act and Natural Gas Policy Act, which give the FERC jurisdiction to regulate virtually all aspects of the pipeline activities.  ONEOK Partners’ intrastate natural gas transportation assets in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively.  ONEOK Partners has flexibility in establishing natural gas transportation rates with customers.  However, there are maximum rates that ONEOK Partners can charge its customers in Oklahoma and Kansas.

Recent EPA regulations on emissions from coal-fired electric-generation plants, including the Maximum Achievable Control Technology Standards and the Mercury and Air Toxics Standards, have increased the demand for natural gas as a fuel for

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electric generation, as well as related transportation and storage services. The demand for natural gas and related transportation and storage services is expected to increase over the next several years as these regulations continue to be implemented.

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.

See further discussion in the “Environmental and Safety Matters” section.

Unconsolidated Affiliates - Our ONEOK Partners segment has investments in unconsolidated affiliates that include Northern Border Pipeline, Overland Pass Pipeline Company, three partnerships that operate natural gas gathering systems located primarily in the Powder River of Wyoming and other investments.  Northern Border Pipeline is a leading transporter of natural gas imported from Canada into the United States.  Overland Pass Pipeline Company operates an interstate natural gas liquids pipeline system that transports natural gas liquids from the Rocky Mountain region to the Mid-Continent NGL market center.

See Note P of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of ONEOK Partners’ unconsolidated affiliates.

Natural Gas Distribution

Separation of Natural Gas Distribution Business - On January 31, 2014, we completed the separation of our natural gas distribution business into a standalone publicly traded company, ONE Gas.  ONE Gas consists of ONEOK’s former Natural Gas Distribution segment that includes Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service.  See additional discussion in Note U of the Notes to the Consolidated Financial Statements. The Natural Gas Distribution segment has been classified as discontinued operations effective February 1, 2014.

Overview - Our former Natural Gas Distribution segment provides natural gas distribution services to more than 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, serving residential, commercial, industrial and transportation customers in all three states.  In addition, our former LDCs serve wholesale and public authority customers.  Its operations are subject to regulations and oversight of various regulatory agencies.

Our operating results were affected primarily by the number of customers, usage and the ability to collect service fees that provided a reasonable rate of return on our investment and recovery of our cost of service.  Natural gas costs were passed through to our customers based on the actual cost of natural gas purchased by the respective natural gas distribution company and related expenses, including transportation and storage costs.  Substantial fluctuations in natural gas sales could occur from year to year without materially or adversely impacting our former LDCs’ net margin, since the fluctuations in natural gas costs affected natural gas sales and cost of gas by an equivalent amount.

Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service distribute natural gas as public utilities to approximately 87 percent, 69 percent and 14 percent of the natural gas distribution customers in Oklahoma, Kansas and Texas, respectively. Natural gas sold to residential and commercial customers as a percentage of our former LDC’s total natural gas sales by state is presented in the table below:

	Oklahoma	Kansas	Texas
Residential	82%	80%	69%
Commercial	17%	19%	22%

Market Conditions and Seasonality - Natural gas supply requirements are affected by weather conditions.  In addition, economic conditions affect the requirements of our former LDCs’ commercial and industrial customers.  Natural gas usage per residential customer may decline as customers change their consumption patterns in response to a variety of factors including:  

• more volatile and higher natural gas prices;

• customers improving the energy efficiency of existing homes by replacing doors and windows, adding insulation and replacing appliances with more efficient ones;

• more energy-efficient construction; and

• fuel switching.

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In each jurisdiction in which our former natural gas distribution segment operated, changes in customer-usage profiles were considered in the periodic redesign of rates.

In managing our natural gas supply portfolios, we partially mitigated price volatility, using a combination of physical and financial derivatives and natural gas in storage.  We had natural gas financial hedging programs authorized by the regulatory authorities in each state in which our former LDCs do business.  We did not utilize financial derivatives for speculative purposes nor did we have trading operations associated with our former Natural Gas Distribution segment.  We utilized 57.3 Bcf of contracted storage capacity in 2013, which allowed natural gas to be purchased during the off-peak season and stored for use in the winter periods.

Demand - See discussion below under “Seasonality” for factors affecting demand for our former natural gas distribution business.

Seasonality - Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas requirements are for heating.  Accordingly, the volume of natural gas sales is higher normally during the months of November through March than in other months of the year.  The impact on margins for our former LDCs resulting from weather temperatures that are above or below normal is offset partially through weather-normalization adjustment (WNA) mechanisms.  These adjustments have been approved by the regulatory authorities for our Oklahoma, Kansas and certain Texas service territories.  WNAs allow us to increase customer billing to offset lower gas usage when weather is warmer than normal and decrease customer billing to offset higher gas usage when weather is colder than normal.

Government Regulation - Rates charged for natural gas transportation services by the LDCs in our former Natural Gas Distribution segment are established by the OCC for Oklahoma Natural Gas and by the KCC for Kansas Gas Service.  Texas Gas Service is subject to regulatory oversight by the various municipalities that it serves, which have primary jurisdiction in their respective areas. Rates in unincorporated areas of Texas and all appellate matters are subject to regulatory oversight by the RRC.  Natural gas supply costs for our former LDCs are passed on to its customers through a purchased-gas cost-adjustment mechanism.  Our former LDCs did not make a profit on the cost of natural gas.

See further discussion in the “Environmental and Safety Matters” section.

Energy Services

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

As a result of the accelerated wind down, in 2013 we recorded noncash charges of approximately $138.6 million, before taxes, which were recorded in cost of sales and fuel in our Consolidated Statements of Income. We expect future cash expenditures associated with the released transportation and storage capacity from the wind down of our Energy Services segment to be approximately $80 million on an after-tax basis, which consist of approximately $33 million in 2014, $24 million in 2015, $13 million in 2016 and $10 million during the period from 2017 through 2023.

During the wind down process, we retained 23.5 Bcf of contracted natural gas storage capacity of which 20.5 will expire by March 31, 2014. In the first quarter 2014, we assigned the remaining 3.0 Bcf of natural gas storage capacity to a third party, effective April 1, 2014, and we expect to record an additional noncash charge of approximately $1.7 million, before taxes. We will utilize this capacity through March 31, 2014, to serve our contracted premium services customers by providing natural gas supply and risk-management services for natural gas and electric utilities and industrial customers. Premium services volumes, revenues and cost of sales decreased materially as we have realigned our business operations with the remaining contracted capacity. Our premium services include next-day and no-notice natural gas delivery services. Next-day services allow our customers to call on additional natural gas supply up to an amount agreed upon in a service contract and expect delivery the following day. No-notice services allow customers to call on additional natural gas supply and expect immediate delivery.  We also provide weather-related protection and other custom solutions based on our customers’ specific needs.

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Government Regulation - Our Energy Services segment purchases natural gas for resale at negotiated rates in interstate commerce.  As such, it has been granted by FERC an automatic blanket certificate of public convenience and necessity authorizing such sales.  This is a limited certificate that does not subject our Energy Services segment to any other regulation of FERC under its Natural Gas Act jurisdiction.  Holders of blanket marketing certificates are subject to certain reporting and document retention requirements.

SEGMENT FINANCIAL INFORMATION

Operating Income, Customers and Total Assets - See Note S of the Notes to Consolidated Financial Statements in this Annual Report for disclosure by segment of our operating income and total assets and for a discussion of revenues from external customers.

Other

Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own a parking garage and an office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, where our headquarters are located.  ONEOK Leasing Company, L.L.C. leases excess office space to others and operates our headquarters office building.  ONEOK Parking Company, L.L.C. owns and operates a parking garage adjacent to our headquarters.

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 our 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.

ENVIRONMENTAL AND SAFETY MATTERS

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

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

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

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

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

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

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

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

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

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

Federal, state and regional initiatives to measure and regulate greenhouse gas emissions are underway.  We monitor all relevant federal and state legislation to assess the potential impact on our operations.  The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual greenhouse gas emissions reporting from affected facilities and the carbon dioxide emissions equivalents for the natural gas delivered by us to our natural gas distribution customers who are not otherwise required to report their own emissions and the emissions equivalents for all NGLs produced by ONEOK Partners as if all of these products were combusted, even if they are used otherwise.

Our 2012 total reported emissions were approximately 64.9 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers and produced, as if all such fuel and NGL products were combusted. The additional cost to gather and report this emissions data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows.  In addition, Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rulemaking associated with greenhouse gas emissions from the oil and gas industry. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

The EPA’s “Tailoring Rule” regulates greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology, conduct air-quality 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.

In July 2011, the EPA issued a proposed rule that would change the air emissions New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and natural gas industry, including natural gas production, processing, transmission and underground storage sectors. In April 2012, the EPA released

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the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification.

In March 2013, the EPA issued proposed rulemaking to amend the NSPS for the crude oil and natural gas industry, pursuant to various industry comments, administrative petitions for reconsideration and/or judicial appeals of portions of the NSPS final rule. The rule was most recently amended again in September 2013, and the EPA has indicated that further amendments may be issued in 2014. Based on the amendments and our understanding of pending stakeholder responses to the NSPS rule, we do not expect future capital, operations and maintenance costs resulting from compliance with the regulation to be material. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude oil and natural gas industry. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

CERCLA - The federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) who caused and/or contributed to the release of a hazardous substance into the environment.  These persons include, but are not limited to, the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. We do not expect our responsibilities under CERCLA will have a material impact on our results of operations, financial position or cash flows.

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

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

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

We participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions.  We continue to focus on maintaining low rates of lost-and-unaccounted-for natural gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.

EMPLOYEES

At February 1, 2014, we employed 1,927 people.

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EXECUTIVE OFFICERS

All executive officers are elected annually by our Board of Directors and each serves until such person resigns, is removed or is otherwise disqualified to serve or until such officer’s successor is duly elected.  Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.

Name and Position	Age	Business Experience in Past Five Years
John W. Gibson	61	2014 to present	Chairman of the Board, ONEOK and ONEOK Partners
Chairman of the Board		2012 to 2014	Chairman and Chief Executive Officer, ONEOK and ONEOK Partners
		2011	Chairman, President and Chief Executive Officer, ONEOK
		2011	Vice Chairman of the Board of Directors, ONEOK
		2010 to 2011	President and Chief Executive Officer, ONEOK
		2010 to 2011	Chairman, President and Chief Executive Officer, ONEOK Partners
		2007 to 2009	Chief Executive Officer, ONEOK
		2007 to 2009	Chairman and Chief Executive Officer, ONEOK Partners
Terry K. Spencer	54	2014 to present	President and Chief Executive Officer, ONEOK and ONEOK Partners
President and Chief Executive Officer		2012 to 2014	President, ONEOK and ONEOK Partners
		2010 to present	Member of the Board of Directors, ONEOK Partners
		2009 to 2011	Chief Operating Officer, ONEOK Partners
		2007 to 2009	Executive Vice President, Natural Gas Liquids, ONEOK Partners
Robert F. Martinovich	56	2014 to present	Executive Vice President, Commercial, ONEOK and ONEOK Partners
Executive Vice President, Commercial		2013 to 2014	Executive Vice President, Operations, ONEOK and ONEOK Partners
		2012	Executive Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners
		2011 to 2012	Member of the Board of Directors, ONEOK Partners
		2011	Senior Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners
		2009 to 2011	Chief Operating Officer, ONEOK
		2007 to 2009	President, Gathering and Processing, ONEOK Partners
Wesley J. Christensen	60	2014 to present	Senior Vice President, Operations, ONEOK and ONEOK Partners
Senior Vice President, Operations		2011 to 2014	Senior Vice President, Operations, ONEOK Partners
		2007 to 2011	Senior Vice President, Natural Gas Liquids Operations
Stephen W. Lake	50	2012 to present	Senior Vice President, General Counsel and Assistant Secretary, ONEOK and ONEOK Partners
Senior Vice President, General Counsel and Assistant Secretary		2011	Senior Vice President, Associate General Counsel and Assistant Secretary, ONEOK and ONEOK Partners
		2008 to 2011	Executive Vice President and General Counsel, McJunkin Red Man Corporation
Derek S. Reiners	42	2013 to present	Senior Vice President, Chief Financial Officer and Treasurer, ONEOK and ONEOK Partners
Senior Vice President, Chief Financial Officer and Treasurer		2009 to 2012	Senior Vice President and Chief Accounting Officer, ONEOK and ONEOK Partners
		2004 to 2009	Partner, Grant Thornton LLP
Sheppard F. Miers III	45	2013 to present	Vice President and Chief Accounting Officer, ONEOK and ONEOK Partners
Vice President and Chief Accounting Officer		2009 to 2012	Vice President and Controller, ONEOK Partners
		2005 to 2009	Vice President, ONEOK
Dandridge L. Harrison	60	2012 to present	Senior Vice President, Administrative Services and Corporate Relations, ONEOK and ONEOK Partners
Senior Vice President, Administrative Services and Corporate Relations		2008 to 2012	Vice President, Investor Relations and Public Affairs, ONEOK and ONEOK Partners

No family relationships exist between any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.  Copies of our Code of Business Conduct and Ethics, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also available on our website, and we will provide copies of these documents upon request.  Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.

ITEM 1A.    RISK FACTORS

Our investors should consider the following risks that could affect us and our business.  Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future.  New risks may emerge at any

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time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance.  Investors should carefully consider the following discussion of risks and the other information included or incorporated by reference in this Annual Report, including “Forward-Looking Statements,” which are included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

RISK FACTORS INHERENT IN OUR BUSINESS

Market volatility and capital availability could affect adversely our business.

The capital and global credit markets have experienced volatility and disruption in the past.  In many cases during these periods, the capital markets have exerted downward pressure on equity values and reduced the credit capacity for certain companies.  Our ability to grow could be constrained if we do not have regular access to the capital and global credit markets.  Similar or more severe levels of global market disruption and volatility may have an adverse affect on us resulting from, but not limited to, disruption of our access to capital and credit markets, difficulty in obtaining financing necessary to expand facilities or acquire assets, increased financing cost and increasingly restrictive covenants.

Our operating results may be affected materially and adversely by unfavorable economic and market conditions.

Economic conditions worldwide have from time to time contributed to slowdowns in the oil and natural gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services.  Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region.  Volatility in commodity prices may have an impact on many of our customers, which, in turn, could have a negative impact on their ability to meet their obligations to us.  If global economic and market conditions (including volatility in commodity markets), or economic conditions in the United States or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition, results of operations and liquidity.

Our cash flow depends heavily on the earnings and distributions of ONEOK Partners.

Our partnership interest in ONEOK Partners is our largest cash-generating source.  Therefore, our cash flow is heavily dependent upon the ability of ONEOK Partners to make distributions to its partners.  A significant decline in ONEOK Partners’ earnings and/or cash distributions could have a corresponding negative impact on us.  For information on the risk factors inherent in the business of ONEOK Partners, see the section below entitled “Additional Risk Factors Related to ONEOK Partners’ Business” and Item 1A, Risk Factors in the ONEOK Partners’ Annual Report.

Some of our nonregulated businesses have a higher level of risk than our regulated businesses.

Some of our nonregulated operations, which include ONEOK Partners’ natural gas gathering and processing business, most of its natural gas liquids business and our energy services business, have a higher level of risk than our regulated operations, which include ONEOK Partners’ natural gas pipelines business and a portion of its natural gas liquids business.  We and ONEOK Partners expect to continue investing in natural gas and natural gas liquids projects and other related projects, some or all of which may involve nonregulated businesses or assets.  These projects could involve risks associated with operational factors, such as competition and dependence on certain suppliers and customers, and financial, economic and political factors, such as rapid and significant changes in commodity prices, the cost and availability of capital and counterparty risk, including the inability of a counterparty, customer or supplier to fulfill a contractual obligation.

Terrorist attacks directed at our facilities could affect adversely our business.

Since the terrorist attacks on September 11, 2001, the United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations.  These developments may subject our operations to increased risks.  Any future terrorist attack that targets our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

Our businesses are subject to market and credit risks.

We are exposed to market and credit risks in all of our operations.  To minimize the risk of commodity price fluctuations, we periodically enter into derivative transactions to hedge anticipated purchases and sales of natural gas, NGLs, crude oil, fuel requirements and firm transportation commitments.  Interest-rate swaps are also used to manage interest-rate risk. However, financial derivative instrument contracts do not eliminate the risks.  Specifically, such risks include commodity price changes,

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market supply shortages, interest-rate changes and counterparty default.  The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts, or increased interest expense.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by customers and counterparties of our Energy Services segment.  The customers of our Energy Services segment are predominantly LDCs, industrial customers, natural gas producers and marketers that may experience deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their creditworthiness or ability to pay for our services.  During the wind down process, if we fail to assess adequately the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting nonpayment and/or nonperformance could affect adversely results of operations for our Energy Services segment.  In addition, if any of our Energy Services segment’s customers or counterparties filed for bankruptcy protection, we may not be able to recover amounts owed, which could impact materially and adversely the results of operations for our Energy Services segment.

We may not be able to make additional strategic acquisitions or investments.

Our ability to make strategic acquisitions and investments will depend on:

• the extent to which acquisitions and investment opportunities become available;

• our success in bidding for the opportunities that do become available;

• regulatory approval, if required, of the acquisitions or investments on favorable terms; and

• our access to capital, including our ability to use our equity in acquisitions or investments, and the terms upon which we obtain capital.

If we are unable to make strategic investments and acquisitions, we may be unable to grow.

Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per-share basis.

Any acquisition involves potential risks that may include, among other things:

• inaccurate assumptions about volumes, revenues and costs, including potential synergies;

• an inability to integrate successfully the businesses we acquire;

• decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

• a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;

• the assumption of unknown liabilities for which we are not indemnified, our indemnity is inadequate or our insurance policies may exclude from coverage;

• an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets;

• limitations on rights to indemnity from the seller;

• inaccurate assumptions about the overall costs of equity or debt;

• the diversion of management’s and employees’ attention from other business concerns;

• unforeseen difficulties operating in new product areas or new geographic areas; 

• increased regulatory burdens;

• customer or key employee losses at an acquired business; and

• increased regulatory requirements.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.

We may engage in acquisitions, divestitures and other strategic transactions, the success of which may impact our results of operations.

We may engage in acquisitions, divestitures and other strategic transactions.  If we are unable to integrate successfully businesses that we acquire with our existing business, our results of operations may be affected materially and adversely. Similarly, we may from time to time divest portions of our business, which may also affect materially and adversely our results of operations.

Our established risk-management policies and procedures may not be effective, and employees may violate our risk-management policies.

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We have developed and implemented a set of policies and procedures that involve both our senior management and the Audit Committee of our Board of Directors to assist us in managing risks associated with, among other things, the marketing, trading and risk-management activities associated with our business segments.  Our risk policies and procedures are intended to align strategies, processes, people, information technology and business knowledge so that risk is managed throughout the organization. As conditions change and become more complex, current risk measures may fail to assess adequately the relevant risk due to changes in the market and the presence of risks previously unknown to us.  Additionally, if employees fail to adhere to our policies and procedures or if our policies and procedures are not effective, potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended.  Ineffective risk-management policies and procedures or violation of risk-management policies and procedures could have an adverse affect on our earnings, financial position or cash flows.

Our indebtedness could impair our financial condition and our ability to fulfill our obligations.

As of December 31, 2013, we had total indebtedness for borrowed money of approximately $1.7 billion, which excludes the debt of ONEOK Partners.  Our indebtedness could have significant consequences.  For example, it could:

• make it more difficult for us to satisfy our obligations with respect to our senior notes and our other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or our senior notes;

• impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;

• diminish our ability to withstand a downturn in our business or the economy;

• require us to dedicate a substantial portion of our cash flow from operations to debt-service payments, reducing the availability of cash for working capital, capital expenditures, acquisitions, or general corporate purposes;

• limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

• place us at a competitive disadvantage compared with our competitors that have proportionately less debt.

We are not prohibited under the indentures governing our senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations summarized in the next paragraph.  If we incur significant additional indebtedness, it could worsen the negative consequences mentioned above and could affect adversely our ability to repay our other indebtedness.

Our revolving debt agreements with banks contain provisions that restrict our ability to finance future operations or capital needs or to expand or pursue our business activities.  For example, certain of these agreements contain provisions that, among other things, limit our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, grant liens or make negative pledges.  Certain agreements also require us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur, as described in the “Liquidity and Capital Resources” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash.  Future financing agreements we may enter into may contain similar or more restrictive covenants.

If we are unable to meet our debt-service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets.  We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

We are subject to risks that could limit our access to capital, thereby increasing our costs and affecting adversely our results of operations.

We have grown rapidly in the past as a result of acquisitions.  Future acquisitions may require additional capital.  If we are unable to access capital at competitive rates, our strategy of enhancing the earnings potential of our existing assets, including through acquisitions of complementary assets or businesses, will be affected adversely.  A number of factors could affect adversely our ability to access capital, including: (i) general economic conditions; (ii) capital market conditions; (iii) market prices for natural gas, NGLs and other hydrocarbons; (iv) the overall health of the energy and related industries; (v) our ability to maintain our investment-grade credit ratings; and (vi) our capital structure.  Much of our business is capital intensive, and achievement of our long-term growth targets is dependent, at least in part, upon our ability to access capital at rates and on terms we determine to be attractive.  If our ability to access capital becomes constrained significantly, our interest costs will likely increase and our financial condition and future results of operations could be harmed significantly.

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The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may increase.

We have a defined benefit pension plan for certain employees and postretirement welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service.  The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension and postretirement benefit plan assets, changing demographics, including longer life expectancy of plan participants and their beneficiaries and changes in health care costs.  For further discussion of our defined benefit pension plan, see Note N of the Notes to Consolidated Financial Statements in this Annual Report.

Any sustained declines in equity markets and reductions in bond yields may have a material adverse effect on the value of our pension and postretirement benefit plan assets.  In these circumstances, additional cash contributions to our pension plans may be required.

Federal, state and local jurisdictions may challenge our tax return positions.

The positions taken in our federal and state tax return filings require significant judgments, use of estimates and the interpretation and application of complex tax laws.  Significant judgment is also required in assessing the timing and amounts of deductible and taxable items.  Despite management’s belief that our tax return positions are fully supportable, certain positions may be successfully challenged by federal, state and local jurisdictions.

The separation of ONE Gas could result in substantial tax liability.

We have received a private letter ruling from the IRS substantially to the effect that, for U.S. federal income tax purposes, the separation and certain related transactions qualify under Sections 355 and/or 368 of the U.S. Internal Revenue Code of 1986, as amended.  If the factual assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in any material respect, then we will not be able to rely on the ruling.  Furthermore, the IRS does not rule on whether a distribution such as the separation satisfies certain requirements necessary to obtain tax-free treatment under section 355 of the Code.  The private letter ruling was based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling.  In connection with the separation, we obtained an opinion of outside legal and tax counsel, substantially to the effect that, for U.S. federal income tax purposes, the separation and certain related transactions qualify under Sections 355 and 368 of the Code.  The opinion relies on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion.  The opinion will not be binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail.

Although we control ONEOK Partners, we may have conflicts of interest with ONEOK Partners that could subject us to claims that we have breached our fiduciary duty to ONEOK Partners and its unitholders.

We are the sole general partner and own 41.2 percent of ONEOK Partners.  Conflicts of interest may arise between us and ONEOK Partners and its unitholders.  In resolving these conflicts, we may favor our own interests and the interests of our affiliates over the interests of ONEOK Partners and its unitholders as long as the resolution does not conflict with the ONEOK Partners’ partnership agreement or our fiduciary duties to ONEOK Partners and its unitholders.

Our use of financial instruments to hedge interest-rate risk may result in reduced income.

We utilize financial instruments to mitigate our exposure to interest-rate fluctuations. Hedging instruments that are used to reduce our exposure to interest-rate fluctuations could expose us to risk of financial loss where we have contracted for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate.  In addition, these hedging arrangements may limit the benefit we would otherwise receive if we had contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate.

An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings.

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets.  GAAP requires us to test goodwill and intangible assets with indefinite useful lives for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired.  Long-lived

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assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.  For the investments ONEOK Partners accounts 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.  For example, if natural gas production continues to decline in areas of the Powder River Basin where coal-bed methane, or dry natural gas, is produced, ONEOK Partners could be unable to recover the carrying value of its assets and equity investments in these areas. If ONEOK Partners determines that an impairment is indicated, it would be required to take an immediate noncash charge to earnings with a correlative effect on our equity and balance sheet leverage as measured by consolidated debt to total capitalization.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions.  If any of our financial, operational or other data processing systems fail or have other significant shortcomings, our financial results could be affected adversely.  Our financial results could also be affected adversely if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our businesses. We use computer programs to help run our financial and operations organizations, and this may subject our business to increased risks.  Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse on our businesses.  In addition, cyber attacks on our customer and employee data may result in a financial loss and may impact negatively our reputation.

Third-party systems on which we rely could also suffer operational system failure.  Any of these occurrences could disrupt one or more of our businesses, result in potential liability or reputational damage or otherwise have an adverse affect on our financial results.

Cyber-attacks against us or others in our industry could result in additional regulations. Current efforts by the federal government, such as the Improving Critical Infrastructure Cybersecurity executive order, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

Changes in interest rates could affect adversely our business.

We use both fixed- and variable-rate debt, and we are exposed to market risk due to the floating interest rates on our short-term borrowings.  From time to time, we use interest-rate derivatives to hedge interest obligations on specific debt issuances, including anticipated debt issuances.  These hedges may be ineffective, and our results of operations, cash flows and financial position could be affected adversely by significant fluctuations or increases or decreases in interest rates from current levels.

A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could affect operations and cash flows available for distribution.

Our operations require skilled and experienced workers with proficiency in multiple tasks.  In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, thus hiring outside resources, which may decrease productivity and increase costs.  This shortage of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain areas, combined with the difficulty of attracting new workers to the midstream energy industry.  This shortage of skilled labor could continue over an extended period.  If the shortage of experienced labor continues or worsens, it could have an adverse impact on labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could affect adversely our operations and cash flows available for distribution to unitholders.

We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could affect adversely financial results.

The workplaces associated with our facilities are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers.  The failure to comply with OSHA requirements or general industry standards, including keeping adequate records or occupational exposure to regulated substances could expose us to civil or

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criminal liability, enforcement actions, and regulatory fines and penalties and could have a material adverse effect on our business, financial position, results of operations and cash flows.

ADDITIONAL RISK FACTORS RELATED TO ONEOK PARTNERS’ BUSINESS

The volatility of natural gas, crude oil and NGL prices could affect adversely ONEOK Partners’ cash flows.

A significant portion of ONEOK Partners’ revenues are derived from the sale of commodities that are received as payment for natural gas gathering and processing services, for the transportation and storage of natural gas, and for the sale of NGLs and NGL products in ONEOK Partners’ natural gas liquids business.  Commodity prices have been volatile and are likely to continue to be so in the future.  The prices ONEOK Partners receives for its commodities are subject to wide fluctuations in response to a variety of factors beyond ONEOK Partners’ control, including, but not limited to, the following:

• overall domestic and global economic conditions;

• relatively minor changes in the supply of, and demand for, domestic and foreign energy;

• market uncertainty;

• the availability and cost of third-party transportation, natural gas processing and natural gas liquids fractionation capacity;

• the level of consumer product demand and storage inventory levels;

• ethane rejection;

• geopolitical conditions impacting supply and demand for natural gas, NGLs and crude oil;

• weather conditions;

• domestic and foreign governmental regulations and taxes;

• the price and availability of alternative fuels;

• speculation in the commodity futures markets;

• overall domestic and global economic conditions;

• the price of natural gas, crude oil, NGL and liquefied natural gas imports and exports;

• the effect of worldwide energy-conservation measures; and

• the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials.

These external factors and the volatile nature of the energy markets make it difficult to estimate reliably future prices of commodities and the impact commodity price fluctuations have on ONEOK Partners’ customers and their need for its services. As commodity prices decline, ONEOK Partners is paid less for its commodities, thereby reducing its cash flow.  NGL volumes could decline if it becomes uneconomical for natural gas processors to recover the ethane component of the natural gas stream as a separate product. In addition, crude-oil and natural gas production could also decline due to lower prices.

Measurement adjustments on ONEOK Partners’ pipeline system can be affected materially by changes in estimation, type of commodity and other factors.

Natural gas and natural gas liquids measurement adjustments occur as part of the normal operating conditions associated with ONEOK Partners’ assets.  The quantification and resolution of measurement adjustments are complicated by several factors including: (1) the significant number (i.e., thousands) of meters that ONEOK Partners uses throughout its natural gas and natural gas liquids systems; (2) varying qualities of natural gas in the streams gathered and processed and the mixed nature of NGLs gathered and fractionated through ONEOK Partners’ systems; and (3) variances in measurement that are inherent in metering technologies.  Each of these factors may contribute to measurement adjustments that can occur on ONEOK Partners’ systems, which could affect negatively its earnings and cash flows.

Increased competition could have a significant adverse financial impact on ONEOK Partners.

The natural gas and natural gas liquids industries are expected to remain highly competitive.  The demand for natural gas and NGLs is primarily a function of commodity prices, including prices for alternative energy sources, customer usage rates, weather, economic conditions and service costs.  ONEOK Partners’ ability to compete also depends on a number of other factors, including competition from other companies for its existing customers, the efficiency, quality and reliability of the services it provides, and competition for throughput at ONEOK Partners’ gathering systems, pipelines, processing plants, fractionators and storage facilities.

ONEOK Partners cannot predict when it will be subject to changes in legislation or regulation, nor can it predict the impact of these changes on its financial position, results of operations or cash flows.  There are no assurances that ONEOK Partners’ business will be positioned to effectively compete in the future.

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ONEOK Partners does not hedge fully against commodity price changes, time differentials or locational differentials. This could result in decreased revenues and increased costs, thereby resulting in lower margins and adversely affecting its results of operations.

Certain of ONEOK Partners’ nonregulated and regulated businesses are exposed to market risk and the impact of market price fluctuations of natural gas, NGLs and crude oil.  Market risk refers to the risk of loss of cash flows and future earnings arising from adverse changes in commodity prices.  ONEOK Partners’ primary exposures arise from:

• the value of the NGLs and natural gas it receives in exchange for the natural gas gathering and processing services it provides;

• the differentials between NGL and natural gas prices associated with its keep-whole contracts and the differentials between the individual NGL products with respect to ONEOK Partners’ natural gas liquids transportation and fractionation agreements;

• the price differentials between the individual NGL products;

• the NGL price differentials at different locations;

• the seasonal price differentials of natural gas and NGLs related to storage operations;

• the fuel costs and the value of the retained fuel in-kind in ONEOK Partners’ natural gas pipelines and storage operations; and

• the differential between ethane and natural gas prices.

ONEOK Partners also is exposed to the risk of changing prices or the cost of transportation resulting from purchasing natural gas or NGLs at one location and selling it at another (referred to as basis risk).  To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, ONEOK Partners uses physical forward transactions and commodity financial derivative instruments such as futures contracts, swaps and options to manage market risk of existing or anticipated purchases and sales of natural gas, NGLs and crude oil.  ONEOK Partners adheres to policies and procedures that monitor its exposure to market risk from open positions.  However, it do not hedge fully against commodity price changes, and therefore, it retains some exposure to market risk.  Accordingly, any adverse changes to commodity prices could result in decreased revenue and/or increased costs.

ONEOK Partners’ use of financial instruments and physical forward transactions to hedge market risk may result in reduced income.

ONEOK Partners utilizes financial instruments and physical forward transactions to mitigate its exposure to interest rate and commodity price fluctuations.  Hedging instruments that are used to reduce ONEOK Partners’ exposure to interest-rate fluctuations could expose it to risk of financial loss where it has contracted for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate.  In addition, these hedging arrangements may limit the benefit ONEOK Partners would otherwise receive if it had contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate.  Hedging arrangements that are used to reduce ONEOK Partners’ exposure to commodity price fluctuations limit the benefit it would otherwise receive if market prices for natural gas, crude oil and NGLs exceed the stated price in the hedge instrument for these commodities.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on ONEOK Partners’ ability to hedge risks associated with its business and increase the working capital requirements to conduct these activities.

In July 2010, the Dodd-Frank Act was enacted, which provides new statutory and regulatory requirements for certain swap transactions.  Certain financial transactions will be required to be cleared on exchanges, and cash collateral will be required for these transactions.  However, the Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users and includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and to the parties to those transactions. Additionally, the Dodd-Frank Act calls for various regulatory agencies, including the SEC and the CFTC, to establish regulations for implementation of many of the provisions of the act.

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 ONEOK Partners has implemented measures to comply with the regulations that are applicable to its businesses. ONEOK Partners expects to continue to participate in financial markets for hedging certain risks inherent in its business, including commodity-price and

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interest-rate risks. ONEOK Partners continues to monitor proposed regulations and the impact the regulations may have on its business and risk-management strategies in the future.

ONEOK Partners’ inability to develop and execute growth projects and acquire new assets could result in reduced cash distributions to its unitholders and to ONEOK.

ONEOK Partners’ primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to unitholders and to increase these distributions over time.  ONEOK Partners’ ability to maintain and grow its distributions to unitholders, including ONEOK, depends on the growth of its existing businesses and strategic acquisitions.  Accordingly, if ONEOK Partners is unable to implement business development opportunities and finance such activities on economically acceptable terms, its future growth will be limited, which could impact adversely its and our results of operations and cash flows.

Growing ONEOK Partners’ business by constructing new pipelines and plants or making modifications to its existing facilities subjects ONEOK Partners to construction and supply risks should adequate natural gas or NGL supply be unavailable upon completion of the facilities.

One of the ways ONEOK Partners intends to grow its business is through the construction of new pipelines and new gathering, processing, storage and fractionation facilities and through modifications to ONEOK Partners’ existing pipelines and existing gathering, processing, storage and fractionation facilities.  The construction and modification of pipelines and gathering, processing, storage and fractionation facilities may require significant capital expenditures, which may exceed ONEOK Partners’ estimates, and involve numerous regulatory, environmental, political, legal and weather-related uncertainties. Construction projects in ONEOK Partners’ industry may increase demand for labor, materials and rights of way, which may, in turn, impact ONEOK Partners’ costs and schedule.  If ONEOK Partners undertakes these projects, it may not be able to complete them on schedule or at the budgeted cost.  Additionally, ONEOK Partners’ revenues may not increase immediately upon the expenditure of funds on a particular project.  For instance, if ONEOK Partners builds a new pipeline, the construction will occur over an extended period of time, and ONEOK Partners will not receive any material increases in revenues until after completion of the project.  ONEOK Partners may have only limited natural gas or NGL supply committed to these facilities prior to their construction.  Additionally, ONEOK Partners may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize.  ONEOK Partners may also rely on estimates of proved reserves in its decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves.  As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve ONEOK Partners’ expected investment return, which could affect materially and adversely ONEOK Partners’ results of operations, financial condition and cash flows.

If the level of drilling and production in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions declines substantially near its assets, ONEOK Partners’ volumes and revenue could decline.

ONEOK Partners’ ability to maintain or expand its businesses depends largely on the level of drilling and production by third parties in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions.  Drilling and production are impacted by factors beyond ONEOK Partners’ control, including:

• demand and prices for natural gas, NGLs and crude oil;

• producers’ finding and developing costs of reserves;

• producers’ desire and ability to obtain necessary permits in a timely and economic manner;

• natural gas field characteristics and production performance;

• surface access and infrastructure issues; and

• capacity constraints on natural gas, crude oil and natural gas liquids infrastructure from the producing areas and ONEOK Partners’ facilities.

If production from the Western Canada Sedimentary Basin remains flat or declines, and demand for natural gas from the Western Canada Sedimentary Basin is greater in market areas other than the Midwestern United States, demand for ONEOK Partners’ interstate gas transportation services could decrease significantly.

ONEOK Partners depends on natural gas supply from the Western Canada Sedimentary Basin for some of ONEOK Partners’ interstate pipelines, primarily Viking Gas Transmission and ONEOK Partners’ investment in Northern Border Pipeline, that transport Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern United States market area.  If demand for natural gas increases in Canada or other markets not served by ONEOK Partners’ interstate pipelines and/or

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production remains flat or declines, demand for transportation service on ONEOK Partners’ interstate natural gas pipelines could decrease significantly, which could impact adversely ONEOK Partners’ results of operations and cash flows.

ONEOK Partners’ operations are subject to operational hazards and unforeseen interruptions that could affect materially and adversely ONEOK Partners’ business and for which neither we nor ONEOK Partners may be insured adequately.

ONEOK Partners’ operations are subject to all of the risks and hazards typically associated with the operation of natural gas and natural gas liquids gathering, transportation and distribution pipelines, storage facilities and processing and fractionation plants.  Operating risks include but are not limited to leaks, pipeline ruptures, the breakdown or failure of equipment or processes, and the performance of pipeline facilities below expected levels of capacity and efficiency.  Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, explosions, fires, the collision of equipment with ONEOK Partners’ pipeline facilities (for example, this may occur if a third party were to perform excavation or construction work near ONEOK Partners’ facilities) and catastrophic events such as tornados, hurricanes, earthquakes, floods or other similar events beyond ONEOK Partners’ control.  It is also possible that ONEOK Partners’ facilities could be direct targets or indirect casualties of an act of terrorism.  A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage.  Liabilities incurred and interruptions to the operations of ONEOK Partners’ pipelines or other facilities caused by such an event could reduce revenues generated by ONEOK Partners and increase expenses, thereby impairing our or ONEOK Partners’ ability to meet our respective obligations.  Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost, and neither we nor ONEOK Partners are fully insured against all risks inherent in our respective businesses.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage.  Consequently, neither we nor ONEOK Partners may be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all.  If either we or ONEOK Partners were to incur a significant liability for which either we or ONEOK Partners was not insured fully, it could have a material adverse effect on our or ONEOK Partners’ financial position and results of operations.  Further, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

ONEOK Partners does not own all of the land on which its pipelines and facilities are located, and it leases certain facilities and equipment, which could disrupt its operations.

ONEOK Partners does not own all of the land on which certain of its pipelines and facilities are located and are, therefore, subject to the risk of increased costs to maintain necessary land use.  ONEOK Partners obtains the rights to construct and operate certain of its pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time.  Loss of these rights, through its inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could have a material adverse effect on ONEOK Partners’ financial condition, results of operations and cash flows.

Pipeline-integrity programs and repairs may impose significant costs and liabilities.

Pursuant to a DOT rule, pipeline operators are required to develop pipeline integrity-management programs for intrastate and interstate natural gas and natural gas liquids pipelines that could affect high-consequence areas in the event of a release of product.  As defined by applicable regulations, high-consequence areas include areas near the route of a pipeline with high-population densities, facilities occupied by persons of limited mobility or indoor or outdoor areas where at least 20 people gather periodically.  The rule requires operators to identify pipeline segments that could impact a high-consequence area; improve data collection, integration and characterization of threats applicable to each segment; implement preventive and mitigating actions; perform ongoing assessments of pipeline integrity; and repair and remediate as necessary.  These testing programs could cause us and ONEOK Partners to incur significant capital and operating expenditures to make repairs or remediate, as well as initiate preventive or mitigating actions that are determined to be necessary.

ONEOK Partners is subject to comprehensive energy regulation by governmental agencies, and the recovery of its costs are dependent on regulatory action.

Federal, state and local agencies have jurisdiction over many of ONEOK Partners’ activities, including regulation by the FERC of its storage and interstate pipeline assets.  The profitability of ONEOK Partners’ regulated operations is dependent on its ability to pass through costs related to providing energy and other commodities to its customers by filing periodic rate

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cases.  The regulatory environment applicable to ONEOK Partners’ regulated businesses could impair its ability to recover costs historically absorbed by its customers.

ONEOK Partners is unable to predict the impact that the future regulatory activities of these agencies will have on its operating results.  Changes in regulations or the imposition of additional regulations could have an adverse impact on ONEOK Partners’ business, financial condition and results of operations.

ONEOK Partners’ regulated pipelines’ transportation rates are subject to review and possible adjustment by federal and state regulators.

Under the Natural Gas Act, which is applicable to interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to crude oil and natural gas liquids pipelines, ONEOK Partners’ interstate transportation rates, which are regulated by the FERC, must be just and reasonable and not unduly discriminatory.

Shippers may protest ONEOK Partners’ pipeline tariff filings, and the FERC and/or state regulatory agencies may investigate tariff rates.  Further, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to be in excess of a just and reasonable level. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective.  The FERC and/or state regulatory agencies also may investigate tariff rates absent shipper complaint.  Any finding that approved rates exceed a just and reasonable level on the natural gas pipelines would take effect prospectively.  In a complaint proceeding challenging natural gas liquids pipeline rates, if the FERC determines existing rates exceed a just and reasonable level, it could require the payment of reparations to complaining shippers for up to two years prior to the complaint.  Any such action by the FERC or a comparable action by a state regulatory agency could affect adversely ONEOK Partners’ pipeline businesses’ ability to charge rates that would cover future increases in costs, or even to continue to collect rates that cover current costs and provide for a reasonable return.  We can provide no assurance that ONEOK Partners’ pipeline systems will be able to recover all of their costs through existing or future rates.

ONEOK Partners’ regulated pipeline companies have recorded certain assets that may not be recoverable from its customers.

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated ratemaking process to be recorded on ONEOK Partners’ balance sheet that could not be recorded under GAAP for nonregulated entities.  ONEOK Partners considers factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets.  If ONEOK Partners determines future recovery is no longer probable, ONEOK Partners would be required to write off the regulatory assets at that time.

Compliance with environmental regulations that ONEOK Partners is subject to may be difficult and costly.

ONEOK Partners is subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid and hazardous wastes, and hazardous material and substance management.  These laws and regulations require ONEOK Partners to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Failure to comply with these laws, regulations, permits and licenses may expose ONEOK Partners to fines, penalties and/or interruptions in its operations that could be material to its results of operations. If a leak or spill of hazardous substance occurs from ONEOK Partners’ pipelines or gathering lines or facilities in the process of transporting natural gas or NGLs or at any facility that ONEOK Partners owns, operates or otherwise uses, ONEOK Partners could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could affect materially its results of operations and cash flows.  In addition, emission controls required under the federal Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at ONEOK Partners’ facilities.  In addition, the EPA issued a rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, with a compliance date in 2013.  The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment.  ONEOK Partners does not expect these expenditures to have a material impact on its results of operations, financial position or cash flows.  ONEOK Partners cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to it.  Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on ONEOK Partners’ business, financial condition and results of operations.  For further discussion on this topic, see Note R of the Notes to Consolidated Financial Statements in this Annual Report.

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ONEOK Partners’ operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose it to significant costs and liabilities.

The risk of incurring substantial environmental costs and liabilities is inherent in ONEOK Partners’ business.  ONEOK Partners’ operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the protection of, the environment.  Examples of these laws include:

• the Clean Air Act and analogous state laws that impose obligations related to air emissions;

• the Clean Water Act and analogous state laws that regulate discharge of waste water from ONEOK Partners’ facilities to state and federal waters;

• the federal CERCLA and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by ONEOK Partners or locations to which ONEOK Partners has sent waste for disposal;

• the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from ONEOK Partners’ facilities; and

• an EPA-issued rule on air-quality standards, known as RICE NESHAP.

Various federal and state governmental authorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them.  Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both.  Joint and several, strict liability may be incurred without regard to fault under the CERCLA, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.

There is an inherent risk of incurring environmental costs and liabilities in ONEOK Partners’ business due to its handling of the products it gathers, transports, processes and stores, air emissions related to its operations, past industry operations and waste disposal practices, some of which may be material.  Private parties, including the owners of properties through which ONEOK Partners’ pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from ONEOK Partners’ operations.  Some sites ONEOK Partners operates are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ONEOK Partners’ sites.  In addition, increasingly strict laws, regulations and enforcement policies could increase significantly ONEOK Partners’ compliance costs and the cost of any remediation that may become necessary, some of which may be material.  Additional information is included under Item 1, Business under “Environmental and Safety Matters” and in Note R of the Notes to Consolidated Financial Statements in this Annual Report.

ONEOK Partners’ insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against ONEOK Partners.  ONEOK Partners’ business may be affected materially and adversely by increased costs due to stricter pollution-control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits.  New environmental regulations might also materially and adversely affect ONEOK Partners’ products and activities, and federal and state agencies could impose additional safety requirements, all of which could affect materially ONEOK Partners’ profitability.

ONEOK Partners may face significant costs to comply with the regulation of greenhouse gas emissions.

Greenhouse gas emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions.  Various federal and state legislative proposals have been introduced to regulate the emission of greenhouse gases, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA.  In addition, there have been international efforts seeking legally binding reductions in emissions of greenhouse gases.

ONEOK Partners believes it is possible that future governmental legislation and/or regulation may require it either to limit greenhouse gas emissions from its operations or to purchase allowances for such emissions that are actually attributable to its NGL customers.  However, it cannot predict precisely what form these future regulations will take, the stringency of the regulations, or when they will become effective.  Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions.  Previously considered proposals have included, among other things, limitations on the amount of greenhouse gases that can be emitted (so called “caps”) together with systems of emissions allowances.  This system could require ONEOK Partners to reduce emissions, even though the technology is not currently available for efficient reduction, or to purchase allowances for such emissions.  Emissions also could be taxed independently of limits.

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In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of greenhouse gas emissions sooner and/or independent of federal regulation.  These regulations could be more stringent than any federal regulation or legislation that is adopted.

Future legislation and/or regulation designed to reduce greenhouse gas emissions could make some of its activities uneconomic to maintain or operate.  Further, ONEOK Partners may not be able to pass on the higher costs to its customers or recover all costs related to complying with greenhouse gas regulatory requirements.  Its future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to its customers.

ONEOK Partners continues to monitor legislative and regulatory developments in this area.  Although the regulation of greenhouse gas emissions may have a material impact on its operations and rates, it is unable to quantify the potential costs of the impacts at this time.

ONEOK Partners may not be able to pass on the higher costs to its customers or recover all costs related to complying with greenhouse gas emission regulatory requirements, which could cause material adverse effects on its and our business, financial condition, results of operations and cash flows.

ONEOK Partners is subject to physical and financial risks associated with climate change.

There is a growing belief that emissions of greenhouse gases may be linked to global climate change.  Climate change creates physical and financial risk.  ONEOK Partners’ customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions may be affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes.  Increased energy use due to weather changes may require ONEOK Partners to invest in more pipelines and other infrastructure to serve increased demand.  A decrease in energy use due to weather changes may affect its financial condition through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions.  Weather conditions outside of ONEOK Partners’ operating territory could also have an impact on its revenues.  Severe weather impacts its operating territories primarily through hurricanes, thunderstorms, tornados and snow or ice storms.  To the extent the frequency of extreme weather events increases, this could increase its cost of providing service.  ONEOK Partners may not be able to pass on the higher costs to its customers or recover all the costs related to mitigating these physical risks.  To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could affect negatively its ability to access capital markets or cause ONEOK Partners to receive less favorable terms and conditions in future financings.  Its business could be affected by the potential for lawsuits against greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change.

ONEOK Partners’ business is subject to regulatory oversight and potential penalties.

The natural gas industry historically has been subject to heavy state and federal regulation that extends to many aspects of ONEOK Partners’ businesses and operations, including:

• rates, operating terms and conditions of service;

• the types of services ONEOK Partners may offer it customers;

• construction of new facilities;

• the integrity, safety and security of facilities and operations;

• acquisition, extension or abandonment of services or facilities;

• reporting and information posting requirements;

• maintenance of accounts and records; and

• relationships with affiliate companies involved in all aspects of the natural gas and energy businesses.

Compliance with these requirements can be costly and burdensome.  Future changes to laws, regulations and policies in these areas may impair ONEOK Partners’ ability to compete for business or to recover costs and may increase the cost and burden of operations. ONEOK Partners cannot guarantee that state or federal regulators will authorize any projects or acquisitions that it may propose in the future.  Moreover, ONEOK Partners cannot guarantee that, if granted, any such authorizations will be made in a timely manner or will be free from potentially burdensome conditions.

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Failure to comply with all applicable state or federal statutes, rules and regulations and orders, could bring substantial penalties and fines.  For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation.

Finally, ONEOK Partners cannot give any assurance regarding future state or federal regulations under which it will operate or the effect such regulations could have on its business, financial condition and results of operations.

Demand for natural gas and for certain of ONEOK Partners’ products and services is highly weather sensitive and seasonal.

The demand for natural gas in our ONEOK Partners segment and for certain of ONEOK Partners’ products, such as propane, is weather sensitive and seasonal, with a portion of revenues derived from sales for heating during the winter months.  Weather conditions influence directly the volume of, among other things, natural gas and propane delivered to customers.  Deviations in weather from normal levels and the seasonal nature of certain of ONEOK Partners’ businesses can create variations in earnings and short-term cash requirements.

Energy efficiency and technological advances may affect the demand for natural gas and affect adversely ONEOK Partners’ operating results.

The national trend toward increased energy conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, may decrease the demand for natural gas by residential customers.  More strict energy-conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could affect adversely ONEOK Partners’ results of operations and cash flows.

In the competition for customers, ONEOK Partners may have significant levels of uncontracted or discounted capacity on its natural gas and natural gas liquids pipelines, processing, fractionation and storage assets.

ONEOK Partners’ natural gas and natural gas liquids pipelines, processing, fractionation and storage assets compete with other pipelines, processing, fractionation and storage facilities for natural gas and NGL supplies delivered to the markets it serves.  As a result of competition, at any given time ONEOK Partners may have significant levels of uncontracted or discounted capacity on its pipelines, processing, fractionation and in its storage assets, which could have a material adverse impact on ONEOK Partners’ results of operations and cash flows.

ONEOK Partners is exposed to the credit risk of its customers or counterparties, and its credit risk management may not be adequate to protect against such risk.

ONEOK Partners is subject to the risk of loss resulting from nonpayment and/or nonperformance by ONEOK Partners’ customers or counterparties.  ONEOK Partners’ customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions or financial difficulties that could impact their creditworthiness or ability to pay ONEOK Partners for its services.  ONEOK Partners assesses the creditworthiness of its customers or counterparties and obtains collateral as it deems appropriate.  If ONEOK Partners fails to assess adequately the creditworthiness of existing or future customers or counterparties, unanticipated deterioration in their creditworthiness and any resulting nonpayment and/or nonperformance could adversely impact ONEOK Partners’ results of operations.  In addition, if any of ONEOK Partners’ customers or counterparties files for bankruptcy protection, this could have a material negative impact on ONEOK Partners’ results of operations and cash flows.

Any reduction in ONEOK Partners’ credit ratings could affect materially and adversely its business, financial condition, liquidity and results of operations.

ONEOK Partners’ senior unsecured long-term debt has been assigned an investment-grade rating by Moody’s of “Baa2” (Stable) and by S&P of “BBB” (Stable) as of February 3, 2014; however, we cannot provide assurance that any of its current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.  Specifically, if Moody’s or S&P were to downgrade ONEOK Partners’ long-term debt rating, particularly below investment grade, its borrowing costs would increase, which would affect adversely its financial results, and its potential pool of investors and funding sources could decrease.  Ratings from credit agencies are not recommendations to buy, sell or hold ONEOK Partners’ debt securities.  Each rating should be evaluated independently of any other rating.

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An event of default may require ONEOK Partners to offer to repurchase certain of its senior notes or may impair its ability to access capital.

The indentures governing ONEOK Partners’ senior notes include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of ONEOK Partners’ outstanding senior notes to declare those senior notes immediately due and payable in full.  ONEOK Partners may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause ONEOK Partners to borrow money under its credit facilities or seek alternative financing sources to finance the repurchases and repayment.  ONEOK Partners could also face difficulties accessing capital or its borrowing costs could increase, impacting its ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill its debt obligations.

ONEOK Partners’ indebtedness could impair its financial condition and ability to fulfill its obligations.

As of December 31, 2013, ONEOK Partners had total indebtedness of approximately $6.1 billion.  Its indebtedness could have significant consequences.  For example, it could:

• make it more difficult to satisfy its obligations with respect to its senior notes and other indebtedness, which could in turn result in an event of default on such other indebtedness or its senior notes;

• impair its ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;

• diminish its ability to withstand a downturn in its business or the economy;

• require it to dedicate a substantial portion of its cash flow from operations to debt-service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, distributions to partners and general partnership purposes;

• limit its flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and

• place it at a competitive disadvantage compared with its competitors that have proportionately less debt.

ONEOK Partners is not prohibited under the indentures governing its senior notes from incurring additional indebtedness, but its debt agreements do subject it to certain operational limitations summarized in the next paragraph. ONEOK Partners’ incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above and could affect adversely its ability to repay its senior notes and other indebtedness.

ONEOK Partners’ debt agreements contain provisions that restrict its ability to finance future operations or capital needs or to expand or pursue its business activities.  For example, certain of these agreements contain provisions that, among other things, limit its ability to make loans or investments, make material changes to the nature of its business, merge, consolidate or engage in asset sales, grant liens or make negative pledges.  Certain agreements also require it to maintain certain financial ratios, which limit the amount of additional indebtedness it can incur.  For example, the ONEOK Partners Credit Agreement contains a legal covenant requiring it to maintain 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 on September 30, 2013, and acquiring the remaining 30 percent interest in its Maysville facility in the fourth quarter 2013, the allowable ratio of indebtedness to adjusted EBITDA increased to 5.5 to1 for the current quarter and will remain at that level through the second quarter 2014.

These restrictions could result in higher costs of borrowing and impair its ability to generate additional cash.   Future financing agreements ONEOK Partners may enter into may contain similar or more restrictive covenants.

If ONEOK Partners is unable to meet its debt-service obligations, it could be forced to restructure or refinance its indebtedness, seek additional equity capital or sell assets.  It may be unable to obtain financing, raise equity or sell assets on satisfactory terms, or at all.

Borrowings under the ONEOK Partners Credit Agreement and its senior notes are nonrecourse to ONEOK, and ONEOK does not guarantee the debt, commercial paper or other similar commitments of ONEOK Partners.

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ONEOK Partners has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders.  The IRS may challenge this treatment, which could adversely affect the value of its limited partner units.

When ONEOK Partners issues additional units or engages in certain other transactions, ONEOK Partners determines the fair market value of its assets and allocates any unrealized gain or loss attributable to its assets to thecapital accounts of its unitholders and its general partner.  ONEOK Partners’ methodology may be viewed as understating the value of its assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders.  Moreover, under ONEOK Partners’ current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ONEOK Partners’ tangible assets and a lesser portion allocated to ONEOK Partners’ intangible assets.  The IRS may challenge ONEOK Partners’ valuation methods or ONEOK Partners’ allocation of the Section 743(b) adjustment attributable to ONEOK Partners’ tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of ONEOK Partners’ unitholders.

A successful IRS challenge to these methods or allocations could affect adversely the amount of taxable income or loss being allocated to ONEOK Partners’ unitholders.  It also could affect the amount of gain from ONEOK Partners unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to ONEOK Partners unitholders’ tax returns without the benefit of additional deductions.

ONEOK Partners’ treatment of a purchaser of common units as having the same tax benefits as the seller could be challenged, resulting in a reduction in value of the common units.

Because ONEOK Partners cannot match transferors and transferees of common units, ONEOK Partners is required to maintain the uniformity of the economic and tax characteristics of these units in the hands of the purchasers and sellers of these units. ONEOK Partners does so by adopting certain depreciation conventions that do not conform to all aspects of existing United States Treasury regulations.  A successful IRS challenge to these conventions could affect adversely the tax benefits to a unitholder of ownership of the common units and could have a negative impact on their value or result in audit adjustments to ONEOK Partners unitholders’ tax returns.

Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could impact adversely ONEOK Partners’ revenues by decreasing the volumes of unprocessed natural gas and NGLs transported on its or its joint ventures’ natural gas and natural gas liquids pipelines.

The natural gas industry is relying increasingly on natural gas supplies from unconventional sources, such as shale and tight sands.  Natural gas extracted from these sources frequently requires hydraulic fracturing, which involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate natural gas production. Recently, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing, and several states have adopted regulations that impose more stringent permitting, disclosure and well-completion requirements on hydraulic fracturing operations.  Legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of unprocessed natural gas and, in turn, adversely affect ONEOK Partners’ revenues and results of operations by decreasing the volumes of unprocessed natural gas and NGLs gathered, treated, processed, fractionated and transported on ONEOK Partners’ or its joint ventures’ natural gas and natural gas liquids pipelines, several of which gather unprocessed natural gas and NGLs from areas where the use of hydraulic fracturing is prevalent.

Continued development of new supply sources could impact demand.

The discovery of unconventional natural gas production areas closer to certain market areas that ONEOK Partners serves may compete with natural gas originating in production areas connected to ONEOK Partners’ systems.  For example, the Marcellus Shale in Pennsylvania, New York, West Virginia and Ohio may cause natural gas in supply areas connected to ONEOK Partners’ systems to be diverted to markets other than its traditional market areas and may affect capacity utilization adversely on ONEOK Partners’ pipeline systems and ONEOK Partners’ ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows.  In addition, supply volumes from these nonconventional natural gas production areas may compete with and displace volumes from the Mid-Continent, Rocky Mountains and Canadian supply sources in certain of ONEOK Partners’ markets.  The displacement of natural gas originating in supply areas connected to ONEOK Partners’ pipeline systems by these new supply sources that are closer to the end-use markets could result in lower

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transportation revenues, which could have a material adverse impact on ONEOK Partners’ business, financial condition, results of operations and cash flows.

A court may use fraudulent conveyance considerations to avoid or subordinate the Intermediate Partnership’s guarantee of certain of ONEOK Partners’ senior notes.

Various applicable fraudulent conveyance laws have been enacted for the protection of creditors.  A court may use fraudulent conveyance laws to subordinate or avoid the guarantee of certain of ONEOK Partners’ senior notes issued the Intermediate Partnership.  It is also possible that under certain circumstances, a court could hold that the direct obligations of the Intermediate Partnership could be superior to the obligations under that guarantee.

A court could avoid or subordinate the Intermediate Partnership’s guarantee of certain of ONEOK Partners’ senior notes in favor of the Intermediate Partnership’s other debts or liabilities to the extent that the court determined either of the following were true at the time the Intermediate Partnership issued the guarantee:

• the Intermediate Partnership incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the Intermediate Partnership contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or

• the Intermediate Partnership did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, the Intermediate Partnership:

–     was insolvent or rendered insolvent by reason of the issuance of the guarantee;

– was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or

–     intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if:

• the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation;

• the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

• it could not pay its debts as they become due.

Among other things, a legal challenge of the Intermediate Partnership’s guarantee of certain of ONEOK Partners’ senior notes on fraudulent conveyance grounds may focus on the benefits, if any, realized by the Intermediate Partnership as a result of ONEOK Partners’ issuance of such senior notes.  To the extent the Intermediate Partnership’s guarantee of certain of ONEOK Partners’ senior notes is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of such senior notes would cease to have any claim in respect of the guarantee.

ONEOK Partners may be unable to cause its joint ventures to take or not to take certain actions unless some or all of its joint-venture participants agree.

ONEOK Partners participates in several joint ventures.  Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture.  These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100 percent) to authorize more significant activities.  Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint-venture participant, litigation and transactions not in the ordinary course of business, among others.  Thus, without the concurrence of joint-venture participants with enough voting interests, ONEOK Partners may be unable to cause any of its joint ventures to take or not to take certain actions, even though those actions may be in the best interest of ONEOK Partners or the particular joint venture.

Moreover, any joint-venture owner generally may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint-venture owners.  Any such transaction could result in ONEOK Partners being required to partner with different or additional parties.

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ONEOK Partners’ operating cash flow is derived partially from cash distributions it receives from its unconsolidated affiliates.

ONEOK Partners’ operating cash flow is derived partially from cash distributions it receives from its unconsolidated affiliates, as discussed in Note P of the Notes to Consolidated Financial Statements.  The amount of cash that ONEOK Partners’ unconsolidated affiliates can distribute principally depends upon the amount of cash flow these affiliates generate from their respective operations, which may fluctuate from quarter to quarter.  ONEOK Partners does not have any direct control over the cash distribution policies of its unconsolidated affiliates.  This lack of control may contribute to ONEOK Partners’ not having sufficient available cash each quarter to continue paying distributions at its current levels.

Additionally, the amount of cash that ONEOK Partners has available for cash distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by noncash items such as depreciation, amortization and provisions for asset impairments. As a result, ONEOK Partners may be able to make cash distributions during periods when it records losses and may not be able to make cash distributions during periods when it records net income.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.    PROPERTIES

DESCRIPTION OF PROPERTIES

ONEOK Partners

Property - Our ONEOK Partners segment owns the following assets at December 31, 2013:

• eight natural gas processing plants with approximately 585 MMcf/d of natural gas processing capacity in the Mid-Continent region, and eight natural gas processing plants, with approximately 465 MMcf/d of processing capacity, in the Rocky Mountain region;

• approximately 30 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Mid-Continent and Rocky Mountain regions;

• approximately 11,300 miles and 7,000 miles of natural gas gathering pipelines in the Mid-Continent and Rocky Mountain regions, respectively;

• approximately 2,700 miles of non-FERC-regulated natural gas liquids gathering pipelines with peak gathering capacity of approximately 772 MBbl/d;

• approximately 170 miles of non-FERC regulated natural gas liquids distribution pipelines with approximately 66 MBbl/d of peak transportation capacity;

• approximately 1,510 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 270 MBbl/d;

• approximately 3,500 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with approximately 708 MBbl/d of peak transportation capacity;

• one natural gas liquids fractionator, located in Oklahoma, with operating capacity of approximately 210 MBbl/d; two natural gas liquids fractionators, located in Kansas, with combined operating capacity of 260 MBbl/d; and one natural gas liquids fractionator, located in Texas, with operating capacity of 75 MBbl/d;

• 80percent ownership interest in one natural gas liquids fractionator in Texas with ONEOK Partners’ proportional share of operating capacity of approximately 128 MBbl/d;

• interest in one natural gas liquids fractionator in Kansas with ONEOK Partners’ proportional share of operating capacity of approximately 11 MBbl/d;

• one isomerization unit in Kansas with operating capacity of 9 MBbl/d;

• six natural gas liquids storage facilities in Oklahoma, Kansas and Texas with operating storage capacity of approximately 23.2 MMBbl;

• eight natural gas liquids product terminals in Missouri, Nebraska, Iowa and Illinois;

• above- and below-ground storage facilities associated with its FERC-regulated natural gas liquids pipeline operations in Iowa, Illinois, Nebraska and Kansas with combined operating capacity of approximately 978 MBbl;

• access to 60 MBbl/d natural gas liquids fractionation capacity in Texas through a fractionation services agreement; and

• access to approximately 2.5 MMBbl of leased NGL storage capacity at facilities in Kansas and Texas;

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• approximately 1,500 miles of FERC-regulated interstate natural gas pipelines with approximately 3.2 Bcf/d of peak transportation capacity;

• approximately 5,100 miles of state-regulated intrastate transmission pipelines with approximately 3.0 Bcf/d of peak transportation capacity; and

• approximately 53.7 Bcf of total working natural gas storage capacity.

ONEOK Partners’ storage includes five underground natural gas storage facilities in Oklahoma, two underground natural gas storage facilities in Kansas and two underground natural gas storage facilities in Texas.

As discussed further in “Growth Projects” in ONEOK Partners segment’s discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, ONEOK Partners expects to complete the following assets in March 2014:

• one natural gas processing plant, the Canadian Valley Plant in Oklahoma, with approximately 200 MMcf/d of processing capacity, in the Mid-Continent region;

• approximately 540 miles of FERC-regulated natural gas liquids distribution pipeline, the Sterling III pipeline, from Medford, Oklahoma, to Mont Belvieu, Texas, with peak capacity of 193 MBbl/d; and

• one ethane/propane splitter with the capacity to produce 32 MBbl/d of purity ethane and 8 MBbl/d of propane located in Texas.

ONEOK Partners also is constructing, or plans to construct, the following assets:

• three natural gas processing plants with approximately 400 MMcf/d of combined processing capacity in the Rocky Mountain region;

• approximately 95 miles of FERC-regulated distribution pipelines from Hutchinson, Kansas, to Medford, Oklahoma;

• one natural gas liquids fractionator, MB-3 located in Texas, with operating capacity of approximately 75 MBbl/d; and

• upgrade and construct natural gas gathering and processing infrastructure related to the Sage Creek expansion project.

Utilization - The utilization rates for ONEOK Partners’ various assets for 2013 and 2012, respectively were as follows:

• natural gas processing plants were approximately 71 percent and 69 percent utilized;

• natural gas pipelines were approximately 90 percent and 89 percent subscribed;

• FERC-regulated natural gas liquids gathering pipelines were approximately 71 percent and 99 percent utilized;

• FERC-regulated natural gas liquids distribution pipelines were approximately 58 percent and 65 percent utilized;

• non-FERC-regulated natural gas liquids pipelines were approximately 69 percent and 68 percent subscribed;

• natural gas liquids fractionators were approximately 78 percent and 89 percent utilized;

• average contracted natural gas liquids storage volumes were approximately 72 percent and 60 percent of storage capacity; and

• natural gas storage facilities were 92 percent and fully subscribed.

ONEOK Partners calculates utilization on its assets using a weighted-average approach, adjusting for the dates that assets were placed in service.  The utilization rate of ONEOK Partners’ NGL fractionation facilities reflects leased capacity and the approximate proportional capacity associated with ONEOK Partners’ ownership interests.

Natural Gas Distribution

Property - At December 31, 2013, we owned approximately 19,000 miles of pipeline and other natural gas distribution facilities in Oklahoma; approximately 13,000 miles of pipeline and other natural gas distribution facilities in Kansas; and approximately 10,000 miles of pipeline and other natural gas distribution facilities in Texas.  In addition, we had 57.3 Bcf of natural gas storage capacity under lease with maximum withdrawal capacity of approximately 1.5 Bcf/d. Following the separation of our natural gas distribution business in January 2014, all of these properties are owned or leased by ONE Gas.

Energy Services

Property - Our total natural gas storage capacity under lease is 23.5 Bcf.  Of the 23.5 Bcf, 20.5 Bcf will expire by March 31, 2014. In the first quarter, we assigned the remaining 3.0 Bcf to a third party, effective April 1, 2014. At December 31, 2013, our natural gas transportation capacity was 0.07 Bcf/d, which will expire on March 31, 2014.  

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Other

Property - We own the 17-story ONEOK Plaza office building, with approximately 505,000 square feet of net rentable space, and an associated parking garage.

ITEM 3.    LEGAL PROCEEDINGS

Gas Index Pricing Litigation:We, OESC and one other affiliate are defending, either individually or together, against the following lawsuits that claim damages resulting from the alleged market manipulation or false reporting of prices to gas index publications by us and others: Sinclair Oil Corporation v. ONEOK Energy Services Corporation, L.P., et al. (filed in the United States District Court for the District of Wyoming in September 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Reorganized FLI, Inc. (formerly J.P. Morgan Trust Company) v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte County, Kansas, in October 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Learjet, Inc., et al. v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte, Kansas, in November 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Arandell Corporation, et al. v. Xcel Energy, Inc., et al. (filed in the Circuit Court for Dane County, Wisconsin, in December 2006, transferred to MDL-1566 in the United States District Court for the District of Nevada); Heartland Regional Medical Center, et al. v. ONEOK, Inc., et al. (filed in the Circuit Court of Buchanan County, Missouri, in March 2007, transferred to MDL-1566 in the United States District Court for the District of Nevada); NewPage Wisconsin System v. CMS Energy Resource Management Company, et al. (filed in the Circuit Court for Wood County, Wisconsin, in March 2009, transferred to MDL-1566 in the United States District Court for the District of Nevada and now consolidated with the Arandell case).  In each of these lawsuits, the plaintiffs allege that we, OESC and one other affiliate and approximately ten other energy companies and their affiliates engaged in an illegal scheme to inflate natural gas prices by providing false information to gas price index publications.  All of the complaints arise out of a CFTC investigation into and reports concerning false gas price index-reporting or manipulation in the energy marketing industry during the years from 2000 to 2002.

On July 18, 2011, the trial court granted judgments in favor of ONEOK, Inc., OESC and other unaffiliated entities in the following cases: Reorganized FLI, Learjet, Arandell, Heartland, and NewPage. The court also granted judgment in favor of OESC on all state law claims asserted in the Sinclair case. On August 18, 2011, the trial court entered an order approving a stipulation by the plaintiffs and our affiliate, Kansas Gas Marketing Company (“KGMC”), for a dismissal without prejudice of the plaintiffs’ claims against KGMC in the Learjet and Heartland cases.

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 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.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET INFORMATION AND HOLDERS

Our common stock is listed on the NYSE under the trading symbol “OKE.”  The corporate name ONEOK is used in newspaper stock listings.  The following table sets forth the high and low closing prices of our common stock for the periods indicated:

	Year Ended December 31, 2013				Year Ended December 31, 2012
	High		Low		High		Low
First Quarter	$	48.17	$	44.00	$	44.40	$	40.22
Second Quarter	$	52.13	$	41.16	$	43.98	$	39.49
Third Quarter	$	54.14	$	40.00	$	48.31	$	42.26
Fourth Quarter	$	62.18	$	52.54	$	49.39	$	42.07

At February 19, 2014, there were 15,321 holders of record of our 207,814,086 outstanding shares of common stock.

DIVIDENDS

The following table sets forth the quarterly dividends declared and paid per share of our common stock during the periods indicated:

	Years Ended December 31,
	2013		2012		2011
First Quarter	$	0.36	$	0.305	$	0.26
Second Quarter	$	0.36	$	0.305	$	0.26
Third Quarter	$	0.38	$	0.33	$	0.28
Fourth Quarter	$	0.38	$	0.33	$	0.28
Total	$	1.48	$	1.27	$	1.08

In January 2014, we declared a dividend of $0.40 per share ($1.60 per share on an annualized basis) which was paid on February 18, 2014, to shareholders of record as of February 10, 2014.

ISSUER PURCHASES OF EQUITY SECURITIES

We repurchased no shares of our common stock for the year ended December 31, 2013. The repurchase program, authorized by our Board of Directors in October 2010, terminated on December 31, 2013.

EMPLOYEE STOCK AWARD PROGRAM

Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $13 per share. Shares issued to employees under this program during 2013 totaled 63,975, and compensation expense related to the Employee Stock Award Plan was $3.6 million.  Shares issued to employees under this program during 2012 totaled 42,467, and compensation expense related to the Employee Stock Award Plan was $1.9 million. For 2011, the number of shares issued under this program totaled 295,694, and compensation expense related to the Employee Stock Award Plan was $16.0 million.

The total number of shares of our common stock available for issuance under this program is 900,000.  The shares issued under this program have not been registered under the Securities Act, in reliance upon the position taken by the SEC (see Release No. 6188, dated February 1, 1980) that the issuance of shares to employees pursuant to a program of this kind does not require registration under the Securities Act.  See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional information.

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PERFORMANCE GRAPH

The following performance graph compares the performance of our common stock with the S&P 500 Index, the S&P Utilities Index and a ONEOK Peer Group during the period beginning on December 31, 2008, and ending on December 31, 2013.  The graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.

Value of $100 Investment Assuming Reinvestment of Dividends

at December 31, 2008, and at the End of Every Year Through December 31, 2013,

Among ONEOK, Inc., the S&P 500 Index, the S&P 500 Utilities Index and a ONEOK Peer Group

	Cumulative Total Return
	Years Ended December 31,
	2009		2010		2011		2012		2013
ONEOK, Inc.	$	161.37	$	208.77	$	336.39	$	341.57	$	511.27
S&P 500 Index	$	126.45	$	145.52	$	148.55	$	172.29	$	228.04
S&P 500 Utilities Index (a)	$	111.93	$	118.08	$	141.52	$	143.35	$	162.35
ONEOK Peer Group (b)	$	131.60	$	172.60	$	209.60	$	215.80	$	270.00

(a) - The Standard & Poors 500 Utilities Index is comprised of the following companies: AES Corp.; AGL Resource, Inc.; Ameren Corp.; American Electric Power Co., Inc.; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.; Dominion Resources, Inc.; DTE Energy Co.; Duke Energy Corp.; Edison International; Entergy Corp.; Exelon Corp.; FirstEnergy Corp.; Integrys Energy Group, Inc.; NextEra Energy, Inc.; NiSource, Inc.; Northeast Utilities; NRG Energy, Inc.; Pepco Holdings, Inc.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Public Service Enterprise Group, Inc.; SCANA Corp.; Sempra Energy; Southern Co.; TECO Energy, Inc.; Wisconsin Energy Corp.; and Xcel Energy, Inc.

(b) - The ONEOK Peer Group is comprised of the following companies: AGL Resources, Inc.; Atmos Energy Corp.; Centerpoint Energy, Inc.; DCP Midstream Partners, L.P.; Enbridge, Inc.; Enterprise Products Partners, L.P.; Energy Transfer Partners, L.P.; Kinder Morgan Energy Partners, L.P.; National Fuel Gas Co.; New Jersey Resources Corp.; NiSource, Inc.; OGE Energy Corp.; Piedmont Natural Gas Company, Inc.; Sempra Energy; Spectra Energy Corp.; Southwest Gas Corp.; TransCanada Corp.; UGI Corp.; Vectren Corp.; WGL Holdings, Inc.; and Wisconsin Energy Corp.

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ITEM 6.    SELECTED FINANCIAL DATA

The following table sets forth our selected financial data for each of the periods indicated:

	Years Ended December 31,
	2013		2012		2011		2010		2009
	(Millions of dollars except per share amounts)
Revenues	$	14,602.7	$	12,632.6	$	14,805.8	$	12,678.8	$	10,805.8
Income from continuing operations	$	577.0	$	729.3	$	757.5	$	540.1	$	483.7
Income from continuing operations attributable to ONEOK	$	266.5	$	346.3	$	358.4	$	333.4	$	297.9
Net income attributable to ONEOK	$	266.5	$	360.6	$	360.6	$	334.6	$	305.5
Total assets	$	17,707.6	$	15,855.3	$	13,696.6	$	12,499.2	$	12,827.7
Long-term debt, including current maturities	$	7,765.6	$	6,526.2	$	4,893.9	$	4,329.8	$	4,602.2
Earnings per share - continuing operations
Basic	$	1.29	$	1.68	$	1.71	$	1.57	$	1.41
Diluted	$	1.27	$	1.64	$	1.67	$	1.55	$	1.40
Earnings per share - total
Basic	$	1.29	$	1.75	$	1.72	$	1.57	$	1.45
Diluted	$	1.27	$	1.71	$	1.68	$	1.55	$	1.44
Dividends declared per common share	$	1.48	$	1.27	$	1.08	$	0.91	$	0.82

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 this Annual Report.

RECENT DEVELOPMENTS

The following discussion highlights some of our planned activities, recent achievements and significant issues affecting us. 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 Operation and our consolidated financial statements and Notes to Consolidated Financial Statements for additional information.

Separation of Natural Gas Distribution Segment - In January 2014, ourboard of directors unanimously approved the separation of our natural gas distribution business into a standalone publicly traded company, which was completed on January 31, 2014. ONE Gas consists of ONEOK’s former Natural Gas Distribution segment 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.

Wind Down of Energy Services Segment - As a result of challenging natural gas market conditions, in June 2013 we announced an accelerated wind down of our Energy Services segment that is expected to be substantially completed on March 31, 2014. Our Energy Services segment no longer fits strategically and has become increasingly smaller on a relative basis because of the market conditions that it has faced and the growth of our other businesses. We expect the Energy Services segment to be classified as discontinued operations after the completion of the accelerated wind down. See additional discussion in the “Financial Results and Operating Information” section of our Energy Services segment.

ONEOK and its subsidiaries will continue to own all of the general partner interest and 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, and will operate our Energy Services segment through the completion of the wind down process, which will be substantially completed on March 31, 2014.

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

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operations.  ONEOK Partners expects continued development of the crude oil and NGL-rich natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin, the Niobrara Shale formation in the Powder River Basin and in the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region.  In response to this increased production of crude oil, natural gas and NGLs, and higher demand for NGL products 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 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 .

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 Q of the Notes to Consolidated Financial Statements.

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

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 the issuances, 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 pay 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

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

See Note Q 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	$	14,602.7		$	12,632.6		$	14,805.8		$	1,970.1		16	%	$	(2,173.2	)	(15	)%
Cost of sales and fuel	12,313.0			10,281.7			12,425.4			2,031.3			20	%	(2,143.7		)	(17	)%
Net margin	2,289.7			2,350.9			2,380.4			(61.2		)	(3	)%	(29.5		)	(1	)%
Operating costs	990.5			909.0			908.3			81.5			9	%	0.7			—	%
Depreciation and amortization	384.4			335.8			312.2			48.6			14	%	23.6			8	%
Goodwill impairment	—			10.3			—			(10.3		)	(100	)%	10.3			100	%
Gain (loss) on sale of assets	11.9			6.7			(1.0		)	5.2			78	%	7.7			*
Operating income	$	926.7		$	1,102.5		$	1,158.9		$	(175.8	)	(16	)%	$	(56.4	)	(5	)%
Equity earnings from investments	$	110.5		$	123.0		$	127.2		$	(12.5	)	(10	)%	$	(4.2	)	(3	)%
Interest expense	$	(334.2	)	$	(302.3	)	$	(297.0	)	$	31.9		11	%	$	5.3		2	%
Net income	$	577.0		$	743.5		$	759.7		$	(166.5	)	(22	)%	$	(16.2	)	(2	)%
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	$	2,256.6		$	1,866.2		$	1,336.1		$	390.4		21	%	$	530.1		40	%

* Percentage change is greater than 100 percent.

2013 vs. 2012 - Revenues for 2013, compared with 2012, increased primarily due to higher natural gas and NGL volumes gathered, processed and sold from ONEOK Partners’ completed capital projects, offset partially by lower net realized natural gas and NGL product prices, and ethane rejection in ONEOK Partners’ business. 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. Our former Natural Gas Distribution segment benefited from new rates and higher sales volumes, primarily due to colder than normal weather in all three states where it operates.

Net margin for 2013, compared with 2012, decreased due primarily to noncash charges related to the accelerated wind down of the Energy Services segment from the release of a significant portion of its natural gas transportation and storage contracts to third parties.

Operating income for 2013 reflects higher results from our former Natural Gas Distribution segment, offset by lower results from our ONEOK Partners and Energy Services segments. 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

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projects in its natural gas gathering and processing and natural gas liquids businesses and higher employee-related costs in the Natural Gas Distribution segment. Operating costs for 2013 also reflect approximately $9.4 million in costs incurred related to the separation of the natural gas distribution business.

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 ONEOK Partners’ investments in growth projects in its natural gas gathering and processing and natural gas liquids businesses.

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.

Capital expenditures increased for 2013, compared with 2012, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

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.

Operating income for 2012 reflected higher results from our ONEOK Partners and Natural Gas Distribution segments, offset by lower results from our Energy Services segment. Our ONEOK Partners segment’s results benefited from higher volumes from completed capital projects in its natural gas gathering and processing and natural gas liquids businesses. These increases were offset partially by less favorable NGL product price differentials and lower NGL transportation capacity available for optimization activities in ONEOK Partners natural gas liquids business. 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 its natural gas gathering and processing business. Our Natural Gas Distribution segment benefited from new rates in all three states where it operates and lower operating costs.

These increases were offset by lower margins in our Energy Services segment 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.

Operating costs for 2012 were relatively unchanged due primarily to the increased costs associated with our ONEOK Partners segment’s expanding operations as a result of several internal growth projects that were placed in service and scheduled maintenance costs being offset by lower employee-related costs in our Natural Gas Distribution and Energy Services segments.

Interest expense increased in 2012, compared with 2011, primarily as a result of higher interest costs from ONEOK’s $700 million debt issuance in January 2012 and ONEOK Partners’ $1.3 billion debt issuance in September 2012, offset partially by higher capitalized interest associated with ONEOK Partners’ growth projects in its natural gas gathering and processing and natural gas liquids businesses.

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.

Capital expenditures increased in 2012, compared with 2011, due to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

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

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ONEOK Partners

Growth Projects - Natural gas gathering and processing projects - ONEOK Partners’ natural gas gathering and processing business 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 including the Williston Basin, Cana-Woodford Shale and the Niobrara shale in the Powder River Basin that ONEOK Partners expects will enable it 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 acreage dedications of approximately 3.1 million acres supporting these plants.  In addition, ONEOK Partners is expanding and upgrading its existing natural gas gathering and compression infrastructure and also adding new well connections associated with these plants.  The Garden Creek plant was placed in service in December 2011 and, together with the related infrastructure, cost approximately $360 million, excluding AFUDC.  ONEOK Partners expects construction costs, excluding AFUDC, for the Garden Creek II plant and related infrastructure will be $310 million to $345 million, and for the Garden Creek III plant and related infrastructure will be approximately $325 million to $360 million. The Garden Creek II and Garden Creek III plants are expected to be completed during the third quarter 2014 and the first quarter 2015, respectively. The Stateline I natural gas processing facility was placed in service in September 2012, and the Stateline II natural gas processing facility was placed in service in April 2013. Together, with the related infrastructure, the Stateline I and Stateline II plants cost approximately $565 million, excluding AFUDC. ONEOK Partners expects construction costs, excluding AFUDC, for the Lonesome Creek natural gas gathering plant and related infrastructure will 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 $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 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 ONEOK Partners’ 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.  ONEOK Partners expects the routine growth capital needed to connect to new wells and expand its infrastructure to increase compared with its historical levels of routine growth capital.

Natural gas liquids projects - The growth strategy in ONEOK Partners’ natural gas liquids business is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other 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 ONEOK Partners to make additional capital investments to expand its infrastructure to bring these commodities from supply basins to market.  Expansion of the

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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.

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

Sterling III Pipeline - ONEOK Partners is constructing a 540-plus-mile natural gas liquids pipeline, the Sterling III Pipeline, which will have the flexibility to transport either unfractionated NGLs or NGL products from the Mid-Continent to the Gulf Coast.  The Sterling III Pipeline will traverse the NGL-rich Woodford Shale that is currently under development, as well as provide transportation capacity for the growing NGL production from the Cana-Woodford Shale and Granite Wash areas, where the pipeline can gather unfractionated NGLs from 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 its existing Sterling I and Sterling II pipelines, which currently distribute NGL products between the Mid-Continent and Gulf Coast natural gas liquids market centers, to transport either unfractionated NGLs or NGL products. The project costs for the new pipeline and reconfiguration projects are estimated to be $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 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 its 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 ONEOK Partners expects will grow over the long term. The facility will be capable of producing 32 MBbl/d of purity ethane and 8 MBbl/d of propane, and is expected to be completed 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

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fractionation and distribution infrastructure in the Mid-Continent.  NGL supply commitments for the Bakken NGL Pipeline are anchored by NGL production from ONEOK Partners’ natural gas processing plants. 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 design 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 area of the Powder River Basin which includes a natural gas liquids pipeline.  The acquired natural gas liquids pipeline will be integrated into ONEOK Partners’ natural gas liquids system and used as a platform for future growth opportunities. ONEOK Partners plans to invest approximately $85 million, excluding AFUDC, to build new NGL pipeline infrastructure and connect the Sage Creek natural gas processing plant to its Bakken NGL Pipeline. These projects are expected to be completed 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 ONEOK Partners’ capacity to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers.  The pipelines are connected to three new third-party natural gas processing facilities and to three existing third-party natural gas processing facilities that were expanded.  Additionally, ONEOK Partners installed additional pump stations on the Arbuckle Pipeline to increase its capacity to 240 MBbl/d.  These projects added, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs, to ONEOK Partners’ existing natural gas liquids gathering systems.  These projects were placed in service in April 2012 and cost approximately $220 million, excluding AFUDC.

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

Selected Financial Results and Operating Information - ONEOK Partners’ 2013 and 2012 operating results reflect the benefits from the following completed growth projects:

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

• the Stateline II natural gas processing plant, which was placed in service in April 2013;

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

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

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

• the Stateline I natural gas processing plant, which was placed in service in September 2012;

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

• the expansion of its 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 volumes gathered and sold, and 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 the ethane rejection. ONEOK Partners expects 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 table sets forth certain selected financial results for our ONEOK Partners 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)
Revenues	$	11,869.3		$	10,182.2		$	11,322.6		$	1,687.1		17	%	$	(1,140.4	)	(10	)%
Cost of sales and fuel	10,222.2			8,540.4			9,745.2			1,681.8			20	%	(1,204.8		)	(12	)%
Net margin	$	1,647.1		$	1,641.8		$	1,577.4		5.3			—	%	64.4			4	%
Operating costs	521.6			482.5			459.4			39.1			8	%	23.1			5	%
Depreciation and amortization	236.7			203.1			177.5			33.6			17	%	25.6			14	%
Gain (loss) on sale of assets	11.9			6.7			(1.0		)	5.2			78	%	7.7			*
Operating income	$	900.7		$	962.9		$	939.5		$	(62.2	)	(6	)%	$	23.4		2	%
Equity earnings from investments	$	110.5		$	123.0		$	127.2		$	(12.5	)	(10	)%	$	(4.2	)	(3	)%
Interest expense	$	(236.7	)	$	(206.0	)	$	(223.1	)	$	30.7		15	%	$	(17.1	)	(8	)%
Capital expenditures	$	1,939.3		$	1,560.5		$	1,063.4		$	378.8		24	%	$	497.1		47	%
Cash paid for acquisitions	$	394.9		$	—		$	—		$	394.9		*		$	—		—	%

* Percentage change is greater than 100 percent.

2013 vs. 2012 - Revenues and net margin for 2013, compared with 2012, increased due to higher natural gas and NGL volumes gathered, processed and sold from ONEOK Partners’ completed capital projects, 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 generally lower NGL prices and narrower NGL 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 price differential for propane between the Conway, Kansas, and Mont Belvieu, Texas, market centers also widened in favor of Conway, Kansas, due to colder than normal weather and lower propane inventory levels. ONEOK Partners expects these prices to continue through the end of the 2014 winter heating season, which we expect will have a favorable impact on ONEOK Partners’ 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.

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 many 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. ONEOK Partners continues to expect that natural gas liquids volumes will be affected negatively as a result of ethane rejection. ONEOK Partners expects 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. ONEOK Partners expects ethane rejection will have a significant impact on its financial results during this period. However, ONEOK Partners’ natural gas liquids business’s integrated assets enable it to mitigate partially the impact of ethane rejection through minimum volume commitments and the

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utilization of 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 its natural gas liquids business.

Net margin increased primarily as a result of the following:

• an increase of $166.5 million in exchange-services margins, which resulted from higher NGL volumes gathered, contract renegotiations for higher fees in ONEOK Partners’ NGL exchange-services activities and higher revenues from customers with minimum volume obligations in ONEOK Partners’ natural gas liquids business;

• an increase of $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 in ONEOK Partners’ natural gas gathering and processing business;

• 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 in ONEOK Partners’ natural gas liquids business;

• an increase of $10.5 million in storage margins due primarily to contract renegotiations in ONEOK Partners’ natural gas liquids business;

• an increase of $9.6 million in transportation margins due primarily to higher rates on Guardian Pipeline and higher contracted capacity with natural gas producers on our intrastate pipelines in ONEOK Partners’ natural gas pipelines business;

• an increase of $6.4 million due to a contract settlement in 2013 in ONEOK Partners’ natural gas gathering and processing business; offset partially by

• 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 in ONEOK Partners’ natural gas liquids business. 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 in ONEOK Partners’ natural gas liquids business;

• a decrease of $41.7 million due primarily to lower net realized NGL prices in ONEOK Partners’ natural gas gathering and processing business;

• a decrease of $22.4 million related to lower isomerization volumes, resulting from the narrower price differential between normal butane and iso-butane in ONEOK Partners’ natural gas liquids business;

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

• a decrease of $3.9 million from lower net retained fuel in ONEOK Partners’ natural gas pipelines business; and

• a decrease of $3.5 million due to lower dry natural gas volumes gathered as a result of continued declines in coal-bed methane production in the Powder River Basin in ONEOK Partners’ natural gas gathering and processing business.

Operating costs increased for 2013, compared with 2012, as a result of the growth of ONEOK Partners operations and reflect the following:

• an increase of $17.7 million in employee-related costs due to higher labor and employee benefit costs, offset partially by lower incentive compensation costs;

• an increase of $18.0 million in higher materials and supplies, and outside service expenses; and

• an increase of $6.9 million due to higher ad valorem taxes.

Depreciation and amortization increased due primarily to the higher depreciation expense associated with ONEOK Partners’ completed capital projects discussed above.

Interest expense increased for 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 issuance of $1.25 billion of senior notes in September 2013, offset partially by higher capitalized interest associated with ONEOK Partners’ investments in the growth projects in its natural gas gathering and processing and natural gas liquids businesses.

Capital expenditures increased for 2013, compared with 2012, due primarily to the growth projects in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses. In 2013, ONEOK Partners also acquired natural gas processing and natural gas liquids facilities in the NGL-rich Niobrara shale area of the Powder River Basin, the Sage Creek acquisition, and the remaining 30 percent interest in its Maysville, Oklahoma, natural gas processing facility.

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Commodity-Price Risk - ONEOK Partners’ natural gas gathering business 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 our commodity-price risk under “Commodity-Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Equity Investments - Equity earnings from ONEOK Partners’ investments decreased in 2013 compared with 2012. In 2013, Northern Border Pipeline reduced transportation rates as a result of a rate settlement, effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower than previous rates. In 2013, there were declines in volumes gathered by ONEOK Partners’ equity investments in the Powder River Basin. Higher volumes were delivered to Overland Pass Pipeline from ONEOK Partners’ Bakken NGL Pipeline, which was placed in service in April 2013. The increased equity earnings from higher Bakken NGL Pipeline volumes were offset partially by reduced volumes as a result of ethane rejection.

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 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 in 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 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 and could result in noncash charges to earnings.

Due to recent reductions in producer activity and declines in natural gas volumes gathered in the coal-bed methane areas 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 our 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 ONEOK Partners’ control. The carrying amount of ONEOK Partners’ investment at December 31, 2013, was $87.8 million, which includes $53.4 million in equity method goodwill.

2012 vs. 2011 -Revenues and cost of sales decreased for 2012 due to lower natural gas and NGL product prices and narrower NGL product price differentials, offset partially by higher natural gas and NGL sales volumes from the ONEOK Partners segment’s completed capital projects. The increase in natural gas supply resulting from development of nonconventional resource areas in North America and a warmer than normal winter have caused lower natural gas prices and narrower natural gas location and seasonal price differentials in the markets it serves. NGL prices, particularly ethane and propane, also decreased in 2012 due primarily to increased NGL production growth from the development of NGL-rich resource 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 the 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 of 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 residue 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. We expect lower natural gas liquids volumes in ONEOK Partners’ natural gas liquids business as a result of widespread and prolonged ethane rejection in 2013 that is expected to have a significant impact on our financial results. We do not expect prolonged ethane rejection to continue in 2014.

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 in ONEOK Partners’ natural gas gathering and processing business;

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

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• an increase of $13.1 million due to higher natural gas liquids storage margins as a result of contract renegotiations at higher fees in ONEOK Partners’ natural gas liquids business; offset partially by

• a decrease of $91.2 million in optimization and marketing margins in ONEOK Partners’ natural gas liquids business, which resulted from a $94.6 million decrease due to narrower NGL location 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 ONEOK Partners’ marketing activities that benefited from higher natural gas liquids truck and rail volumes;

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

• a decrease of $31.4 million due to lower net realized natural gas and NGL prices, particularly ethane and propane, in ONEOK Partners’ natural gas gathering and processing business; and

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

Operating costs increased for 2012, compared with 2011, as a result of the growth of ONEOK Partners operations and reflect the following:

• an increase of $27.3 million from higher materials and supplies, and outside services expenses, including costs associated with scheduled maintenance at ONEOK Partners’ existing facilities, and higher ad valorem taxes; offset partially by

• a decrease of $3.7 million due primarily to $9.0 million decrease of labor and employee-related costs associated with incentive and benefit plans, offset partially by a $5.3 million increase in other labor and employee-related costs due to the growth of operations in its natural gas gathering and processing and natural gas liquids businesses.

Depreciation and amortization increased due primarily to the higher depreciation expense associated with ONEOK Partners’ completed capital projects, which includes the completion of its Garden Creek and Stateline I natural gas processing plants, well connections and infrastructure projects supporting the volume growth in the Williston Basin.

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

Capital expenditures increased for 2012, compared with 2011, due primarily to the growth projects in ONEOK Partners’ natural gas liquids business, offset partially by timing of expenditures on growth projects in ONEOK Partners’ natural gas gathering and processing business.

Previously, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which we 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.

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Selected Operating Information - The following table sets forth selected operating information for our ONEOK Partners segment for the periods indicated:

Operating Information	2013			2012			2011
Natural gas gathering and processing business (a)
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
Natural gas liquids business
NGL sales (MBbl/d)	657			572			497
NGLs fractionated (MBbl/d) (d)	535			574			537
NGLs transported-gathering lines (MBbl/d) (a)	547			520			436
NGLs transported-distribution lines (MBbl/d) (a)	435			491			473
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)	$	0.04		$	0.17		$	0.28
Natural gas pipelines business (a)
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.

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

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

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

2013 vs. 2012 - Naturalgas gathered, natural gas processed,NGLssold and residue gas sold increased for 2013 compared with 2012 due to increased well connections and completion of growth projects, offset partially by continued declines in 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, ONEOK Partners’ 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.

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

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.

2012 vs. 2011 - Natural gas gathered volumes increased in 2012, compared with 2011, due to increased drilling activity in the Williston Basin and western Oklahoma, completion of additional natural gas gathering lines and compression to support ONEOK Partners’ new Garden Creek and Stateline I natural gas processing plants, offset partially by continued declines in coal-bed methane production in the Powder River Basin in Wyoming.

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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 recover ethane during 2012. As a result, the 2012 equity NGL volumes and realized composite NGL net sales price associated with its natural gas gathering and processing business were weighted more toward the relatively higher priced propane, iso-butane, normal butane and natural gasoline compared with 2011.  This has the effect of producing a higher NGL composite barrel realized price, while most individual NGL products prices are substantially lower in 2012 compared with 2011.

ONEOK Partners’ operating information above does not include its 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 settlement was approved and the new rates became effective January 1, 2013.

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. Increased NGL 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. Increased Gulf Coast NGL fractionation capacity was made available by the 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’ natural gas liquids distribution pipelines between its Mid-Continent facilities to optimize the delivery of supply.

Natural Gas Distribution

Separation of Natural Gas Distribution Business - On January 31, 2014, we completed the separation of our natural gas distribution business into a standalone publicly traded company, ONE Gas. ONE Gas consists of ONEOK’s former Natural Gas Distribution segment that included Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service. The Natural Gas Distribution segment will be classified as discontinued operations in the first quarter 2014. See additional discussion in Note U of the Notes to the Consolidated Financial Statements.

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

Selected Financial Results - The following table sets forth certain selected financial results for the continuing operations of our former Natural Gas Distribution 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)
Gas sales	$	1,558.5	$	1,252.0	$	1,492.5	$	306.5		24	%	$	(240.5	)	(16	)%
Transportation revenues	98.7		88.8		90.9		9.9			11	%	(2.1		)	(2	)%
Cost of gas	876.9		620.2		869.5		256.7			41	%	(249.3		)	(29	)%
Net margin, excluding other revenues	780.3		720.6		713.9		59.7			8	%	6.7			1	%
Other revenues	32.7		35.8		37.9		(3.1		)	(9	)%	(2.1		)	(6	)%
Net margin	813.0		756.4		751.8		56.6			7	%	4.6			1	%
Operating costs	444.9		410.6		422.0		34.3			8	%	(11.4		)	(3	)%
Depreciation and amortization	144.7		130.1		132.2		14.6			11	%	(2.1		)	(2	)%
Operating income	$	223.4	$	215.7	$	197.6	$	7.7		4	%	$	18.1		9	%
Capital expenditures	$	292.1	$	280.3	$	242.6	$	11.8		4	%	$	37.7		16	%

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

							Variances				Variances
	Years Ended December 31						2013 vs. 2012				2012 vs. 2011
Net Margin, Excluding Other Revenues	2013		2012		2011		Increase (Decrease)				Increase (Decrease)
Gas sales	(Millions of dollars)
Residential	$	564.5	$	523.4	$	510.5	$	41.1	8	%	$	12.9		3	%
Commercial and industrial	111.5		103.8		107.9		7.7		7	%	(4.1		)	(4	)%
Wholesale/public authority	5.6		4.6		4.6		1.0		22	%	—			—	%
Net margin on gas sales	681.6		631.8		623.0		49.8		8	%	8.8			1	%
Transportation margin	98.7		88.8		90.9		9.9		11	%	(2.1		)	(2	)%
Net margin, excluding other revenues	$	780.3	$	720.6	$	713.9	$	59.7	8	%	$	6.7		1	%

2013 vs. 2012 - Net margin increased due primarily to the following:

• an increase of $36.8 million from new rates in all three states;

• an increase of $12.5 million due to higher sales volume due primarily to colder than normal weather in all three states in 2013, compared with warmer than normal weather in 2012; and

• an increase of $5.9 million from higher transportation volumes, due primarily to higher demand from weather-sensitive customers in Kansas.

Operating costs increased due primarily to the following:

• an increase of $14.3 million in employee-related expense, primarily pension cost increases resulting from an annual change in the estimated discount rate;

• an increase of $10.1 million in share-based compensation costs due primarily to the appreciation in ONEOK’s share price in 2013;

• an increase of $7.0 million in ad valorem tax expense primarily as a result of an increase in the level of this expense recovered in base rates, which is offset in net margin. For Kansas Gas Service, actual ad valorem taxes incurred that differ from the level of ad valorem taxes recovered in base rates are deferred or refunded through an ad valorem tax surcharge; and

• an increase of $2.9 million in bad debt expense as a result of increased revenues.

Depreciation and amortization expense increased due primarily to the settlement agreement approved by the KCC, authorizing the separation of the Kansas Gas Service assets from ONEOK to ONE Gas, whereby Kansas Gas Service agreed to expense a $10.2 million regulatory asset related to a transaction cost recovery. In addition, depreciation and amortization expense increased as a result of an increase in amortization of amounts previously deferred for ad valorem taxes, which is offset in net margin.

2012 vs. 2011 - Net margin increased due primarily to the following:

• an increase of $15.4 million from new rates in all three states; offset partially by

• a decrease of $8.5 million due to expiration of the Integrity Management Program (IMP) rider, which allowed Oklahoma Natural Gas to recover certain deferred pipeline-integrity costs in Oklahoma.  This decrease is offset by lower regulatory amortization in depreciation and amortization expense; and

• a decrease of $2.2 million from lower transportation volumes due to weather-sensitive customers in Kansas and Oklahoma.

Operating costs decreased due primarily to the following:

• a decrease of $16.7 million in share-based compensation costs from common stock awarded in 2011 to employees as part of ONEOK’s stock award program and the appreciation in ONEOK’s share price during 2011;

• a decrease of $8.9 million in employee-related incentive and health benefit costs due to reduced short-term incentives and medical claims expenses; offset partially by

• an increase of $5.4 million in pension costs as a result of the annual change in our estimated discount rate;

• an increase of $4.8 million due primarily to expenses associated with outside services and pipeline maintenance; and

• an increase of $4.0 million in litigation expense.

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Depreciation and amortization expense decreased due primarily to a decrease of $8.5 million in regulatory amortization associated with the expiration of the IMP rider, offset partially by an increase of $6.1 million associated with additional capital expenditures.

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

Capital expenditures increased for 2013, compared with 2012, primarily as a result of extending service to new areas. Capital expenditures increased for 2012, compared with 2011, primarily as a result of increased spending on pipeline replacements.

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

	Years Ended December 31,
Number of Customers	2013	2012	2011
Residential	1,943,930	1,932,484	1,921,017
Commercial and industrial	155,196	154,252	154,475
Wholesale/public authority	2,755	2,737	2,730
Transportation	12,031	11,926	11,708
Total customers	2,113,912	2,101,399	2,089,930

	Years Ended December 31,
Volumes (MMcf)	2013	2012	2011
Gas sales
Residential	122,855	103,799	117,969
Commercial and industrial	36,956	31,459	35,172
Wholesale/public authority	4,403	6,135	3,287
Total volumes sold	164,214	141,393	156,428
Transportation	205,915	199,408	203,655
Total volumes delivered	370,129	340,801	360,083

Residential, commercial and industrial natural gas sales volumes increased for 2013, compared with 2012, due primarily to colder temperatures in 2013; however, the impact on margins was mitigated largely by weather-normalization mechanisms.

Residential and commercial volumes decreased for 2012, compared with 2011, due primarily to warmer temperatures in 2012; however, the impact on margins was mitigated largely by weather-normalization mechanisms. Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties.  Wholesale volumes increased for 2012, compared to 2011; however, the impact to net margin was minimal.

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

Regulatory Initiatives - Oklahoma - On October 18, 2013, Oklahoma Natural Gas filed a joint application with the OCC to postpone its 2014 rate case. The joint stipulation and settlement agreement in support of the application was approved by the OCC in January 2014. As a result, Oklahoma Natural Gas will file a Performance-Based Rate Change (PBRC) application in 2014 and a rate case in 2015 based on a test year consisting of the first four calendar quarters of Oklahoma Natural Gas’ operations as a division of ONE Gas.

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

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In July 2012, a joint stipulation settling Oklahoma Natural Gas’ annual PBRC filing was approved by the OCC. The settlement granted a $9.5 million rate increase and modified Oklahoma Natural Gas’ PBRC tariff. The modified tariff narrowed the range of allowed return on equity (ROE) to a range of 10.0 percent to 11.0 percent from our previous range of 9.75 percent to 11.25 percent, increases the ROE reflected in any rate increase resulting from a revenue deficiency to 10.5 percent from 10.25 percent, and reduced the number of allowed pro forma adjustments that can be proposed by Oklahoma Natural Gas in a PBRC proceeding.

In May 2011, the OCC approved a portfolio of conservation and energy-efficiency programs and authorized recovery of costs and performance incentives.  The agreement allows Oklahoma Natural Gas to pursue key energy-efficiency programs and to earn up to $1.5 million annually, if program objectives are achieved. In May 2013, the OCC approved the extension of the program to include the years 2014-2016, as well as adjustments to rebate amounts and targets that were requested by Oklahoma Natural Gas.

Kansas - In December 2013, the KCC approved a settlement agreement between ONEOK, the staff of the KCC and the Citizens’ Utility Ratepayer Board for the separation from ONEOK of the natural gas distribution business, including Kansas Gas Service. Among other things, the terms of the settlement agreement include the following:

• Kansas Gas Service shall not change its base rates prior to January 1, 2017. The time limitation on filing a general rate case to change base rates does not preclude Kansas Gas Service from changing rates or tariffs to recover appropriate costs under its current approved riders and tariffs, including its cost-of-gas rider, annual cost adjustment, weather-normalization adjustment, ad valorem tax surcharge and gas system reliability surcharge (GSRS) tariffs;

• Kansas Gas Service agreed to expense certain costs associated with ONEOK’s acquisition of Kansas Gas Service in 1997 that were recorded previously as a regulatory asset and were being amortized and recovered in rates over a 40-year period. As such, we recorded a noncash charge as amortization expense of approximately $10.2 million in the fourth quarter 2013;

• The level of pension and postretirement benefit costs used to calculate Kansas Gas Service’s Pension and Other Postretirement Benefit Trackers shall be adjusted to $13.6 million from $16.6 million with a corresponding reduction to revenues; and

• ONEOK agreed to make a one-time contribution to 501(c)(3) organizations of $1.2 million that was recorded in the fourth quarter 2013, to provide financial assistance for weatherization of housing for low-income natural gas customers of Kansas Gas Service.

The agreement authorized the transfer of ONEOK’s Kansas natural gas distribution assets, certificates of convenience and necessity, franchises and tariffs to ONE Gas, conditioned upon the completion of the separation.

In August 2013, Kansas Gas Service filed an application to increase the GSRS by $1.5 million. This surcharge is a capital-recovery mechanism that allows for rate adjustment, providing recovery of and a return on incremental safety-related and government-mandated capital investments made between rate cases. The KCC approved the final ruling, and new rates became effective December 1, 2013.

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

In September 2012, the KCC denied Kansas Gas Service’s application to implement an infrastructure-replacement program that would have allowed Kansas Gas Service to accelerate the rate at which it is replacing cast-iron pipe. Costs incurred by Kansas Gas Service to replace cast-iron pipe are eligible for the GSRS. This surcharge is a capital-recovery mechanism that allows for rate adjustment, providing recovery of and a return on incremental safety-related and government-mandated capital investments made between rate cases.

The KCC approved an application from Kansas Gas Service to increase the GSRS by an additional $2.9 million, effective January 2012.

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

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

In the normal course of business, we filed rate cases and sought GRIP and cost-of-service adjustments in various other Texas jurisdictions to address investments in rate base and changes in expense. Annual rate increases totaling $4.2 million associated with these filings were approved in 2013.

In January 2012, the RRC approved a settlement between Texas Gas Service and the City of El Paso that allows for recovery of pipeline-integrity expenditures and partial recovery of rate-case expenses from 2010 through 2013. The settlement did not have a material impact on our results of operations.

General - Certain costs to be recovered through the ratemaking process have been capitalized as regulatory assets. Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria for recognition and accordingly, a write-off of regulatory assets and stranded costs may be required. In 2013, as part of the KCC settlement related to the ONE Gas separation as discussed above, Kansas Gas Service expensed the remaining $10.2 million regulatory asset balance for certain costs associated with ONEOK’s acquisition of Kansas Gas Service in 1997. There were no write-offs of regulatory assets during 2012 or 2011.

Energy Services

Selected Financial Results - The following table sets forth certain selected financial results for our Energy Services 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)
Revenues	$	1,577.6		$	1,526.6		$	2,777.2	$	51.0		3	%	$	(1,250.6	)	(45	)%
Cost of sales and fuel	1,750.6			1,575.9			2,728.5		174.7			11	%	(1,152.6		)	(42	)%
Net margin	(173.0		)	(49.3		)	48.7		(123.7		)	*		(98.0		)	*
Operating costs	13.1			18.0			24.5		(4.9		)	(27	)%	(6.5		)	(27	)%
Depreciation and amortization	0.3			0.3			0.4		—			—	%	(0.1		)	(25	)%
Goodwill impairment	—			10.3			—		(10.3		)	(100	)%	10.3			100	%
Operating income (loss)	$	(186.4	)	$	(77.9	)	$	23.8	$	(108.5	)	*		$	(101.7	)	*

*Percentage change is greater than 100 percent.

Segment wind down charges - During the year ended December 31, 2013, we recorded approximately $138.6 million of noncash charges related to the full release and assignment of a significant portion of our natural gas transportation and storage contracts to third parties, and we made cash payments of $17.7 million related to this obligation.

2013 vs. 2012 - Revenues and cost of sales and fuel have increased for the year ended December 31, 2013, compared with 2012, due primarily to higher natural gas prices. Cost of sales and fuel have also increased due to the noncash charges described above.

Excluding noncash charges related to the released capacity, net margin increased by $16.0 million for the year ended December 31, 2013, compared with 2012, primarily due to the following:

• a net increase of $24.3 million in storage and marketing margins, net of hedging activities, due primarily to an increase related to the reclassification in the first quarter 2012 of deferred losses into earnings from accumulated other comprehensive income (loss) on certain financial contracts that were used to hedge forecasted purchases on natural gas in 2012 and reduced storage capacity resulting in lower demand charges in the current year, offset partially by decreases due to lower realized seasonal storage differentials and marketing margins, net of hedging activities; and

• an increase of $17.1 million in transportation margins from lower transportation costs, due primarily to reduced contracted transportation capacity resulting in lower demand charges in the current year; offset partially by

• a decrease of $19.8 million in premium-services margins, associated primarily with lower demand fees due to the reduced size of our operations as a result of our decision to wind down this segment; and

• a decrease of $5.6 million in financial trading margins due to the reduced size of our operations as a result of our decision to wind down this segment.

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Operating costs decreased for the year ended December 31, 2013, compared with 2012, due primarily to lower employee-related expenses as employees were redeployed in other ONEOK business segments as a result of the accelerated wind down.

2012 vs. 2011 - In 2012, we realized $44.6 million in premium-services margins, and our storage and marketing margins consisted of $40.0 million from realized seasonal price differentials and marketing optimization activities and $89.9 million from storage demand costs. Our 2012 results were lower than 2011 when we realized $53.1 million in premium-services margins, and our storage and marketing margins consisted of $96.0 million from realized seasonal price differentials and marketing optimization activities and $87.7 million from storage demand costs.  In addition, we recognized a loss on the change in fair value of our nonqualifiying economic storage hedges of $1.0 million in 2012, compared with a gain of $8.5 million in 2011. Our premium services were impacted negatively by lower natural gas prices and decreased natural gas price volatility. The impact of our hedge strategies and the inability to hedge seasonal price differentials at levels that were available to us in 2011 significantly reduced our storage margins. We also experienced reduced opportunities to optimize our storage assets, which negatively affected our marketing margins.

We realized a loss in our transportation margins of $42.4 million in 2012, compared with a loss of $18.8 million in 2011, due primarily to a $29.5 million decrease in transportation hedges. Our transportation business continues to be affected by narrow price location differentials and the inability to hedge at levels that were available to us in prior years. As a result of significant increases in the supply of natural gas, primarily from shale gas production across North America and new pipeline infrastructure projects, location and seasonal price differentials narrowed significantly beginning in 2010 and continuing through 2012. This market change resulted in our transportation contracts being unprofitable impacting our ability to recover our fixed costs.

Operating costs decreased due primarily to lower employee-related expenses, which include the impact of fewer employees.

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

Selected Operating Information - At December 31, 2013, our natural gas transportation capacity was 0.07 Bcf/d compared with 1.0 Bcf/d of total capacity and 1.0 Bcf/d of long-term capacity at December 31, 2012. During the fourth quarter 2013, we released approximately 0.03 Bcf/d of transportation capacity. The remaining 0.07 Bcf/d of transportation capacity will expire on March 31, 2014.

Our natural gas in storage at December 31, 2013, was 17.5 Bcf, compared with 55.5 Bcf at December 31, 2012.  At December 31, 2013, our total natural gas storage capacity under lease was 23.5 Bcf, compared with 71.5 Bcf at December 31, 2012.  During the first quarter 2014, we assigned approximately 3.0 Bcf of storage capacity to a third party effective April 1, 2014, and the remaining 20.5 Bcf of storage capacity will expire on March 31, 2014. At December 31, 2013, our natural gas storage capacity under lease had a maximum withdrawal capability of 0.5 Bcf/d and maximum injection capability of 0.4 Bcf/d. 

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

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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 2013, we announced plans to exit our Energy Services business through an accelerated wind down process that will be completed substantially by March 31, 2014. We expect future cash expenditures associated with the released transportation and storage capacity from the wind down of our Energy Services segment to be 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 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, ONEOK Partners expects 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:

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	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%

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.

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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 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

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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.

Based on the forward LIBOR curve, ONEOK Partners expects the interest rates on its short-term borrowings to increase in 2014, compared with interest rates on amounts outstanding during 2013.

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. ONEOK Partners expects to fund its longer-term cash requirements by issuing common units or long-term notes. Other options to obtain financing include, but are not limited to, issuance of convertible debt securities, asset securitization and the sale and lease back of facilities.

ONEOK and ONEOK Partners are subject to changes in the debt and equity markets, and there is no assurance they will be able or willing to access the public or private markets in the future.  ONEOK and ONEOK Partners may choose to meet their cash requirements by utilizing some combination of cash flows from operations, borrowing under existing commercial paper or credit facilities, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, or pursuing other debt or equity financing alternatives.  Some of these alternatives could 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.

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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.

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 ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses.

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

2014 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners	$	2,024
Other	16
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 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

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liquidity requirements associated with commodity price volatility.  See discussion under “Commodity-Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for information on our hedging activities.

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

During 2013, we made no contributions to our defined benefit pension plans and $11.8 million in contributions to our postretirement benefit plans.  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.

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		$	990.9		$	1,360.0
Investing activities	(2,642.0		)	(1,814.2		)	(1,371.6		)
Financing activities	912.9			1,332.1			55.4
Change in cash and cash equivalents	(434.3		)	508.8			43.8
Change in cash and cash equivalents included in discontinued operations	—			8.9			(8.2		)
Change in cash and cash equivalents from continuing operations	(434.3		)	517.7			35.6
Cash and cash equivalents at beginning of period	583.6			66.0			30.4
Cash and cash equivalents at end of period	$	149.3		$	583.6		$	66.0

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 $1,347.2 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 $356.3 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 $1,347.2 million for 2012 compared with $1,397.7 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 $356.3 million for 2012, compared with a decrease of $37.7 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

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

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

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

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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 and Note R of the Notes to Consolidated Financial Statements in this Annual 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.

Other - Several regulatory initiatives impacted the earnings for our Natural Gas Distribution segment. See discussion of our Natural Gas Distribution segment’s regulatory initiatives in the Natural Gas Distribution section of the Management Discussion and Analysis.

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 Annual 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

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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 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 and Note D of the Notes to Consolidated Financial Statements in this Annual 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

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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 and Note E of the Notes to Consolidated Financial Statements in this Annual 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 Energy Services segment’s 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. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services. 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.

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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 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 F, G and P of the Notes to Consolidated Financial Statements 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 N of the Notes to Consolidated Financial Statements in this Annual Report for additional information.

During 2013, we recorded net periodic benefit costs of $64.7 million related to our defined benefit pension plans and $10.5 million related to postretirement benefits.

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.

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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.

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.  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 R of the Notes to Consolidated Financial Statements in this Annual 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 I and R, respectively, of the Notes to the Consolidated Financial Statements in this Annual Report.

	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	16.1		3.4		2.9		2.5		2.1		1.9		3.3
Natural Gas Distribution firm transportation and storage contracts	900.0		172.4		200.9		164.1		142.1		127.8		92.7
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	45.9		5.9		7.0		24.0		9.0		—		—
Natural gas purchase commitments	684.3		$	424.2	$	230.6	$	6.1	$	5.1	$	5.1	$	13.2
ONEOK total	$	5,270.2	$	1,601.9	$	958.7	$	285.5	$	236.8	$	207.4	$	1,979.9
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	$	16,687.8	$	2,157.7	$	1,372.9	$	1,760.9	$	995.2	$	979.3	$	9,421.8

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. The amounts above include leases obligations related to our former Natural Gas Distribution segment that are obligations of ONE Gas as of the separation of approximately $14.5 million.

Natural Gas Distribution firm transportation and storage contracts - Our former Natural Gas Distribution segment is party to fixed-price contracts providing it with firm transportation and storage capacity. The costs associated with these contracts are recovered as part of the purchased gas cost mechanisms. These contracts are obligations of ONE Gas as of the separation of the natural gas distribution business.

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

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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 our ONEOK Partners and Energy Services segments’ 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 amounts.

Employee benefit plans - Employee benefit plans include our anticipated contributions to our pension and postretirement benefit plans for 2014.  Anticipated contributions assumed by ONE Gas upon completion of the separation are approximately $5.9 million in 2014 and $13 million in 2016. See Note N of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our employee benefit plans.

Natural gas purchase commitments - Our former Natural Gas Distribution segment is party to fixed-price and variable-price contracts for the purchase of natural gas. Estimated future variable-price natural gas purchase commitments are estimated based on market price information. Actual future variable-price purchase commitments may vary depending on market prices at the time of delivery. As market information changes daily and is potentially volatile, these values may change significantly. The commitments associated with these contracts are recoverable through the former segment’s purchased gas cost mechanisms as allowed by the applicable regulatory authority. These commitments are obligations of ONE Gas as of the separation.

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 Annual 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 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 Annual 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 Annual 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;

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

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

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

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

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

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

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

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

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

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

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

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

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

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Policy and Oversight - We control the scope of risk management, marketing and trading operations through a comprehensive set of policies and procedures involving senior levels of management.  The Audit Committee of our Board of Directors has oversight responsibilities for our risk-management limits and policies.  Our risk oversight committee, comprised of corporate and business-segment officers, oversees all activities related to commodity, price and credit risk management, marketing and trading activities and interest rate risk.  The committee also monitors risk metrics including VAR, position limits and mark-to-market losses.  We have a risk-control group that is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics.  Key risk-control activities include risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.

Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that could occur assuming hypothetical future movements in commodity prices or interest rates.  Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.

COMMODITY-PRICE RISK

We are exposed to commodity-price risk and the impact of market price fluctuations of natural gas, NGLs and crude oil. Commodity-price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in energy prices, including the impact on seasonal and location price differentials.  To minimize the risk from market price fluctuations of natural gas, NGLs and crude oil, we use commodity derivative instruments such as futures, physical forward contracts, swaps and options to manage commodity-price risk associated with existing or anticipated purchase and sale agreements, existing physical natural gas or natural gas liquids in storage and location price differentials. As a result of the accelerated wind down of our Energy Services segment, we expect our exposure to commodity-price risk to be eliminated; however, ONEOK Partners will continue to have exposure to commodity-price risk which can affect us.

ONEOK Partners

ONEOK Partners is exposed to commodity-price risk as a result of receiving commodities in exchange for services associated with its POP contracts. Less than 2 percent of ONEOK Partners’ contracted volume exposure arises from the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to its keep-whole contracts.  ONEOK Partners is also exposed to basis risk between the various production and market locations where it receives and sells commodities.  As part of ONEOK Partners’ hedging strategy, ONEOK Partners uses previously described commodity derivative financial instruments and physical-forward contracts to minimize the impact of price fluctuations related to natural gas, NGLs and condensate.

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As of December 31, 2013, ONEOK Partners had $8.5 million of commodity-related derivative assets and $8.6 million of commodity-related derivative liabilities, excluding the impact of netting. The following tables set forth ONEOK Partners’ hedging information for the periods indicated:

	Year Ending December 31, 2014
	Volumes Hedges	Average Price			Percentage Hedged
NGLs (Bbl/d)	9,351	$	1.19	/ gallon	71%
Condensate (Bbl/d)	2,545	$	2.25	/ gallon	75%
Total (Bbl/d)	11,896	$	1.42	/ gallon	72%
Natural gas (MMBtu/d)	82,808	$	4.06	/ MMBtu	75%

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

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

• a $0.10 per MMBtu change in the price of natural gas would change annual net margin by approximately $4.0 million;

• a $0.01 per gallon change in the composite price of NGLs would change annual net margin by approximately $2.0 million; and

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

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

ONEOK Partners is also exposed to price differential risk primarily as a result of NGLs in storage, the relative values of the various NGL products to each other, the relative value of NGLs to natural gas and the relative value of NGL purchases at one location and sales at another location.  ONEOK Partners utilizes physical-forward contracts to reduce earnings volatility related to NGL price fluctuations in the storage and optimization activities of its natural gas liquids business. ONEOK Partners has not entered into any financial instruments with respect to its natural gas liquids business’ marketing activities.

In addition, ONEOK Partners is exposed to commodity-price risk as its natural gas interstate and intrastate pipelines retain natural gas from its customers for operations or as part of its fee for services provided.  When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by its customers, the pipelines must buy or sell natural gas, or store or use natural gas from inventory, which exposes ONEOK Partners to commodity-price risk depending on the regulatory treatment for this activity.  To the extent that commodity-price risk in its natural gas pipelines business is not mitigated by fuel cost-recovery mechanisms, ONEOK Partners utilizes physical-forward contracts to reduce the impact of price fluctuations related to natural gas. At December 31, 2013, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas pipeline business.

Natural Gas Distribution

Our former Natural Gas Distribution segment uses financial derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect its customers from upward volatility in the market price of natural gas.  Gains or losses associated with these financial derivative instruments are included in, and recoverable through, the monthly purchased-gas cost-adjustment mechanisms.

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Energy Services

Our Energy Services segment historically was exposed to commodity-price risk, seasonal and location-price risk and price volatility arising from natural gas in storage, peaking natural gas load requirement contracts, asset management contracts and index-based purchases and sales of natural gas at various market locations.  We attempted to mitigate our exposure to commodity-price risk through the use of derivative instruments, which, under certain circumstances, are designated as cash flow or fair value hedges. We were also exposed to commodity-price risk from fixed-price purchases and sales of natural gas, which we hedge with derivative instruments.  Both the fixed-price purchases and sales and related derivatives are recorded at fair value.

Fair Value Component of the Energy Marketing and Risk-Management Assets and Liabilities - The following table sets forth the fair value component of the energy marketing and risk management assets and liabilities, excluding $3.9 million of net liabilities and $27.4 million of net assets at December 31, 2013 and 2012, respectively, from derivative instruments declared as either fair value or cash flow hedges for the periods indicated:

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at January 1, 2012	$	12,609
Derivatives reclassified or otherwise settled during the period	(15,074		)
Fair value of new derivatives entered into during the period	178
Other changes in fair value	7,320
Net fair value of derivatives outstanding at December 31, 2012	5,033
Derivatives reclassified or otherwise settled during the period	(1,726		)
Fair value of new derivatives entered into during the period	(1,460		)
Other changes in fair value	(3,815		)
Net fair value of derivatives outstanding at December 31, 2013 (a)	$	(1,968	)

(a) - The maturities of derivatives are based on injection and withdrawal periods from April through March, which is consistent with our business strategy. The maturities are as follows: $0.6 million net assets matures through March 2014 and $2.6 million net liabilities matures through March 2016.

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

For further discussion of fair value measurements and trading activities and assumptions used in our trading activities, see the “Estimates and Critical Accounting Policies” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.  Also, see Notes D and E of the Notes to Consolidated Financial Statements in this Annual Report.

VAR Disclosure of Commodity-Price Risk - We measure commodity-price risk in our Energy Services segment using a VAR methodology, which estimates the expected maximum loss of our portfolio over a specified time horizon within a given confidence interval.  Our VAR calculations are based on the Monte Carlo approach.  The quantification of commodity-price risk using VAR provides a consistent measure of risk across diverse energy markets and products with different risk factors in order to set overall risk tolerance and to determine risk thresholds.  The use of this methodology requires a number of key assumptions, including the selection of a confidence level and the holding period to liquidation.  Historical data is used to estimate our VAR with more weight given to recent data, which is considered a more relevant predictor of immediate future commodity market movements.  Other assumptions include a distribution of prices and historical data to calculate volatility and price correlations.  We rely on VAR to determine the potential reduction in the portfolio values arising from changes in market conditions over a defined period.  While management believes that the referenced assumptions and approximations are reasonable, no uniform industry methodology exists for estimating VAR.  Different assumptions and approximations could produce materially different VAR estimates.

Our VAR exposure represents an estimate of potential losses that would be recognized due to adverse commodity-price movements in our Energy Services segment’s portfolio of derivative financial instruments, physical commodity contracts, leased transport, storage capacity contracts and natural gas in storage.  A one-day time horizon and a 95 percent confidence level are used in our VAR data.  Actual future gains and losses will differ from those estimated by the VAR calculation based on actual fluctuations in commodity prices, operating exposures and timing thereof, and the changes in our derivative financial instruments, physical contracts and natural gas in storage.  VAR information should be evaluated in light of these assumptions and the methodology’s other limitations.

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The potential impact on our future earnings, as measured by VAR, was $0.1 million and $1.5 million at December 31, 2013 and 2012, respectively.  The following table sets forth the average, high and low VAR calculations for the periods indicated:

	Years Ended December 31,
Value-at-Risk	2013		2012
	(Millions of dollars)
Average	$	1.0	$	2.6
High	$	2.7	$	4.0
Low	$	0.1	$	1.4

Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges.  The variations in the VAR data reflect market volatility and changes in our portfolio during the year. The decrease in average VAR for 2013, compared with 2012, was due primarily to the decrease in total storage and transportation capacity as a result of the wind down of our Energy Services segment.

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

INTEREST-RATE RISK

General - We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps.  Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts. At December 31, 2013 and 2012, ONEOK Partners had forward-starting interest-rate swaps with notional amounts totaling $400 million that have been designated as cash flow hedges of the variability of interest payments on a portion of forecasted debt issuances that may result from changes in the benchmark interest rate before the debt is issued. Future issuances of long-term debt could be impacted by recent increases in interest rates, which could result in higher interest costs. At December 31, 2013 and 2012, ONEOK Partners had derivative assets of $54.5 million and $10.9 million, respectively, related to these interest-rate swaps.

COUNTERPARTY CREDIT RISK

ONEOK and ONEOK Partners assess the creditworthiness of their counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

ONEOK, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows present fairly, in all material respects, the financial position of ONEOK, Inc. and its subsidiaries (the Company) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A.  Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/  PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 25, 2014

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED  STATEMENTS OF INCOME
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars, except per share amounts)
Revenues	$	14,602,717		$	12,632,559		$	14,805,794
Cost of sales and fuel	12,313,034			10,281,718			12,425,435
Net margin	2,289,683			2,350,841			2,380,359
Operating expenses
Operations and maintenance	872,125			806,087			813,666
Depreciation and amortization	384,377			335,844			312,160
Goodwill impairment	—			10,255			—
General taxes	118,328			102,891			94,657
Total operating expenses	1,374,830			1,255,077			1,220,483
Gain (loss) on sale of assets	11,881			6,736			(963		)
Operating income	926,734			1,102,500			1,158,913
Equity earnings from investments (Note P)	110,517			123,024			127,246
Allowance for equity funds used during construction	30,522			13,648			2,335
Other income	24,483			12,504			1,410
Other expense	(17,707		)	(4,925		)	(9,336		)
Interest expense (net of capitalized interest of $57,775, $41,776 and $23,960, respectively)	(334,206		)	(302,305		)	(297,006		)
Income before income taxes	740,343			944,446			983,562
Income taxes (Note O)	(163,382		)	(215,195		)	(226,048		)
Income from continuing operations	576,961			729,251			757,514
Income from discontinued operations, net of tax (Note C)	—			762			2,230
Gain on sale of discontinued operations, net of tax (Note C)	—			13,517			—
Net income	576,961			743,530			759,744
Less: Net income attributable to noncontrolling interests	310,428			382,911			399,150
Net income attributable to ONEOK	$	266,533		$	360,619		$	360,594
Amounts attributable to ONEOK:
Income from continuing operations	$	266,533		$	346,340		$	358,364
Income from discontinued operations	—			14,279			2,230
Net income	$	266,533		$	360,619		$	360,594
Basic earnings per share:
Income from continuing operations (Note L)	$	1.29		$	1.68		$	1.71
Income from discontinued operations	—			0.07			0.01
Net income	$	1.29		$	1.75		$	1.72
Diluted earnings per share:
Income from continuing operations (Note L)	$	1.27		$	1.64		$	1.67
Income from discontinued operations	—			0.07			0.01
Net income	$	1.27		$	1.71		$	1.68
Average shares (thousands)
Basic	206,044			206,140			209,344
Diluted	209,695			210,710			214,498
Dividends declared per share of common stock	$	1.48		$	1.27		$	1.08

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Net income	$	576,961		$	743,530		$	759,744
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk management assets/ liabilities, net of tax of $(5,574), $(10,601) and $(8,670), respectively	25,609			22,826			(19,828		)
Realized (gains) losses in net income, net of tax of $(1,905), $10,327 and $53,714, respectively	7,926			(49,499		)	(84,025		)
Unrealized holding gains (losses) on available-for-sale securities, net of tax of $112, $(30) and $242, respectively	(177		)	47			(384		)
Change in pension and postretirement benefit plan liability, net of tax of $(52,436), $6,977 and $16,298, respectively	83,126			(11,061		)	(25,837		)
Other, net of tax of $0, $0 and $50, respectively	—			—			(79		)
Total other comprehensive income (loss), net of tax	116,484			(37,687		)	(130,153		)
Comprehensive income	693,445			705,843			629,591
Less: Comprehensive income attributable to noncontrolling interests	332,101			355,901			366,316
Comprehensive income attributable to ONEOK	$	361,344		$	349,942		$	263,275

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	December 31,		December 31,
	2013		2012
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	149,313	$	583,618
Accounts receivable, net	1,549,563		1,349,371
Gas and natural gas liquids in storage	417,077		517,014
Commodity imbalances	82,144		90,211
Energy marketing and risk management assets (Notes D and E)	1,687		48,577
Other current assets	171,018		175,869
Total current assets	2,370,802		2,764,660
Property, plant and equipment
Property, plant and equipment	15,536,156		13,088,991
Accumulated depreciation and amortization	3,238,652		2,974,651
Net property, plant and equipment (Note F)	12,297,504		10,114,340
Investments and other assets
Investments in unconsolidated affiliates (Note P)	1,229,838		1,221,405
Goodwill and intangible assets (Note G)	1,182,515		996,206
Other assets	626,899		758,664
Total investments and other assets	3,039,252		2,976,275
Total assets	$	17,707,558	$	15,855,275

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	December 31,			December 31,
	2013			2012
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt (Note I)	$	10,656		$	10,855
Notes payable (Note H)	564,462			817,170
Accounts payable	1,503,699			1,333,489
Commodity imbalances	212,136			272,436
Energy marketing and risk management liabilities (Notes D and E)	4,032			9,990
Other current liabilities	401,422			369,054
Total current liabilities	2,696,407			2,812,994
Long-term debt, excluding current maturities (Note I)	7,754,975			6,515,372
Deferred credits and other liabilities
Deferred income taxes (Note O)	1,938,262			1,592,802
Other deferred credits	472,734			701,657
Total deferred credits and other liabilities	2,410,996			2,294,459
Commitments and contingencies (Note R)
Equity (Note J)
ONEOK shareholders’ equity:
Common stock, $0.01 par value:
authorized 600,000,000 shares; issued 245,811,180 shares and outstanding 206,618,877 shares at December 31, 2013; issued 245,811,180 shares and outstanding 204,935,043 shares at December 31, 2012	2,458			2,458
Paid-in capital	1,433,600			1,324,698
Accumulated other comprehensive loss (Note K)	(121,987		)	(216,798		)
Retained earnings	2,020,815			2,059,024
Treasury stock, at cost: 39,192,303 shares at December 31, 2013 and 40,876,137 shares at December 31, 2012	(997,035		)	(1,039,773		)
Total ONEOK shareholders’ equity	2,337,851			2,129,609
Noncontrolling interests in consolidated subsidiaries	2,507,329			2,102,841
Total equity	4,845,180			4,232,450
Total liabilities and equity	$	17,707,558		$	15,855,275

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Operating activities
Net income	$	576,961		$	743,530		$	759,744
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	384,377			335,852			312,288
Charges attributable to exit activities, net of settlements	121,971			—			—
Impairment of goodwill	—			10,255			—
Gain on sale of discontinued operations	—			(13,517		)	—
Equity earnings from investments	(110,517		)	(123,024		)	(127,246		)
Distributions received from unconsolidated affiliates	106,364			120,442			132,741
Deferred income taxes	151,515			229,398			256,688
Share-based compensation expense	46,194			36,692			66,371
Pension and postretirement benefit expense, net of contributions	56,600			(57,073		)	(29,863		)
Allowance for equity funds used during construction	(30,522		)	(13,648		)	(2,335		)
Loss (gain) on sale of assets	(11,881		)	(6,736		)	963
Other	(5,656		)	27,982			(1,471		)
Changes in assets and liabilities:
Accounts receivable	(189,809		)	(14,774		)	(55,861		)
Gas and natural gas liquids in storage	99,937			33,343			65,845
Accounts payable	165,076			(30,981		)	102,621
Commodity imbalances, net	(52,233		)	43,471			(54,886		)
Energy marketing and risk management assets and liabilities	25,072			(174,953		)	(31,999		)
Other assets and liabilities	(38,682		)	(162,264		)	(37,434		)
Cash provided by operating activities	1,294,767			983,995			1,356,166
Investing activities
Capital expenditures (less allowance for equity funds used during construction)	(2,256,585		)	(1,866,153		)	(1,336,067		)
Acquisitions	(394,889		)	—			—
Proceeds from sale of discontinued operations, net of cash sold	—			32,946			—
Contributions to unconsolidated affiliates	(35,308		)	(30,768		)	(64,491		)
Distributions received from unconsolidated affiliates	31,134			35,299			23,644
Proceeds from sale of assets	13,617			12,240			1,288
Other	—			2,237			4,000
Cash used in investing activities	(2,642,031		)	(1,814,199		)	(1,371,626		)
Financing activities
Borrowing (repayment) of notes payable, net	(252,708		)	(24,812		)	285,127
Issuance of debt, net of discounts	1,247,822			1,994,693			1,295,450
Long-term debt financing costs	(10,246		)	(15,036		)	(10,986		)
Repayment of debt	(7,868		)	(361,464		)	(727,562		)
Repurchase of common stock	—			(150,000		)	(300,108		)
Issuance of common stock	20,602			15,969			17,906
Issuance of common units, net of issuance costs	583,929			459,587			—
Dividends paid	(304,742		)	(261,969		)	(227,020		)
Distributions to noncontrolling interests	(374,142		)	(324,906		)	(277,375		)
Excess tax benefit from share-based awards	10,312			6,948			3,806
Cash provided by financing activities	912,959			1,339,010			59,238
Change in cash and cash equivalents	(434,305		)	508,806			43,778
Change in cash and cash equivalents included in discontinued operations	—			8,859			(8,166		)
Change in cash and cash equivalents from continuing operations	(434,305		)	517,665			35,612
Cash and cash equivalents at beginning of period	583,618			65,953			30,341
Cash and cash equivalents at end of period	$	149,313		$	583,618		$	65,953
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized	$	294,240		$	439,398		$	278,162
Cash paid (refunds received) for income taxes	$	(16,640	)	$	872		$	(68,696	)

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
	ONEOK Shareholders’ Equity
	Common Stock Issued	Common Stock		Paid-in Capital			Accumulated Other Comprehensive Income (Loss)
	(Shares)	(Thousands of dollars)
January 1, 2011	245,631,272	$	2,456	$	1,391,443		$	(108,802	)
Net income	—	—		—			—
Other comprehensive income (loss)	—	—		—			(97,319		)
Repurchase of common stock	—	—		—			—
Common stock issued	178,576	2		25,742			—
Common stock dividends - $1.08 per share	—	—		—			—
Distributions to noncontrolling interests	—	—		—			—
December 31, 2011	245,809,848	2,458		1,417,185			(206,121		)
Net income	—	—		—			—
Other comprehensive income (loss)	—	—		—			(10,677		)
Repurchase of common stock	—	—		—			—
Common stock issued	1,332	—		(23,404		)	—
Common stock dividends - $1.27 per share	—	—		—			—
Issuance of common units of ONEOK Partners	—	—		(51,100		)	—
Distributions to noncontrolling interests	—	—		—			—
Other	—	—		(17,983		)	—
December 31, 2012	245,811,180	2,458		1,324,698			(216,798		)
Net income	—	—		—			—
Other comprehensive income (loss)	—	—		—			94,811
Common stock issued	—	—		(16,549		)	—
Common stock dividends - $1.48 per share	—	—		—			—
Issuance of common units of ONEOK Partners	—	—		87,295			—
Distributions to noncontrolling interests	—	—		—			—
Other	—	—		38,156			—
December 31, 2013	245,811,180	$	2,458	$	1,433,600		$	(121,987	)

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(Continued)
	ONEOK Shareholders’ Equity
	Retained Earnings			Treasury Stock			Noncontrolling Interest in Consolidated Subsidiaries			Total Equity
	(Thousands of dollars)
January 1, 2011	$	1,826,800		$	(663,274	)	$	1,472,218		$	3,920,841
Net income	360,594			—			399,150			759,744
Other comprehensive income (loss)	—			—			(32,834		)	(130,153		)
Repurchase of common stock	—			(300,108		)	—			(300,108		)
Common stock issued	—			28,059			—			53,803
Common stock dividends - $1.08 per share	(227,020		)	—			—			(227,020		)
Distributions to noncontrolling interests	—			—			(277,375		)	(277,375		)
December 31, 2011	1,960,374			(935,323		)	1,561,159			3,799,732
Net income	360,619			—			382,911			743,530
Other comprehensive income (loss)	—			—			(27,010		)	(37,687		)
Repurchase of common stock	—			(150,000		)	—			(150,000		)
Common stock issued	—			45,550			—			22,146
Common stock dividends - $1.27 per share	(261,969		)	—			—			(261,969		)
Issuance of common units of ONEOK Partners	—			—			510,687			459,587
Distributions to noncontrolling interests	—			—			(324,906		)	(324,906		)
Other	—			—			—			(17,983		)
December 31, 2012	2,059,024			(1,039,773		)	2,102,841			4,232,450
Net income	266,533			—			310,428			576,961
Other comprehensive income (loss)	—			—			21,673			116,484
Common stock issued	—			42,738			—			26,189
Common stock dividends - $1.48 per share	(304,742		)	—			—			(304,742		)
Issuance of common units of ONEOK Partners	—			—			446,529			533,824
Distributions to noncontrolling interests	—			—			(374,142		)	(374,142		)
Other	—			—			—			38,156
December 31, 2013	$	2,020,815		$	(997,035	)	$	2,507,329		$	4,845,180

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ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations - We are a diversified energy company and successor to the company founded in 1906 known as Oklahoma Natural Gas Company.  We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.”  We are the sole general partner and own 41.2 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest publicly traded master limited partnerships.

At December 31, 2013, we have divided our operations into three reportable business segments as follows:

• ONEOK Partners;

• Natural Gas Distribution; and

• Energy Services.

On January 31, 2014, we completed the separation of our natural gas distribution business into a standalone publicly traded company, ONE Gas. In addition, we expect to complete an accelerated wind down of our Energy Services business on March 31, 2014. ONEOK and its subsidiaries will continue to be the sole general partner and own 41.2 percent of ONEOK Partners as of December 31, 2013. Following the separation of the natural gas distribution business and the wind down of our energy services business, our cash flows will be derived from the cash distributions we receive from ONEOK Partners associated with our limited and general partner interests, including incentive distribution rights. See Note U for additional discussion of the separation of the natural gas distribution business. See Note B for additional discussion of the exit activities associated with the wind down of the energy services business.

ONEOK Partners is a publicly traded master limited partnership involved in the gathering, processing, storage and transportation of natural gas in the United States.  In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.  To aid in understanding the important business and financial characteristics of our ONEOK Partners segment, the following describes its business with reference to its underlying activities.

ONEOK Partners gathers and/or processes natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming, which includes the NGL-rich Frontier, Turner, Sussex and Niobrara Shale formations.  Coal-bed methane, or dry natural gas, in the Powder River Basin does not require processing or NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee. ONEOK Partners also gathers and processes natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale, Woodford Shale, Granite Wash area and the Mississippian Lime formation of Oklahoma and Kansas and the Hugoton and Central Kansas Uplift Basins of Kansas.  The natural gas ONEOK Partners gathers from its Sage Creek plant contains NGL-rich natural gas from the Niobrara Shale area of the Powder River Basin.

ONEOK Partners’ natural gas liquids business consists of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas, Texas and the Rocky Mountain region where it provides nondiscretionary services to producers for NGLs.  Its natural gas liquids business owns or has an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, Wyoming, Colorado, North Dakota and Montana, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois.  It also owns FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect its Mid-Continent assets with Midwest markets, including Chicago, Illinois.  ONEOK Partners’ natural gas liquids business also owns and operates truck- and rail-loading and -unloading facilities that interconnect with its NGL fractionation and pipeline assets.

ONEOK Partners’ natural gas pipeline business operates interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.  ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico.  ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states, including the Cana-Woodford, Woodford Shale, Granite Wash and Mississippian Lime areas.  ONEOK Partners owns underground natural gas storage facilities in Oklahoma and Texas, which are connected to its intrastate natural gas pipeline assets, as well as underground natural gas storage facilities in Kansas.

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Our former Natural Gas Distribution segment provides natural gas distribution services to more than 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. The natural gas utilities serve residential, commercial, industrial and transportation customers in all three states.  In addition, the natural gas distribution companies serve wholesale and public authority customers.

Our Energy Services segment is a provider of nonuniform natural gas supply and risk-management services for natural gas and electric utilities and industrial customers with natural gas needs.  We use a network of leased storage and transportation capacity to supply natural gas to our customers.  This network connects major supply and demand centers and, coupled with our industry knowledge and market intelligence, allows us to provide our customers with customized services in a more efficient and reliable manner than they can achieve independently. Our customers are primarily LDCs, electric utilities and industrial end-users.  Our customers’ natural gas needs vary with seasonal changes in weather and are therefore somewhat unpredictable.

Consolidation - Our consolidated financial statements include the accounts of ONEOK and our subsidiaries over which we have control or are the primary beneficiary.  We have recorded noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheets to recognize the portion of ONEOK Partners that we do not own.  We reflected our ownership interest in ONEOK Partners’ accumulated other comprehensive income (loss) in our consolidated accumulated other comprehensive income (loss).  The remaining portion is reflected as an adjustment to noncontrolling interests in consolidated subsidiaries.  All significant intercompany balances and transactions have been eliminated in consolidation. We have recast prior period amounts in the Consolidated Statements of Cash Flows to revise the classification of the excess tax benefit of share-based compensation to financing from operating activities.

Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive income. For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Impairment of equity investments is recorded when the impairments are other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment.  The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows. See Note P for disclosures of our unconsolidated affiliates.

Use of Estimates - 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 amount 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.  Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, gas purchased expense for natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances.  Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

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

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other liquid money-market instrument rates.  We also utilize internally developed basis curves that incorporate observable and unobservable market data.  We validate our valuation inputs with third-party information and settlement prices from other sources, where available.

In addition, as prescribed by the income approach, we compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from LIBOR, Eurodollar futures and interest-rate swaps.  We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner over a reasonable period of time under current market conditions.  We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitor the credit default swap markets.  Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.

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.

We recognize transfers into and out of Level 3 as of the end of each reporting period.  Transfers into Level 3 represent existing assets or liabilities that were categorized previously at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

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. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.  See Note D for additional disclosures of our fair value measurements.

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

Revenue Recognition - Our operating segments recognize revenue when services are rendered or product is delivered. ONEOK Partners’ natural gas gathering and processing operations record revenue when gas is processed in or transported through its facilities.  ONEOK Partners’ natural gas liquids operations record revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the period services are provided.  Revenue for ONEOK Partners’ natural gas pipelines and a portion of its natural gas liquids operations is recognized based upon contracted capacity and contracted volumes transported and stored under service agreements in the period services are provided.

Our former Natural Gas Distribution segment’s major industrial and commercial natural gas distribution customers are invoiced at the end of each month.  All natural gas distribution residential customers and some commercial customers are invoiced on a cyclical basis throughout the month, and the utilities accrue unbilled revenues at the end of each month.

Our revenues from sales to our Energy Services segment’s wholesale customers are accrued in the month of physical delivery based on contracted sales price and estimated volumes.  Demand payments received for requirements contracts are recognized in the period in which the service is provided.  Our fixed-price physical sales are accounted for as derivatives and are recorded at fair value.  See discussion below in “Derivative and Risk Management Activities” for additional information.

Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services rendered, net of allowances for doubtful accounts.  We assess the creditworthiness of our counterparties on an ongoing basis

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and require security, including prepayments and other forms of collateral, when appropriate.  Outstanding customer receivables are reviewed regularly for possible nonpayment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date.  At December 31, 2013 and 2012, our allowance for doubtful accounts was not material.

Inventories - The values of current natural gas and NGLs in storage are determined using the lower of weighted-average cost or market method.  Noncurrent natural gas and NGLs are classified as property and valued at cost.  Materials and supplies are valued at average cost.

Commodity Imbalances -Commodity imbalances represent amounts payable or receivable for NGL exchange contracts and natural gas pipeline imbalances and are valued at fair value.  Under the majority of our NGL exchange agreements, we physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the exchange counterparty.  In turn, we deliver NGL products back to the customer and charge them gathering and fractionation fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a net exchange receivable or payable position with the counterparties.  These net exchange receivables and payables are settled with movements of NGL products rather than with cash.  Natural gas pipeline imbalances are settled in cash or in-kind, subject to the terms of the pipelines’ tariffs or by agreement.

Derivatives 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.  The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.

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

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in earnings
Cash flow hedge	-	Recorded at fair value	-	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	-	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	-	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
Fair value hedge	-	Recorded at fair value	-	The gain or loss on the derivative instrument is recognized in earnings
	-	Change in fair value of the hedged item is recorded as an adjustment to book value	-	Change in fair value of the hedged item is recognized in earnings

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

We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item.  We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our cash flow and fair value hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis.  We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

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The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts.  All financially settled derivative instruments, as well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income.  The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and nonderivative contracts are reported on a gross basis.  Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on a gross basis.

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

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

See Notes D and E for more discussion of our fair value measurements and risk management and hedging activities using derivatives.

Property, Plant and Equipment - Our properties are stated at cost, including AFUDC.  Generally, the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation.  Gains and losses from sales or retirement of nonregulated properties or an entire operating unit or system of our regulated properties are recognized in income. Maintenance and repairs are charged directly to expense.

The interest portion of AFUDC represents the cost of borrowed funds used to finance construction activities.  We capitalize interest costs during the construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction.

Our properties are depreciated using the straight-line method over their estimated useful lives.  Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances.  We periodically conduct depreciation studies to assess the economic lives of our assets.  For our regulated assets, these depreciation studies are completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are billed.  For our nonregulated assets, if it is determined that the estimated economic life changes, the changes are made prospectively.  Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or results of operations.

Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated.  Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.

See Note F for disclosures of our property, plant and equipment.

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 Energy Services segment’s 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. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services. There were also no impairment charges resulting from our 2012 and 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

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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 and 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 in the Powder River Basin.  The reduced coal-bed methane development activities and natural production declines in the dry natural gas formation of the Powder River Basin resulted in lower volumes available to be gathered.  While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects.  Bighorn Gas Gathering, in which ONEOK Partners owns a 49 percent equity interest, has operations in the coal-bed methane areas of the Powder River Basin. Due to declines in volumes gathered on Bighorn Gas Gathering’s system, 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 estimate reasonably 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 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.

A continued decline in coal-bed methane natural gas volumes in the coal-bed methane production 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. 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

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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 F, G and P for our long-lived assets, goodwill and intangible assets and investment in unconsolidated affiliates disclosures.

Regulation - Our former natural gas distribution operations and ONEOK Partners’ intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. ONEOK Partners’ interstate natural gas and natural gas liquids pipelines are subject to regulation by the FERC.  In Kansas and Texas, natural gas storage may be regulated by the state and the FERC for certain types of services.  Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK Partners segment follow the accounting and reporting guidance for regulated operations.  During the rate-making process, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time, as opposed to expensing such costs as incurred. Examples include costs for fuel and fuel losses, acquisition costs and contributions in aid of construction. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery.  Actions by regulatory authorities could have an effect on the amount recovered from rate payers.  Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action.  A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer:

• established by independent, third-party regulators;

• designed to recover the specific entity’s costs of providing regulated services; and

• set at levels that will recover our costs when considering the demand and competition for our services.

In December 2013, the KCC approved a settlement agreement for the separation of our Kansas Gas Service natural gas distribution business to ONE Gas from ONEOK. The terms of the settlement agreement provided that amounts previously recorded as a regulatory asset related to ONEOK’s acquisition of Kansas Gas Service in 1997 would no longer be recovered in rates. As a result, the carrying amount of the regulatory asset was written off, and we recorded a noncash charge to income of approximately $10.2 million in the fourth quarter 2013.

At December 31, 2013 and 2012, we recorded regulatory assets of approximately $383.6 million and $585.0 million, respectively, which are being recovered or are expected to be recovered as a result of various approved rate proceedings.  Of these amounts, the total regulatory assets related to our natural gas distribution business were $376.8 million and $577.1 million at December 31, 2013 and 2012, respectively. The natural gas distribution balances included approximately $341.1 million and $499.4 million related to our pension and postretirement benefit plans at December 31, 2013 and 2012, respectively, which are discussed in Note N.  Regulatory assets are being recovered as a result of approved rate proceedings over varying time periods up to 25 years.  These assets are reflected in other assets on our Consolidated Balance Sheets.

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 N for more discussion of pension and postretirement employee benefits.

Income Taxes - Deferred income taxes are recorded for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse.  The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas, if, as a result of an action by a regulator, it is probable that the effect of the change in tax rates will be recovered from or returned to customers through future rates.  For all other operations, the effect is recognized in income in the period that includes the enactment date.  We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.

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We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return.  We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute.  During 2013, 2012 and 2011, our tax positions did not require an establishment of a material reserve.

We file numerous consolidated and separate income tax returns with federal tax authorities of the United States and Canada, along with the tax authorities of several states.  There are no United States federal audits or statute waivers at this time. See Note O for additional discussion of income taxes.

Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.  Certain long-lived assets that comprise our natural gas distribution systems and ONEOK Partners’ natural gas gathering and processing, natural gas liquids and pipeline facilities are subject to agreements or regulations that give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the assets. We recognize the fair value of a liability for an asset-retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made.  We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our and ONEOK Partners’ assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. We expect our former natural gas distribution assets and ONEOK Partners’ pipeline assets, for which we are unable to estimate reasonably the fair value of the asset retirement obligation, will continue to operate as long as natural gas supply and demand for natural gas and natural gas liquids exists. Based on the widespread use of natural gas for heating and cooking activities by residential users and electric-power generation by commercial users, as well as use of natural gas liquids by the petrochemical industry, we and ONEOK Partners expect supply and demand to exist for the foreseeable future.

For our assets where we are able to make an estimate, the fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset.  The liability is accreted at the end of each period through charges to operating expense.  If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.  The depreciation and accretion expense are immaterial to our consolidated financial statements.

In accordance with long-standing regulatory treatment, we collect, through rates, the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs collected through our rates include costs attributable to legal and nonlegal removal obligations; however, the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory liability for financial reporting purposes. Historically, with the exception of the regulatory authority in Kansas, the regulatory authorities that have jurisdiction over our regulated operations have not required us to quantify or disclose this amount; rather, these costs are addressed prospectively in depreciation rates and are set in each general rate order. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our jurisdictions; however, for financial reporting purposes, significant uncertainty exists regarding the future disposition of this regulatory liability, pending, among other issues, clarification of regulatory intent.  We continue to monitor the regulatory requirements, and the liability may be adjusted as more information is obtained.  We record the estimated asset removal obligation in noncurrent liabilities in other deferred credits on our Consolidated Balance Sheets.  To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on earnings.

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 estimated reasonably.  We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates 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.  Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.  See Note R for additional discussion of contingencies.

Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures.  We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.

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Earnings per Common Share - Basic EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period.  Diluted EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period plus potentially dilutive components.  The dilutive components are calculated based on the dilutive effect for each quarter.  For fiscal-year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.

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

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires presentation in a single location, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source.  We adopted this guidance with our March 31, 2013, Quarterly Report, and it did not impact our financial position or results of operations. See Note K for additional disclosures.

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

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” which increases disclosures about offsetting assets and liabilities. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards related to the offsetting of financial instruments, including derivatives. The existing GAAP guidance allowing balance sheet offsetting remains unchanged. This guidance was effective for interim and annual periods beginning on January 1, 2013, and was applied retrospectively for all comparative periods presented. The adoption of this guidance beginning with our March 31, 2013, Quarterly Report did not affect our financial condition, results of operations or cash flows.

B. EXIT ACTIVITIES

Wind down of Energy Services Business - In June 2013, we announced we would exit the operations of our Energy Services segment through an accelerated wind down process. Our Energy Services segment has faced challenging industry conditions that show no signs of improving. Increased natural gas supply and infrastructure, coupled with lower natural gas price volatility and narrowed seasonal and location natural gas price differentials, has resulted in limited opportunities to generate revenues to cover our fixed costs on our contracted storage and transportation capacity. We executed agreements in 2013 to release a significant portion of our nonaffiliated natural gas transportation and storage contracts to third parties between July 1 and December 31, 2013, at current market rates that resulted in noncash charges of $138.6 million. In addition, pursuant to a request for proposal, our Energy Services segment assigned contracts for 18.0 Bcf of affiliated storage capacity to our Natural Gas Distribution segment in June 2013. Our Energy Services segment will continue to serve its existing contracted premium-services customers during the wind down, and we expect the Energy Services segment to be classified as discontinued operations, effective April 1, 2014, when substantially all operations of the segment have ceased.

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

	Year Ended
	December 31, 2013
	(Millions of dollars)
Beginning balance	$	—
Noncash charges	138.6
Settlements	(17.7		)
Accretion	1.1
Ending balance	$	122.0

We recorded these noncash charges in cost of sales and fuel in our Consolidated Statements of Income. We expect to record an additional noncash charge of approximately $1.7 million before taxes in the first quarter 2014, to reflect the assignment of our remaining natural gas storage contract that extends beyond March 31, 2014. We do not expect the total charge attributable to any severance benefits will be material. We expect future cash payments associated with released transportation and storage capacity from the wind down of our Energy Services segment to total approximately $80 million on an after-tax basis, which consist of approximately $33 million paid in 2014, $24 million in 2015, $13 million in 2016, and $10 million during the period from 2017 through 2023.

C. DISCONTINUED OPERATIONS

On February 1, 2012, we sold ONEOK Energy Marketing Company, our Natural Gas Distribution segment’s retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital.  We received net proceeds of approximately $32.9 million and recognized a gain on the sale of approximately $13.5 million, net of taxes of $8.3 million. The proceeds from the sale were used to reduce short-term borrowings.  The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Annual Report.  All prior periods presented have been recast to reflect the discontinued operations.

The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated:

	One Month Ended			Year Ended
	January 31,			December 31,
	2012			2011
	(Thousands of dollars)
Revenues	$	27,607		$	313,371
Cost of sales and fuel	25,961			302,561
Net margin	1,646			10,810
Operating costs	408			7,147
Depreciation and amortization	8			128
Operating income	1,230			3,535
Other income (expense), net	—			(50		)
Income taxes	(468		)	(1,255		)
Income from discontinued operations, net	$	762		$	2,230

Separation of Natural Gas Distribution Business - On January 31, 2014, we completed the separation of our natural gas distribution business into a standalone publicly traded company, ONE Gas.  ONE Gas consists of ONEOK’s former Natural Gas Distribution segment that includes Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service.  The Natural Gas Distribution segment was classified as discontinued operations, effective February 1, 2014. See additional discussion in Note U of the Notes to the Consolidated Financial Statements.

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D. FAIR VALUE MEASUREMENTS

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

	December 31, 2013
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	4,477		$	647		$	3,094		$	8,218		$	(2,850	)	$	5,368
Physical contracts	—			4			1,764			1,768			(1,157		)	611
Interest-rate contracts	—			54,503			—			54,503			—			54,503
Total derivative assets	4,477			55,154			4,858			64,489			(4,007		)	60,482
Fair value of firm commitments (b)	—			—			599			599			—			599
Available-for-sale investment securities (b)	1,569			—			—			1,569			—			1,569
Total assets	$	6,046		$	55,154		$	5,457		$	66,657		$	(4,007	)	$	62,650
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(7,624	)	$	(776	)	$	(3,435	)	$	(11,835	)	$	10,767		$	(1,068	)
Physical contracts	—			(4		)	(4,117		)	(4,121		)	1,157			(2,964		)
Total derivative liabilities	$	(7,624	)	$	(780	)	$	(7,552	)	$	(15,956	)	$	11,924		$	(4,032	)

(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2013, we held no cash collateral and had posted $15.7 million of cash collateral with various counterparties.

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

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	December 31, 2012
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	69,957		$	10,780		$	7,107		$	87,844		$	(51,602	)	$	36,242
Physical contracts	—			2,083			2,032			4,115			(151		)	3,964
Interest-rate contracts	—			10,923			—			10,923			—			10,923
Total derivative assets	69,957			23,786			9,139			102,882			(51,753		)	51,129
Trading securities (b)	5,978			—			—			5,978			—			5,978
Available-for-sale investment securities (c)	2,027			—			—			2,027			—			2,027
Total assets	$	77,962		$	23,786		$	9,139		$	110,887		$	(51,753	)	$	59,134
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(35,172	)	$	(1,737	)	$	(7,177	)	$	(44,086	)	$	33,878		$	(10,208	)
Physical contracts	—			—			(279		)	(279		)	151			(128		)
Total derivative liabilities	(35,172		)	(1,737		)	(7,456		)	(44,365		)	34,029			(10,336		)
Fair value of firm commitments (d)	—			—			(1,280		)	(1,280		)	—			(1,280		)
Total liabilities	$	(35,172	)	$	(1,737	)	$	(8,736	)	$	(45,645	)	$	34,029		$	(11,616	)

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

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

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

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

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

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

Our Level 3 fair value amounts are based on inputs that may include one or more unobservable inputs including internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties.  We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes.  These balances categorized as Level 3 are comprised of derivatives for natural gas and NGLs.  Also included in Level 3 are the fair values of firm commitments.  We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material.  The significant unobservable inputs used are the unpublished forward basis and index curves.  Significant increases or decreases in either of those inputs in isolation would not have a material impact on our fair value measurements.

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

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2013	$	1,683		$	(1,280	)	$	403
Total realized/unrealized gains (losses):
Included in earnings (a)	(5,627		)	1,879			(3,748		)
Included in other comprehensive income (loss)	800			—			800
Settlements	450			—			450
December 31, 2013	$	(2,694	)	$	599		$	(2,095	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2013 (a)	$	(804	)	$	670		$	(134	)

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

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)	(13,503		)	6,003			(7,500		)
Included in other comprehensive income (loss)	(5,587		)	—			(5,587		)
Sale of discontinued operations	(3,636		)	—			(3,636		)
Transfers out of Level 3	(695		)	—			(695		)
December 31, 2012	$	1,683		$	(1,280	)	$	403
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2012 (a)	$	1,971		$	(112	)	$	1,859

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

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

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

Other Financial Instruments -The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and notes payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1.  Our notes payable are classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market.

The estimated fair value of our consolidated long-term debt, including current maturities, was $8.2 billion and $7.5 billion at December 31, 2013 and 2012, respectively.  The book value of long-term debt, including current maturities, was $7.8 billion and $6.5 billion at December 31, 2013 and 2012, respectively.  The estimated fair value of the aggregate of ONEOK’s and ONEOK Partners’ senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities.  The estimated fair value of our consolidated long-term debt is classified as Level 2.

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E. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Our Energy Services and ONEOK Partners segments are exposed to various risks that we manage by periodically entering into derivative instruments. In June 2013, we announced we will exit the operations of our Energy Services segment. As a result, the use of derivative instruments will decrease significantly within our Energy Services segment. See Note C for additional information. These risks include the following:

• Commodity-price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate.  We use commodity derivative instruments such as futures, physical-forward contracts, swaps and options to mitigate the commodity-price risk associated with a portion of the forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage.  Commodity-price volatility may have a significant impact on the fair value of our derivative instruments as of a given date;

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

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

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

• Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;

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

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

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

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

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

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

• reducing our exposure to fluctuations in interest rates; and

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

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

Our former Natural Gas Distribution segment also used derivative instruments to hedge the cost of a portion of anticipated natural gas purchases during the winter heating months to protect our customers from upward volatility in the market price of natural gas. The use of these derivative instruments and the associated recovery of these costs have been approved by the OCC, KCC and regulatory authorities in certain Texas jurisdictions.

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

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

	December 31, 2013						December 31, 2012
	Fair Values of Derivatives (a)						Fair Values of Derivatives (a)
	Assets			(Liabilities)			Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	8,011	(b)	$	(10,573	)	$	47,516	(c)	$	(4,885	)
Physical contracts	1,064			(3,463		)	56			(126		)
Interest-rate contracts	54,503			—			10,923			—
Total derivatives designated as hedging instruments	63,578			(14,036		)	58,495			(5,011		)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts	202			(1,262		)	24,970			(25,009		)
Physical contracts	704			(658		)	4,059			(153		)
Trading instruments
Financial contracts	5			—			15,358			(14,192		)
Total derivatives not designated as hedging instruments	911			(1,920		)	44,387			(39,354		)
Total derivatives	$	64,489		$	(15,956	)	$	102,882		$	(44,365	)

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

(b) - Includes $5.8 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive income (loss).

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

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

		December 31, 2013				December 31, 2012
	Contract Type	Purchased/ Payor		Sold/ Receiver		Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
-Natural gas (Bcf)	Futures, forwards and swaps	—		(65.0	)	—		(85.1	)
-Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	—		(4.0	)	—		(1.1	)
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	—		(57.4	)	—		(56.3	)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	400.0	—		$	400.0	—
Fair value hedges
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	1.1		(1.1	)	59.1		(59.1	)
Derivatives not designated as hedging instruments:
Fixed price
-Natural gas (Bcf)	Futures, forwards and swaps	5.8		(9.7	)	60.7		(60.4	)
	Options	—		—		102.1		(100.8	)
-Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	0.3		(0.3	)	—		—
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	8.5		(11.2	)	80.2		(81.7	)
Index
-Natural gas (Bcf)	Futures, forwards and swaps	1.8		—		20.3		(22.3	)

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

Cash Flow Hedges -Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas.  Accumulated other comprehensive income (loss) at December 31, 2013, includes losses of approximately $5.8 million, net of tax, related to these hedges that will be recognized within the next 24 months as the forecasted transactions affect earnings.  If prices remain at current levels, we will recognize $7.0 million in net losses over the next 12 months and net gains of $1.2 million thereafter.  The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $49.6 million, net of tax, which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $5.3 million, net of tax, will be reclassified into earnings during the next 12 months as the hedged items affect earnings. The remaining amounts in accumulated other comprehensive income (loss) are attributable primarily to ONEOK Partners’ forward-starting interest-rate swaps with settlement dates greater than 12 months, which will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of ONEOK Partners debt.

For the year ended December 31, 2013, cost of sales and fuel in our Consolidated Statements of Income includes $10.1 million reflecting an adjustment to natural gas inventory at the lower of cost or market value. We reclassified $8.0 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings. For the year ended December 31, 2012, net margin in our Consolidated Statement of Income included losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas.  As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial

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contracts exceeded the amount expected to be recovered through sales of that inventory after considering related sales hedges, which required reclassification of the loss from accumulated other comprehensive loss to current period earnings. In 2011, cost of sales and fuel in our Consolidated Statements of Income included $91.1 million, reflecting an adjustment to natural gas inventory at the lower of cost or market value.  We also reclassified $91.1 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.

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

Derivatives in Cash Flow Hedging Relationships	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Commodity contracts	$	(15,433	)	$	62,898		$	117,508
Interest-rate contracts	46,616			(29,471		)	(128,666		)
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	31,183		$	33,427		$	(11,158	)

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

	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships		Years Ended December 31,
		2013			2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	19,049		$	140,862		$	48,601
Commodity contracts	Cost of sales and fuel	(14,320		)	(73,881		)	89,618
Interest-rate contracts	Interest expense	(14,560		)	(7,155		)	(480		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(9,831	)	$	59,826		$	137,739

Ineffectiveness related to our cash flow hedges was not material for the years ended December 31, 2013, 2012 and 2011.  In the event that it becomes probable that a forecasted transaction will not occur, we will discontinue cash flow hedge treatment, which will affect earnings.  For the year ended December 31, 2013, we recorded immaterial gains due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable. For the years ended December 31, 2012 and 2011, there were no gains or losses due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable.

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

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	Years Ended December 31,
		2013				2012		2011
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	(2,051	)		$	2,413	$	1,796
Commodity contracts - non-trading (a)	Cost of sales and fuel	(2,266		)	(b)	5,956		16,178
Total gain (loss) recognized in income on derivatives		$	(4,317	)		$	8,369	$	17,974

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

(b) - Includes losses of $2.2 million for the year ended December 31, 2013, on certain derivatives derecognized that were designated previously as fair value hedges of firm transportation commitments that no longer meet the definition of a firm commitment.

Our former Natural Gas Distribution segment held natural gas call options with fair values of $8.7 million and $1.8 million at December 31, 2013 and 2012, respectively.  The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism.  We recorded losses of $4.5 million, $5.9 million and $14.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, which are deferred as part of our unrecovered purchased-gas costs.

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Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements that had been designated as fair value hedges. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged.  Interest expense savings from the amortization of terminated swaps for 2013, 2012 and 2011, were $1.7 million, $1.7 million and $4.3 million, respectively.

Our Energy Services segment uses basis swaps to hedge the fair value of location price differentials related to certain firm transportation commitments.  Cost of sales and fuel in our Consolidated Statements of Income includes losses of $1.4 million, and gains of $0.4 million and $14.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, related to the change in fair value of derivatives designated as fair value hedges.  Revenues include gains of $1.6 million and $0.5 million, and losses of $13.8 million for the years ended December 31, 2013, 2012 and 2011, respectively, to recognize the change in fair value of the related hedged firm commitments.  The ineffectiveness related to these hedges was not material for the years ended December 31, 2013, 2012 and 2011.

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

Some of our derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s.  If our credit ratings on senior unsecured long-term debt were to decline below investment-grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position as of December 31, 2013, was $1.1 million.  On February 3, 2014, S&P reduced our credit rating below investment grade as a result of the ONE Gas separation. Moody’s also downgraded our credit rating; however, our credit rating with Moody’s remained investment-grade.

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

At December 31, 2013, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial services sector.

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F. PROPERTY, PLANT AND EQUIPMENT

The following table sets forth our property, plant and equipment by property type, for the periods indicated:

	Estimated Useful Lives (Years)	December 31, 2013			December 31, 2012
		(Thousands of dollars)
Non-Regulated
Gathering pipelines and related equipment	5 to 40	$	2,173,271		$	1,638,037
Processing and fractionation and related equipment	5 to 40	2,295,983			1,625,146
Storage and related equipment	5 to 54	362,704			335,237
Transmission pipelines and related equipment	22 to 54	302,718			311,038
General plant and other	2 to 60	402,523			348,636
Construction work in process	—	1,112,182			881,788
Regulated
Natural gas distribution pipelines and related equipment	15 to 80	3,703,593			3,512,660
Storage and related equipment	5 to 54	135,922			136,938
Natural gas transmission pipelines and related equipment	5 to 77	1,850,559			1,796,683
Natural gas liquids transmission pipelines and related equipment	5 to 80	2,049,461			1,490,511
General plant and other	2 to 85	324,703			309,119
Construction work in process	—	822,537			703,198
Property, plant and equipment		15,536,156			13,088,991
Accumulated depreciation and amortization - non-regulated		(1,112,192		)	(954,398		)
Accumulated depreciation and amortization - regulated		(2,126,460		)	(2,020,253		)
Net property, plant and equipment		$	12,297,504		$	10,114,340

The average depreciation rates for our regulated property are set forth, by segment, in the following table for the periods indicated:

	Years Ended December 31,
Regulated Property	2013	2012	2011
ONEOK Partners	2.0% - 2.2%	1.9% - 2.2%	1.9% - 2.2%
Natural Gas Distribution	2.0% - 3.0%	2.0% - 3.0%	2.0% - 2.9%

We and ONEOK Partners incurred liabilities for construction work in process that had not been paid at December 31, 2013, 2012 and 2011 of $237.2 million, $228.5 million and $155.7 million, respectively. Such amounts are not included in capital expenditures (less allowance for equity funds used during construction) on the Consolidated Statements of Cash Flows.

G. GOODWILL AND INTANGIBLE ASSETS

Goodwill - The following table sets forth our goodwill by segment for the periods indicated:

	ONEOK Partners		Natural Gas Distribution		Energy Services		Total
	(Thousands of dollars)
December 31, 2012	$	433,535	$	157,953	$	—	$	591,488
Acquisitions	92,000		—		—		92,000
December 31, 2013	$	525,535	$	157,953	$	—	$	683,488

As a result of our 2012 interim impairment assessment of our Energy Services segment’s goodwill, 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. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services. There were no impairment charges resulting from our 2013 or 2011 annual impairment tests.

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Intangible Assets - The following table sets forth the gross carrying amount and accumulated amortization of intangible assets for the periods indicated:

	December 31,			December 31,
	2013			2012
	(Thousands of dollars)
Gross intangible assets	$	565,215		$	462,214
Accumulated amortization	(66,188		)	(57,496		)
Net intangible assets	$	499,027		$	404,718

At December 31, 2013 and 2012, our ONEOK Partners segment has $343.5 million and $249.2 million, respectively, of intangible assets related primarily to contracts acquired through acquisition, which are being amortized over a period of 20 to 40 years.  The remaining intangible asset balance has an indefinite life.  Amortization expense for intangible assets for 2013, 2012 and 2011 was $8.7 million, $7.7 million and $7.7 million, respectively, and the aggregate amortization expense for each of the next five years is estimated to be approximately $11.3 million.

Acquisition - On September 30, 2013, ONEOK Partners completed the acquisition of a business, the Sage Creek acquisition. Included in this acquisition were supply contracts with acreage dedications and customer relationships that were included as intangible assets of $103 million in the purchase price allocation. The $92 million excess of purchase price over the fair value of the identifiable assets acquired was recorded as goodwill. For additional information related to the acquisition, see Note Q of the Notes to Consolidated Financial Statements in this Annual Report.

H. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK Credit Agreement - At December 31, 2013, the ONEOK Credit Agreement contained certain financial, operational and legal covenants.  Among other things, these covenants included maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 67.5 percent at the end of any calendar quarter, limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets, a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners, and a limit on new investments in master limited partnerships. The ONEOK Credit Agreement also contained customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends.  The debt covenant calculations in the ONEOK Credit Agreement excluded the debt of ONEOK Partners.  In the event of a breach of certain covenants by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become due and payable immediately. At December 31, 2013, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 48.3 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

At December 31, 2013, ONEOK had $564.5 million of commercial paper outstanding and $2.2 million in letters of credit issued. ONEOK is terminating its commercial paper program in conjunction with the separation of its natural gas distribution business.

The weighted-average interest rate on ONEOK’s short-term debt outstanding was 0.39 percent and 0.46 percent at December 31, 2013 and 2012, respectively.

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. This 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.

This amendment 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, as amended, ONEOK may request an increase 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 rating, borrowings, if any, will accrue at LIBOR plus 125 basis points, and the annual facility fee is 25 basis points.

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ONEOK Partners Credit Agreement - The ONEOK Partners Credit Agreement is available for general partnership purposes, including repayment of ONEOK Partners’ commercial paper notes, if necessary. Amounts outstanding under ONEOK Partners’ commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement. At December 31, 2013, ONEOK Partners had no commercial paper outstanding, no letters of credit issued and no borrowings under the ONEOK Partners Credit Agreement.

In December 2013, ONEOK Partners amended and restated the ONEOK Partners Credit Agreement effective on January 31, 2014, to increase the size of the facility to $1.7 billion from $1.2 billion. 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 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 ONEOK Partners Credit Agreement are nonrecourse to ONEOK.

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 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 on September 30, 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 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.

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

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 include maintaining ONE Gas’s 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.

Upon completion of the separation on January 31, 2014, ONEOK’s obligations related to the ONE Gas Credit Agreement terminated.

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I. LONG-TERM DEBT

All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.  The following table sets forth our long-term debt for the periods indicated:

	December 31,			December 31,
	2013			2012
	(Thousands of dollars)
ONEOK
$400,000 at 5.2% due 2015	$	400,000		$	400,000
$700,000 at 4.25% due 2022	700,000			700,000
$100,000 at 6.5% due 2028	87,649			87,662
$100,000 at 6.875% due 2028	100,000			100,000
$400,000 at 6.0% due 2035	400,000			400,000
Other	1,323			1,528
Total ONEOK senior notes payable	1,688,972			1,689,190
ONEOK Partners
$650,000 at 3.25% due 2016	650,000			650,000
$450,000 at 6.15% due 2016	450,000			450,000
$400,000 at 2.0% due 2017	400,000			400,000
$425,000 at 3.2% due 2018	425,000			—
$500,000 at 8.625% due 2019	500,000			500,000
$900,000 at 3.375 % due 2022	900,000			900,000
$425,000 at 5.0 % due 2023	425,000			—
$600,000 at 6.65% due 2036	600,000			600,000
$600,000 at 6.85% due 2037	600,000			600,000
$650,000 at 6.125% due 2041	650,000			650,000
$400,000 at 6.2% due 2043	400,000			—
Guardian Pipeline
Average 7.85%, due 2022	67,208			74,857
Total ONEOK Partners senior notes payable	6,067,208			4,824,857
Total long-term notes payable	7,756,180			6,514,047
Unamortized portion of terminated swaps	25,340			27,058
Unamortized debt discount	(15,889		)	(14,878		)
Current maturities	(10,656		)	(10,855		)
Long-term debt	$	7,754,975		$	6,515,372

The aggregate maturities of long-term debt outstanding for the years 2014 through 2018 are shown below:

	ONEOK		ONEOK Partners		Guardian Pipeline		Total
	(Millions of dollars)
2014	$	3.0	$	—	$	7.7	$	10.7
2015	$	403.0	$	—	$	7.7	$	410.7
2016	$	3.0	$	1,100.0	$	7.7	$	1,110.7
2017	$	3.0	$	400.0	$	7.7	$	410.7
2018	$	3.0	$	425.0	$	7.7	$	435.7

Additionally, our senior notes due 2028 (6.5 percent) are callable at par at our option from now until maturity.

ONE Gas Debt Issuance - In January 2014, ONE Gas completed a private placement of three series of senior notes aggregating $1.2 billion, consisting of $300 million of five-year senior notes at 2.07 percent; $300 million of 10-year senior notes at 3.61 percent; and $600 million of 30-year senior notes at 4.658 percent. ONE Gas received approximately $1.19 billion from the offering, net of issuance costs.

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ONEOK Debt Repayment - ONE Gas made a cash payment to ONEOK of approximately $1.13 billion from the proceeds of the ONE Gas senior notes offering. In February 2014, we retired approximately $152.5 million of the 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, including accrued but unpaid interest to the redemption date.

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 Covenants - The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full. 

ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest.  ONEOK may redeem the remaining balance of its 4.25 percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

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

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

ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid

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

ONEOK Partners’ Debt Guarantee - ONEOK Partners’ senior notes are guaranteed on a senior unsecured basis by the Intermediate Partnership.  The Intermediate Partnership’s guarantee is full and unconditional, subject to certain customary automatic release provisions.  The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.  ONEOK Partners, L.P. has no significant assets or operations other than its investment in the Intermediate Partnership, which is also consolidated.  At December 31, 2013, the Intermediate Partnership held the equity of ONEOK Partners’ subsidiaries, as well as a 50 percent interest in Northern Border Pipeline.  ONEOK Partners’ long-term debt is nonrecourse to ONEOK.

Guardian Pipeline Senior Notes - These senior notes were issued under a master shelf agreement dated November 8, 2001, with certain financial institutions.  Principal payments are due quarterly through 2022. These senior notes contain financial covenants that require the maintenance of certain ratios defined in the master shelf agreement based on Guardian Pipeline’s financial position and results of operations.  Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately.  At December 31, 2013, Guardian Pipeline was in compliance with its financial covenants.

Interest-rate Swaps - See Note E for a discussion of our interest-rate swaps.

Other - We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.

J. EQUITY

Series A and B Convertible Preferred Stock - There are no shares of Series A or Series B Preferred Stock currently issued or outstanding.

Series C Preferred Stock - The Series C Preferred Stock (Series C) was issuable in connection with our now expired ONEOK Rights Agreement, which was designed to protect our shareholders from coercive or unfair takeover tactics.  No shares of Series C were issued, and the ONEOK Rights Agreement expired February 4, 2013, and was not renewed.

Common Stock - At December 31, 2013, we had approximately 362.4 million shares of authorized and unreserved common stock available for issuance.

Dividends - Dividends paid totaled $304.7 million, $262.0 million and $227.0 million for 2013, 2012 and 2011, respectively. The following table sets forth the quarterly dividends per share declared and paid on our common stock for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
First Quarter	$	0.36	$	0.305	$	0.26
Second Quarter	$	0.36	$	0.305	$	0.26
Third Quarter	$	0.38	$	0.33	$	0.28
Fourth Quarter	$	0.38	$	0.33	$	0.28
Total	$	1.48	$	1.27	$	1.08

Additionally, a quarterly dividend of $0.40 per share was declared in January 2014, payable in the first quarter 2014.

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Stock Repurchase Program - Our three-year stock repurchase program, which expired on December 31, 2013, was authorized by our Board of Directors in October 2010 to buy up to $750 million of our common stock.  We executed a $300 million repurchase of approximately 8.6 million shares in 2011, a $150 million repurchase of approximately 3.4 million shares in September 2012 and did not repurchase any shares of our common stock in 2013.

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

K. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	Unrealized Gains (Losses) on Energy Marketing and Risk-Management Assets/Liabilities (a)			Unrealized Holding Gains (Losses) on Investment Securities (a)			Pension and Postretirement Benefit Plan Obligations (a)			Accumulated Other Comprehensive Income (Loss) (a)
	(Thousands of dollars)
January 1, 2012	$	(55,367	)	$	987		$	(151,741	)	$	(206,121	)
Other comprehensive income (loss) before reclassifications	16,709			47			(47,004		)	(30,248		)
Amounts reclassified from accumulated other comprehensive income (loss)	(16,372		)	—			35,943			19,571
Other comprehensive income (loss) attributable to ONEOK	337			47			(11,061		)	(10,677		)
December 31, 2012	(55,030		)	1,034			(162,802		)	(216,798		)
Other comprehensive income (loss) before reclassifications	8,842			(177		)	37,144			45,809
Amounts reclassified from accumulated other comprehensive income (loss)	3,020			—			45,982			49,002
Other comprehensive income (loss) attributable to ONEOK	11,862			(177		)	83,126			94,811
December 31, 2013	$	(43,168	)	$	857		$	(79,676	)	$	(121,987	)

(a) All amounts are presented net of tax.

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The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) on our Consolidated Statements of Income for the period indicated:

Details about Accumulated Other Comprehensive Income (Loss) Components	Year Ended December 31, 2013			Affected Line Item in the Consolidated Statements of Income
	(Thousands of dollars)
Unrealized (gains) losses on energy marketing and risk- management assets/liabilities
Commodity contracts	$	(19,049	)	Revenues
Commodity contracts	14,320			Cost of sales and fuel
Interest-rate contracts	14,560			Interest expense
	9,831			Income before income taxes
	(1,905		)	Income tax expense
	7,926			Net income
Noncontrolling interest	4,906			Less: Net income attributable to noncontrolling interest
	$	3,020		Net income attributable to ONEOK
Pension and postretirement benefit plan obligations (a)
Amortization of net loss	$	78,887
Amortization of unrecognized prior service cost	(5,522		)
Amortization of unrecognized net asset at adoption	284
Settlement charge	1,338
	74,987			Income before income taxes
	(29,005		)	Income tax expense
	$	45,982		Net income attributable to ONEOK
Total reclassifications for the period attributable to ONEOK	$	49,002		Net income attributable to ONEOK

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

L. EARNINGS PER SHARE

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

	Year Ended December 31, 2013
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	266,533	206,044	$	1.29
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		3,651
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	266,533	209,695	$	1.27

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	Year Ended December 31, 2012
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	346,340	206,140	$	1.68
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		4,570
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	346,340	210,710	$	1.64

	Year Ended December 31, 2011
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	358,364	209,344	$	1.71
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		5,154
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	358,364	214,498	$	1.67

There were no option shares excluded from the calculation of diluted EPS for 2013, 2012 and 2011.

M. SHARE-BASED PAYMENTS

The ONEOK, Inc. Equity Compensation Plan (ECP) and the ONEOK, Inc. Long-Term Incentive Plan (LTIP) provide for the granting of stock-based compensation, including incentive stock options, nonstatutory stock options, stock bonus awards, restricted stock awards, restricted stock-unit awards, performance stock awards and performance-unit awards to eligible employees and the granting of stock awards to nonemployee directors. We have reserved 10.0 million and 15.6 million shares of common stock for issuance under the ECP and LTIP, respectively. At December 31, 2013, we had approximately 2.0 million and 0.9 million shares available for issuance under the ECP and LTIP, respectively, which reflect shares issued and estimated shares expected to be issued upon vesting of outstanding awards granted under these plans, less forfeitures.  These plans allow for the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code section 409A requirements.

Restricted Stock Units - We have granted restricted stock units to key employees that vest over a three-year period and entitle the grantee to receive shares of our common stock.  Restricted stock unit awards are measured at fair value as if they were vested and issued on the grant date, reduced by expected dividend payments and adjusted for estimated forfeitures. No dividends were paid prior to vesting on the restricted stock units granted prior to 2013.  Beginning in 2013, restricted stock unit awards granted accrue dividend equivalents in the form of additional restricted stock units prior to vesting. Compensation expense is recognized on a straight-line basis over the vesting period of the award.

Performance-Unit Awards -We have granted performance-unit awards to key employees.  The shares of our common stock underlying the performance units vest at the expiration of a period determined by the Executive Compensation Committee if certain performance criteria are met by the company.  Outstanding performance units vest at the expiration of a three-year period.  Upon vesting, a holder of performance units is entitled to receive a number of shares of our common stock equal to a percentage (0 percent to 200 percent) of the performance units granted, based on our total shareholder return over the vesting period, compared with the total shareholder return of a peer group of other energy companies over the same period. Compensation expense is recognized on a straight-line basis over the period of the award.

If paid, the outstanding performance unit awards entitle the grantee to receive the grant in shares of our common stock.  Our outstanding performance unit awards are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market condition is satisfied.  The fair value of these performance units was estimated on the grant date based on a Monte Carlo model. No dividends were paid prior to vesting on performance stock units granted prior to

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2013. Beginning in 2013, performance stock unit awards granted accrue dividend equivalents in the form of additional performance units prior to vesting. The compensation expense on these awards only will be adjusted for changes in forfeitures.

Options - No stock options have been granted since 2003. Stock option activity was not material in 2013, 2012 and 2011. All previously issued stock options expired or were exercised as of February 2013.

Stock Compensation Plan for Non-Employee Directors

The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) provides for the granting of stock options, stock bonus awards, including performance-unit awards, restricted stock awards and restricted stock unit awards. Under the DSCP, these awards may be granted by the Executive Compensation Committee at any time, until grants have been made for all shares authorized under the DSCP.  We have reserved a total of 1.4 million shares of common stock for issuance under the DSCP, and at December 31, 2013, we had approximately 1.0 million shares available for issuance under the plan. The maximum number of shares of common stock that can be issued to a participant under the DSCP during any year is 40,000. No performance unit awards or restricted stock awards have been made to nonemployee directors under the DSCP.

General

For all awards outstanding, we used a 3 percent forfeiture rate based on historical forfeitures under our share-based payment plans. We primarily use treasury stock to satisfy our share-based payment obligations.

Compensation cost expensed for our share-based payment plans described above was $28.6 million, $22.6 million and $40.7 million during 2013, 2012 and 2011, respectively, which is $17.6 million, $14.2 million and $25.7 million, net of tax benefits, respectively. Capitalized share-based compensation cost was not material for 2013, 2012 and 2011.

Cash received from the exercise of awards under all share-based payment arrangements was not material for 2013, 2012 and 2011.  The tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements was not material for 2013, 2012 and 2011.

Restricted Stock Unit Activity

As of December 31, 2013, we had $9.3 million of total unrecognized compensation cost related to our nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 1.7 years years.  The following tables set forth activity and various statistics for our restricted stock unit awards:

	Number of Shares		Weighted Average Price
Nonvested December 31, 2012	1,020,600		$	27.21
Granted	167,301		$	47.46
Released to participants	(384,883	)	$	19.06
Forfeited	(26,422	)	$	37.23
Nonvested December 31, 2013	776,596		$	35.27

	2013		2012		2011
Weighted-average grant date fair value (per share)	$	47.46	$	36.65	$	28.50
Fair value of shares granted (thousands of dollars)	$	7,940	$	11,030	$	11,728

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Performance-Unit Activity

As of December 31, 2013, we had $22.5 million of total unrecognized compensation cost related to the nonvested performance-unit awards, which is expected to be recognized over a weighted-average period of 1.7 years.  The following tables set forth activity and various statistics related to the performance-unit awards and the assumptions used in the valuations of the 2013, 2012 and 2011 grants at the grant date:

	Number of Units		Weighted Average Price
Nonvested December 31, 2012	2,133,157		$	32.74
Granted	377,200		$	52.34
Released to participants	(801,354	)	$	24.05
Forfeited	(56,858	)	$	42.53
Nonvested December 31, 2013	1,652,145		$	41.10

	2013	2012	2011
Volatility (a)	22.27%	27.00%	39.91%
Dividend Yield	3.04%	2.86%	3.30%
Risk-free Interest Rate	0.42%	0.38%	1.33%

(a) - Volatility was based on historical volatility over three years using daily stock price observations.

	2013		2012		2011
Weighted-average grant date fair value (per share)	$	52.34	$	42.39	$	34.68
Fair value of shares granted (thousands of dollars)	$	19,742	$	25,466	$	29,186

Employee Stock Purchase Plan

We have reserved a total of 11.6 million shares of common stock for issuance under our ONEOK, Inc. Employee Stock Purchase Plan (the ESPP).  Subject to certain exclusions, all full-time employees are eligible to participate in the ESPP. Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to terms and limitations of the plan.  The Executive Compensation Committee may allow contributions to be made by other means, provided that in no event will contributions from all means exceed 10 percent of the employee’s annual base pay.  The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price.  Approximately 52 percent, 55 percent and 56 percent of employees participated in the plan in 2013, 2012 and 2011, respectively. Compensation expense for the ESPP was $6.6 million and $7.2 million in 2013 and 2011, respectively, and was not material in 2012. Under the plan, we sold 254,960 shares at $35.97 in 2013, 256,490 shares at $35.97 per share in 2012 and 365,116 shares at $23.70 per share in 2011.

Employee Stock Award Program

Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $13 per share.  The total number of shares of our common stock available for issuance under this program was 900,000.  Shares issued to employees under this program during 2013, 2012 and 2011 totaled 63,975, 42,467 and 295,694 respectively, and compensation expense related to the Employee Stock Award Plan was $3.6 million, $1.9 million and $16.0 million in 2013, 2012 and 2011, respectively.

Deferred Compensation Plan for Non-Employee Directors

The ONEOK, Inc. Nonqualified Deferred Compensation Plan for Non-Employee Directors provides our nonemployee directors the option to defer all or a portion of their compensation for their service on our Board of Directors.  Under the plan, directors may elect either a cash deferral option or a phantom stock option.  Under the cash deferral option, directors may defer the receipt of all or a portion of their annual retainer fees, plus accrued interest.  Under the phantom stock option, directors may defer all or a portion of their annual retainer fees and receive such fees on a deferred basis in the form of shares of common stock under our Long-Term Incentive Plan or Equity Compensation Plan.  Shares are distributed to nonemployee directors at the fair market value of our common stock at the date of distribution.

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Impact of ONE Gas Separation on Stock Compensation Plans

In connection with the separation of the natural gas distribution business on January 31, 2014, ONEOK entered into an Employee Matters Agreement with ONE Gas, which provides that employees of ONE Gas no longer participate in stock compensation plans sponsored or maintained by ONEOK. Pursuant to the Employee Matters Agreement, we made certain adjustments to the number of our share-based compensation awards, with the intention of preserving the intrinsic value of each award immediately prior to the separation.

Restricted Stock Units - Restricted stock units were converted to awards in shares of the entity where the employee holding them was assigned following the separation. Therefore, restricted stock units held by an employee who separated with ONE Gas were surrendered as a result of the separation; these ONE Gas employees were granted awards by ONE Gas that are equal in value to their surrendered ONEOK shares. The number of restricted stock units held by employees who remained with ONEOK was adjusted by issuing additional units to preserve the intrinsic value of the awards immediately prior to the separation. The additional shares granted by ONEOK and the shares surrendered by ONE Gas employees resulted in a net decrease of approximately 77 thousand nonvested, restricted stock unit awards and a decrease of approximately $2.4 million in unrecognized compensation costs.

Performance-Unit Awards -Performance-unit awards held by an employee who separated with ONE Gas were surrendered as a result of the separation, and new performance-unit awards were concurrently granted by ONE Gas with an equivalent intrinsic value of the intrinsic value of the ONEOK awards immediately prior to the separation. The number of performance unit awards held by employees who remained with ONEOK was adjusted by issuing additional units to preserve the intrinsic value of the awards immediately prior to the separation. The additional shares granted by ONEOK and the shares surrendered by ONE Gas employees resulted in a net decrease of approximately 151 thousand nonvested performance-unit awards and a decrease of approximately $5.6 million in unrecognized compensation costs.

Employee Stock Purchase Plan - For those employees who separated with ONE Gas, enrollment in the plan was terminated upon the separation. Employees who separated with ONE Gas will receive shares of ONEOK common stock at the end of the offering period based upon the contributions made while employed at ONEOK. There was no impact to enrollment for those employees who remained at ONEOK. The grant date market price for ONEOK stock will be adjusted to reflect the impact of the distribution of ONE Gas shares.

Deferred Awards - Deferred shares associated with vested restricted stock unit awards or performance unit awards held by directors or employees were treated in the same manner as regular shareholders, by crediting one deferred share of ONE Gas stock for every four deferred shares of ONEOK stock.

N. EMPLOYEE BENEFIT PLANS

Retirement and Postretirement Benefit Plans

Retirement Plans - We have a defined benefit pension plan covering nonbargaining unit employees hired before January 1, 2005, and certain bargaining-unit employees hired before December 15, 2011.  Nonbargaining unit employees hired after December 31, 2004; employees represented by Local No. 304 of the IBEW hired on or after July 1, 2010; employees represented by the United Steelworkers hired on or after December 15, 2011; and employees who accepted a one-time opportunity to opt out of our pension plan, are covered by our Profit-Sharing Plan.  In addition, we have a supplemental executive retirement plan for the benefit of certain officers.  No new participants in our supplemental executive retirement plan have been approved since 2005, and effective January 2014 the plan formally was closed to new participants.  We fund our pension costs at a level needed to maintain or exceed the minimum funding levels required by the Employee Retirement Income Security Act of 1974, as amended, and the Pension Protection Act of 2006.

Postretirement Benefit Plans - We sponsor health and welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service.  The postretirement medical plan is contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance.

In December 2011, we announced to participants a change from a self-insured postretirement medical plan to a fully insured solution for plan participants who are medicare eligible.  This announcement resulted in a $44.6 million reduction in our accumulated postretirement benefit obligation that was recognized in other comprehensive income and will be amortized to net periodic benefit cost over the expected remaining years of service for plan participants.

Regulatory Treatment - The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and postretirement benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively.

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The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for pension and postretirement costs.  Differences, if any, between the expense and the amount recovered through rates are reflected in earnings, net of authorized deferrals.

Our regulated entities historically have recovered pension and postretirement benefit costs through rates.  We believe it is probable that regulators will continue to include the net periodic pension and postretirement benefit costs in our regulated entities’ cost of service.  Accordingly, we have recorded a regulatory asset for the minimum liability associated with our regulated entities’ pension and postretirement benefit obligations that otherwise would have been recorded in accumulated other comprehensive income.

Obligations and Funded Status - The following tables set forth our pension and postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated:

	Pension Benefits						Postretirement Benefits
	December 31,						December 31,
	2013			2012			2013			2012
Change in Benefit Obligation	(Thousands of dollars)
Benefit obligation, beginning of period	$	1,313,560		$	1,215,932		$	299,172		$	286,044
Service cost	22,968			21,301			4,612			4,960
Interest cost	54,449			59,237			11,713			13,893
Plan participants’ contributions	—			—			4,293			5,851
Actuarial loss (gain)	(110,552		)	105,732			(29,460		)	9,935
Benefits paid	(58,976		)	(88,642		)	(18,411		)	(21,380		)
Plan amendment	—			—			17,228			(131		)
Benefit obligation, end of period	1,221,449			1,313,560			289,147			299,172
Change in Plan Assets
Fair value of plan assets, beginning of period	995,264			902,235			148,162			124,163
Actual return on plan assets	176,889			90,026			27,483			14,273
Employer contributions	—			91,881			866			10,728
Benefits paid	(59,404		)	(88,878		)	(876		)	(1,002		)
Fair value of assets, end of period	1,112,749			995,264			175,635			148,162
Balance at December 31	$	(108,700	)	$	(318,296	)	$	(113,512	)	$	(151,010	)
Current liabilities	$	(5,457	)	$	(4,695	)	$	—		$	—
Noncurrent liabilities	(103,243		)	(313,601		)	(113,512		)	(151,010		)
Balance at December 31	$	(108,700	)	$	(318,296	)	$	(113,512	)	$	(151,010	)

The accumulated benefit obligation for our pension plans was $1,159.0 million and $1,240.3 million at December 31, 2013 and 2012, respectively.

There are no plan assets expected to be withdrawn and returned to us in 2014.

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Components of Net Periodic Benefit Cost -The following tables set forth the components of net periodic benefit cost for our pension and postretirement benefit plans for the periods indicated:

	Pension Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	22,968		$	21,301		$	20,013
Interest cost	54,449			59,237			58,757
Expected return on assets	(81,272		)	(82,756		)	(75,500		)
Amortization of unrecognized prior service cost	920			969			1,018
Amortization of net loss	66,282			48,439			35,708
Settlements	1,338			1,401			—
Net periodic benefit cost	$	64,685		$	48,591		$	39,996

	Postretirement Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	4,612		$	4,960		$	4,987
Interest cost	11,713			13,893			15,632
Expected return on assets	(12,259		)	(10,687		)	(10,272		)
Amortization of unrecognized net asset at adoption	284			2,874			3,189
Amortization of unrecognized prior service cost	(6,442		)	(8,252		)	(2,518		)
Amortization of net loss	12,605			13,184			8,123
Net periodic benefit cost	$	10,513		$	15,972		$	19,141

Other Comprehensive Income (Loss) - The following tables set forth the amounts recognized in other comprehensive income (loss) related to our pension benefits and postretirement benefits for the periods indicated:

	Pension Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Regulatory asset gain (loss)	$	(110,437	)	$	67,472		$	114,625
Net gain (loss) arising during the period	201,251			(103,199		)	(182,987		)
Amortization of regulatory asset	(44,378		)	(32,527		)	(23,265		)
Amortization of prior service credit	920			969			1,018
Amortization of loss	67,620			49,839			35,708
Deferred income taxes	(44,473		)	6,748			21,236
Total recognized in other comprehensive income (loss)	$	70,503		$	(10,698	)	$	(33,665	)

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	Postretirement Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Regulatory asset gain (loss)	$	(7,674	)	$	4,376		$	7,389
Net gain (loss) arising during the period	44,685			(6,348		)	(40,765		)
Amortization of regulatory asset	(5,643		)	(6,557		)	(7,214		)
Amortization of transition obligation	284			2,874			3,189
Amortization of prior service cost	(6,442		)	(8,252		)	(2,518		)
Amortization of loss	12,605			13,184			8,123
Plan amendment	(17,228		)	131			44,562
Deferred income taxes	(7,964		)	229			(4,938		)
Total recognized in other comprehensive income (loss)	$	12,623		$	(363	)	$	7,828

The table below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense for the periods indicated:

	Pension Benefits						Postretirement Benefits
	December 31,						December 31,
	2013			2012			2013			2012
	(Thousands of dollars)
Transition obligation	$	—		$	—		$	—		$	(283	)
Prior service credit (cost)	(1,102		)	(2,022		)	14,631			38,301
Accumulated loss	(415,375		)	(684,245		)	(59,362		)	(116,652		)
Accumulated other comprehensive loss before regulatory assets	(416,477		)	(686,267		)	(44,731		)	(78,634		)
Regulatory asset for regulated entities	288,017			442,833			43,254			56,571
Accumulated other comprehensive loss after regulatory assets	(128,460		)	(243,434		)	(1,477		)	(22,063		)
Deferred income taxes	49,689			94,161			572			8,534
Accumulated other comprehensive loss, net of tax	$	(78,771	)	$	(149,273	)	$	(905	)	$	(13,529	)

The following table sets forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets expected to be recognized as components of net periodic benefit expense in the next fiscal year. The table does not include amounts applicable to employees of ONE Gas, as those amounts are expected to be recognized by ONE Gas as a result of the separation of the natural gas distribution business.

	Pension Benefits		Postretirement Benefits
Amounts to be recognized in 2014	(Thousands of dollars)
Transition obligation	$	—	$	—
Prior service credit (cost)	$	193	$	(1,662	)
Net loss	$	15,021	$	833

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for pension and postretirement benefits for the periods indicated:

	Pension Benefits		Postretirement Benefits
	December 31,		December 31,
	2013	2012	2013	2012
Discount rate	5.25%	4.25%	5.00%	4.00%
Compensation increase rate	3.35% - 3.40%	3.45% - 3.50%	3.35% - 3.40%	3.45% - 3.50%

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The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated:

	Years Ended December 31,
	2013	2012	2011
Discount rate - pension plans	4.25%	5.00%	5.50%
Discount rate - postretirement plans	4.00%	5.00%	5.50%
Expected long-term return on plan assets	8.25%	8.25%	8.25%
Compensation increase rate	3.45% - 3.50%	3.20% - 3.80%	3.30% - 3.90%

We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and economic growth models.

We determine our discount rates annually.  We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our pension and postretirement obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows.  Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds.  Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.

Health Care Cost Trend Rates -The following table sets forth the assumed health care cost-trend rates for the periods indicated:

	2013	2012
Health care cost-trend rate assumed for next year	4.0% - 8.25%	4.0% - 9.0%
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate)	4.0% - 5.0%	4.0% - 5.0%
Year that the rate reaches the ultimate trend rate	2022	2022

Assumed health care cost-trend rates have an impact on the amounts reported for our health care 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
	(Thousands of dollars)
Effect on total of service and interest cost	$	1,136	$	(1,022	)
Effect on postretirement benefit obligation	$	15,152	$	(14,350	)

Plan Assets -Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals.  The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations.  The plan’s investments include a diverse blend of various domestic and international equities, investments in various classes of debt securities, insurance contracts and venture capital.  The target allocation for the assets of our pension plan is as follows:

U.S. large-cap equities	37	%
Aggregate bonds	24	%
Developed foreign large-cap equities	10	%
Alternative investments	8	%
Mid-cap equities	6	%
Emerging markets equities	5	%
Small-cap equities	4	%
High-yield bonds	3	%
Developed foreign bonds	2	%
Emerging market bonds	1	%
Total	100	%

As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.

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The following tables set forth our pension benefits and postretirement benefits plan assets by fair value category as of the measurement date:

	Pension Benefits
	December 31, 2013
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	680,590	$	60,336	$	—	$	740,926
Government obligations	—		111,288		—		111,288
Corporate obligations (b)	—		95,432		—		95,432
Cash and money market funds (c)	27,699		—		—		27,699
Insurance and group annuity contracts	—		—		63,458		63,458
Other investments (d)	—		—		73,946		73,946
Total assets	$	708,289	$	267,056	$	137,404	$	1,112,749

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Pension Benefits
	December 31, 2012
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	541,539	$	61,242	$	—	$	602,781
Government obligations	—		116,936		—		116,936
Corporate obligations (b)	—		104,078		—		104,078
Cash and money market funds (c)	33,296		—		—		33,296
Insurance and group annuity contracts	—		—		70,411		70,411
Other investments (d)	—		—		67,762		67,762
Total assets	$	574,835	$	282,256	$	138,173	$	995,264

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Postretirement Benefits
	December 31, 2013
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	37,796	$	90	$	—	$	37,886
Government obligations	—		166		—		166
Corporate obligations (b)	17,207		142		—		17,349
Cash and money market funds (c)	13,936		—		—		13,936
Insurance and group annuity contracts	—		106,189		—		106,189
Other investments (d)	—		—		109		109
Total assets	$	68,939	$	106,587	$	109	$	175,635

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

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	Postretirement Benefits
	December 31, 2012
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	21,548	$	140	$	—	$	21,688
Government obligations	—		268		—		268
Corporate obligations (b)	17,522		238		—		17,760
Cash and money market funds (c)	18,311		—		—		18,311
Insurance and group annuity contracts	—		89,979		—		89,979
Other investments (d)	—		—		156		156
Total assets	$	57,381	$	90,625	$	156	$	148,162

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category represents money market funds.

(d) - This category represents alternative investments.

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

	Pension Benefits
	December 31, 2013
	Insurance and Group Annuity Contracts			Other Investments		Total
	(Thousands of dollars)
January 1, 2013	$	70,411		$	67,762	$	138,173
Net realized and unrealized gains (losses)	(6,953		)	6,184		(769		)
December 31, 2013	$	63,458		$	73,946	$	137,404

	Pension Benefits
	December 31, 2012
	Insurance and Group Annuity Contracts			Other Investments		Total
	(Thousands of dollars)
January 1, 2012	$	70,818		$	66,243	$	137,061
Net realized and unrealized gains (losses)	(407		)	1,519		1,112
December 31, 2012	$	70,411		$	67,762	$	138,173

Contributions -During 2013, we made no contributions to our defined benefit pension plans and $11.8 million in contributions to our postretirement benefit plans.  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 plans and postretirement plans in 2014.

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Pension and Postretirement Benefit Payments - Benefit payments for our pension and postretirement benefit plans for the period ending December 31, 2013, were $59.0 million and $18.4 million, respectively.  The following table sets forth the pension benefits and postretirement benefits payments expected to be paid in 2014-2023:

	Pension Benefits		Postretirement Benefits
Benefits to be paid in:	(Thousands of dollars)
2014	$	63,856	$	16,251
2015	$	64,588	$	17,135
2016	$	66,477	$	18,142
2017	$	68,626	$	19,095
2018	$	70,873	$	19,875
2019 through 2023	$	386,366	$	106,346

The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2013, and include estimated future employee service.

Other Employee Benefit Plans

Thrift Plan - We have a Thrift Plan covering all full-time employees, and employee contributions are discretionary.  We match 100 percent of employee contributions up to 6 percent of each participant’s eligible compensation, subject to certain limits. Our contributions made to the plan were $17.0 million, $16.4 million and $15.9 million in 2013, 2012 and 2011, respectively.

Profit-Sharing Plan - We have a profit-sharing plan (Profit-Sharing Plan) for all nonbargaining unit employees hired after December 31, 2004, and employees covered by the IBEW collective bargaining agreement hired after June 30, 2010.  Nonbargaining unit employees who were employed prior to January 1, 2005, and employees covered by the IBEW collective bargaining agreement employed prior to July 1, 2010, were given a one-time opportunity to make an irrevocable election to participate in the Profit-Sharing Plan and not accrue any additional benefits under our defined benefit pension plan after December 31, 2004, and June 30, 2010, respectively.  Employees covered by the United Steelworker collective bargaining agreement employed prior to December 16, 2011, were given a one-time opportunity to make an irrevocable election to participate in the Profit-Sharing Plan.  We plan to make a contribution to the Profit-Sharing Plan each quarter equal to 1 percent of each participant’s eligible compensation during the quarter.  Additional discretionary employer contributions may be made at the end of each year.  Employee contributions are not allowed under the plan.  Our contributions made to the plan were $5.1 million, $6.6 million and $6.7 million in 2013, 2012 and 2011, respectively.

Employee Deferred Compensation Plan -The ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan provides select employees, as approved by our Board of Directors, with the option to defer portions of their compensation and provides nonqualified deferred compensation benefits that are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws.  Our contributions made to the plan were not material in 2013, 2012 and 2011.

ONE Gas Employee Benefit Plans

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.

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O. INCOME TAXES

The following table sets forth our provisions for income taxes for the periods indicated:

	Years Ended December 31,
	2013		2012			2011
Current income taxes	(Thousands of dollars)
Federal	$	7,313	$	(16,083	)	$	(32,291	)
State	4,554		1,798			1,707
Total current income taxes from continuing operations	11,867		(14,285		)	(30,584		)	(a)
Deferred income taxes
Federal	137,654		213,127			228,257
State	13,861		16,353			28,375
Total deferred income taxes from continuing operations	151,515		229,480			256,632			(a)
Total provision for income taxes from continuing operations	163,382		215,195			226,048
Discontinued operations	—		8,749			1,255
Total provision for income taxes	$	163,382	$	223,944		$	227,303

(a) Includes a $37.7 million reclassification from current income taxes to deferred related to revisions of estimated depreciation in our filed tax returns compared with our 2010 tax provision.

The following table is a reconciliation of our income tax provision from continuing operations for the periods indicated:

	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Income from continuing operations before income taxes	$	740,343		$	944,446		$	983,562
Less: Net income attributable to noncontrolling interest	310,428			382,911			399,150
Income from continuing operations attributable to ONEOK before income taxes	429,915			561,535			584,412
Federal statutory income tax rate	35		%	35		%	35		%
Provision for federal income taxes	150,470			196,537			204,543
State income taxes, net of federal tax benefit	11,970			11,799			20,334
Other, net	942			6,859			1,171
Income tax provision from continuing operations	$	163,382		$	215,195		$	226,048

The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated:

	December 31, 2013		December 31, 2012
Deferred tax assets	(Thousands of dollars)
Employee benefits and other accrued liabilities	$	78,793	$	128,418
Federal net operating loss	12,484		—
State net operating loss and benefits	38,322		31,990
Energy Services capacity release	46,726		—
Other comprehensive income	78,369		140,802
Other	20,872		1,446
Total deferred tax assets	275,566		302,656
Deferred tax liabilities
Excess of tax over book depreciation and depletion	822,706		760,211
Investment in partnerships	1,217,605		969,347
Regulatory assets	132,676		204,625
Total deferred tax liabilities	2,172,987		1,934,183
Net deferred tax liabilities	$	1,897,421	$	1,631,527

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We had income taxes receivable of approximately $15.6 million and $30.8 million at December 31, 2013 and 2012, respectively.

Tax benefits related to net operating loss (NOL) carryforwards will begin expiring in 2032. We believe that it is more likely than not that the tax benefits of the net operating loss carryforwards will be utilized prior to their expirations; therefore, no valuation allowance is necessary.

Deferred tax assets related to tax benefits of employee share-based compensation have been reduced for performance share units and restricted share units that vested in periods in which ONEOK was in an NOL position.  This vesting resulted in tax deductions in excess of previously recorded benefits based on the performance share unit and restricted share unit value at the time of grant.  Although these additional tax benefits are reflected in NOL carryforwards in the tax return, the additional tax benefit is not recognized until the deduction reduces taxes payable.  A portion of the tax benefit does not reduce ONEOK’s current taxes payable due to NOL carryforwards; accordingly, these tax benefits are not reflected in ONEOK’s NOLs in deferred tax assets.  Tax benefits included in NOL carryforwards but not reflected in deferred tax assets were $35.9 million as of December 31, 2013, and $11.0 million as of December 31, 2012.

P. UNCONSOLIDATED AFFILIATES

Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated:

	Net Ownership Interest	December 31, 2013		December 31, 2012
		(Thousands of dollars)
Northern Border Pipeline	50%	$	404,803	$	393,317
Overland Pass Pipeline Company	50%	466,671		468,710
Fort Union Gas Gathering, L.L.C.	37%	125,220		120,782
Bighorn Gas Gathering	49%	87,837		90,428
Other	Various	145,307		148,168
Investments in unconsolidated affiliates (a)		$	1,229,838	$	1,221,405

(a) - Equity method goodwill (Note A) was $224.3 million at December 31, 2013 and 2012.

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

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Northern Border Pipeline	$	65,046	$	72,705	$	76,365
Overland Pass Pipeline Company	20,461		20,043		19,535
Fort Union Gas Gathering, L.L.C.	15,826		17,218		15,280
Bighorn Gas Gathering	1,952		3,820		5,990
Other	7,232		9,238		10,076
Equity earnings from investments	$	110,517	$	123,024	$	127,246

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

	December 31, 2013			December 31, 2012
	(Thousands of dollars)
Balance Sheet
Current assets	$	155,310		$	175,930
Property, plant and equipment, net	$	2,557,571		$	2,593,122
Other noncurrent assets	$	34,478		$	35,005
Current liabilities	$	98,967		$	145,147
Long-term debt	$	442,103		$	472,630
Other noncurrent liabilities	$	58,221		$	42,451
Accumulated other comprehensive loss	$	(2,291	)	$	(2,503	)
Owners’ equity	$	2,150,359		$	2,146,332

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	528,665	$	573,197	$	496,158
Costs and expenses	$	256,292	$	269,858	$	221,261
Net income	$	248,998	$	279,766	$	249,559
Distributions paid to us	$	137,498	$	155,741	$	156,385

We incurred expenses in transactions with unconsolidated affiliates of $53.8 million, $36.5 million, and $33.7 million for 2013, 2012, and 2011, respectively, primarily related to Overland Pass Pipeline Company. Accounts payable to our equity method investees at December 31, 2013 and 2012, were not material.

Overland Pass Pipeline Company - 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 percentage interest.  The Overland Pass Pipeline Company Management Committee determines the amount and timing of such distributions.  Any changes to, or suspensions 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.

Northern Border Pipeline - 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.

During 2013, ONEOK Partners made equity contributions to Northern Border Pipeline Company of approximately $30.8 million.

In September 2012, Northern Border Pipeline filed with the FERC a settlement with its customers to modify its transportation rates. In January 2013, the settlement was approved and the new rates are effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower compared with previous rates.

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Q. ONEOK PARTNERS

Ownership Interestin ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of December 31, 2013:

General partner interest	2.0	%
Limited partner interest (a)	39.2	%
Total ownership interest	41.2	%

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

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 its 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 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.

As a result of these transactions, ONEOK’s 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 its 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.  As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent at December 31, 2012, from 42.8 percent at December 31, 2011.

We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction.  If ONEOK Partners issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital.  As a result of ONEOK Partners’ issuance of common units, we recognized an increase to paid-in capital of approximately $87.3 million, net of taxes, in 2013 and a decrease to paid-in capital of approximately $51.1 million, net of taxes, in 2012.

Cash Distributions - We receive distributions from ONEOK Partners on our common and Class B units and our 2 percent general partner interest, which includes our incentive distribution rights.  Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in the ONEOK Partners partnership agreement (Partnership Agreement), as amended.  Available cash generally will be distributed 98 percent to limited partners and 2 percent to the general partner.  The general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter.  In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among the general partner and limited partners to reflect the two-for-one unit split of ONEOK Partners’ common units.  Under the incentive distribution provisions, as set forth in ONEOK Partners’ partnership agreement, as amended, the general partner receives:

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

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

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

The following table shows ONEOK Partners’ distributions paid during the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	2.870	$	2.590	$	2.325
General partner distributions	$	18,193	$	15,217	$	12,189
Incentive distributions	251,664		186,130		123,386
Distributions to general partner	269,857		201,347		135,575
Limited partner distributions to ONEOK	266,302		235,442		197,132
Limited partner distributions to noncontrolling interest	373,554		324,123		276,739
Total distributions paid	$	909,713	$	760,912	$	609,446

ONEOK Partners’ distributions are declared and paid within 45 days of the end of each quarter. The following table shows ONEOK Partners’ distributions declared for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	2.890	$	2.690	$	2.365
General partner distributions	$	18,625	$	16,355	$	12,515
Incentive distributions	259,466		210,095		131,212
Distributions to general partner	278,091		226,450		143,727
Limited partner distributions to ONEOK	268,157		249,600		200,524
Limited partner distributions to noncontrolling interest	384,988		341,704		281,500
Total distributions declared	$	931,236	$	817,754	$	625,751

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

ONEOK Partners accounted for this acquisition as a business combination, which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of the purchase price over the fair values of the identifiable assets acquired was recorded as goodwill.

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The purchase price and assessment of the fair value of the assets acquired and liabilities assumed were as follows (in thousands):

	Total
Property, plant and equipment
Gathering pipelines and related equipment	$	59,174
Processing and fractionation and related equipment	50,595
General plant and other	120
Intangible assets	103,000
Identifiable assets acquired	212,889
Goodwill	92,000
Total purchase price	$	304,889

Identifiable intangible assets recognized in the Sage Creek acquisition are primarily related to natural gas gathering and processing and natural gas liquids supply contracts and customer relationships. The basis for determining the value of these intangible assets is the estimated future net cash flows to be derived from acquired supply contracts and customer relationships, which are offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. Those intangible assets are being amortized on a straight-line basis over a period ranging from 20 to 30 years, which represents the periods during which the customer contracts and relationships are expected to contribute to ONEOK Partners’ cash flows.

Revenues and earnings related to the Sage Creek acquisition are included within ONEOK Partners’ Consolidated Statement of Comprehensive Income since the acquisition dates. Supplemental pro forma revenue and earnings reflecting this acquisition as if it had occurred as of January 1, 2013, are not materially different from the information presented in ONEOK Partners’ accompanying Consolidated Statement of Comprehensive Income since the historical operations of this acquisition were insignificant relative to ONEOK Partners’ historical operations and are, therefore, not presented.

In December 2013, ONEOK Partners acquired the remaining 30 percent undivided interest in its Maysville natural gas processing facility for $90 million. Beginning December 1, 2013, the results of operations for its 100 percent interest are included in our ONEOK Partners segment.

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

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

ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment.  In addition, a portion of ONEOK Partners’ revenues from its natural gas pipelines business is from our Energy Services and Natural Gas Distribution segments, which contract with ONEOK Partners for natural gas transportation and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and its natural gas gathering and processing operations. As a result of the wind down activities discussed in Note B, our Energy Services segment will not execute affiliate transactions with ONEOK Partners after the wind down is completed. ONEOK Partners expects to continue providing midstream services, including marketing natural gas, NGLs and condensate as a service for third parties or other ONEOK affiliates. ONEOK Partners expects to enter into future commodity derivative financial contracts with unaffiliated third parties or ONEOK affiliates.

Previously, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which it 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. In June 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.

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

The following table shows ONEOK Partners’ transactions with us for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Revenues	$	340,743	$	352,099	$	403,603
Expenses
Cost of sales and fuel	$	37,963	$	33,094	$	48,163
Administrative and general expenses	265,448		246,050		251,239
Total expenses	$	303,411	$	279,144	$	299,402

R. COMMITMENTS AND CONTINGENCIES

Commitments - Operating leases represent future minimum lease payments under noncancelable equipment leases covering office space, pipeline equipment, rights of way and vehicles.  Firm transportation and storage contracts are fixed-price contracts that provide us with firm transportation and storage capacity.  Rental expense in 2013, 2012 and 2011 was not material.  The following table sets forth our operating lease and firm transportation and storage contract payments for the periods indicated:

ONEOK	Operating Leases
	(Millions of dollars)
2014	$	3.4
2015	2.9
2016	2.5
2017	2.1
2018	1.9
Thereafter	3.3
Total	$	16.1

Our former Natural Gas Distribution segment is a party to fixed-price contracts providing it with firm transportation and storage capacity. The costs associated with these contracts are recovered through rates. Future commitments related to these contracts are $900.0 million. These contracts are obligations of ONE Gas as the result of the separation.

Our Energy Services segment also is a party to fixed-price contracts related to firm transportation and storage that are not being released as part of the wind down process and will expire before April 2014. Future commitments related to these contracts are $11.2 million.

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ONEOK Partners	Operating Leases		Firm Transportation and Storage Contracts		Total
	(Millions of dollars)
2014	$	2.0	$	18.4	$	20.4
2015	0.5		16.3		16.8
2016	0.3		14.4		14.7
2017	0.2		12.8		13.0
2018	0.2		11.9		12.1
Thereafter	0.7		30.2		30.9
Total	$	3.9	$	104.0	$	107.9

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

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

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

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

Our expenditures for environmental assessment, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters have had no material effects on earnings or cash flows during 2013, 2012 or 2011.

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

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NESHAP rule. While the rule could require capital expenditures for the purchase and installation of new emissions-control equipment, we do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

In July 2011, the EPA issued a proposed rule that would change the air emissions New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and natural gas industry, including natural gas production, processing, transmission and underground storage sectors. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification.

In March 2013, the EPA issued proposed rulemaking to amend the NSPS for the crude oil and natural gas industry, pursuant to various industry comments, administrative petitions for reconsideration and/or judicial appeals of portions of the NSPS final rule. The rule was most recently amended in September 2013, and the EPA has indicated that further amendments may be issued in 2014. Based on the amendments and our understanding of pending stakeholder responses to the NSPS rule, we anticipate a reduction in our anticipated capital, operations and maintenance costs resulting from compliance with the regulation. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude oil and natural gas industry. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

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

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

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

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

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

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

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

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

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Certiorari with the United States Supreme Court on August 26, 2013. The Ninth Circuit has ordered the cases stayed until the final disposition of the Petition for Writ of Certiorari.

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

Other Legal Proceedings - We are a party to various other litigation matters and claims that have arisen in the normal course of our operations. While the results of these various other litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses on such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

S. SEGMENTS

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

• our ONEOK Partners segment reflects the consolidated operations of ONEOK Partners.  At December 31, 2013, we have a 41.2 percent ownership interest and control ONEOK Partners through our ownership of its general partner interest.  ONEOK Partners gathers, processes, treats, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs.  We and ONEOK Partners maintain significant financial and corporate governance separations.  We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of its businesses individually;

• our former Natural Gas Distribution segment, which we separated into a standalone publicly traded company, ONE Gas, on January 31, 2014, was comprised of regulated public utilities that deliver natural gas to residential, commercial and industrial customers, and transport natural gas; and

• our Energy Services segment, which we are winding down, markets natural gas to wholesale customers.

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

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

Customers - In 2013, 2012 and 2011, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.

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

Year Ended December 31, 2013	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	11,528,530	$	1,689,945	$	1,381,636		$	2,606		$	14,602,717
Intersegment revenues	340,743		7		195,926			(536,676		)	—
Total revenues	$	11,869,273	$	1,689,952	$	1,577,562		$	(534,070	)	$	14,602,717
Net margin	$	1,647,060	$	813,008	$	(172,985	)	$	2,600		$	2,289,683
Operating costs	521,513		444,866		13,133			10,941			990,453
Depreciation and amortization	236,743		144,758		277			2,599			384,377
Gain on sale of assets	11,881		—		—			—			11,881
Operating income	$	900,685	$	223,384	$	(186,395	)	$	(10,940	)	$	926,734
Equity earnings from investments	$	110,517	$	—	$	—		$	—		$	110,517
Investments in unconsolidated affiliates	$	1,229,838	$	—	$	—		$	—		$	1,229,838
Total assets	$	12,862,608	$	3,857,722	$	347,470		$	639,758		$	17,707,558
Noncontrolling interests in consolidated subsidiaries	$	4,536	$	—	$	—		$	2,502,793		$	2,507,329
Capital expenditures	$	1,939,326	$	292,080	$	—		$	25,179		$	2,256,585

(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $781.7 million, net margin of $545.0 million and operating income of $281.0 million.

Year Ended December 31, 2012	ONEOK Partners (a)		Natural Gas Distribution			Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	9,830,052	$	1,379,366		$	1,421,171		$	1,970		$	12,632,559
Intersegment revenues	352,099		(2,717		)	105,402			(454,784		)	—
Total revenues	$	10,182,151	$	1,376,649		$	1,526,573		$	(452,814	)	$	12,632,559
Net margin	$	1,641,832	$	756,389		$	(49,344	)	$	1,964		$	2,350,841
Operating costs	482,540		410,572			17,950			(2,084		)	908,978
Depreciation and amortization	203,101		130,150			361			2,232			335,844
Goodwill impairment	—		—			10,255			—			10,255
Gain on sale of assets	6,736		—			—			—			6,736
Operating income	$	962,927	$	215,667		$	(77,910	)	$	1,816		$	1,102,500
Equity earnings from investments	$	123,024	$	—		$	—		$	—		$	123,024
Investments in unconsolidated affiliates	$	1,221,405	$	—		$	—		$	—		$	1,221,405
Total assets	$	10,959,230	$	3,535,489		$	493,006		$	867,550		$	15,855,275
Noncontrolling interests in consolidated subsidiaries	$	4,767	$	—		$	—		$	2,098,074		$	2,102,841
Capital expenditures	$	1,560,513	$	280,294		$	—		$	25,346		$	1,866,153

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $722.1 million, net margin of $618.0 million and operating income of $375.6 million.

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Year Ended December 31, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	10,919,004		$	1,609,628	$	2,274,799	$	2,363		$	14,805,794
Intersegment revenues	403,603			11,706		502,418		(917,727		)	—
Total revenues	$	11,322,607		$	1,621,334	$	2,777,217	$	(915,364	)	$	14,805,794
Net margin	$	1,577,380		$	751,835	$	48,740	$	2,404		$	2,380,359
Operating costs	459,364			422,073		24,527		2,359			908,323
Depreciation and amortization	177,549			132,212		445		1,954			312,160
Loss on sale of assets	(963		)	—		—		—			(963		)
Operating income	939,504			197,550		23,768		(1,909		)	1,158,913
Equity earnings from investments	$	127,246		$	—	$	—	$	—		$	127,246
Investments in unconsolidated affiliates	$	1,223,398		$	—	$	—	$	—		$	1,223,398
Total assets	$	8,946,676		$	3,392,475	$	562,728	$	794,756		$	13,696,635
Noncontrolling interests in consolidated subsidiaries	$	5,112		$	—	$	—	$	1,556,047		$	1,561,159
Capital expenditures	$	1,063,383		$	242,590	$	41	$	30,053		$	1,336,067

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $658.5 million, net margin of $469.0 million and operating income of $232.8 million.

T. QUARTERLY FINANCIAL DATA (UNAUDITED)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2013
	(Thousands of dollars except per share amounts)
Total revenues	$	3,541,445	$	3,349,236	$	3,571,925	$	4,140,111
Net margin	$	623,452	$	453,389	$	561,188	$	651,654
Income from continuing operations	$	165,705	$	79,495	$	147,698	$	184,063
Net income	$	165,705	$	79,495	$	147,698	$	184,063
Net income attributable to ONEOK	$	112,521	$	919	$	62,356	$	90,737
Earnings per share total
Basic	$	0.55	$	—	$	0.30	$	0.44
Diluted	$	0.54	$	—	$	0.30	$	0.43

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2012
	(Thousands of dollars except per share amounts)
Total revenues	$	3,414,600	$	2,529,260	$	3,028,775	$	3,659,924
Net margin	$	643,587	$	548,962	$	553,972	$	604,320
Income from continuing operations	$	219,450	$	148,938	$	164,988	$	195,875
Income from discontinued operations and gain on sale, net of tax	$	14,012	$	267	$	—	$	—
Net income	$	233,462	$	149,205	$	164,988	$	195,875
Net income attributable to ONEOK	$	122,865	$	60,993	$	65,219	$	111,542
Earnings per share total
Basic	$	0.59	$	0.29	$	0.32	$	0.55
Diluted	$	0.58	$	0.29	$	0.31	$	0.53

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U. Subsequent Events

On January 8, 2014, our Board of Directors unanimously approved the distribution of all the shares of common stock of ONE Gas, our wholly owned subsidiary, to our shareholders. On January 14, 2014, we entered into the following agreements with ONE Gas which provide a framework for our relationship with ONE Gas after the distribution:

• Separation and Distribution Agreement - sets forth the agreements between us and ONE Gas regarding the principal transactions necessary to effect the distribution. This agreement also sets forth other agreements that govern certain aspects of our relationship with ONE Gas after the completion of the distribution.

• Tax Matters Agreement - governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and other matters regarding taxes.

• Transition Services Agreement - provides for an orderly transition to ONE Gas being an independent, publicly traded company. Under this agreement, ONEOK and ONE Gas have agreed to provide each other with various services, including services relating to treasury and risk management, human resources and payroll management, tax compliance, telecommunications services and information technology services.

• Employee Matters Agreement - allocates liabilities and responsibilities relating to employee compensation and benefit plans and programs and other related matters in connection with the separation, including the treatment of outstanding incentive awards and certain retirement and welfare benefit obligations.

On January 27, 2014, ONE Gas, which at the time was our wholly owned subsidiary, completed a private placement of three series of Senior Notes totaling $1.2 billion. The following table details information about each of the three series of Senior Notes:

	(In millions)
2.07% notes due February 1, 2019	$	300
3.61% notes due February 1, 2024	300
4.658% notes due February 1, 2044	600
	$	1,200

Our obligations related to the ONE Gas Senior Notes and Credit Agreement terminated in connection with the completion of the separation of ONE Gas.

ONE Gas made a cash payment to us of approximately $1.13 billion from the proceeds of this offering. In February 2014, we retired approximately $152.5 million of the 4.25 percent senior notes due 2022 through a tender offer. The total amount paid, including fees and other charges, was approximately $150 million. We also repaid all commercial paper outstanding, which totaled approximately $600.5 million.

On January 31, 2014, the separation of ONE Gas was completed through a stock dividend distribution of ONE Gas shares to our shareholders after the market closed. We distributed one share of common stock of ONE Gas for every four shares of ONEOK common stock held by ONEOK shareholders of record as of the close of business on January 21, 2014, the record date for the distribution.  We retained no ownership interest in ONE Gas.

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.

In connection with the separation, John W. Gibson retired as Chief Executive Officer of ONEOK and remained Chairman of the Board of ONEOK and ONEOK Partners, effective January 31, 2014. Our Board of Directors approved the expansion of the number of directors of the Board of Directors of ONEOK to 11 from 10 and elected Terry K. Spencer to serve as a member of the Board of Directors effective January 31, 2014. Mr. Spencer serves on the Executive Committee. Mr. Spencer also was elected President and Chief Executive Officer of ONEOK and ONEOK Partners. Also in connection with the separation, Pierce H. Norton II resigned as an officer of ONEOK effective January 31, 2014, to become President and Chief Executive Officer of ONE Gas.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rule 13a-15(b) of the Exchange Act.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).  Under the supervision and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, we evaluated the effectiveness of our internal control over financial reporting based on the framework in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.  Based on our evaluation under that framework and applicable SEC rules, our management concluded that our internal control over financial reporting was effective as of December 31, 2013.

The effectiveness of our internal control over financial reporting as of December 31, 2013, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein (Item 8).

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting during the quarter ended December 31, 2013, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.    OTHER INFORMATION

Not applicable.

PART III.

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors of the Registrant

Information concerning our directors is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

Executive Officers of the Registrant

Information concerning our executive officers is included in Part I, Item 1, Business, of this Annual Report.

Compliance with Section 16(a) of the Exchange Act

Information on compliance with Section 16(a) of the Exchange Act is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

Code of Ethics

Information concerning the code of ethics, or code of business conduct, is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

140

Nominating Committee Procedures

Information concerning the Nominating Committee procedures is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

Audit Committee

Information concerning the Audit Committee is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

Audit Committee Financial Experts

Information concerning the Audit Committee Financial Experts is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 11.    EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Security Ownership of Certain Beneficial Owners

Information concerning the ownership of certain beneficial owners is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

Security Ownership of Management

Information on security ownership of directors and officers is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

Equity Compensation Plan Information

The following table sets forth certain information concerning our equity compensation plans as of December 31, 2013:

	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights			Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities in Column (a))
Plan Category	(a)	(b)			(c)
Equity compensation plans approved by security holders (1)	3,300,215	$	29.61		7,847,642
Equity compensation plans not approved by security holders (2)	498,728	$	42.75	(3)	1,007,204
Total	3,798,943	$	31.33		8,854,846

(1) - Includes shares granted under our Employee Stock Purchase Plan and Employee Stock Award Program, and stock options, restricted stock incentive units and performance-unit awards granted under our Long-Term Incentive Plan and Equity Compensation Plan. For a brief description of the material features of these plans, see Note M of the Notes to Consolidated Financial Statements in this Annual Report. Column (c) includes 2,521,982, 263,489, 1,300,732 and 3,761,439 shares available for future issuance under our Employee Stock Purchase Plan, Employee Stock Award Program, Long-Term Incentive Plan and Equity Compensation Plan, respectively.

(2) - Includes our Employee Non-Qualified Deferred Compensation Plan, Deferred Compensation Plan for Non-Employee Directors and Stock Compensation Plan for Non-Employee Directors. For a brief description of the material features of these plans, see Note M of the Notes to Consolidated Financial Statements in this Annual Report.

(3) - Compensation deferred into our common stock under our Employee Non-Qualified Deferred Compensation Plan and Deferred Compensation Plan for Non-Employee Directors is distributed to participants at fair market value on the date of distribution. The price

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used for these plans to calculate the weighted-average exercise price in the table is $42.75, which represents the year-end closing price of our common stock on the NYSE.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information on certain relationships and related transactions and director independence is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information concerning the principal accountant’s fees and services is set forth in our 2014 definitive Proxy Statement and is incorporated herein by this reference.

PART IV.

ITEM 15.EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(1) Financial Statements			Page No.
	(a)	Report of Independent Registered Public Accounting Firm	81
	(b)	Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011	82
	(c)	Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011	83
	(d)	Consolidated Balance Sheets as of December 31, 2013 and 2012	84-85
	(e)	Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	87
	(f)	Consolidated Statements of Shareholder’s Equity for the years ended December 31, 2013, 2012 and 2011	88-89
	(g)	Notes to Consolidated Financial Statements	90-139
(2) Financial Statements Schedules
	All schedules have been omitted because of the absence of conditions under which they are required.

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(3) Exhibits
	2	Separation and Distribution Agreement, dated as of January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 2.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 15, 2014 (File No. 1-13643)).
	3	Not used.
	3.1	Not used.
	3.2	Not used.
	3.3	Not used.
	3.4	Amended and Restated Bylaws of ONEOK, Inc. (incorporated by reference from Exhibit 3.1 to ONEOK, Inc.’s Current Report on Form 8-K filed February 21, 2014 (File No. 1-13643)).
	3.5	Amended and Restated Certificate of Incorporation of ONEOK, Inc. dated May 15, 2008, as amended (incorporated by reference from Exhibit 3.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q filed August 1, 2012 (File No. 1-13643)).
	3.6	Not used.
	4	Certificate of Designation for Convertible Preferred Stock of WAI, Inc. (now ONEOK, Inc.) filed November 21, 2008 (incorporated by reference from Exhibit 3.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q filed August 1, 2012 (File No. 1-13643)).
	4.1	Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc. filed November 21, 2008 (incorporated by reference from Exhibit No. 3.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q filed August 1, 2012 (File No. 1-13643)).
	4.2	Not used
	4.3	Form of Common Stock Certificate (incorporated by reference from Exhibit 1 to ONEOK, Inc.’s Registration Statement on Form 8-A filed November 21, 1997 (File No. 1-13643)).

4.4	Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.1 to ONEOK, Inc.’s Registration Statement on Form S-3 filed August 26, 1998 (File No. 333-62279)).
4.5	Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to Amendment No. 1 to ONEOK, Inc.’s Registration Statement on Form S-3 filed December 28, 2001 (File No. 333-65392)).
4.6	First Supplemental Indenture dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(a) to ONEOK, Inc.’s Current Report on Form 8-K/A filed October 2, 1998 (File No. 1-13643)).
4.7	Second Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(b) to ONEOK, Inc.’s Current Report on Form 8-K/A filed October 2, 1998 (File No. 1-13643)).

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4.8	Second Amended and Restated Rights Agreement, dated March 31, 2011, between ONEOK, Inc. and Wells Fargo Bank, N.A. as Rights Agent (incorporated by reference from Exhibit 4.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed May 5, 2011 (File No. 1-13643)).
4.9	Not used.
4.10	Not used.
4.11	Not used.
4.12	Not used.
4.13	Not used.
4.14	Second Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to ONEOK, Inc.’s Current Report on Form 8-K filed June 17, 2005 (File No. 1-13643)).
4.15	Third Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.3 to ONEOK, Inc.’s Current Report on Form 8-K filed June 17, 2005 (File No. 1-13643)).
4.16	Tenth Supplemental Indenture, dated September 12, 2013, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.200 percent Senior Notes due 2018 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
4.17	Eleventh Supplemental Indenture, dated September 12, 2013, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 5.000 percent Senior Notes due 2023 (incorporated by reference to Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
4.18	Twelfth Supplemental Indenture, dated September 12, 2013, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.200 percent Senior Notes due 2043 (incorporated by reference to Exhibit 4.4 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
4.19	Indenture, dated September 25, 2006, between ONEOK Partners, L.P. and Wells Fargo Bank, N.A., as trustee (incorporated by reference to Exhibit 4.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 26, 2006 (File No. 1-12202)).
4.20	Eighth Supplemental Indenture, dated  September 13, 2012, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 2.000% Senior Notes due 2017 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 13, 2012 (File No. 1-12202)).
4.21	Second Supplemental Indenture, dated September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.15 percent Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 26, 2006 (File No. 1-12202)).
4.22	Third Supplemental Indenture, dated September 25, 2006, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.65 percent Senior Notes due 2036 (incorporated by reference to Exhibit 4.4 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 26, 2006 (File No. 1-12202)).

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4.23	Fourth Supplemental Indenture, dated September 28, 2007, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.85 percent Senior Notes due 2037 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 28, 2007 (File No. 1-12202)).
4.24	Fifth Supplemental Indenture, dated March 3, 2009, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 8.625 percent Senior Notes due 2019 (incorporated by reference to Exhibit 4.2 to ONEOK Partner, L.P.’s Current Report on Form 8-K filed March 3, 2009 (File No. 1-12202)).
4.25	Ninth Supplemental Indenture, dated September 13, 2012, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.375% Senior Notes due 2022 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 13, 2012 (File No. 1-12202)).
4.26	Form of Class B unit certificate of ONEOK Partners, L.P. (incorporated by reference to Exhibit 4.1 to Northern Border Partners, L.P.’s Current Report on Form 8-K filed April 12, 2006 (File No. 1-12202)).
4.27	Sixth Supplemental Indenture, dated January 26, 2011, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 3.250 percent Senior Notes due 2016 (incorporated by reference from Exhibit 4.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed January 26, 2011 (File No. 1-12202)).
4.28	Seventh Supplemental Indenture, dated January 26, 2011, among ONEOK Partners, L.P., ONEOK Partners Intermediate Limited Partnership and Wells Fargo Bank, N.A., as trustee, with respect to the 6.125 percent Senior Notes due 2041 (incorporated by reference from Exhibit 4.3 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed January 26, 2011 (File No. 1-12202)).
4.29	Indenture, dated January 26, 2012, among ONEOK, Inc. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 26, 2012 (File No. 1.13643)).
4.30	First Supplemental Indenture, dated January 26, 2012, among ONEOK, Inc. and U.S. Bank National Association, as trustee, with respect to the 4.25 percent Senior Notes due 2022 (incorporated by reference to Exhibit 4.2 to ONEOK, Inc.’s Current Report on Form 8-K filed January 26, 2012 (File No. 1-13643)).
10	ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002 (File No. 1-13643).
10.1	ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by reference from Exhibit 99 to ONEOK, Inc.’s Registration Statement on Form S-8 filed January 25, 2001 (File No. 333-95039)).
10.2	ONEOK, Inc. Supplemental Executive Retirement Plan terminated and frozen December 31, 2004 (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed December 20, 2004 (File No. 1-13643)).
10.3	ONEOK, Inc. 2005 Supplemental Executive Retirement Plan, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.3 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009 (File No. 1-13643)).
10.4	Not used.

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10.5	Form of Indemnification Agreement between ONEOK, Inc. and ONEOK, Inc. officers and directors, as amended, dated January 1, 2003 (incorporated by reference from Exhibit 10.4 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003 (File No. 1-13643)).
10.6	Amended and Restated ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed May 27, 2009 (File No. 1-13643)).
10.7	ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan, as amended and restated December 16, 2004 (incorporated by reference from Exhibit 10.3 to ONEOK, Inc.’s Current Report on Form 8-K filed December 20, 2004 (File No. 1-13643)).
10.8	ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.8 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009 (File No. 1-13643)).
10.9	ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.9 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009 (File No. 1-13643)).
10.10	Not used.
10.11	Not used.
10.12	Credit Agreement, dated April 5, 2011, among ONEOK, Inc., as borrower, the lenders party thereto, Bank of America, N.A., as administrative agent, swing line lender, and a letter of credit issuer, and JPMorgan Chase Bank, N.A. and The Royal Bank of Scotland plc, as letter of credit issuers (incorporated by reference from Exhibit 10.1 to ONEOK Inc.’s Current Report on Form 8-K filed April 7, 2011 (File No. 1-13643)).
10.13	Amended and Restated Limited Liability Company Agreement of Overland Pass Pipeline Company LLC entered into between ONEOK Overland Pass Holdings, L.L.C. and Williams Field Services Company, LLC dated May 31, 2006 (incorporated by reference to Exhibit 10.6 to ONEOK Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006, filed August 4, 2006 (File No. 1-12202)).
10.14	Form of ONEOK, Inc. Officer Change in Control Severance Plan (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed July 22, 2011 (File No. 1-13643)).
10.15	First Amendment to Credit Agreement, dated as of March 28, 2013, among ONEOK, Inc., as borrower, the lenders party thereto, Bank of America, N.A., as administrative agent, swing-line lender, and a letter of credit issuer, and JPMorgan Chase Bank, N.A. and The Royal Bank of Scotland plc, as letter of credit issuers (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed on April 2, 2013 (File No. 1-13643)).
10.16	Amendment No. 1 to the Equity Distribution Agreement dated January 13, 2013, by and between ONEOK Partners, L.P. and Citigroup Global Markets Inc. (incorporated by reference to Exhibit 1.2 to ONEOK Partners, L.P.’s Registration Statement on Form S-3 filed January 10, 2013 (File No. 1-12202)).
10.17	Form of Restricted Unit Stock Bonus Award Agreement, as amended and restated effective February 20, 2013 (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Form 8-K filed February 22, 2013 (File No. 1-13643)).
10.18	Form of Performance Unit Award Agreement, as amended and restated effective February 20, 2013 (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Form 8-K filed February 22, 2013 (File No. 1-13643)).

146

10.19	Form of Restricted Unit Stock Bonus Award Agreement dated February 15, 2012 (incorporated by reference to Exhibit 10.19 to ONEOK, Inc.’s Form 10-K filed February 21, 2012, for the fiscal year ended December 31, 2011 (File No. 1-13643)).
10.20	Form of Performance Unit Award Agreement dated February 15, 2012 (incorporated by reference to Exhibit 10.20 to ONEOK, Inc.’s Form 10-K filed February 21, 2012, for the fiscal year ended December 31, 2011 (File No. 1-13643)).
10.21	Not used.
10.22	Underwriting Agreement dated February 28, 2012, among ONEOK Partners, L.P. and Barclays Capital Inc., Citigroup Global Capital Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co. LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed March 2, 2012 (File No. 1-12202)).
10.23	Common Unit Purchase Agreement dated February 28, 2012, between ONEOK Partners, L.P. and ONEOK, Inc. (incorporated by reference to Exhibit 1.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed March 2, 2012 (File No. 1-12202)).
10.24	Equity Distribution Agreement dated November 13, 2012, by and among ONEOK Partners, L.P. and Citigroup Global Capital Markets Inc. (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed November 13, 2012 (File No. 1-12202 )).
10.25	Letter Agreement between ONEOK, Inc. and John W. Gibson dated as of December 9, 2013 (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed on December 10, 2013 (File No. 1-13643)).
10.26	Credit Agreement, dated August 1, 2011, among ONEOK Partners, L.P., as borrower, the lenders party thereto, Citibank, N.A., as administrative agent, swing-line lender and a letter-of-credit issuer, and Barclays Bank and Wells Fargo Bank, N.A., as letter-of-credit issuers (incorporated by reference from Exhibit 10.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed August 2, 2011 (File No. 1-12202)).
10.27	Guaranty Agreement, dated August 1, 2011, by ONEOK Partners Intermediate Limited Partnership in favor of the Citibank, N.A., as administrative agent (incorporated by reference from Exhibit 10.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed August 2, 2011 (File No. 1-12202)).
10.28	Not used.
10.29	Underwriting Agreement, dated September 10, 2012, among ONEOK Partners, L.P. and ONEOK Partner Intermediate Limited Partnership and RBS Securities Inc., Mitsubishi UFJ Securities (USA), Inc. and U.S. Bancorp Investments, Inc., as representative of the several underwriters named therein (incorporated by reference from Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 13, 2012 (File No. 1-12202)).
10.30	Extension Agreement, dated August 1, 2012, among ONEOK Partners, L.P., as Borrower, the lenders party thereto and Citibank, N.A., as administrative agent, swing-line lender and letter-of-credit issuer (incorporated by reference from Exhibit 10.1 to ONEOK Partners, L.P.’s Quarterly Report on 10-Q for the quarter ended June 30, 2012, filed August 1, 2012 (File No. 1-12202)).
10.31	Not used.

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10.32	Services Agreement among ONEOK, Inc., Northern Plains Natural Gas Company, LLC, NBP Services, LLC, Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership executed April 6, 2006, but effective as of April 1, 2006 (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed April 12, 2006 (File No. 1-13643)).
10.33	Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated September 15, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed September 19, 2006 (File No. 1-12202)).
10.34	Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed February 17, 2012 (File No. 1-12202)).
10.35	Form of 2013 Additional Restricted Unit Stock Bonus Award Agreement, effective February 19, 2014.
10.36	Form of 2013 Additional Performance Unit Award Agreement, effective February 19, 2014.
10.37	ONEOK, Inc. Profit-Sharing Plan dated January 1, 2005 (incorporated by reference from Exhibit 99 to ONEOK, Inc.’s Registration Statement on Form S-8 filed December 30, 2004 (File No. 333-121769)).
10.38	Not used.
10.39	Form of Non-Statutory Stock Option Agreement (incorporated by reference from Exhibit 10.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, filed November 3, 2004 (File No. 1-13643)).
10.40	Underwriting Agreement, dated August 7, 2013, among ONEOK Partners, L.P. and Morgan Stanley & Co. LLC, Barclays Capital Inc., J.P. Morgan Securities LLC, UBS Securities LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on August 12, 2013 (File No. 1-12202)).
10.41	Underwriting Agreement, dated September 9, 2013, among ONEOK Partners, L.P. and ONEOK Partners Intermediate Limited Partnership and RBS Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Deutsche Bank Securities Inc., as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on September 12, 2013 (File No. 1-12202)).
10.42	Amendment Agreement, dated as of December 20, 2013, among ONEOK, Inc., Bank of America, N.A., as administrative agent, swing-line lender, a letter of credit issuer and a lender, and the other lenders and letter of credit issuers parties thereto (including the Amended and Restated Credit Agreement attached as an annex thereto) (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed on December 23, 2013 (File No. 1-13643)).
10.43	Amendment Agreement, dated as of December 20, 2013, among ONEOK Partners, L.P., Citibank, N.A., as administrative agent, swing-line lender, a letter of credit issuer and a lender, and the other lenders and letter of credit issuers parties thereto (including the Amended and Restated Credit Agreement attached as an annex thereto) (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed on December 23, 2013 (File No. 1-12202)).
10.44	ONEOK, Inc. Equity Compensation Plan, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.44 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009 (File No. 1-13643)).

148

10.45	Credit Agreement, dated as of December 20, 2013, among ONE Gas, Inc., Bank of America, N.A., as administrative agent, swing-line lender and a letter of credit issuer, and the other lenders and letter of credit issuers parties thereto (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Current Report on Form 8-K filed on December 23, 2013 (File No. 1-13643)).
10.46	Tax Matters Agreement, dated as of January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Current Report on Form 8-K filed January 15, 2014 (File No. 1-13643)).
10.47	Transition Services Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Current Report on Form 8-K filed January 15, 2014 (File No. 1-13643)).
10.48	Employee Matters Agreement, dated January 14, 2014, by and between ONE Gas, Inc. and ONEOK, Inc. (incorporated by reference to Exhibit 10.3 to ONEOK, Inc.’s Current Report on Form 8-K filed January 15, 2014 (File No. 1-13643)).
10.49	Form of 2012 Additional Restricted Unit Stock Bonus Award Agreement, effective February 19, 2014.
10.50	Form of 2012 Additional Performance Unit Award Agreement, effective February 19, 2014.
10.51	Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated July 20, 2007 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, filed August 3, 2007 (File No. 1-12202)).
10.52	Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated July 12, 2011 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed July 13, 2011 (File No. 1-12202)).
10.53	Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of ONEOK Partners GP, L.L.C. effective July 14, 2009 (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed February 17, 2012 (File No. 1-12202)).
10.54	Form of 2014 Restricted Unit Award Agreement, effective February 19, 2014.
10.55	Form of 2014 Performance Unit Award Agreement, effective February 19, 2014.
10.56	First Amended and Restated Limited Liability Company Agreement of ONEOK ILP GP, L.L.C. effective July 14, 2009 (incorporated by reference to Exhibit 99.2 to ONEOK Partners, L.P.’s Current Report on Form 8-K filed July 17, 2009 (File No. 1-12202)).
10.57	Not used.
10.58	Not used.
10.59	Form of Restricted Unit Stock Bonus Award Agreement (incorporated by reference from Exhibit 10.59 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, filed February 22, 2011 (File No. 1-13643)).
10.60	Form of Performance Unit Award Agreement (incorporated by reference from Exhibit 10.60 to ONEOK, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010, filed February 22, 2011 (File No. 1-13643)).

149

10.61	Accelerated Share Repurchase Agreement dated June 11, 2012, by and between ONEOK, Inc. and Goldman Sachs & Co. (incorporated by reference to Exhibit 10.1 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, filed August 1, 2012 (File No. 1-12202)).
10.62	ONEOK, Inc. Employee Stock Purchase Plan as amended and restated effective May 23, 2012 (incorporated by reference to Exhibit 10.2 to ONEOK, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2012, filed August 1, 2012 (File No. 1-12202)).
12	Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2013, 2012, 2011, 2010 and 2009.
21	Required information concerning the registrant’s subsidiaries.
23	Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.
31.1	Certification of Terry K. Spencer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Derek S. Reiners pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Terry K. Spencer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
32.2	Certification of Derek S. Reiners pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definitions Document
101.LAB	XBRL Taxonomy Label Linkbase Document
101.PRE	XBRL Taxonomy Presentation Linkbase Document

Attached as Exhibit 101 to this Annual Report are the following XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the years ended December 31, 2013, 2012 and 2011; (iii) Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011; (iv) Consolidated Balance Sheets at December 31, 2013 and 2012; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; (vi) Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2013, 2012 and 2011; and (vii) Notes to Consolidated Financial Statements.

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

150

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Date: February 25, 2014		ONEOK, Inc.
		Registrant
	By:	/s/ Derek S. Reiners
		Derek S. Reiners
		Senior Vice President,
		Chief Financial Officer and Treasurer

Pursuant to the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on this 25th day of February 2014.

/s/ John W. Gibson	/s/ Terry K. Spencer
John W. Gibson	Terry K. Spencer
Chairman of the Board	President, Chief Executive Officer and
	Director
/s/ Derek S. Reiners	/s/ Sheppard F. Miers III
Derek S. Reiners	Sheppard F. Miers III
Senior Vice President,	Vice President and
Chief Financial Officer and Treasurer	Chief Accounting Officer
/s/ James C. Day	/s/ Julie H. Edwards
James C. Day	Julie H. Edwards
Director	Director
/s/ William L. Ford	/s/ Bert H. Mackie
William L. Ford	Bert H. Mackie
Director	Director
/s/ Steven J. Malcolm	/s/ Jim W. Mogg
Steven J. Malcolm	Jim W. Mogg
Director	Director
/s/ Pattye L. Moore	/s/ Gary D. Parker
Pattye L. Moore	Gary D. Parker
Director	Director
/s/ Eduardo A. Rodriguez
Eduardo A. Rodriguez
Director

151

EX-10.35

Exhibit 10.35

ADDITIONAL 2013 RESTRICTED UNIT

STOCK BONUS AWARD

AGREEMENT

On January 31, 2014, shares of common stock of ONE Gas, Inc. were distributed to shareholders of ONEOK, Inc. common stock (the “Distribution”). The Board of Directors of ONEOK, Inc. has approved the equitable adjustment of outstanding share-based awards in an attempt to preserve the value of such awards immediately before and after the Distribution. Accordingly, this Additional Restricted Unit Stock Bonus Award Agreement (hereinafter referred to as “Agreement”) is entered into as of the ___ day of February, 2014, by and between ONEOK, Inc., an Oklahoma corporation, (hereinafter referred to as “Corporation”), and «Officer_Name» (hereinafter referred to as “Grantee”), an employee of the Corporation or a division or subsidiary thereof, pursuant to the terms of the ONEOK, Inc. Long-Term Incentive Plan, as amended (hereinafter referred to as the “Plan”).

1.Adjustment to 2013 Restricted Unit Award. This Agreement and that certain Restricted Unit Stock Bonus Award, dated February ___, 2014, a copy of which is attached hereto and incorporated herein by reference (collectively, the “Agreement”) constitute evidence of the issuance and grant of a Stock Bonus Award (hereinafter referred to as “Award”) to the Grantee by the Corporation under the Adjustment provisions of the Plan and the Restricted Unit Stock Bonus Award dated February 20, 2013 (the “2013 Agreement”), pursuant to which shares of the Corporation’s common stock (hereinafter referred to as “Common Stock”) shall be distributed in the future to the Grantee in lieu of, or as a supplement to, any other compensation that may have been earned by services rendered prior to the date the distribution is made, pursuant to and in accordance with the terms of this Agreement under which the Corporation grants a Stock Bonus Award under the Plan that shall include and is to be awarded by the grant restricted stock units (“Restricted Units”) under the Plan in the amount of «No_of_Restricted_Units» additional Restricted Units that shall entitle the Grantee to receive shares of Common Stock all subject to the terms, provisions, and conditions of this Agreement (including, without limitation, the restrictions stated in paragraph 5, below) and of the Plan, which are incorporated herein by reference. The Award and Restricted Units granted pursuant to this Agreement include the right of Grantee to receive dividend equivalents (“Dividend Equivalents”) upon the declaration and payment of dividends by the Corporation to all holders of all common stock to the extent and as provided for in paragraph 5 of this Agreement, below. This Agreement, when executed by the Grantee, together with the Notice of Restricted Unit Stock Bonus Award and Agreement constitute an agreement between the Corporation and the Grantee. Notwithstanding the foregoing, should there be any inconsistency between the provisions of this Agreement and the terms of the Award stated in the resolutions and records of the Board of Directors of the Corporation, or the Plan, the provisions of such resolutions and records of the Plan shall control. Moreover, the Restricted Units awarded pursuant to this Agreement shall be deemed to satisfy any obligation of the Corporation to provide any additional Restricted Units to Grantee under the Plan or the 2013 Agreement as a result of the Distribution. The grant of Restricted Units to the Grantee and the Grantee’s entitlement to receive and be issued shares of Common Stock shall be effective in the manner and to the extent provided in this Agreement and the Plan as to all or any part of the shares of Common Stock subject to the grant from time to time during the period stated herein.

2.Plan. The Award is issued pursuant to the Plan, as approved by the Shareholders of the Corporation, which provides that a specific aggregate number of shares of Common Stock of the Corporation may be issued or transferred pursuant to Stock Incentives under the Plan. The Plan specifies the authority of the Corporation, its Board of Directors, and a committee of the Board of Directors to select employees to be granted Stock Incentives. The Executive Compensation Committee of the Board of Directors (hereinafter referred to as the “Committee”) is authorized to administer the Plan with respect to the Award and the grant of the Award made to the Grantee pursuant to the Plan. Except where expressly stated or clearly indicated otherwise by the terms of this Agreement, all terms, words and phrases used herein shall have the same meaning and effect as stated and as defined in the Plan. The Grantee has been provided a complete copy of the Plan with this Agreement.

3.Grantee’s Agreement Concerning Award and Employment. In consideration of the Corporation’s granting the Award as incentive compensation to Grantee pursuant to this Agreement, the Grantee by acceptance thereof, and signing this Agreement evidencing its terms, agrees to such terms and to continue to contribute and perform service in the employ of the Corporation (or a division or subsidiary thereof) at the direction, will and pleasure of the Corporation and the Board of Directors. Provided, however, neither the foregoing agreement of the Grantee in this paragraph 3, nor any other provision in the Plan shall confer on the Grantee any right to continue in the employ of the Corporation (or a division or subsidiary thereof), or interfere in any way with the right of the Corporation (or such division or subsidiary) to terminate the Grantee’s employment at any time.

4.Registration of Stock; Grantee’s Representation With Respect to Acquiring for Investment. It is intended by the Corporation that the Plan and shares of Common Stock covered by the Award issued and granted to the Grantee referred to in paragraph 1, above, are to be registered under the Securities Act of 1933, as amended, prior to the date of the grant; provided, that in the event such registration is for any reason not made effective for such shares, the Grantee agrees, for the Grantee, and for the Grantee’s heirs and legal representatives by inheritance or bequest, that all shares acquired pursuant to the grant will be acquired for investment and not with a view to, or for sale or tender in connection with the distribution of any part thereof, including any transfer or distribution of such shares by the Grantee pursuant to the grant and this Agreement or as otherwise allowed by the Plan.

5.Restrictions; Restricted Period; Transfer of Common Stock to Grantee. The issue and grant of the Award to the Grantee stated in paragraph 1, above, are subject to the following terms and conditions:

(a)The ownership and transfer of the Restricted Units granted to the Grantee shall be restricted during the period beginning February __, 2014, the date of the grant thereof (hereinafter referred to as “Grant Date”) and ending on February 20, 2016, (which period is hereinafter referred to as “Restricted Period”), as herein provided.

(b)The Restricted Units, or any Common Stock or cash to be paid or transferred to Grantee as a Stock Bonus Award under the Plan pursuant to the Award may not be sold, assigned, transferred, pledged, encumbered or otherwise disposed of by Grantee or any other

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person except as provided in this Agreement and the Plan until the expiration of the Restricted Period.

(c)The Grantee shall earn and become vested and entitled to the Restricted Units granted by this Award under paragraph 1, above, at the expiration of the Restricted Period. Upon expiration of the Restricted Period, the Grantee shall be entitled to receive, and the Corporation shall issue to Grantee one (1) share of Common Stock for each Restricted Unit that becomes earned by and vested in the Grantee pursuant to the Award. The Common Stock the Grantee becomes entitled to receive under the Award shall be paid, distributed, transferred and issued on the date of expiration of the Restricted Period, or as soon as practicable after such date as determined by the Committee, but in no event after the 15^th day of the third month after such date.

(1)The Grantee shall become vested in the Restricted Units granted to the Grantee hereunder and Common Stock paid and transferred pursuant to the Award free and clear of all restrictions imposed by the Award if the Grantee’s employment by the Corporation (or a division or Subsidiary thereof) does not terminate during the Restricted Period; provided, that the Grantee shall become partially vested in the Restricted Units and Common Stock payable pursuant to the Award and the restrictions imposed by the Award shall partially cease to apply in certain events to the extent described in paragraph 6(d), below.

(2)If the Grantee’s employment with the Corporation (or a division or Subsidiary thereof) terminates prior to the end of the Restricted Period by reason of (i) the Grantee’s voluntary termination of the Grantee’s employment with the Corporation (or a division or Subsidiary), or (ii) the involuntary Termination for Cause by the Corporation of the Grantee’s employment with the Corporation (or a division or Subsidiary), the Grantee shall forfeit all the Grantee’s right, title or interest in the Restricted Units, and to any Common Stock payable or to be issued pursuant to the Award; and the Grantee shall forfeit such right, title and interest in the Restricted Units, and to any Common Stock payable or to be issued pursuant to the Award regardless of the reason for such termination of employment. Any such termination of employment of the Grantee described in the preceding sentence shall not be deemed to occur by reason of transfer of employment of the Grantee by or between the Corporation and any division or Subsidiary of the Corporation.

(3) The Grantee shall not be entitled to vote any shares of Common Stock and, except as provided in paragraph 5(c)(4), the Grantee shall not have any right or interest as a holder of Common Stock by reason of the Award granted under this Agreement prior to the end of the Restricted Period and actual issuance of Common Stock to the Grantee pursuant to the Award.

(4) During the Restricted Period Grantee shall earn and Dividend Equivalents shall be credited to Grantee with respect to Restricted Units in the form of additional Restricted Units (“Additional Restricted Units”) to the extent and as provided for in this Agreement, as follows:

(i) On each date on which (a) the Restricted Units and Additional Restricted Units credited to Grantee pursuant to the Award under this Agreement have not become vested

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or have not been forfeited pursuant to the terms and provisions of this Agreement, and (b) the Company declares and pays a cash dividend to holders of Common Stock (each, a “Dividend Payment Date”), a number of Additional Restricted Units will be credited to Grantee in an amount (including fractional Additional Restricted Units) determined by dividing (x) the aggregate cash dividends that would have been paid on the number of shares of Common Stock (including fractional shares of Common Stock) into which the Restricted Units and Additional Restricted Units theretofore granted and credited to the Grantee under this Agreement on the Dividend Payment Date would be converted if vested on such date, by (y) the Fair Market Value of a share of Common Stock on such Dividend Payment Date.

(ii) The Additional Restricted Units credited to Grantee pursuant to paragraph 5(c)(4)(i) shall be added to and included in a cumulative aggregate amount of Additional Restricted Units credited to the Grantee hereunder, which shall be recorded and accounted for as a separate identifiable amount to the credit of the Grantee (“Additional Restricted Units Amount”).

(iii) Except as provided below with respect to the treatment of a fractional Additional Restricted Unit or fractional share of Common Stock attributable to Grantee upon vesting hereunder, all the Additional Restricted Units and the Additional Restricted Units Amount so credited to Grantee shall be subject to the same terms and conditions as the Restricted Units granted pursuant to paragraph 1 above, and such Additional Restricted Units and Additional Restricted Units Amount shall be forfeited in the event that the Restricted Units granted pursuant to paragraph 1, above are forfeited.

(iv) Unless otherwise expressly stated herein, any reference to Restricted Units in this Agreement, including without limitation, provisions regarding partial vesting of Restricted Units in particular circumstances, shall be deemed to similarly and in like manner refer and apply to Additional Restricted Units credited to Grantee.

(v) The Grantee shall earn and become vested and entitled to the Additional Restricted Units granted by this Award under this paragraph 5(c)(4) at the expiration of the Restricted Period. Upon expiration of the Restricted Period, Grantee shall be entitled to receive, and the Corporation shall issue to Grantee one (1) share of Common Stock for each Additional Restricted Unit that becomes earned by and vested in Grantee pursuant to the Award; provided, that the shares of Common Stock to be issued to and received by Grantee for Additional Restricted Units, shall be only issued in whole shares of Common Stock, and any fractional share of Common Stock attributable to the Additional Restricted Units credited to Grantee shall paid to Grantee in an amount of cash equal to the Fair Market Value of a fractional share of Common Stock.

6.Transferability of Restricted Units, Cash or Common Stock; Termination of Employment.

(a)Except as provided in subparagraph (b) of this paragraph 6, below, this Agreement, the Grantee’s rights and obligations hereunder, and the Restricted Units granted hereunder shall not be transferable by the Grantee otherwise than by will or the laws of descent and distribution which apply to the Grantee’s estate.

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(b)Notwithstanding the foregoing, the Grantee may transfer any part or all of the Grantee’s rights in the Restricted Units to members of the Grantee’s immediate family, or to one or more trusts for the benefit of such immediate family members, or partnerships in which such immediate family members are the only partners if the Grantee does not receive any consideration for the transfer. In the event of any such transfer, Restricted Units shall continue to be subject to the same terms and conditions otherwise applicable hereunder and under the Plan immediately prior to its transfer, except that such rights shall not be further transferable by the transferee inter vivos, except for transfer back to the original Grantee. For any such transfer to be effective, the Grantee must provide prior written notice thereof to the Committee, unless otherwise authorized and approved by the Committee, in its sole discretion; and the Grantee shall furnish to the Committee such information as it may request with respect to the transferee and the terms and conditions of any such transfer. For purposes of transfer of this grant under this subparagraph (b), “immediate family” shall mean the Grantee’s spouse, children and grandchildren.

(c)Notwithstanding anything to the contrary expressed or implied herein (including without limitation, the restrictions stated in paragraph 5, above, applicable to the Restricted Units), all rights and interest of the Grantee in the Restricted Units shall become invalid and wholly terminated and forfeited upon (i) the Grantee’s voluntary termination of the Grantee’s employment with the Corporation (or a division or Subsidiary), or (ii) the involuntary Termination for Cause by the Corporation of the Grantee’s employment with the Corporation (or a division or Subsidiary).

(d)Notwithstanding the foregoing provisions, in the event of termination of the Grantee’s employment with the Corporation (or a division or Subsidiary) during the Restricted Period by reason of (i) the involuntary termination of the Grantee’s employment with the Corporation (or a division or Subsidiary) other than a Termination for Cause (ii) the Retirement of the Grantee, (iii) the Total Disability of the Grantee, or (iv) the Grantee’s death while still employed by the Corporation (or a division or Subsidiary), then partial vesting shall be allowed as provided in this paragraph 6(d) and the Grantee shall become vested in and receive, in the event of any such involuntary termination of employment other than a Termination for Cause, Retirement or Total Disability, and the legatees, designated Beneficiary, personal representative or heirs of the Grantee shall be vested in and entitled to receive, in the event of the Grantee’s death, the percentage of the Restricted Units which is determined by dividing the number of full months which have elapsed under the Restricted Period at the time of such termination of employment by the number of full months in the Restricted Period. The Grantee, or legatees, designated Beneficiary, personal representative or heirs of the Grantee, as applicable, shall be entitled to receive and the Corporation shall issue, to the Grantee, or such legatees, designated Beneficiary, personal representative or heirs, as applicable, one share of Common Stock for each vested Restricted Unit, which shall be issued, paid and transferred pursuant to the Award free and clear of all restrictions imposed by the Award on the date of expiration of the Restricted Period, or as soon as practicable thereafter as determined by the Committee, but in no event later than the 15^th day of the third calendar month after the date of the expiration of the Restricted Period.

(e)The Grantee may designate a Beneficiary to receive any rights of the Grantee which may become vested in the event of the death of the Grantee under procedures and

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in the form established by the Committee; and in the absence of such designation of a beneficiary, any such rights shall be deemed to be transferred to the estate of the Grantee.

(f)For purposes of the Award and this Agreement, an “involuntary termination” shall mean that the Corporation (or a division or Subsidiary) has ended the Grantee’s employment with the Corporation (or a division or Subsidiary) without the Grantee having an opportunity to continue employment with the Corporation (or a division or Subsidiary); an “involuntary Termination for Cause” of the Grantee’s employment with and by the Corporation (or a division or Subsidiary) shall mean that the Corporation (or a division or Subsidiary) has ended such employment by reason of (i) the Grantee’s conviction in a court of law of a felony, or any crime or offense involving misuse or misappropriation of money or property, (ii) the Grantee’s violation of any covenant, agreement or obligation not to disclose confidential information regarding the business of the Corporation (or a division or Subsidiary), (iii) any violation by the Grantee of any covenant not to compete with the Corporation (or a division or Subsidiary), (iv) any act of dishonesty by the Grantee which adversely effects the business of the Corporation (or a division or Subsidiary), (v) any willful or intentional act of the Grantee which adversely affects the business of, or reflects unfavorably on the reputation of the Corporation (or a division or Subsidiary), (vi) the Grantee’s use of alcohol or drugs which interferes with the Grantee’s Restricted of duties as an employee of the Corporation (or a division or Subsidiary), or (vii) the Grantee’s failure or refusal to perform the specific directives of the Corporation’s Board of Directors, or its officers which directives are consistent with the scope and nature of the Grantee’s duties and responsibilities with the existence and occurrence of all of such causes to be determined by the Corporation, in its sole discretion; provided, that nothing contained in the foregoing provisions of this paragraph shall be deemed to interfere in any way with the right of the Corporation (or a division or Subsidiary), which is hereby acknowledged, to terminate the Grantee’s employment at any time without cause; and “voluntary termination” shall mean that the Grantee had an opportunity to continue employment with the Corporation (or a division or Subsidiary), but did not do so.

(g)For purposes of the Award and this Agreement, “Retirement” shall mean a voluntary termination of employment of the Grantee with the Corporation (or a division or Subsidiary) by the Grantee if at the time of such termination of employment the Grantee has both completed five (5) years of service with the Corporation (or a division or Subsidiary) and attained age fifty (50); and “Total Disability” shall mean that the Grantee is permanently and totally disabled and unable to engage in any substantial gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than twelve (12) months, and has established such disability to the extent and in the manner and form as may be required under the provisions of Section 22(e)(3) of the Internal Revenue Code of 1986, as amended (or corresponding section of any future federal tax code), and regulations thereunder.

7.Deferral of Payment, Distribution and Transfer of Stock.

(a)The payment, distribution and transfer of Restricted Units, Common Stock and cash of the Grantee becomes entitled to receive upon the Grantee’s separation from service with the Corporation upon the Grantee’s Retirement prior to the expiration of the Restricted Period under paragraph 6 (d), above, shall be paid, distributed and transferred to the Grantee in a

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single payment, distribution and transfer at the Specified Time of the Grantee’s separation from service with the Corporation by such Retirement, as soon as practicable thereafter as determined by the Committee, but in no event later than the 15^th day of the third calendar month after date of such Retirement, and the Grantee shall not be permitted, directly or indirectly, to designate the time of payment, distribution and transfer or the taxable year in which it is to be made. The Specified Time of payment, distribution and transfer of any other compensation that is deferred under this Agreement or the Award shall be the date of expiration of the Restricted Period, or as soon as practicable thereafter as determined by the Committee, but in no event later than the 15^th day of the third calendar month after the date of expiration of the Restricted Period, and the Grantee shall not be permitted, directly or indirectly, to designate the time of payment, distribution or transfer or the taxable year in which it is to be made.

(b)The Specified Time of payment and form of payment specified in paragraph 6(a), above shall be considered as the irrevocable deferral election of the Corporation and the Grantee of the time and form of payment for purposes of the application to this Agreement and the Award of the provisions of Section 409A of the Internal Revenue Code of 1986, as amended, and the provisions of this Agreement related thereto. No other election to defer compensation, or subsequent election or acceleration of the time and form of payment of compensation is intended or shall be allowed.

(c)The Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the restrictions made applicable to the Grantee and the Restricted Units during the Restricted Period. This Agreement and the rights and obligations of the parties involved, shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the Common Stock that would otherwise be transferred and delivered to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

(d)The provisions of this Agreement providing for the deferral of payment, distribution, transfer or issuance of Restricted Units, Common Stock or cash shall be applicable solely and exclusively to the Grantee and the Award Agreement and Award referred to herein, and shall not apply to any other stock incentive or other grant, award or transfer provided for or made under the Plan.

(e)Notwithstanding anything otherwise provided under the Plan or in this Agreement the following requirements shall apply to this Award Agreement and the Award, to

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all elections or subsequent elections made by the Grantee, and to all distributions and payments made to the Grantee pursuant to this Award Agreement and Award

(1)Any compensation for services performed by the Grantee during a taxable year may be deferred only if the election to defer such compensation by the Grantee or the Corporation is made not later than the close of the preceding taxable year or such other time as provided in Treasury Regulations under section 409A of the Internal Revenue Code of 1986, as amended (“Code”), but in all events any deferral of the payment, distribution, transfer or issuance of Restricted Units, Common Stock or cash pursuant to the Award and Award Agreement may be made only by an election that is made on or before the Election Date.

(2)Any compensation deferred shall not be distributed earlier than:

(i) Separation from Service of the Grantee,

(ii) the date the Grantee becomes Disabled,

(iii) death of the Grantee,

(iv) Specified Time (or pursuant to a Fixed Schedule) specified under

the plan under which the compensation is deferred at the date

of deferral of such compensation,

(v) a Change in Ownership or Control, or

(vi) the occurrence of an Unforeseeable Emergency.

(3)If the Grantee is a Specified Employee, no payment or distribution shall be made before the date which is six (6) months after the date of the Grantee’s Separation from Service, or, if earlier, the date of death of the Grantee.

(4)No acceleration of the time or schedule of any distribution or payment under the plan under which compensation is deferred shall be permitted or allowed, except to the extent provided in Treasury Regulations issued under Code section 409A.

(5)This Agreement shall not permit a subsequent election, unless authorized and agreed to in writing by the Corporation and Grantee; and if under the Plan or this Agreement compensation is deferred or the Committee acting pursuant to the Plan, permits under any subsequent election by a Participant a delay in a payment or a change in the form of payment of compensation deferred under this Award Agreement and Award, such subsequent election shall not take effect until at least twelve (12) months after the date on which it is made. In the case of a subsequent election related to a payment to be made upon Separation from Service of the Grantee, at a Specified Time or pursuant to a Fixed Schedule, or upon a Change in Ownership or Control, the first payment with respect to which such subsequent election is made shall be deferred for a period of not less than five (5) years from the date such payment would otherwise have been made; and any such subsequent election related to a payment at a Specified Time or pursuant to a Fixed Schedule may not be made less than twelve (12) months prior to the date of the first scheduled payment to which it relates.

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(6)For purposes of the Plan, this Agreement and the Award, and the entitlement to and time of payment of any compensation deferred under this Agreement or the Award, the following terms and definitions shall apply:

(i)”Change of Ownership or Control” means to the extent provided by Treasury Regulations issued under Code Section 409A, a change in the ownership or effective control of the Corporation, or in the ownership of a substantial portion of the assets of the Corporation, which shall be if (i) a Person acquires more than 50% of the Corporation’s stock; (ii) a Person acquires during a 12-month period at least 30% (or a higher percentage specified under the Plan) of the Corporation’s stock; (iii) a majority of the members of the Board of Directors of the Corporation are replaced during a 12-month period; or (iv) a Person acquires during a 12-month period at least 40% of the gross fair market value of the Corporation’s assets.

(ii)”Disabled” means that an individual (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of the individual’s employer

(iii)”Fixed Schedule” means the distribution or payment of compensation deferred under this Agreement and award in a fixed schedule of distributions or payments that are determined and fixed at the time the deferral of such compensation is first elected by the Grantee or the Corporation.

(iv)”Specified Employee” means a key employee (as defined in Code section 416(i) without regard to paragraph (5) thereof) of the Corporation

(v)”Specified Time” means a specified date at which deferred compensation deferred by or for the Grantee pursuant to this Agreement and Award is required to be distributed or paid and which is specified at the time of the election of deferral of such deferred compensation.

(vi)“Unforeseeable Emergency” means a severe financial hardship to the participant resulting from an illness or accident of the participant, the participant’s spouse, or a dependent (as defined in Code section 152(a)) of the participant, loss of the participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. As determined under Treasury Regulations under Code section 409A, the amounts distributed with respect to an emergency shall not exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the participant’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship).

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8.Administration of Restricted Unit Award. The grant of the Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the restrictions made applicable to the Grantee and the Restricted Units during the Restricted Period. This Agreement and the rights and obligations of the parties involved, shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the Common Stock that would otherwise be transferred and delivered to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

9.Adjustment Provisions. It is understood that, prior to the expiration of the Restricted Period, certain changes in capitalization of the Corporation may occur. It is, therefore, understood and agreed with respect to changes in capitalization that:

(a)If a stock dividend is declared on the Common Stock of the Corporation, which has not been granted as a dividend equivalent, there shall be added to the number of Restricted Units described in paragraph 1 of this Agreement, the number of Restricted Units which the Grantee would have been entitled to if the Grantee had been fully vested and the unrestricted owner of the number of Restricted Units then held under the Award granted, but not theretofore received without restriction; provided, however, that the additional Restricted Units shall be subject to all terms and provisions of this Agreement (including, without limitation, the restrictions stated in paragraph 5, above), and in making such adjustments, no fractional Restricted Units shall be awarded, and the Grantee shall be entitled to receive only the number of full Restricted Units to which the Grantee may be entitled by reason of such adjustment at the adjusted grant price per share.

(b)In the event of an increase in the outstanding shares of Common Stock of the Corporation, effectuated for the purpose of acquiring properties or securities of another corporation or business enterprise, there shall be no increase in the number of shares of Restricted Units which are the subject matter of the Award evidenced by this Agreement as a result of such acquisition.

(c)In the event of an increase or decrease in the number of outstanding shares of Common Stock of the Corporation through recapitalization, reclassification, stock split-ups, consolidation of shares, changes in par value and the like, an appropriate adjustment shall be made in the number of Restricted Units described in paragraph 1 of this Agreement, by increasing or decreasing the number of Restricted Units, as may be required to enable the

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Grantee to acquire the same proportionate stockholdings as the grant of the Award would originally have provided. Provided, however, that any additional Restricted Units shall be subject to all terms and provisions of this Agreement (including, without limitation, the restrictions stated in paragraph 5, above), and that in making such adjustments, no fractional Restricted Units shall be awarded, and the Grantee shall be entitled to receive only the number of full Restricted Units to which the Grantee may be entitled by reason of such adjustment.

(d)Except with respect to the time of payment of any compensation deferred under this Agreement, to the extent Restricted Units are still restricted and not vested in Grantee at the time of a Change in Control with respect to the Corporation, then pursuant to the provisions of the Plan, they shall become fully vested and completely unrestricted and free and clear of any restrictions stated herein at that time; provided, that if such Change in Control occurs less than six (6) months after the date of the grant of Restricted Units to the Grantee, then Restricted Units shall become fully vested and completely unrestricted and free and clear of any restrictions stated herein at the time of such Change in Control only if the Grantee agrees in writing, if requested by the Corporation in writing, to remain in the employ of the Corporation or a division or subsidiary of the Corporation at least through the date which is six (6) months after the date the grant was made with substantially the same title, duties, authority, reporting relationships, and compensation as on the day immediately preceding the Change in Control. The provisions of this subparagraph (d) shall be applied in addition to, and shall not reduce, modify, or change any other obligation or right of the Grantee otherwise provided for in paragraph 3, above, concerning the Grantee’s continued employment with the Corporation or the termination thereof. If the Restricted Units become subject to this subparagraph (d), they shall become fully vested in the Grantee and nonforfeitable. Such Restricted Units are subject to the provisions of the Plan authorizing the Corporation, or a committee of its Board of Directors, to provide in advance or at the time of a Change in Control for cash to be paid in settlement of the Restricted Units, all subject to such terms and conditions as the Corporation or the Committee, in its sole discretion, may determine and impose. For purposes of this subparagraph (d), the term “Change in Control” shall have the same meaning as provided in the definition of that term stated in the Plan, including any amendments thereof which may be made from time to time in the future pursuant to the provisions of the Plan, with any amended definition of such term to apply to all events thereafter coming within the amended meaning.

10.Required Grantee Repayment/Reduction Provision. Notwithstanding anything in the Plan, the Award or this Agreement to the contrary, all or a portion of the Award made to the Grantee under this Agreement is subject to being called for repayment to the Corporation or reduced in any situation where the Board of Directors of the Corporation or a Committee thereof determines that fraud, negligence, or intentional misconduct by the Grantee was a contributing factor to the Corporation having to restate all or a portion of its financial statement(s). The Committee may determine whether the Corporation shall effect any such repayment or reduction: (i) by seeking repayment from the Grantee, (ii) by reducing (subject to applicable law and the terms and conditions of the Plan or any other applicable plan, program, or arrangement) the amount that would otherwise be awarded or payable to the Grantee under the Award, the Plan or any other compensatory plan, program, or arrangement maintained by the Corporation, (iii) by withholding payment of future increases in compensation (including the payment of any discretionary bonus amount) or grants of compensatory awards that would otherwise have been made in accordance with the Corporation’s otherwise applicable

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compensation practices, or (iv) by any combination of the foregoing. The determination regarding the Grantee’s conduct, and repayment or reduction under this provision shall be within the sole discretion of the Committee and shall be final and binding on the Grantee and the Corporation. The Grantee, in consideration of the grant of the Award, and by the Grantee’s execution of this Agreement, acknowledges the Grantee’s understanding of the agreement to this provision, and hereby agrees to make and allow an immediate and complete repayment or reduction in accordance with this provision in the event of a call for repayment or other action by the Corporation or Committee to effect its terms with respect to the Grantee, the Award and/or any other compensation described herein.

11.Stock Reserved. The Corporation shall at all times during the term of the Award reserve and keep available such number of shares of its Common Stock as will be sufficient to satisfy the Award issued and granted to Grantee and the terms stated in this Agreement, and shall pay all original issue taxes, if any, on the transfer of the Common Stock to the Grantee and all other fees and expenses necessarily incurred by the Corporation in connection therewith.

12.Rights of Shareholder. Except as otherwise provided in this Agreement, the Grantee shall have no rights as a shareholder of the Corporation in respect of the Restricted Units or Common Stock for which the Award is granted; and the Grantee shall not be considered or treated as a record owner of shares of Common Stock with respect to the Restricted Units until the Common Stock is issued to Grantee and no longer subject to any of the restrictions imposed under the Award indicated in this Agreement, and Common Stock is actually issued and transferred to Grantee.

13.Entire Agreement. This Agreement contains the entire terms of the Award, and may not be changed orally or other than by a written Agreement issued and approved by the Corporation pursuant to the Plan. This Agreement supersedes any agreements or understandings that may have previously existed, and there are no other agreements or understandings, relating to its subject matter.

14.Successors and Assigns. The Award evidenced by this Agreement shall inure to the benefit of and be binding upon the heirs, legatees, legal representatives, successors, and assigns of the parties hereto.

The Grantee hereby acknowledges receipt of this Agreement, the Notice of Restricted Unit Award Agreement and a copy of the Plan, and accepts the Award under the terms and conditions stated in this Agreement, subject to all terms and provisions of the Plan, by signing this Agreement in duplicate originals, as of the date first stated above.

Date	«Officer_Name»
	Grantee

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EX-10.36

Exhibit 10.36

ADDITIONAL 2013 PERFORMANCE UNIT AWARD AGREEMENT

On January 31, 2014, shares of common stock of ONE Gas, Inc. were distributed to shareholders of ONEOK, Inc. common stock (the “Distribution”). The Board of Directors of ONEOK, Inc. has approved the equitable adjustment of outstanding share-based awards in an attempt to preserve the value of such awards immediately before and after the Distribution. Accordingly, this Additional Performance Unit Award Agreement (hereinafter referred to as “Agreement”) is entered into as of the __ day of February, 2014, by and between ONEOK, Inc., an Oklahoma corporation, (hereinafter referred to as “Corporation”), and «Officer_Name» (hereinafter referred to as “Grantee”), an employee of the Corporation or a division or subsidiary thereof, pursuant to the terms of the ONEOK, Inc. Equity Compensation Plan, effective February 17, 2005, as amended (hereinafter referred to as the “Plan”).

1.Adjustment to 2013 Performance Unit Award. This Agreement and that certain Notice of Performance Unit Award and Agreement, dated February __, 2014, a copy of which is attached hereto and incorporated herein by reference (collectively, the “Agreement”), constitute evidence of the issuance and grant of a Performance Unit Award (hereinafter referred to as “Award”) of «No_of_Perf_Units» additional Performance Units (“Performance Units”) to the Grantee by the Corporation, pursuant to the Adjustment provisions of the Plan and the Performance Unit Award Agreement dated February 20, 2013 (the “2013 Agreement”), that shall entitle the Grantee to receive shares of the Corporation’s common stock (hereinafter also referred to as “Common Stock”) or cash, all pursuant and subject to the terms, provisions, and conditions of this Agreement (including, without limitation, the conditions, restrictions and limitations stated in paragraph 5, below) and the terms and provisions of the Plan, which are incorporated herein by reference. This Agreement, when executed by the Grantee, together with the Notice of Performance Unit Award and Agreement constitute an agreement between the Corporation and the Grantee. The Performance Unit Award and Performance Units granted pursuant to this Agreement include the right of Grantee to receive dividend equivalents (“Dividend Equivalents”) upon the declaration and payment of dividends by the Corporation to holders of all common stock to the extent and as provided for in paragraph 5 of this Notice of Performance Unit Award and Agreement, below. Notwithstanding the foregoing, should there be any inconsistency between the provisions of this Agreement and the terms and provisions of the Award stated in the resolutions and records of the Board of Directors of the Corporation providing for the Award or provisions of the Plan, the provisions of such resolutions and records and of the Plan shall control. Moreover, the Performance Units awarded pursuant to this Agreement shall be deemed to satisfy any obligation of the Corporation to provide any additional Performance Units to Grantee under the Plan or the 2013 Agreement as a result of the Distribution. The grant of such Performance Units to the Grantee shall be effective in the manner and to the extent provided in this Agreement and the Plan as to all or any part of the shares of Common Stock subject to the grant from time to time during the period stated herein.

2.Plan. The Award is made to the Grantee pursuant to the terms and provisions of the Plan, as approved by the Shareholders of the Corporation, which Plan provides that a specific aggregate number of shares of Common Stock of the Corporation may be issued or transferred pursuant to Stock Incentives under the Plan. The Plan specifies the authority of the Corporation, its Board of Directors, and a committee of the Board of Directors to select employees to be

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granted Stock Incentives under the Plan. The Executive Compensation Committee of the Board of Directors (hereinafter referred to as the “Committee”) is authorized to administer the Plan with respect to this Agreement and the grant of the Award made to the Grantee pursuant to the Plan. Except where expressly stated or clearly indicated otherwise by the terms of this Agreement, all terms, words and phrases used herein shall have the same meaning and effect as stated and as defined in the Plan. The Grantee has been provided a complete copy of the Plan with this Agreement.

3.Grantee’s Agreement Concerning Award and Employment. In consideration of the Corporation’s granting of the Award of Performance Units and entitlement to shares of Common Stock, as incentive compensation to Grantee pursuant to this Agreement, the Grantee, by acceptance thereof, and signing this Agreement evidencing its terms, agrees to such terms and to continue to contribute and perform service in the employ of the Corporation or a division or subsidiary thereof, at the direction, will and pleasure of the Corporation and the Board of Directors. Provided, however, neither the foregoing agreement of the Grantee in this paragraph 3, nor any other provision in this Agreement shall confer on the Grantee any right to continue in the employ of the Corporation (or a division or Subsidiary thereof), or interfere in any way with the right of the Corporation (or such division or Subsidiary) to terminate the Grantee’s employment at any time.

4.Registration of Stock; Grantee’s Representation With Respect To Acquiring for Investment. It is intended by the Corporation that the Plan and the shares of Common Stock covered by the Award issued and granted to the Grantee referred to in paragraph 1, above, are to be registered under the Securities Act of 1933, as amended, prior to the date of the grant; provided, that in the event such registration is for any reason not made effective for such shares, the Grantee agrees, for the Grantee, and for the Grantee’s permissible assignees, heirs and legal representatives by inheritance or bequest, that all shares acquired pursuant to the grant will be acquired for investment and not with a view to, or for sale or tender in connection with the distribution of any part thereof, including any transfer or distribution of such shares by the Grantee pursuant to the grant and this Agreement or as otherwise allowed by the Plan.

5.Terms and Conditions of Award; Transfer of Stock to Grantee. The issue and grant of the Award of Performance Units to the Grantee stated in paragraph 1, above, shall be subject to the following terms and conditions:

(a)The right to ownership and transfer of the Performance Units granted to the Grantee shall be subject to the Award during the period beginning February __, 2014, the date of the grant thereof (hereinafter referred to as “Grant Date”), and ending on February 20, 2016, (which period is hereinafter referred to as “Performance Period”), as herein provided.

(b)The Grantee shall earn and become entitled to receive a percentage of the number of Performance Units granted under paragraph 1, above, and Additional Performance Units Credited under (f), below, at the expiration of the Performance Period as provided for in Exhibit A and Exhibit B, attached hereto, based upon the Corporation’s ranking for Total Stockholder Return in the ONEOK Peer Group listed in Exhibit C attached hereto, all as determined by the Committee, in its sole discretion (the “Performance Goal”).

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(c)Upon expiration of the Performance Period, the Grantee shall be entitled to receive one (1) share of Common Stock for each Performance Unit that becomes earned by and vested in the Grantee pursuant to the Award; provided, no fractional shares shall be issued and any amount attributable to a fractional share shall be paid to the Grantee in cash.

(d)All Common Stock the Grantee becomes entitled to receive pursuant to the Award and any other compensation payable to the Grantee under the Award shall be paid, distributed, transferred and issued by the Corporation to the Grantee at the expiration of the Performance Period, or as soon as practicable after the determination that the Grantee has earned and become entitled to Performance Units and to receive such Common Stock and cash, as determined by the Committee, and in no event later than the 15^th day of the third month after the date of expiration of the Performance Period, and the Grantee shall not be permitted, directly or indirectly, to designate the time of payment, distribution or transfer or the taxable year in which it is to be made. Provided, that if the Grantee elects pursuant to paragraph 6, below, to defer the receipt of all Performance Units, Common Stock and cash for each Performance Unit that becomes earned by and vested in the Grantee pursuant to the Award, the payment, distribution and transfer of such Performance Units, Common Stock and cash shall be deferred and thereafter paid, distributed and transferred by the Corporation to the Grantee at the specified time and in accordance with the method of payment, distribution and transfer that is elected in by the Grantee in accordance with the election provisions set forth therein.

(e)The Grantee shall not be entitled to vote any shares of Common Stock of the Corporation and, except as provided in paragraph 5 (f), the Grantee shall not have any right or interest as a holder of common stock by reason of the Performance Unit Award granted under this Agreement during the Performance Period, and prior to the actual transfer of common stock to the Grantee pursuant to the Award.

(f)During the Performance Period Grantee shall earn and Dividend Equivalents shall be credited to Grantee with respect to Performance Units in the form of additional Performance Units (“Additional Performance Units”) to Grantee with respect to the Performance Units to the extent and as provided for in this Agreement, as follows:

(i) On each date on which (a) the Performance Units and Additional Performance Units credited to Grantee pursuant to the Award under this Agreement have not become vested or have not been forfeited pursuant to the terms and provisions of this Agreement, and (b) the Company declares and pays a cash dividend to holders of Common Stock (each, a “Dividend Payment Date”), a number of Additional Performance Units will be credited to the Grantee in an amount (including fractional Additional Performance Units) determined by dividing (x) the aggregate cash dividends that would have been paid on the number of shares of Common Stock (including fractional shares of Common Stock) into which the Performance Units and Additional Performance Units theretofore granted and credited to Grantee under this Notice of Performance Unit Award and Agreement on the Dividend Payment Date would be converted if vested on such date, by (y) the Fair Market Value of a share of Common Stock on such Dividend Payment Date.

(ii) The Additional Performance Units credited to Grantee pursuant to paragraph 5(f)(i) shall be added to and included in a cumulative aggregate amount of Additional

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Performance Units credited to the Grantee hereunder, which shall be recorded and accounted for as a separate identifiable amount to the credit of the Grantee (“Additional Performance Units Amount”).

(iii) Except as provided below with respect to the treatment of a fractional Additional Performance Unit or fractional share of Common Stock attributable to Grantee upon vesting hereunder, all the Additional Performance Units and the Additional Performance Units Amount so credited to Grantee shall be subject to the same terms and conditions as the Performance Units granted pursuant to paragraph 1 above, and such Additional Performance Units and Additional Performance Units Amount shall be forfeited in the event that the Performance Units granted pursuant to paragraph 1, above, are forfeited.

(iv) Unless otherwise expressly stated herein, any reference to Performance Units in this Agreement, including without limitation, provisions regarding partial vesting of Performance Units in particular circumstances, shall be deemed to similarly and in like manner refer and apply to Additional Performance Units credited to Grantee.

(v) The Grantee shall earn and become vested and entitled to the Additional Performance Units granted by this Award under this paragraph 5(f) at the expiration of the Performance Period. Upon expiration of the Performance Period, Grantee shall be entitled to receive, and the Corporation shall issue to Grantee one (1) share of Common Stock for each Additional Performance Unit that becomes earned by and vested in Grantee pursuant to the Award; provided, that the shares of Common Stock to be issued to and received by Grantee for Additional Performance Units, shall be only issued in whole shares of Common Stock, and any fractional share of Common Stock attributable to the Additional Performance Units credited to Grantee shall paid to Grantee in an amount of cash equal to the Fair Market Value of a fractional share of Common Stock.

(g)The Common Stock or cash to which the Grantee becomes entitled shall be paid and transferred to the Grantee only upon the determination of the Performance Units earned by the Grantee at the expiration of the Performance Period. The payment and transfer of such Common Stock or cash to the Grantee shall be made as soon as reasonably practicable after the expiration of the Performance Period, as determined and directed by the Committee, in its sole discretion.

(h)The Performance Units or any Common Stock or cash to be paid or transferred to Grantee pursuant to the Award may not be sold, assigned, transferred, pledged, encumbered or otherwise disposed of by Grantee or any other person except as provided in the Award and the Plan until the expiration of the Performance Period and payment and transfer of Common Stock or cash pursuant to the Agreement and Plan.

(i)The Grantee shall become entitled to receive Performance Units earned, and shall become owner of the shares of Common Stock or cash paid and transferred to the Grantee pursuant to the Award free and clear of all terms, conditions and restrictions imposed by the Award if the Grantee’s employment by the Corporation does not terminate during the Performance Period; provided, that the Grantee shall become entitled to a prorated amount of

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Performance Units and the terms and conditions imposed by the Award shall partially cease to apply in certain events to the extent described in paragraph 7(d), below.

(j)If the Grantee’s employment with the Corporation (or a division or Subsidiary thereof) terminates prior to the end of the Performance Period other than by reason of Retirement, Total Disability or death, the Grantee shall forfeit all of the Grantee’s right, title or interest in the Performance Units; and the Grantee shall forfeit such right, title and interest in the Performance Units regardless of the reason for such termination of employment. Any such termination of employment of the Grantee described in the preceding sentence shall not be deemed to occur by reason of transfer of employment of the Grantee by or between the Corporation and any division or Subsidiary of the Corporation. Upon forfeiture the Performance Units forfeited shall be cancelled for all purposes.

6.Deferral of Payment, Distribution and Transfer of Stock.

(a)The Grantee may irrevocably elect to defer the time of payment, distribution and transfer of Performance Units, Common Stock and cash that the Grantee becomes entitled to receive under this Agreement and Award from the end of the Performance Period generally provided for in paragraph 5, above, to a specified time by filing with the Committee, on or before the deferral election date (hereinafter referred to as “Election Date”) described in paragraph 6(b), below, a signed written irrevocable election (hereinafter referred to as “Election”) which shall be in the form substantially the same as attached hereto as Exhibit D, or as otherwise prescribed by the Committee.

(b)An Election of the Grantee to defer the payment, distribution and transfer of Performance Units, Common Stock and cash that the Grantee becomes entitled to receive under this Agreement and Award shall be filed by the Grantee with the Committee on or before the Election Date, which shall be August 20, 2015, the date that is six (6) months before the end of the Performance Period, provided that the Grantee performs services for the Corporation continuously from the later of the beginning of the Performance Period or the date the performance criteria are established through the date the Election is made under this paragraph 6(b), and provided, further, that in no event may the Grantee make an Election to defer the payment, distribution and transfer of Performance Units, Common Stock or cash after such compensation has become readily ascertainable; and in this regard for purposes of this paragraph 6(b), if the amount of Performance Units, Common Stock and cash, or other compensation, as performance-based compensation, is a specified or calculable amount, then it shall be considered compensation that is readily ascertainable if and when the amount is first substantially certain to be paid, distributed and transferred to the Grantee. If the amount of Performance Units, Common Stock and cash, or other compensation, is performance-based compensation that is not a specified or calculable amount because, for example, the amount may vary based upon the level of performance, such compensation, or any portion of the compensation, shall be considered readily ascertainable when the amount is first both calculable and substantially certain to be paid. For this purpose, such performance-based compensation is to be bifurcated between the portion that is readily ascertainable and the amount that is not readily ascertainable, and, in general, any minimum amount that is both calculable and substantially certain to be paid shall be treated as readily ascertainable.

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(c)A Grantee that makes an Election to defer payment, distribution and transfer of Performance Units, Common Stock and cash that the Grantee becomes entitled to receive under this Agreement and Award may irrevocably elect to have payment, distribution and transfer made to the Grantee at a Specified Time, that shall be either (i) the later of (A) the date of the Grantee’s separation from service with the Corporation, or (B) a specified calendar date, or (ii) the date of the Grantee’s separation from service with the Corporation; and may elect to have payment made in a specified form of payment that shall be either (i) a single lump sum payment, distribution and transfer, or (ii) a payment, distribution and transfer in two, three, four or five equal annual installments commencing at the Specified Time elected by the Grantee hereunder and thereafter on each anniversary thereof, until fully paid, transferred and distributed.

(d)The Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the restrictions made applicable to the Grantee and the Performance Units during the Performance Period. This Agreement and the rights and obligations of the parties involved, shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the Common Stock that would otherwise be transferred and delivered to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

(e)The provisions of this Agreement providing for the deferral of payment, distribution, transfer or issuance of Performance Units, Common Stock or cash shall be applicable solely and exclusively to the Grantee and the Award Agreement and Award referred to herein, and shall not apply to any other stock incentive or other grant, award or transfer provided for or made under the Plan.

(f)Notwithstanding anything otherwise provided under the Plan or in the Award Agreement and Award, the following requirements shall apply to this Award Agreement and the Award, to all elections or subsequent elections made by the Grantee, and to all distributions and payments made to the Grantee pursuant to this Award Agreement and Award:

(1)Any compensation for services performed by the Grantee during a taxable year may be deferred at the Grantee’s election or the Corporation’s election or determination only if the election to defer such compensation is made not later than the close of the preceding taxable year or such other time as provided in Treasury Regulations under section 409A of the Internal Revenue Code of 1986, as amended (“Code”), but in all events any deferral of the payment, distribution, transfer or issuance of Performance Units, Common Stock or cash

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pursuant to the Award and Award Agreement may be made only by an election that is made on or before the Election Date.

(2) Any compensation deferred under the Plan shall not be distributed earlier than

(i)Separation from Service of the Grantee,

(ii)the date the Grantee becomes Disabled,

(iii)death of the Grantee,

(iv)a Specified Time (or pursuant to a Fixed Schedule) specified under the plan under which the compensation is deferred at the date of deferral of such compensation,

(v)a Change in Ownership or Control, or

(vi)the occurrence of an Unforeseeable Emergency.

(3)If the Grantee is a Specified Employee, no payment or distribution shall be made before the date which is six (6) months after the date of the Grantee’s Separation from Service, or, if earlier, the date of death of the Grantee.

(4)No acceleration of the time or schedule of any distribution or payment under the plan under which compensation is deferred shall be permitted or allowed, except to the extent provided in Treasury Regulations issued under Code section 409A.

(5)This Agreement shall not permit a subsequent election unless authorized and agreed upon in writing by the Corporation and Grantee, and if the Plan or this Agreement permits under any subsequent election by the Grantee a delay in a payment or a change in the form of payment of compensation deferred under this Award Agreement and Award, such subsequent election shall not take effect until at least twelve (12) months after the date on which it is made. In the case of a subsequent election related to a payment to be made upon Separation from Service of the Grantee, at a Specified Time or pursuant to a Fixed Schedule, or upon a Change in Ownership or Control, the first payment with respect to which such subsequent election is made shall be deferred for a period of not less than five (5) years from the date such payment would otherwise have been made; and any such subsequent election related to a payment at a Specified Time or pursuant to a Fixed Schedule may not be made less than twelve (12) months prior to the date of the first scheduled payment to which it relates.

(6)For purposes of the Plan and this Agreement and the Award, the following terms and definitions shall apply with respect to deferral of compensation and the time of payment of any deferred compensation:

(i)”Change of Ownership or Control” means to the extent provided by Treasury Regulations issued under Code Section 409A, a change in the ownership or effective control of the Corporation, or in the ownership of a substantial portion of the assets

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of the Corporation, which shall be if (i) a Person acquires more than 50% of the Corporation’s stock; (ii) a Person acquires during a 12-month period at least 30% (or a higher percentage specified under the Plan) of the Corporation’s stock; (iii) a majority of the members of the Board of Directors of the Corporation are replaced during a 12-month period; or (iv) a Person acquires during a 12-month period at least 40% of the gross fair market value of the Corporation’s assets.

(ii)”Disabled” means that an individual (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of the individual’s employer.

(iii)”Fixed Schedule” means the distribution or payment of compensation deferred under this Agreement and Award in a fixed schedule of distributions or payments that are determined and fixed at the time the deferral of such compensation is first elected by the Grantee or the Corporation.

(iv)”Specified Employee” means a key employee (as defined in Code section 416(i) without regard to paragraph (5) thereof) of the Corporation.

(v)”Specified Time” means a specified date at which deferred compensation deferred by or for the Grantee pursuant to this Agreement and Award is required to be distributed or paid and which is specified at the time of the election of deferral of such deferred compensation

(vi)“Unforeseeable Emergency” means a severe financial hardship to the participant resulting from an illness or accident of the participant, the participant’s spouse, or a dependent (as defined in Code section 152(a)) of the participant, loss of the participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. As determined under Treasury Regulations under Code section 409A, the amounts distributed with respect to an emergency shall not exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the participant’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship).”

7.Transferability of Performance Units; Termination of Employment.

(a)Except as provided in subparagraph (b) of this paragraph 7, below, the Award, the Grantee’s rights and obligations hereunder and the Performance Units granted hereunder shall not be transferable by the Grantee otherwise than by will or the laws of descent and distribution which apply to the Grantee’s estate.

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(b)Notwithstanding the foregoing, the Grantee may transfer any part or all of the Grantee’s rights in and to the Performance Units to members of the Grantee’s immediate family, or to one or more trusts for the benefit of such immediate family members, or partnerships in which such immediate family members are the only partners if the Grantee does not receive any consideration for the transfer. In the event of any such transfer, Performance Units shall continue to be subject to the same terms and conditions otherwise applicable hereunder and under the Plan immediately prior to its transfer, except that this stock shall not be further transferable by the transferee intervivos, except for transfer back to the original Grantee. For any such transfer to be effective, the Grantee must provide prior written notice thereof to the Committee, unless otherwise authorized and approved by the Committee, in its sole discretion; and the Grantee shall furnish to the Committee such information as it may request with respect to the transferee and the terms and conditions of any such transfer. For purposes of transfer of this grant under this subparagraph (b), “immediate family” shall mean the Grantee’s spouse, children and grandchildren.

(c)Notwithstanding anything to the contrary expressed or implied herein (including without limitation, the restrictions stated in paragraph 5, above, applicable to the Performance Units), all rights and interest of the Grantee in the Performance Units shall become invalid and wholly terminated and forfeited upon the termination of the Grantee’s employment with the Corporation (or a division or Subsidiary), during the Performance Period other than a termination by reason of Retirement, Total Disability or death of the Grantee.

(d)Notwithstanding the foregoing provisions, in the event of termination of the Grantee’s employment with the Corporation (or a division or Subsidiary) during the Performance Period by reason of (i) the Retirement of the Grantee, (ii) the Total Disability of the Grantee, or (iii) the Grantee’s death while still employed by the Corporation (or a division or Subsidiary), then an adjusted and prorated entitlement to Performance Units shall be allowed as provided in this paragraph 7(d). The Grantee shall become vested in and entitled to receive, in the event of any such Retirement or Total Disability, and the legatees, designated Beneficiary, or personal representatives or heirs of the Grantee shall be vested in and entitled to receive, in the event of the Grantee’s death, a prorated award of Performance Units earned in the Performance Period following such Retirement, Total Disability or death. The award shall be a prorated amount of Performance Units equal to the total of Performance Units earned under the Award at the end of the Performance Period for the Grantee, multiplied by a fraction of which the numerator shall be the number of full months which have elapsed under the Performance Period at the time of such termination of employment by reason of Retirement, Total Disability or death, and the denominator of which shall be the total number of months in the Performance Period. The Grantee, legatees, designated Beneficiary, or personal representatives or heirs of the Grantee, as the case may be, shall become entitled to receive such prorated award at the expiration of the Performance Period and following application of the performance criteria as provided in the Award and determined by the Committee.

The prorated award of Performance Units earned in the Performance Period to which the Grantee or the legatees, a designated Beneficiary, or the personal representative or heirs of the Grantee shall become vested in and entitled to receive under the foregoing provisions in event of Retirement, Total Disability or death of the Grantee, is to be qualified performance-based compensation paid solely on account of attainment of the Performance Goal, as provided

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for in Treas. Reg. §1.162-27(e)(2)(i). The Retirement, Total Disability or death of the Grantee during the Performance Period in and of itself alone shall in no case vest the Grantee in Performance Units or any part of thereof. A prorated vesting and entitlement to Performance Units or a part thereof, hereunder by reason of such events shall in all cases remain subject to and dependent solely upon the attainment of the Performance Goal as provided herein.

(e)The Grantee may designate a Beneficiary to receive any rights of the Grantee which may become vested in the event of the death of the Grantee under procedures and in the form established by the Committee; and in the absence of such designation of a Beneficiary, any such rights shall be deemed to be transferred to the estate of the Grantee.

(f)For purposes of the Award and this Agreement, “Retirement” shall mean a voluntary termination of employment of the Grantee with the Corporation and/or a division or subsidiary thereof by the Grantee if at the time of such termination of employment the Grantee has both completed five (5) years of service with the Corporation and/or a division or subsidiary thereof and attained age fifty (50), and “voluntary termination” shall mean that the Grantee had an opportunity to continue employment with the Corporation and/or a division or subsidiary thereof, but did not do so; and except as provide for in paragraph 6 with respect to deferred compensation payments, “Total Disability” shall mean that the Grantee is permanently and totally disabled and unable to engage in any substantial gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than twelve (12) months, and has established such disability to the extent and in the manner and form as may be required under the provisions of Section 22(e) of the Internal Revenue Code of 1986, as amended (or corresponding section of any future federal tax code), and regulations thereunder.

8.Administration of Performance Unit Award. The grant of the Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the terms and conditions made applicable to the Grantee and the Performance Units during the Performance Period. The Award, this Agreement, and the rights and obligations of the parties thereto shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the shares of Common Stock or cash that would otherwise be paid and transferred to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

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9.Adjustment Provisions. It is understood that, prior to the expiration of the Performance Period certain changes in capitalization of the Corporation may occur. It is, therefore, understood and agreed with respect to changes in capitalization that:

(a)If a stock dividend is declared on the Common Stock of the Corporation, which has not been granted as a dividend equivalent, there shall be added to the number of Performance Units provided for under the Award and stated in paragraph 1 of this Agreement, the number of Performance Units equal to the number of Performance Units which would have been granted to the Grantee had the Grantee been the fully vested and unrestricted owner of the number of Performance Units then provided for under the Award granted, but not theretofore received without restriction; provided, however, that the additional Performance Units shall be subject to all terms and provisions of this Agreement (including, without limitation, the terms and conditions stated in paragraph 5, above), and in making such adjustments, no fractional units, shares, or scrip certificates in lieu thereof, shall be granted or issuable by the Corporation, and the Grantee shall be entitled to only the number of full Performance Units to which the Grantee may be entitled by reason of such adjustment at the adjusted grant.

(b)In the event of an increase in the outstanding shares of Common Stock of the Corporation, effectuated for the purpose of acquiring properties or securities of another corporation or business enterprise, there shall be no increase in the number of Performance Units which are the subject matter of the Award under this Agreement as a result of such acquisition.

(c)In the event of an increase or decrease in the number of outstanding shares of Common Stock of the Corporation through recapitalization, reclassification, stock split-ups, consolidation of shares, changes in par value and the like, an appropriate adjustment shall be made in the number of Performance Units provided for under the Award and stated in Section 1 of this Agreement, by increasing or decreasing the number of Performance Units, as may be required to enable the Grantee to acquire the same proportionate stockholdings as the grant of the Award would originally have provided. Provided, however, that any additional Performance Units shall be subject to all terms and provisions of this Agreement (including, without limitation, the restrictions stated in paragraph 5, above), and that in making such adjustments, no fractional Performance Units shall be awarded, and the Grantee shall be entitled to receive only the number of full Performance Units to which the Grantee may be entitled by reason of such adjustment.

(d)Except as otherwise provided for with respect to the payment of any deferred compensation in paragraph 6, above, to the extent Performance Units are still not vested in Grantee at the time of a Change in Control with respect to the Corporation, then pursuant to the provisions of the Plan, they shall become fully vested and completely free and clear of any conditions or restrictions stated herein at that time; provided, that if such Change in Control occurs less than six (6) months after the date of the grant of the Award hereunder to the Grantee, then Performance Units shall become fully vested and completely free and clear of any conditions or restrictions stated herein at the time of such Change in Control only if the Grantee agrees in writing, if requested by the Corporation in writing, to remain in the employ of the Corporation or a division or subsidiary of the Corporation at least through the date which is six (6) months after the date the grant was made with substantially the same title, duties, authority, reporting relationships, and compensation as on the day immediately preceding the Change in

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Control. The provisions of this subparagraph (d) shall be applied in addition to, and shall not reduce, modify, or change any other obligation or right of the Grantee otherwise provided for in paragraph 3, above, concerning the Grantee’s continued employment with the Corporation or the termination thereof. If the Performance Units become subject to this subparagraph (d), they shall become fully vested in the Grantee and nonforfeitable. The Performance Units are subject to the provisions of the Plan authorizing the Corporation, or a committee of its Board of Directors, to provide in advance or at the time of a Change in Control for cash to be paid in actual settlement of the shares of Common Stock for earned Performance Units, all subject to such terms and conditions as the Corporation or the Committee, in its sole discretion, may determine and impose. For purposes of this subparagraph (d), the term “Change in Control” shall have the same meaning as provided in the definition of that term stated in the Plan, including any amendments thereof which may be made from time to time in the future pursuant to the provisions of the Plan, with any amended definition of such term to apply to all events thereafter coming within the amended meaning.

10.Required Grantee Repayment/Reduction Provision. Notwithstanding anything in the Plan, the Award or this Agreement to the contrary, all or a portion of the Award made to the Grantee under this Agreement is subject to being called for repayment to the Corporation or reduced in any situation where the Board of Directors of the Corporation or a Committee thereof determines that fraud, negligence, or intentional misconduct by the Grantee was a contributing factor to the Corporation having to restate all or a portion of its financial statement(s). The Committee may determine whether the Corporation shall effect any such repayment or reduction: (i) by seeking repayment from the Grantee, (ii) by reducing (subject to applicable law and the terms and conditions of the Plan or any other applicable plan, program, or arrangement) the amount that would otherwise be awarded or payable to the Grantee under the Award, the Plan or any other compensatory plan, program, or arrangement maintained by the Corporation, (iii) by withholding payment of future increases in compensation (including the payment of any discretionary bonus amount) or grants of compensatory awards that would otherwise have been made in accordance with the Corporation’s otherwise applicable compensation practices, or (iv) by any combination of the foregoing. The determination regarding the Grantee’s conduct, and repayment or reduction under this provision shall be within the sole discretion of the Committee and shall be final and binding on the Grantee and the Corporation. The Grantee, in consideration of the grant of the Award, and by the Grantee’s execution of this Agreement, acknowledges the Grantee’s understanding of the agreement to this provision, and hereby agrees to make and allow an immediate and complete repayment or reduction in accordance with this provision in the event of a call for repayment or other action by the Corporation or Committee to effect its terms with respect to the Grantee, the Award and/or any other compensation described herein.

11.Stock Reserved. The Corporation shall at all times during the term of the Award reserve and keep available such number of shares of its Common Stock as will be sufficient to satisfy the Award issued and granted to Grantee and the requirements thereof as evidenced by this Agreement, and shall pay all original issue taxes, if any, on the transfer of Common Stock to the Grantee, and all other fees and expenses necessarily incurred by the Corporation in connection therewith.

12.Rights of Shareholder. Except as otherwise provided in the Award and this Agreement, the Grantee shall have no rights as a shareholder of the Corporation in respect of the

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Performance Units or Common Stock for which the Award is granted; and the Grantee shall not be considered or treated as a record owner of shares with respect to the Common Stock until the Performance Units are fully vested and no longer subject to any of the conditions, performance requirements, or restrictions imposed under the Award, and Common Stock is actually issued and transferred to the Grantee.

13.Entire Agreement. This Agreement contains the entire terms of the Award, and may not be changed orally or other than by a written Agreement issued and approved by the Corporation pursuant to the Plan. This Agreement supersedes any agreements or understandings that may previously have existed, and there are no other agreements or understandings, relating to its subject matter.

14.Successors and Assigns. The Award shall inure to the benefit of and be binding upon the heirs, legatees, legal representatives, successors, and assigns of the parties thereto.

The Grantee hereby acknowledges receipt of this Agreement, the Notice of Performance Unit Award and a copy of the Plan, and accepts the Award under the terms and conditions stated in this Agreement, subject to all terms and provisions of the Plan, by signing this Agreement in duplicate originals, as of the date first above written.

Date	«Officer_Name»
	Grantee

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Exhibit A

Performance Units Criteria

2013-2016 Performance Period

Total Stockholder Return (TSR):vs. ONEOK Peer Group
ONEOK TSR Ranking vs. ONEOK Peer Group	Percentage of Performance Units Earned
90th percentile and above 75th percentile 50th percentile 25th percentile Below 25th percentile	200% 150% 100% 50% 0%

IF ONEOK’s TSR ranking at the end of the performance period is between the stated percentile levels in the above table, the percentage of the performance units earned will be interpolated between the earning levels. No Performance Units are earned if ONEOK’s TSR ranking at the end of the performance period is below the 25^th percentile.

Exhibit B

Illustration of Hypothetical 2013-2016 Performance Period

Performance Unit Award Calculation

Illustration assumes 500 Performance Units Granted

Total Stockholder Return (TSR) vs. ONEOK Peer Group

Hypothetical 2013-2016 ONEOK TSR Ranking = 40^th percentile

A 40^th percentile TSR ranking earns 80% of Performance Units granted (i.e., 500 units)

as interpolated between 50% and 100% from Table A (see chart below)

400 units earned

Total Performance Units Earned

TR 400 Performance Units

400 performance units earned out of 500units granted = 80% “earn-out” [80% (500 shares) paid and distributed in the form of Common Stock as provided in section 5.c.]

Exhibit C

2013-16 ONEOK TSR Peer Group

Company Name	Sym
AGL Resources Inc.	GAS
ATMOS Energy	ATO
CenterPoint Energy Inc.	CNP
Enbridge Inc.	ENB
Energy Transfer Partners LP	ETP
Enterprise Products Partners LP	EPD
EQT Corporation	EQT
Integrys Energy Group Inc.	TEG
Kinder Morgan Energy LP	KMP
MDU Resources Corp	MDU
Magellan Midstream Partners LP	MMP
MarkWest Energy Partners LP	MWE
National Fuel Gas Company	NFG
NiSource Inc.	NI
OGE Energy Corp	OGE
ONEOK, Inc.	OKE
Questar Corp	STR
SEMPRA Energy	SRE
Spectra Energy Corporation	SE
Targa Resources Partners LP	NGLS
TransCanada Corporation	TRP
Williams Companies Inc.	WMB

Exhibit D

ONEOK, INC. EQUITY COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

DEFERRAL ELECTION

This Election is made by the undersigned Grantee pursuant to that certain Performance Unit Award granted to me under the ONEOK, Inc. Equity Compensation Plan, on the ___ day of February 2014, a copy of which is attached hereto (the “Award”).

This Election is made on or before the date of August 20, 2015, which is six (6) months before the end of the Performance Period on February 20, 2016.

I hereby irrevocably elect to defer the payment, distribution and transfer and my receipt of all Performance Units, Common Stock and cash that I may earn and become entitled to receive from the regularly scheduled time of payment, distribution and transfer provided for in paragraph 5(d) of the Award, until a later date as follows:

A.     Election of Specified Time of Payment (Initial one election of time of payment)

___    I elect to have all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award and Award Agreement deferred and paid, distributed, transferred and issued to me on the later of (i) the date of my separation from service as an employee of the Corporation, or (ii) _________________, 20__ in the form specified below.

___    I elect to have all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award and Award Agreement deferred and paid, distributed, transferred and issued to me on the date of my separation from service as an employee of the Corporation.

B.     Election of Form of Payment (Initial one election of form of payment)

___    I elect to receive payment, transfer and distribution of all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award or Award Agreement in a single lump sum payment.

____    I elect to receive payment, transfer and distribution of all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award or Award Agreement in ______(specify 2, 3, 4 or 5) equal annual installments commencing on the specified date of payment elected above, and thereafter on each anniversary thereof until fully paid and transferred. The number of shares of Common Stock or cash received in each installment will equal the number and amount that have not been settled, paid, transferred and distributed (as of the date immediately preceding the installment payment date) divided by the number of installments remaining to be paid (as of the date immediately preceding the installment payment date) rounded down to the next whole number except that the final installment shall be rounded up to the next whole number.

C.    Election for Death Prior to Specified Time of Payment (Put initials by your choice)

___    In the event of my death prior to the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation in a single lump sum within 60 days following my death.

___    In the event of my death prior to the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation be paid and transferred in ______ (specify 2, 3, 4 or 5) equal annual installments commencing within 60 days following my death, and thereafter on each anniversary of the commencement date until fully paid and transferred. The number of shares of Common Stock or cash received in each installment will equal the number and amount that have not been paid (as of the date immediately preceding the installment payment date) divided by the number of installments remaining to be paid (as of the date immediately preceding the installment payment date) rounded down to the next whole number except that the final installment shall be rounded up to the next whole number.

D.     Election for Death After Specified Time of Payment (Put initials by your choice)

___    In the event of my death after the Specified Time of Payment elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation in a single lump sum within 60 days following my death.

___    In the event of my death after the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment of any remaining Common Stock, cash or other compensation in accordance with the installment schedule elected above.

E.    Designation of Beneficiary (List each beneficiary and percentage)

I designate the following individuals (entities) as my beneficiaries to receive the following share(s) of my Common Stock, cash or other deferred compensation, as indicated below:

Name of Beneficiary	Percent
	100% (total must equal 100%)

F.    Change in Ownership or Control

Notwithstanding the foregoing, immediately following a Change in Ownership or Control the Common Stock, cash or other deferred compensation that have not been paid and transferred will be paid and transferred. In the event shares of Common Stock no longer exist at the time of payment and transfer, each of the deferred Performance Units shall be converted in a manner that is consistent with the manner in which shareholders of Common Stock were treated with respect to the Change in Ownership or Control.

Solely for purposes of this election, a “Change in Ownership or Control” shall mean and shall have occurred if one of the following has occurred: A person acquires more than 50% (or a higher percentage specified under the Plan) of the Corporation’s stock; a person acquires during a 12-month period at least 30% (or a higher percentage specified under the Plan) of the Corporation’s stock; a majority (or a higher percentage specified under the Plan) of the members of the Board of Directors of the Corporation are replaced during a 12-month period; or a person acquires during a 12-month period at least 40% (or a higher percentage specified under the Plan) of the gross fair market value of the Corporation’s assets.

Made and executed by me as Grantee of the Award pursuant to the terms and provisions of Section 6 thereof, on this _______day of ______________, 20___.

_____________________________________

Grantee

Received this [____] day of [________, 20__],

______________________________________

For the Committee

EX-10.49

Exhibit 10.49

ADDITIONAL 2012 RESTRICTED UNIT

STOCK BONUS AWARD

AGREEMENT

On January 31, 2014, shares of common stock of ONE Gas, Inc. were distributed to shareholders of ONEOK, Inc. common stock (the “Distribution”). The Board of Directors of ONEOK, Inc. has approved the equitable adjustment of outstanding share-based awards in an attempt to preserve the value of such awards immediately before and after the Distribution. Accordingly, this instrument is issued as of the __ day of February, 2014, by ONEOK, Inc., an Oklahoma corporation, (hereinafter referred to as “Corporation”), to «Officer_Name» (hereinafter referred to as “Grantee”), an employee of the Corporation or a division or subsidiary thereof, pursuant to the terms of the ONEOK, Inc. Long-Term Incentive Plan, as amended (hereinafter referred to as the “Plan”).

1.Adjustment to 2012Restricted Unit Award. This instrument and that certain Restricted Unit Stock Bonus Award and Agreement, dated February __, 2014, a copy of which is attached hereto and incorporated herein by reference (the “Notice of Restricted Unit Stock Bonus Award and Agreement”) constitute evidence of the issuance and grant of a Stock Bonus Award (hereinafter referred to as “Award”) to the Grantee by the Corporation under the Adjustment provisions of the Plan and the Restricted Unit Stock Bonus Award Agreement dated February 15, 2012 (the “2012 Agreement”), pursuant to which shares of the Corporation’s Common Stock (hereinafter referred to as “Common Stock”) shall be distributed in the future to the Grantee in lieu of, or as a supplement to, any other compensation that may have been earned by services rendered prior to the date the distribution is made, pursuant to and in accordance with the terms of this instrument under which the Corporation grants a Stock Bonus Award under the Plan that shall include and is to be awarded by the grant restricted stock units (“Restricted Units”) under the Plan in the amount of «No_of_Restricted_Units» additional Restricted Units that shall entitle the Grantee to receive shares of Common Stock all subject to the terms, provisions, and conditions of this instrument (including, without limitation, the restrictions stated in paragraph 5, below) and of the Plan, which are incorporated herein by reference. This instrument, when executed by the Grantee, together with the Notice of Restricted Unit Stock Bonus Award and Agreement constitute an agreement between the Corporation and the Grantee. Notwithstanding the foregoing, should there be any inconsistency between the provisions of this instrument and the terms of the Award stated in the resolutions and records of the Board of Directors of the Corporation, or the Plan, the provisions of such resolutions and records of the Plan shall control. Moreover, the Restricted Units awarded pursuant to this Agreement shall be deemed to satisfy any obligation of the Corporation to provide any additional Restricted Units to Grantee under the Plan or the 2012 Agreement as a result of the Distribution. The grant of Restricted Units to the Grantee and the Grantee’s entitlement to receive and be issued shares of Common Stock shall be effective in the manner and to the extent provided in this instrument and the Plan as to all or any part of the shares of Common Stock subject to the grant from time to time during the period stated herein.

2.Plan. The Award is issued pursuant to the Plan, as approved by the Shareholders of the Corporation, which provides that a specific aggregate number of shares of Common Stock of the Corporation may be issued or transferred pursuant to Stock Incentives under the Plan. The

Plan specifies the authority of the Corporation, its Board of Directors, and a committee of the Board of Directors to select employees to be granted Stock Incentives. The Executive Compensation Committee of the Board of Directors (hereinafter referred to as the “Committee”) is authorized to administer the Plan with respect to the Award and the grant of the Award made to the Grantee pursuant to the Plan. Except where expressly stated or clearly indicated otherwise by the terms of this instrument, all terms, words and phrases used herein shall have the same meaning and effect as stated in the Plan. The Grantee has been provided a complete copy of the Plan with this instrument.

3.Grantee’s Agreement Concerning Award and Employment. In consideration of the Corporation’s granting the Award as incentive compensation to Grantee pursuant to this instrument, the Grantee by acceptance thereof, and signing this instrument evidencing its terms, agrees to such terms and to continue to contribute and perform service in the employ of the Corporation (or a division or subsidiary thereof) at the direction, will and pleasure of the Corporation and the Board of Directors. Provided, however, neither the foregoing agreement of the Grantee in this paragraph 3, nor any other provision in the Plan shall confer on the Grantee any right to continue in the employ of the Corporation (or a division or subsidiary thereof), or interfere in any way with the right of the Corporation (or such division or subsidiary) to terminate the Grantee’s employment at any time.

4.Registration of Stock; Grantee’s Representation With Respect to Acquiring for Investment. It is intended by the Corporation that the Plan and shares of Common Stock covered by the Award issued and granted to the Grantee referred to in paragraph 1, above, are to be registered under the Securities Act of 1933, as amended, prior to the date of the grant; provided, that in the event such registration is for any reason not made effective for such shares, the Grantee agrees, for the Grantee, and for the Grantee’s heirs and legal representatives by inheritance or bequest, that all shares acquired pursuant to the grant will be acquired for investment and not with a view to, or for sale or tender in connection with the distribution of any part thereof, including any transfer or distribution of such shares by the Grantee pursuant to the grant and this instrument or as otherwise allowed by the Plan.

5.Restrictions; Restricted Period; Transfer of Common Stock to Grantee. The issue and grant of the Award to the Grantee stated in paragraph 1, above, are subject to the following terms and conditions:

(a)The ownership and transfer of the Restricted Units granted to the Grantee shall be restricted during the period beginning February __, 2014, the date of the grant thereof (hereinafter referred to as “Grant Date”) and ending on February 15, 2015, (which period is hereinafter referred to as “Restricted Period”), as herein provided.

(b)The Restricted Units, or any Common Stock or cash to be paid or transferred to Grantee as a Stock Bonus Award under the Plan pursuant to the Award may not be sold, assigned, transferred, pledged, encumbered or otherwise disposed of by Grantee or any other person except as provided in this instrument and the Plan until the expiration of the Restricted Period.

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(c)The Grantee shall earn and become vested and entitled to the Restricted Units granted by this Award under paragraph 1, above, at the expiration of the Restricted Period. Upon expiration of the Restricted Period, the Grantee shall be entitled to receive, and the Corporation shall issue to Grantee one (1) share of Common Stock for each Restricted Unit that becomes earned by and vested in the Grantee pursuant to the Award. The Common Stock the Grantee becomes entitled to receive under the Award shall be paid, distributed, transferred and issued on the date of expiration of the Restricted Period, or as soon as practicable after such date as determined by the Committee, but in no event after the 15^th day of the third month after such date.

(1)The Grantee shall become vested in the Restricted Units granted to the Grantee hereunder and Common Stock paid and transferred pursuant to the Award free and clear of all restrictions imposed by the Award if the Grantee’s employment by the Corporation (or a division or Subsidiary thereof) does not terminate during the Restricted Period; provided, that the Grantee shall become partially vested in the Restricted Units and Common Stock payable pursuant to the Award and the restrictions imposed by the Award shall partially cease to apply in certain events to the extent described in paragraph 6(d), below.

(2)If the Grantee’s employment with the Corporation (or a division or Subsidiary thereof) terminates prior to the end of the Restricted Period by reason of (i) the Grantee’s voluntary termination of the Grantee’s employment with the Corporation (or a division or Subsidiary), or (ii) the involuntary Termination for Cause by the Corporation of the Grantee’s employment with the Corporation (or a division or Subsidiary), the Grantee shall forfeit all the Grantee’s right, title or interest in the Restricted Units, and to any Common Stock payable or to be issued pursuant to the Award; and the Grantee shall forfeit such right, title and interest in the Restricted Units, and to any Common Stock payable or to be issued pursuant to the Award regardless of the reason for such termination of employment. Any such termination of employment of the Grantee described in the preceding sentence shall not be deemed to occur by reason of transfer of employment of the Grantee by or between the Corporation and any division or Subsidiary of the Corporation.

(3) The Grantee shall not be entitled to vote any shares of Common Stock or have any right or interest as a holder of Common Stock by reason of the Award granted under the Notice of Restricted Unit Stock Bonus Award and Agreement prior to the end of the Restricted Period and actual issuance of such Common Stock to the Grantee pursuant to the Award.

6.Transferability of Restricted Units, Cash or Common Stock; Termination of Employment.

(a)Except as provided in subparagraph (b) of this paragraph 6, below, this instrument, the Grantee’s rights and obligations hereunder, and the Restricted Units granted hereunder shall not be transferable by the Grantee otherwise than by will or the laws of descent and distribution which apply to the Grantee’s estate.

(b)Notwithstanding the foregoing, the Grantee may transfer any part or all of the Grantee’s rights in the Restricted Units to members of the Grantee’s immediate family, or to one or more trusts for the benefit of such immediate family members, or

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partnerships in which such immediate family members are the only partners if the Grantee does not receive any consideration for the transfer. In the event of any such transfer, Restricted Units shall continue to be subject to the same terms and conditions otherwise applicable hereunder and under the Plan immediately prior to its transfer, except that such rights shall not be further transferable by the transferee inter vivos, except for transfer back to the original Grantee. For any such transfer to be effective, the Grantee must provide prior written notice thereof to the Committee, unless otherwise authorized and approved by the Committee, in its sole discretion; and the Grantee shall furnish to the Committee such information as it may request with respect to the transferee and the terms and conditions of any such transfer. For purposes of transfer of this grant under this subparagraph (b), “immediate family” shall mean the Grantee’s spouse, children and grandchildren.

(c)Notwithstanding anything to the contrary expressed or implied herein (including without limitation, the restrictions stated in paragraph 5, above, applicable to the Restricted Units), all rights and interest of the Grantee in the Restricted Units shall become invalid and wholly terminated and forfeited upon (i) the Grantee’s voluntary termination of the Grantee’s employment with the Corporation (or a division or Subsidiary), or (ii) the involuntary Termination for Cause by the Corporation of the Grantee’s employment with the Corporation (or a division or Subsidiary).

(d)Notwithstanding the foregoing provisions, in the event of termination of the Grantee’s employment with the Corporation (or a division or Subsidiary) during the Restricted Period by reason of (i) the involuntary termination of the Grantee’s employment with the Corporation (or a division or Subsidiary) other than a Termination for Cause (ii) the Retirement of the Grantee, (iii) the Total Disability of the Grantee, or (iv) the Grantee’s death while still employed by the Corporation (or a division or Subsidiary), then partial vesting shall be allowed as provided in this paragraph 6(d) and the Grantee shall become vested in and receive, in the event of any such involuntary termination of employment other than a Termination for Cause, Retirement or Total Disability, and the legatees, designated Beneficiary, personal representative or heirs of the Grantee shall be vested in and entitled to receive, in the event of the Grantee’s death, the percentage of the Restricted Units which is determined by dividing the number of full months which have elapsed under the Restricted Period at the time of such termination of employment by the number of full months in the Restricted Period. The Grantee, or legatees, designated Beneficiary, personal representative or heirs of the Grantee, as applicable, shall be entitled to receive and the Corporation shall issue, to the Grantee, or such legatees, designated Beneficiary, personal representative or heirs, as applicable, one share of Common Stock for each vested Restricted Unit, which shall be issued, paid and transferred pursuant to the Award free and clear of all restrictions imposed by the Award on the date of expiration of the Restricted Period, or as soon as practicable thereafter as determined by the Committee, but in no event later than the 15^th day of the third calendar month after the date of the expiration of the Restricted Period.

(e)The Grantee may designate a Beneficiary to receive any rights of the Grantee which may become vested in the event of the death of the Grantee under procedures and in the form established by the Committee; and in the absence of such designation of a beneficiary, any such rights shall be deemed to be transferred to the estate of the Grantee.

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(f)For purposes of the Award and this instrument, an “involuntary termination” shall mean that the Corporation (or a division or Subsidiary) has ended the Grantee’s employment with the Corporation (or a division or Subsidiary) without the Grantee having an opportunity to continue employment with the Corporation (or a division or Subsidiary); an “involuntary Termination for Cause” of the Grantee’s employment with and by the Corporation (or a division or Subsidiary) shall mean that the Corporation (or a division or Subsidiary) has ended such employment by reason of (i) the Grantee’s conviction in a court of law of a felony, or any crime or offense involving misuse or misappropriation of money or property, (ii) the Grantee’s violation of any covenant, agreement or obligation not to disclose confidential information regarding the business of the Corporation (or a division or Subsidiary), (iii) any violation by the Grantee of any covenant not to compete with the Corporation (or a division or Subsidiary), (iv) any act of dishonesty by the Grantee which adversely effects the business of the Corporation (or a division or Subsidiary), (v) any willful or intentional act of the Grantee which adversely affects the business of, or reflects unfavorably on the reputation of the Corporation (or a division or Subsidiary), (vi) the Grantee’s use of alcohol or drugs which interferes with the Grantee’s Restricted of duties as an employee of the Corporation (or a division or Subsidiary), or (vii) the Grantee’s failure or refusal to perform the specific directives of the Corporation’s Board of Directors, or its officers which directives are consistent with the scope and nature of the Grantee’s duties and responsibilities with the existence and occurrence of all of such causes to be determined by the Corporation, in its sole discretion; provided, that nothing contained in the foregoing provisions of this paragraph shall be deemed to interfere in any way with the right of the Corporation (or a division or Subsidiary), which is hereby acknowledged, to terminate the Grantee’s employment at any time without cause; and “voluntary termination” shall mean that the Grantee had an opportunity to continue employment with the Corporation (or a division or Subsidiary), but did not do so.

(g)For purposes of the Award and this instrument, “Retirement” shall mean a voluntary termination of employment of the Grantee with the Corporation (or a division or Subsidiary) by the Grantee if at the time of such termination of employment the Grantee has both completed five (5) years of service with the Corporation (or a division or Subsidiary) and attained age fifty (50); and “Total Disability” shall mean that the Grantee is permanently and totally disabled and unable to engage in any substantial gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than twelve (12) months, and has established such disability to the extent and in the manner and form as may be required under the provisions of Section 22(e)(3) of the Internal Revenue Code of 1986, as amended (or corresponding section of any future federal tax code), and regulations thereunder.

7Deferral of Payment, Distribution and Transfer of Stock.

(a)The payment, distribution and transfer of Restricted Units, Common Stock and cash of the Grantee becomes entitled to receive upon the Grantee’s separation from service with the Corporation upon the Grantee’s Retirement prior to the expiration of the Restricted Period under paragraph 6 (d), above, shall be paid, distributed and transferred to the Grantee in a single payment, distribution and transfer at the Specified Time of the Grantee’s separation from service with the Corporation by such Retirement, as soon as practicable thereafter as determined by the Committee, but in no event later than the 15^th day of the third calendar month after date of

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such Retirement, and the Grantee shall not be permitted, directly or indirectly, to designate the time of payment, distribution and transfer or the taxable year in which it is to be made. The Specified Time of payment, distribution and transfer of any other compensation that is deferred under this instrument or the Award shall be the date of expiration of the Restricted Period, or as soon as practicable thereafter as determined by the Committee, but in no event later than the 15^th day of the third calendar month after the date of expiration of the Restricted Period, and the Grantee shall not be permitted, directly or indirectly, to designate the time of payment, distribution or transfer or the taxable year in which it is to be made.

(b)The Specified Time of payment and form of payment specified in paragraph 6(a), above shall be considered as the irrevocable deferral election of the Corporation and the Grantee of the time and form of payment for purposes of the application to this instrument and the Award of the provisions of Section 409A of the Internal Revenue Code of 1986, as amended, and the provisions of this instrument related thereto. No other election to defer compensation, or subsequent election or acceleration of the time and form of payment of compensation is intended or shall be allowed.

(c)The Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the restrictions made applicable to the Grantee and the Restricted Units during the Restricted Period. This instrument and the rights and obligations of the parties involved, shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the Common Stock that would otherwise be transferred and delivered to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

(d)The provisions of this instrument providing for the deferral of payment, distribution, transfer or issuance of Restricted Units, Common Stock or cash shall be applicable solely and exclusively to the Grantee and the Award Agreement and Award referred to herein, and shall not apply to any other stock incentive or other grant, award or transfer provided for or made under the Plan.

(e)Notwithstanding anything otherwise provided under the Plan or in this instrument the following requirements shall apply to this Award Agreement and the Award, to all elections or subsequent elections made by the Grantee, and to all distributions and payments made to the Grantee pursuant to this Award Agreement and Award

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(1)Any compensation for services performed by the Grantee during a taxable year may be deferred only if the election to defer such compensation by the Grantee or the Corporation is made not later than the close of the preceding taxable year or such other time as provided in Treasury Regulations under section 409A of the Internal Revenue Code of 1986, as amended (“Code”), but in all events any deferral of the payment, distribution, transfer or issuance of Restricted Units, Common Stock or cash pursuant to the Award and Award Agreement may be made only by an election that is made on or before the Election Date.

(2)Any compensation deferred shall not be distributed earlier than:

(i) Separation from Service of the Grantee,

(ii) the date the Grantee becomes Disabled,

(iii) death of the Grantee,

(iv) Specified Time (or pursuant to a Fixed Schedule) specified under the plan under which the compensation is deferred at the date of deferral of such compensation,

(v) a Change in Ownership or Control, or

(vi) the occurrence of an Unforeseeable Emergency.

(3)If the Grantee is a Specified Employee, no payment or distribution shall be made before the date which is six (6) months after the date of the Grantee’s Separation from Service, or, if earlier, the date of death of the Grantee.

(4)No acceleration of the time or schedule of any distribution or payment under the plan under which compensation is deferred shall be permitted or allowed, except to the extent provided in Treasury Regulations issued under Code section 409A.

(5)This instrument shall not permit a subsequent election, unless authorized and agreed to in writing by the Corporation and Grantee; and if under the Plan or this instrument compensation is deferred or the Committee acting pursuant to the Plan, permits under any subsequent election by a Participant a delay in a payment or a change in the form of payment of compensation deferred under this Award Agreement and Award, such subsequent election shall not take effect until at least twelve (12) months after the date on which it is made. In the case of a subsequent election related to a payment to be made upon Separation from Service of the Grantee, at a Specified Time or pursuant to a Fixed Schedule, or upon a Change in Ownership or Control, the first payment with respect to which such subsequent election is made shall be deferred for a period of not less than five (5) years from the date such payment would otherwise have been made; and any such subsequent election related to a payment at a Specified Time or pursuant to a Fixed Schedule may not be made less than twelve (12) months prior to the date of the first scheduled payment to which it relates.

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(6)For purposes of the Plan, this instrument and the Award, and the entitlement to and time of payment of any compensation deferred under this instrument or the Award, the following terms and definitions shall apply:

(i)”Change of Ownership or Control” means to the extent provided by Treasury Regulations issued under Code Section 409A, a change in the ownership or effective control of the Corporation, or in the ownership of a substantial portion of the assets of the Corporation, which shall be if (i) a Person acquires more than 50% of the Corporation’s stock; (ii) a Person acquires during a 12-month period at least 30% (or a higher percentage specified under the Plan) of the Corporation’s stock; (iii) a majority of the members of the Board of Directors of the Corporation are replaced during a 12-month period; or (iv) a Person acquires during a 12-month period at least 40% of the gross fair market value of the Corporation’s assets.

(ii)”Disabled” means that an individual (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of the individual’s employer

(iii)”Fixed Schedule” means the distribution or payment of compensation deferred under this instrument and award in a fixed schedule of distributions or payments that are determined and fixed at the time the deferral of such compensation is first elected by the Grantee or the Corporation.

(iv)”Specified Employee” means a key employee (as defined in Code section 416(i) without regard to paragraph (5) thereof) of the Corporation

(v)”Specified Time” means a specified date at which deferred compensation deferred by or for the Grantee pursuant to this instrument and Award is required to be distributed or paid and which is specified at the time of the election of deferral of such deferred compensation.

(vi)“Unforeseeable Emergency” means a severe financial hardship to the participant resulting from an illness or accident of the participant, the participant’s spouse, or a dependent (as defined in Code section 152(a)) of the participant, loss of the participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. As determined under Treasury Regulations under Code section 409A, the amounts distributed with respect to an emergency shall not exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the participant’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship).

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8.Administration of Restricted Unit Award. The grant of the Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the restrictions made applicable to the Grantee and the Restricted Units during the Restricted Period. This instrument and the rights and obligations of the parties involved, shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the Common Stock that would otherwise be transferred and delivered to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

9.Adjustment Provisions. It is understood that, prior to the expiration of the Restricted Period, certain changes in capitalization of the Corporation may occur. It is, therefore, understood and agreed with respect to changes in capitalization that:

(a)If a stock dividend is declared on the Common Stock of the Corporation, which has not been granted as a dividend equivalent, there shall be added to the number of Restricted Units described in paragraph 1 of this instrument, the number of Restricted Units which the Grantee would have been entitled to if the Grantee had been fully vested and the unrestricted owner of the number of Restricted Units then held under the Award granted, but not theretofore received without restriction; provided, however, that the additional Restricted Units shall be subject to all terms and provisions of this instrument (including, without limitation, the restrictions stated in paragraph 5, above), and in making such adjustments, no fractional Restricted Units shall be awarded, and the Grantee shall be entitled to receive only the number of full Restricted Units to which the Grantee may be entitled by reason of such adjustment at the adjusted grant price per share.

(b)In the event of an increase in the outstanding shares of Common Stock of the Corporation, effectuated for the purpose of acquiring properties or securities of another corporation or business enterprise, there shall be no increase in the number of shares of Restricted Units which are the subject matter of the Award evidenced by this instrument as a result of such acquisition.

(c)In the event of an increase or decrease in the number of outstanding shares of Common Stock of the Corporation through recapitalization, reclassification, stock split-ups, consolidation of shares, changes in par value and the like, an appropriate adjustment shall be made in the number of Restricted Units described in paragraph 1 of this instrument, by increasing or decreasing the number of Restricted Units, as may be required to enable the Grantee to acquire the same proportionate stockholdings as the grant of the Award would

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originally have provided. Provided, however, that any additional Restricted Units shall be subject to all terms and provisions of this instrument (including, without limitation, the restrictions stated in paragraph 5, above), and that in making such adjustments, no fractional Restricted Units shall be awarded, and the Grantee shall be entitled to receive only the number of full Restricted Units to which the Grantee may be entitled by reason of such adjustment.

(d)Except with respect to the time of payment of any compensation deferred under this instrument, to the extent Restricted Units are still restricted and not vested in Grantee at the time of a Change in Control with respect to the Corporation, then pursuant to the provisions of the Plan, they shall become fully vested and completely unrestricted and free and clear of any restrictions stated herein at that time; provided, that if such Change in Control occurs less than six (6) months after the date of the grant of Restricted Units to the Grantee, then Restricted Units shall become fully vested and completely unrestricted and free and clear of any restrictions stated herein at the time of such Change in Control only if the Grantee agrees in writing, if requested by the Corporation in writing, to remain in the employ of the Corporation or a division or subsidiary of the Corporation at least through the date which is six (6) months after the date the grant was made with substantially the same title, duties, authority, reporting relationships, and compensation as on the day immediately preceding the Change in Control. The provisions of this subparagraph (d) shall be applied in addition to, and shall not reduce, modify, or change any other obligation or right of the Grantee otherwise provided for in paragraph 3, above, concerning the Grantee’s continued employment with the Corporation or the termination thereof. If the Restricted Units become subject to this subparagraph (d), they shall become fully vested in the Grantee and nonforfeitable. Such Restricted Units are subject to the provisions of the Plan authorizing the Corporation, or a committee of its Board of Directors, to provide in advance or at the time of a Change in Control for cash to be paid in settlement of the Restricted Units, all subject to such terms and conditions as the Corporation or the Committee, in its sole discretion, may determine and impose. For purposes of this subparagraph (d), the term “Change in Control” shall have the same meaning as provided in the definition of that term stated in the Plan, including any amendments thereof which may be made from time to time in the future pursuant to the provisions of the Plan, with any amended definition of such term to apply to all events thereafter coming within the amended meaning.

10.Required Grantee Repayment/Reduction Provision. Notwithstanding anything in the Plan, the Award or this instrument to the contrary, all or a portion of the Award made to the Grantee under this instrument is subject to being called for repayment to the Corporation or reduced in any situation where the Board of Directors of the Corporation or a Committee thereof determines that fraud, negligence, or intentional misconduct by the Grantee was a contributing factor to the Corporation having to restate all or a portion of its financial statement(s). The Committee may determine whether the Corporation shall effect any such repayment or reduction: (i) by seeking repayment from the Grantee, (ii) by reducing (subject to applicable law and the terms and conditions of the Plan or any other applicable plan, program, or arrangement) the amount that would otherwise be awarded or payable to the Grantee under the Award, the Plan or any other compensatory plan, program, or arrangement maintained by the Corporation, (iii) by withholding payment of future increases in compensation (including the payment of any discretionary bonus amount) or grants of compensatory awards that would otherwise have been made in accordance with the Corporation’s otherwise applicable compensation practices, or (iv) by any combination of the foregoing. The determination

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regarding the Grantee’s conduct, and repayment or reduction under this provision shall be within the sole discretion of the Committee and shall be final and binding on the Grantee and the Corporation. The Grantee, in consideration of the grant of the Award, and by the Grantee’s execution of this instrument, acknowledges the Grantee’s understanding of the agreement to this provision, and hereby agrees to make and allow an immediate and complete repayment or reduction in accordance with this provision in the event of a call for repayment or other action by the Corporation or Committee to effect its terms with respect to the Grantee, the Award and/or any other compensation described herein.

11.Stock Reserved. The Corporation shall at all times during the term of the Award reserve and keep available such number of shares of its Common Stock as will be sufficient to satisfy the Award issued and granted to Grantee and the terms stated in this instrument, and shall pay all original issue taxes, if any, on the transfer of the Common Stock to the Grantee and all other fees and expenses necessarily incurred by the Corporation in connection therewith.

12.Rights of Shareholder. Except as otherwise provided in this instrument, the Grantee shall have no rights as a shareholder of the Corporation in respect of the Restricted Units or Common Stock for which the Award is granted; and the Grantee shall not be considered or treated as a record owner of shares of Common Stock with respect to the Restricted Units until the Common Stock is issued to Grantee and no longer subject to any of the restrictions imposed under the Award indicated in this instrument, and Common Stock is actually issued and transferred to Grantee.

13.Entire Agreement. This instrument contains the entire terms of the Award, and may not be changed orally or other than by a written instrument issued and approved by the Corporation pursuant to the Plan. This instrument supersedes any agreements or understandings that may have previously existed, and there are no other agreements or understandings, relating to its subject matter.

14.Successors and Assigns. The Award evidenced by this instrument shall inure to the benefit of and be binding upon the heirs, legatees, legal representatives, successors, and assigns of the parties hereto.

The Grantee hereby acknowledges receipt of this instrument, the Notice of Restricted Unit Award Agreement and a copy of the Plan, and accepts the Award under the terms and conditions stated in this instrument, subject to all terms and provisions of the Plan, by signing this instrument in duplicate originals, as of the date first stated above.

Date	«Officer_Name»
	Grantee

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EX-10.50

Exhibit 10.50

ADDITIONAL 2012 PERFORMANCE UNIT AWARD AGREEMENT

On January 31, 2014, shares of common stock of ONE Gas, Inc. were distributed to shareholders of ONEOK, Inc. common stock (the “Distribution”). The Board of Directors of ONEOK, Inc. has approved the equitable adjustment of outstanding share-based awards in an attempt to preserve the value of such awards immediately before and after the Distribution. Accordingly, this instrument is issued as of the ___ day of February, 2014, by ONEOK, Inc., an Oklahoma corporation, (hereinafter referred to as “Corporation”), to «Officer_Name» (hereinafter referred to as “Grantee”), an employee of the Corporation or a division or subsidiary thereof, pursuant to the terms of the ONEOK, Inc. Equity Compensation Plan, effective February 17, 2005, as amended (hereinafter referred to as the “Plan”).

1.Adjustment to 2012 Performance Unit Award. This instrument and that certain Notice of Performance Unit Award and Agreement, dated February __, 2014, a copy of which is attached hereto and incorporated herein by reference (the “Notice of Performance Unit Award and Agreement”), constitute evidence of the issuance and grant of a Performance Unit Award (hereinafter referred to as “Award”) of «No_of_Perf_Units» additional Performance Units (“Performance Units”) to the Grantee by the Corporation, pursuant to the Adjustment provisions of the Plan and the Performance Unit Award Agreement dated February 15, 2012 (the “2012 Agreement”), that shall entitle the Grantee to receive shares of the Corporation’s Common Stock (hereinafter also referred to as “Common Stock”) or cash, all pursuant and subject to the terms, provisions, and conditions of this instrument (including, without limitation, the conditions, restrictions and limitations stated in paragraph 5, below) and the terms and provisions of the Plan, which are incorporated herein by reference. This instrument, when executed by the Grantee, together with the Notice of Performance Unit Award and Agreement constitute an agreement between the Corporation and the Grantee. Notwithstanding the foregoing, should there be any inconsistency between the provisions of this instrument and the terms and provisions of the Award stated in the resolutions and records of the Board of Directors of the Corporation providing for the Award or provisions of the Plan, the provisions of such resolutions and records and of the Plan shall control. Moreover, the Performance Units awarded pursuant to this Agreement shall be deemed to satisfy any obligation of the Corporation to provide any additional Performance Units to Grantee under the Plan or the 2012 Agreement as a result of the Distribution. The grant of such Performance Units to the Grantee shall be effective in the manner and to the extent provided in this instrument and the Plan as to all or any part of the shares of Common Stock subject to the grant from time to time during the period stated herein.

2.Plan. The Award is made to the Grantee pursuant to the terms and provisions of the Plan, as approved by the Shareholders of the Corporation, which Plan provides that a specific aggregate number of shares of Common Stock of the Corporation may be issued or transferred pursuant to Stock Incentives under the Plan. The Plan specifies the authority of the Corporation, its Board of Directors, and a committee of the Board of Directors to select employees to be granted Stock Incentives under the Plan. The Executive Compensation Committee of the Board of Directors (hereinafter referred to as the “Committee”) is authorized to administer the Plan with respect to this instrument and the grant of the Award made to the Grantee pursuant to the Plan. Except where expressly stated or clearly indicated otherwise by the terms of this instrument, all terms, words and phrases used herein shall have the same meaning and effect as

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stated and in the Plan. The Grantee has been provided a complete copy of the Plan with this instrument.

3.Grantee’s Agreement Concerning Award and Employment. In consideration of the Corporation’s granting of the Award of Performance Units and entitlement to shares of Common Stock, as incentive compensation to Grantee pursuant to this instrument, the Grantee, by acceptance thereof, and signing this instrument evidencing its terms, agrees to such terms and to continue to contribute and perform service in the employ of the Corporation or a division or subsidiary thereof, at the direction, will and pleasure of the Corporation and the Board of Directors. Provided, however, neither the foregoing agreement of the Grantee in this paragraph 3, nor any other provision in this instrument shall confer on the Grantee any right to continue in the employ of the Corporation (or a division or Subsidiary thereof), or interfere in any way with the right of the Corporation (or such division or Subsidiary) to terminate the Grantee’s employment at any time.

4.Registration of Stock; Grantee’s Representation With Respect To Acquiring for Investment. It is intended by the Corporation that the Plan and the shares of Common Stock covered by the Award issued and granted to the Grantee referred to in paragraph 1, above, are to be registered under the Securities Act of 1933, as amended, prior to the date of the grant; provided, that in the event such registration is for any reason not made effective for such shares, the Grantee agrees, for the Grantee, and for the Grantee’s permissible assignees, heirs and legal representatives by inheritance or bequest, that all shares acquired pursuant to the grant will be acquired for investment and not with a view to, or for sale or tender in connection with the distribution of any part thereof, including any transfer or distribution of such shares by the Grantee pursuant to the grant and this instrument or as otherwise allowed by the Plan.

5.Terms and Conditions of Award; Transfer of Stock to Grantee. The issue and grant of the Award of Performance Units to the Grantee stated in paragraph 1, above, shall be subject to the following terms and conditions:

(a)The right to ownership and transfer of the Performance Units granted to the Grantee shall be subject to the Award during the period beginning February __, 2014, the date of the grant thereof (hereinafter referred to as “Grant Date”), and ending on February 15, 2015, (which period is hereinafter referred to as “Performance Period”), as herein provided.

(b)The Grantee shall earn and become entitled to receive a percentage of the number of Performance Units granted under paragraph 1, above, at the expiration of the Performance Period as provided for in Exhibit A and Exhibit B, attached hereto, based upon the Corporation’s ranking for Total Stockholder Return in the ONEOK Peer Group listed in Exhibit C attached hereto, all as determined by the Committee, in its sole discretion (the “Performance Goal”)

(c)Upon expiration of the Performance Period, the Grantee shall be entitled to receive one (1) share of Common Stock for each Performance Unit that becomes earned by and vested in the Grantee pursuant to the Award; provided, no fractional shares shall be issued and any amount attributable to a fractional share shall be paid to the Grantee in cash.

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(d)All Common Stock the Grantee becomes entitled to receive pursuant to the Award and any other compensation payable to the Grantee under the Award shall be paid, distributed, transferred and issued by the Corporation to the Grantee at the expiration of the Performance Period, or as soon as practicable after the determination that the Grantee has earned and become entitled to Performance Units and to receive such Common Stock and cash, as determined by the Committee, and in no event later than the 15^th day of the third month after the date of expiration of the Performance Period, and the Grantee shall not be permitted, directly or indirectly, to designate the time of payment, distribution or transfer or the taxable year in which it is to be made. Provided, that if the Grantee elects pursuant to paragraph 6, below, to defer the receipt of all Performance Units, Common Stock and cash for each Performance Unit that becomes earned by and vested in the Grantee pursuant to the Award, the payment, distribution and transfer of such Performance Units, Common Stock and cash shall be deferred and thereafter paid, distributed and transferred by the Corporation to the Grantee at the specified time and in accordance with the method of payment, distribution and transfer that is elected in by the Grantee in accordance with the election provisions set forth therein.

(e)The Grantee shall not be entitled to vote any shares of Common Stock of the Corporation have any right or interest as a holder of Common Stock by reason of the Performance Unit Award granted under the Award during the Performance Period, and prior to the actual transfer of Common Stock to the Grantee pursuant to the Award.

(f)The Common Stock or cash to which the Grantee becomes entitled shall be paid and transferred to the Grantee only upon the determination of the Performance Units earned by the Grantee at the expiration of the Performance Period. The payment and transfer of such Common Stock or cash to the Grantee shall be made as soon as reasonably practicable after the expiration of the Performance Period, as determined and directed by the Committee, in its sole discretion.

(g)The Performance Units or any Common Stock or cash to be paid or transferred to Grantee pursuant to the Award may not be sold, assigned, transferred, pledged, encumbered or otherwise disposed of by Grantee or any other person except as provided in the Award and the Plan until the expiration of the Performance Period and payment and transfer of Common Stock or cash pursuant to the Agreement and Plan.

(h)The Grantee shall become entitled to receive Performance Units earned, and shall become owner of the shares of Common Stock or cash paid and transferred to the Grantee pursuant to the Award free and clear of all terms, conditions and restrictions imposed by the Award if the Grantee’s employment by the Corporation does not terminate during the Performance Period; provided, that the Grantee shall become entitled to a prorated amount of Performance Units and the terms and conditions imposed by the Award shall partially cease to apply in certain events to the extent described in paragraph 7(d), below.

(i)If the Grantee’s employment with the Corporation (or a division or Subsidiary thereof) terminates prior to the end of the Performance Period other than by reason of Retirement, Total Disability or death, the Grantee shall forfeit all of the Grantee’s right, title or interest in the Performance Units; and the Grantee shall forfeit such right, title and interest in the Performance Units regardless of the reason for such termination of employment. Any such

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termination of employment of the Grantee described in the preceding sentence shall not be deemed to occur by reason of transfer of employment of the Grantee by or between the Corporation and any division or Subsidiary of the Corporation. Upon forfeiture the Performance Units forfeited shall be cancelled for all purposes.

6.Deferral of Payment, Distribution and Transfer of Stock.

(a)    The Grantee may irrevocably elect to defer the time of payment, distribution and transfer of Performance Units, Common Stock and cash that the Grantee becomes entitled to receive under this Agreement and Award from the end of the Performance Period generally provided for in paragraph 5, above, to a specified time by filing with the Committee, on or before the deferral election date (hereinafter referred to as “Election Date”) described in paragraph 6(b), below, a signed written irrevocable election (hereinafter referred to as “Election”) which shall be in the form substantially the same as attached hereto as Exhibit D, or as otherwise prescribed by the Committee.

(b)An Election of the Grantee to defer the payment, distribution and transfer of Performance Units, Common Stock and cash that the Grantee becomes entitled to receive under this Agreement and Award shall be filed by the Grantee with the Committee on or before the Election Date, which shall be August 20, 2015, the date that is six (6) months before the end of the Performance Period, provided that the Grantee performs services for the Corporation continuously from the later of the beginning of the Performance Period or the date the performance criteria are established through the date the Election is made under this paragraph 6(b), and provided, further, that in no event may the Grantee make an Election to defer the payment, distribution and transfer of Performance Units, Common Stock or cash after such compensation has become readily ascertainable; and in this regard for purposes of this paragraph 6(b), if the amount of Performance Units, Common Stock and cash, or other compensation, as performance-based compensation, is a specified or calculable amount, then it shall be considered compensation that is readily ascertainable if and when the amount is first substantially certain to be paid, distributed and transferred to the Grantee. If the amount of Performance Units, Common Stock and cash, or other compensation, is performance-based compensation that is not a specified or calculable amount because, for example, the amount may vary based upon the level of performance, such compensation, or any portion of the compensation, shall be considered readily ascertainable when the amount is first both calculable and substantially certain to be paid. For this purpose, such performance-based compensation is to be bifurcated between the portion that is readily ascertainable and the amount that is not readily ascertainable, and, in general, any minimum amount that is both calculable and substantially certain to be paid shall be treated as readily ascertainable.

(c)A Grantee that makes an Election to defer payment, distribution and transfer of Performance Units, Common Stock and cash that the Grantee becomes entitled to receive under this Agreement and Award may irrevocably elect to have payment, distribution and transfer made to the Grantee at a Specified Time, that shall be either (i) the later of (A) the date of the Grantee’s separation from service with the Corporation, or (B) a specified calendar date, or (ii) the date of the Grantee’s separation from service with the Corporation; and may elect to have payment made in a specified form of payment that shall be either (i) a single lump sum payment, distribution and transfer, or (ii) a payment, distribution and transfer in two, three, four

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or five equal annual installments commencing at the Specified Time elected by the Grantee hereunder and thereafter on each anniversary thereof, until fully paid, transferred and distributed.

(d) The Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the restrictions made applicable to the Grantee and the Performance Units during the Performance Period. This instrument and the rights and obligations of the parties involved, shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the Common Stock that would otherwise be transferred and delivered to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

(e) The provisions of this instrument providing for the deferral of payment, distribution, transfer or issuance of Performance Units, Common Stock or cash shall be applicable solely and exclusively to the Grantee and the Award Agreement and Award referred to herein, and shall not apply to any other stock incentive or other grant, award or transfer provided for or made under the Plan.

(f) Notwithstanding anything otherwise provided under the Plan or in the Award Agreement and Award, the following requirements shall apply to this Award Agreement and the Award, to all elections or subsequent elections made by the Grantee, and to all distributions and payments made to the Grantee pursuant to this Award Agreement and Award:

(1) Any compensation for services performed by the Grantee during a taxable year may be deferred at the Grantee’s election or the Corporation’s election or determination only if the election to defer such compensation is made not later than the close of the preceding taxable year or such other time as provided in Treasury Regulations under section 409A of the Internal Revenue Code of 1986, as amended (“Code”), but in all events any deferral of the payment, distribution, transfer or issuance of Performance Units, Common Stock or cash pursuant to the Award and Award Agreement may be made only by an election that is made on or before the Election Date.

(2) Any compensation deferred under the Plan shall not be distributed earlier than

(i) Separation from Service of the Grantee,

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(ii) the date the Grantee becomes Disabled,

(iii) death of the Grantee,

(iv) a Specified Time (or pursuant to a Fixed Schedule) specified under the plan under which the compensation is deferred at the date of deferral of such compensation,

(v) a Change in Ownership or Control, or

(vi) the occurrence of an Unforeseeable Emergency.

(3) If the Grantee is a Specified Employee, no payment or distribution shall be made before the date which is six (6) months after the date of the Grantee’s Separation from Service, or, if earlier, the date of death of the Grantee.

(4) No acceleration of the time or schedule of any distribution or payment under the plan under which compensation is deferred shall be permitted or allowed, except to the extent provided in Treasury Regulations issued under Code section 409A.

(5) This instrument shall not permit a subsequent election unless authorized and agreed upon in writing by the Corporation and Grantee, and if the Plan or this instrument permits under any subsequent election by the Grantee a delay in a payment or a change in the form of payment of compensation deferred under this Award Agreement and Award, such subsequent election shall not take effect until at least twelve (12) months after the date on which it is made. In the case of a subsequent election related to a payment to be made upon Separation from Service of the Grantee, at a Specified Time or pursuant to a Fixed Schedule, or upon a Change in Ownership or Control, the first payment with respect to which such subsequent election is made shall be deferred for a period of not less than five (5) years from the date such payment would otherwise have been made; and any such subsequent election related to a payment at a Specified Time or pursuant to a Fixed Schedule may not be made less than twelve (12) months prior to the date of the first scheduled payment to which it relates.

(6) For purposes of the Plan and this instrument and the Award, the following terms and definitions shall apply with respect to deferral of compensation and the time of payment of any deferred compensation:

(i) ”Change of Ownership or Control” means to the extent provided by Treasury Regulations issued under Code Section 409A, a change in the ownership or effective control of the Corporation, or in the ownership of a substantial portion of the assets of the Corporation, which shall be if (i) a Person acquires more than 50% of the Corporation’s stock; (ii) a Person acquires during a 12-month period at least 30% (or a higher percentage specified under the Plan) of the Corporation’s stock; (iii) a majority of the members of the Board of Directors of the Corporation are replaced during a 12-month period; or (iv) a Person acquires during a 12-month period at least 40% of the gross fair market value of the Corporation’s assets.

(ii) ”Disabled” means that an individual (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental

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impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving income replacement benefits for a period of not less than 3 months under an accident and health plan covering employees of the individual’s employer.

(iii) ”Fixed Schedule” means the distribution or payment of compensation deferred under this instrument and Award in a fixed schedule of distributions or payments that are determined and fixed at the time the deferral of such compensation is first elected by the Grantee or the Corporation.

(iv) ”Specified Employee” means a key employee (as defined in Code section 416(i) without regard to paragraph (5) thereof) of the Corporation.

(v) ”Specified Time” means a specified date at which deferred compensation deferred by or for the Grantee pursuant to this instrument and Award is required to be distributed or paid and which is specified at the time of the election of deferral of such deferred compensation

(vi) “Unforeseeable Emergency” means a severe financial hardship to the participant resulting from an illness or accident of the participant, the participant’s spouse, or a dependent (as defined in Code section 152(a)) of the participant, loss of the participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. As determined under Treasury Regulations under Code section 409A, the amounts distributed with respect to an emergency shall not exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the participant’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship).”

7.Transferability of Performance Units; Termination of Employment.

(a)Except as provided in subparagraph (b) of this paragraph 7, below, the Award, the Grantee’s rights and obligations hereunder and the Performance Units granted hereunder shall not be transferable by the Grantee otherwise than by will or the laws of descent and distribution which apply to the Grantee’s estate.

(b)Notwithstanding the foregoing, the Grantee may transfer any part or all of the Grantee’s rights in and to the Performance Units to members of the Grantee’s immediate family, or to one or more trusts for the benefit of such immediate family members, or partnerships in which such immediate family members are the only partners if the Grantee does not receive any consideration for the transfer. In the event of any such transfer, Performance Units shall continue to be subject to the same terms and conditions otherwise applicable hereunder and under the Plan immediately prior to its transfer, except that this stock shall not be further transferable by the transferee intervivos, except for transfer back to the original Grantee.

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For any such transfer to be effective, the Grantee must provide prior written notice thereof to the Committee, unless otherwise authorized and approved by the Committee, in its sole discretion; and the Grantee shall furnish to the Committee such information as it may request with respect to the transferee and the terms and conditions of any such transfer. For purposes of transfer of this grant under this subparagraph (b), “immediate family” shall mean the Grantee’s spouse, children and grandchildren.

(c)Notwithstanding anything to the contrary expressed or implied herein (including without limitation, the restrictions stated in paragraph 5, above, applicable to the Performance Units), all rights and interest of the Grantee in the Performance Units shall become invalid and wholly terminated and forfeited upon the termination of the Grantee’s employment with the Corporation (or a division or Subsidiary), during the Performance Period other than a termination by reason of Retirement, Total Disability or death of the Grantee.

(d)Notwithstanding the foregoing provisions, in the event of termination of the Grantee’s employment with the Corporation (or a division or Subsidiary) during the Performance Period by reason of (i) the Retirement of the Grantee, (ii) the Total Disability of the Grantee, or (iii) the Grantee’s death while still employed by the Corporation (or a division or Subsidiary), then an adjusted and prorated entitlement to Performance Units shall be allowed as provided in this paragraph 7(d). The Grantee shall become vested in and entitled to receive, in the event of any such Retirement or Total Disability, and the legatees, designated Beneficiary, or personal representatives or heirs of the Grantee shall be vested in and entitled to receive, in the event of the Grantee’s death, a prorated award of Performance Units earned in the Performance Period following such Retirement, Total Disability or death. The award shall be a prorated amount of Performance Units equal to the total of Performance Units earned under the Award at the end of the Performance Period for the Grantee, multiplied by a fraction of which the numerator shall be the number of full months which have elapsed under the Performance Period at the time of such termination of employment by reason of Retirement, Total Disability or death, and the denominator of which shall be the total number of months in the Performance Period. The Grantee, legatees, designated Beneficiary, or personal representatives or heirs of the Grantee, as the case may be, shall become entitled to receive such prorated award at the expiration of the Performance Period and following application of the performance criteria as provided in the Award and determined by the Committee.

The prorated award of Performance Units earned in the Performance Period to which the Grantee or the legatees, a designated Beneficiary, or the personal representative or heirs of the Grantee shall become vested in and entitled to receive under the foregoing provisions in event of Retirement, Total Disability or death of the Grantee, is to be qualified performance-based compensation paid solely on account of attainment of the Performance Goal, as provided for in Treas. Reg. §1.162-27(e)(2)(i). The Retirement, Total Disability or death of the Grantee during the Performance Period in and of itself alone shall in no case vest the Grantee in Performance Units or any part of thereof. A prorated vesting and entitlement to Performance Units or a part thereof, hereunder by reason of such events shall in all cases remain subject to and dependent solely upon the attainment of the Performance Goal as provided herein.

(e)The Grantee may designate a Beneficiary to receive any rights of the Grantee which may become vested in the event of the death of the Grantee under procedures and

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in the form established by the Committee; and in the absence of such designation of a Beneficiary, any such rights shall be deemed to be transferred to the estate of the Grantee.

(f)For purposes of the Award and this instrument, “Retirement” shall mean a voluntary termination of employment of the Grantee with the Corporation and/or a division or subsidiary thereof by the Grantee if at the time of such termination of employment the Grantee has both completed five (5) years of service with the Corporation and/or a division or subsidiary thereof and attained age fifty (50), and “voluntary termination” shall mean that the Grantee had an opportunity to continue employment with the Corporation and/or a division or subsidiary thereof, but did not do so; and except as provide for in paragraph 6 with respect to deferred compensation payments, “Total Disability” shall mean that the Grantee is permanently and totally disabled and unable to engage in any substantial gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than twelve (12) months, and has established such disability to the extent and in the manner and form as may be required under the provisions of Section 22(e) of the Internal Revenue Code of 1986, as amended (or corresponding section of any future federal tax code), and regulations thereunder.

8.Administration of Performance Unit Award. The grant of the Award shall be subject to such other rules and requirements as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof and the terms and conditions made applicable to the Grantee and the Performance Units during the Performance Period. The Award, this instrument, and the rights and obligations of the parties thereto shall be subject to interpretation and construction by the Committee to the same extent and with the same effect as the Committee actions under pertinent provisions of the Plan. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof. The Grantee agrees to pay to the Corporation any applicable federal, state, or local income, employment, social security, Medicare, or other withholding tax obligation arising in connection with the grant of the Award to the Grantee; and the Corporation shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the shares of Common Stock or cash that would otherwise be paid and transferred to the Grantee, with any shares of Common Stock so withheld to be valued at the Fair Market Value (as defined in the Plan) on the date of such withholding. The Grantee, with the consent of the Corporation, may satisfy such withholding tax by delivery and transfer to the Corporation of shares of Common Stock previously owned by the Grantee, with any shares so delivered and transferred to be valued at the Fair Market Value on the date of such delivery.

9.Adjustment Provisions. It is understood that, prior to the expiration of the Performance Period certain changes in capitalization of the Corporation may occur. It is, therefore, understood and agreed with respect to changes in capitalization that:

(a)If a stock dividend is declared on the Common Stock of the Corporation, which has not been granted as a dividend equivalent, there shall be added to the number of Performance Units provided for under the Award and stated in paragraph 1 of this instrument, the number of Performance Units equal to the number of Performance Units which would have been granted to the Grantee had the Grantee been the fully vested and unrestricted owner of the

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number of Performance Units then provided for under the Award granted, but not theretofore received without restriction; provided, however, that the additional Performance Units shall be subject to all terms and provisions of this instrument (including, without limitation, the terms and conditions stated in paragraph 5, above), and in making such adjustments, no fractional units, shares, or scrip certificates in lieu thereof, shall be granted or issuable by the Corporation, and the Grantee shall be entitled to only the number of full Performance Units to which the Grantee may be entitled by reason of such adjustment at the adjusted grant.

(b)In the event of an increase in the outstanding shares of Common Stock of the Corporation, effectuated for the purpose of acquiring properties or securities of another corporation or business enterprise, there shall be no increase in the number of Performance Units which are the subject matter of the Award under this instrument as a result of such acquisition.

(c)In the event of an increase or decrease in the number of outstanding shares of Common Stock of the Corporation through recapitalization, reclassification, stock split-ups, consolidation of shares, changes in par value and the like, an appropriate adjustment shall be made in the number of Performance Units provided for under the Award and stated in Section 1 of this instrument, by increasing or decreasing the number of Performance Units, as may be required to enable the Grantee to acquire the same proportionate stockholdings as the grant of the Award would originally have provided. Provided, however, that any additional Performance Units shall be subject to all terms and provisions of this instrument (including, without limitation, the restrictions stated in paragraph 5, above), and that in making such adjustments, no fractional Performance Units shall be awarded, and the Grantee shall be entitled to receive only the number of full Performance Units to which the Grantee may be entitled by reason of such adjustment.

(d)Except as otherwise provided for with respect to the payment of any deferred compensation in paragraph 6, above, to the extent Performance Units are still not vested in Grantee at the time of a Change in Control with respect to the Corporation, then pursuant to the provisions of the Plan, they shall become fully vested and completely free and clear of any conditions or restrictions stated herein at that time; provided, that if such Change in Control occurs less than six (6) months after the date of the grant of the Award hereunder to the Grantee, then Performance Units shall become fully vested and completely free and clear of any conditions or restrictions stated herein at the time of such Change in Control only if the Grantee agrees in writing, if requested by the Corporation in writing, to remain in the employ of the Corporation or a division or subsidiary of the Corporation at least through the date which is six (6) months after the date the grant was made with substantially the same title, duties, authority, reporting relationships, and compensation as on the day immediately preceding the Change in Control. The provisions of this subparagraph (d) shall be applied in addition to, and shall not reduce, modify, or change any other obligation or right of the Grantee otherwise provided for in paragraph 3, above, concerning the Grantee’s continued employment with the Corporation or the termination thereof. If the Performance Units become subject to this subparagraph (d), they shall become fully vested in the Grantee and nonforfeitable. The Performance Units are subject to the provisions of the Plan authorizing the Corporation, or a committee of its Board of Directors, to provide in advance or at the time of a Change in Control for cash to be paid in actual settlement of the shares of Common Stock for earned Performance Units, all subject to such terms and

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conditions as the Corporation or the Committee, in its sole discretion, may determine and impose. For purposes of this subparagraph (d), the term “Change in Control” shall have the same meaning as provided in the definition of that term stated in the Plan, including any amendments thereof which may be made from time to time in the future pursuant to the provisions of the Plan, with any amended definition of such term to apply to all events thereafter coming within the amended meaning.

10.Required Grantee Repayment/Reduction Provision. Notwithstanding anything in the Plan, the Award or this instrument to the contrary, all or a portion of the Award made to the Grantee under this instrument is subject to being called for repayment to the Corporation or reduced in any situation where the Board of Directors of the Corporation or a Committee thereof determines that fraud, negligence, or intentional misconduct by the Grantee was a contributing factor to the Corporation having to restate all or a portion of its financial statement(s). The Committee may determine whether the Corporation shall effect any such repayment or reduction: (i) by seeking repayment from the Grantee, (ii) by reducing (subject to applicable law and the terms and conditions of the Plan or any other applicable plan, program, or arrangement) the amount that would otherwise be awarded or payable to the Grantee under the Award, the Plan or any other compensatory plan, program, or arrangement maintained by the Corporation, (iii) by withholding payment of future increases in compensation (including the payment of any discretionary bonus amount) or grants of compensatory awards that would otherwise have been made in accordance with the Corporation’s otherwise applicable compensation practices, or (iv) by any combination of the foregoing. The determination regarding the Grantee’s conduct, and repayment or reduction under this provision shall be within the sole discretion of the Committee and shall be final and binding on the Grantee and the Corporation. The Grantee, in consideration of the grant of the Award, and by the Grantee’s execution of this instrument, acknowledges the Grantee’s understanding of the agreement to this provision, and hereby agrees to make and allow an immediate and complete repayment or reduction in accordance with this provision in the event of a call for repayment or other action by the Corporation or Committee to effect its terms with respect to the Grantee, the Award and/or any other compensation described herein.

11.Stock Reserved. The Corporation shall at all times during the term of the Award reserve and keep available such number of shares of its Common Stock as will be sufficient to satisfy the Award issued and granted to Grantee and the requirements thereof as evidenced by this instrument, and shall pay all original issue taxes, if any, on the transfer of Common Stock to the Grantee, and all other fees and expenses necessarily incurred by the Corporation in connection therewith.

12.Rights of Shareholder. Except as otherwise provided in the Award and this instrument, the Grantee shall have no rights as a shareholder of the Corporation in respect of the Performance Units or Common Stock for which the Award is granted; and the Grantee shall not be considered or treated as a record owner of shares with respect to the Common Stock until the Performance Units are fully vested and no longer subject to any of the conditions, performance requirements, or restrictions imposed under the Award, and Common Stock is actually issued and transferred to the Grantee.

13.Entire Agreement. This instrument contains the entire terms of the Award, and may not be changed orally or other than by a written instrument issued and approved by the

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Corporation pursuant to the Plan. This instrument supersedes any agreements or understandings that may previously have existed, and there are no other agreements or understandings, relating to its subject matter.

14.Successors and Assigns. The Award shall inure to the benefit of and be binding upon the heirs, legatees, legal representatives, successors, and assigns of the parties thereto.

The Grantee hereby acknowledges receipt of this instrument, the Notice of Performance Unit Award and a copy of the Plan, and accepts the Award under the terms and conditions stated in this instrument, subject to all terms and provisions of the Plan, by signing this instrument in duplicate originals, as of the date first above written.

Date	«Officer_Name»
	Grantee

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\

Exhibit A

Performance Units Criteria

2012-2015 Performance Period

Total Stockholder Return (TSR):vs. ONEOK Peer Group
ONEOK TSR Ranking vs. ONEOK Peer Group	Percentage of Performance Units Earned
90th percentile and above 75th percentile 50th percentile 25th percentile Below 25th percentile	200% 150% 100% 50% 0%

IF ONEOK’s TSR ranking at the end of the performance period is between the stated percentile levels in the above table, the percentage of the performance units earned will be interpolated between the earning levels. No Performance Units are earned if ONEOK’s TSR ranking at the end of the performance period is below the 25^th percentile.

Exhibit B

Illustration of Hypothetical 2012-2015 Performance Period

Performance Unit Award Calculation

Illustration assumes 500 Performance Units Granted

Total Stockholder Return (TSR) vs. ONEOK Peer Group

Hypothetical 2012-2015 ONEOK TSR Ranking = 40^th percentile

A 40^th percentile TSR ranking earns 80% of Performance Units granted (i.e., 500 units)

as interpolated between 50% and 100% from Table A (see chart below)

400 units earned

Total Performance Units Earned

TR 400 Performance Units

400 performance units earned out of 500units granted = 80% “earn-out” [80% (500 shares) paid and distributed in the form of Common Stock as provided in section 5.c.]

Exhibit C

ONEOK PEER GROUP - 2012
Company Name	Sym
AGL Resources Inc.	GAS
ATMOS Energy	ATO
CenterPoint Energy Inc.	CNP
Enbridge Inc.	ENB
Energy Transfer Partners LP	ETP
Enterprise Products Partners LP	EPD
EQT Corporation	EQT
Integrys Energy Group Inc.	TEG
Kinder Morgan Energy LP	KMP
MDU Resources Corp	MDU
Magellan Midstream Partners LP	MMP
MarkWest Energy Partners LP	MWE
National Fuel Gas Company	NFG
NiSource Inc.	NI
OGE Energy Corp	OGE
ONEOK, Inc.	OKE
Questar Corp	STR
SEMPRA Energy	SRE
Spectra Energy Corporation	SE
Targa Resources Partners LP	NGLS
TransCanada Corporation	TRP
Williams Companies Inc.	WMB

Exhibit D

ONEOK, INC. EQUITY COMPENSATION PLAN

PERFORMANCE UNIT AWARD AGREEMENT

DEFERRAL ELECTION

This Election is made by the undersigned Grantee pursuant to that certain Performance Unit Award granted to me under the ONEOK, Inc. Equity Compensation Plan, on the ___ day of February 2014, a copy of which is attached hereto (the “Award”).

This Election is made on or before the date of August 15, 2014, which is six (6) months before the end of the Performance Period on February 15, 2015.

I hereby irrevocably elect to defer the payment, distribution and transfer and my receipt of all Performance Units, Common Stock and cash that I may earn and become entitled to receive from the regularly scheduled time of payment, distribution and transfer provided for in paragraph 5(d) of the Award, until a later date as follows:

A.     Election of Specified Time of Payment (Initial one election of time of payment)

___    I elect to have all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award and Award Agreement deferred and paid, distributed, transferred and issued to me on the later of (i) the date of my separation from service as an employee of the Corporation, or (ii) _________________, 20__ in the form specified below.

___    I elect to have all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award and Award Agreement deferred and paid, distributed, transferred and issued to me on the date of my separation from service as an employee of the Corporation.

B.     Election of Form of Payment (Initial one election of form of payment)

___     I elect to receive payment, transfer and distribution of all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award or Award Agreement in a single lump sum payment.

____    I elect to receive payment, transfer and distribution of all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award or Award Agreement in ______(specify 2, 3, 4 or 5) equal annual installments commencing on the specified date of payment elected above, and thereafter on each anniversary thereof until fully paid and transferred. The number of shares of Common Stock or cash received in each installment will equal the number and amount that have not been settled, paid, transferred and distributed (as of the date immediately preceding the installment payment date) divided by the number of installments remaining to be paid (as of the date immediately preceding the installment payment date) rounded down to the next whole number except that the final installment shall be rounded up to the next whole number.

C.     Election for Death Prior to Specified Time of Payment (Put initials by your choice)

___    In the event of my death prior to the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation in a single lump sum within 60 days following my death.

___    In the event of my death prior to the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation be paid and transferred in ______ (specify 2, 3, 4 or 5) equal annual installments commencing within 60 days following my death, and thereafter on each anniversary of the commencement date until fully paid and transferred. The number of shares of Common Stock or cash received in each installment will equal the number and amount that have not been paid (as of the date immediately preceding the installment payment date) divided by the number of installments remaining to be paid (as of the date immediately preceding the installment payment date) rounded down to the next whole number except that the final installment shall be rounded up to the next whole number.

D.     Election for Death After Specified Time of Payment (Put initials by your choice)

___    In the event of my death after the Specified Time of Payment elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation in a single lump sum within 60 days following my death.

___    In the event of my death after the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment of any remaining Common Stock, cash or other compensation in accordance with the installment schedule elected above.

E.    Designation of Beneficiary (List each beneficiary and percentage)

I designate the following individuals (entities) as my beneficiaries to receive the following share(s) of my Common Stock, cash or other deferred compensation, as indicated below:

Name of Beneficiary	Percent
	100% (total must equal 100%)

F.    Change in Ownership or Control

Notwithstanding the foregoing, immediately following a Change in Ownership or Control the Common Stock, cash or other deferred compensation that have not been paid and transferred will be paid and transferred. In the event shares of Common Stock no longer exist at the time of payment and transfer, each of the deferred Performance Units shall be converted in a manner that is consistent with the manner in which shareholders of Common Stock were treated with respect to the Change in Ownership or Control.

Solely for purposes of this election, a “Change in Ownership or Control” shall mean and shall have occurred if one of the following has occurred: A person acquires more than 50% (or a higher percentage specified under the Plan) of the Corporation’s stock; a person acquires during a 12-month period at least 30% (or a higher percentage specified under the Plan) of the Corporation’s stock; a majority (or a higher percentage specified under the Plan) of the members of the Board of Directors of the Corporation are replaced during a 12-month period; or a person acquires during a 12-month period at least 40% (or a higher percentage specified under the Plan) of the gross fair market value of the Corporation’s assets.

Made and executed by me as Grantee of the Award pursuant to the terms and provisions of Section 6 thereof, on this _______day of ______________, 2014.

_____________________________________

Grantee

Received this ____ day of ________, 2014,

______________________________________

For the Committee

EX-10.54

Exhibit 10.54

RESTRICTED UNIT AWARD

AGREEMENT

This Restricted Unit Award Agreement (the “Agreement”) is entered into as of the [____] day of February, 2014, by and between ONEOK, Inc. (the “Company”) and «Officer_Name» (the “Grantee”), an employee of the Company or a Subsidiary thereof, pursuant to the terms of the ONEOK, Inc. Long-Term Incentive Plan (the “Plan”).

1.Restricted Unit Award. This Agreement and the Notice of Restricted Unit Award and Agreement dated February [__], 2014, a copy of which is attached hereto and incorporated herein by reference, establish the terms and conditions for the Company’s grant of an Award of «No_of_Restricted_Units» Restricted Units (the “Award”) to the Grantee pursuant to the Plan. This Agreement, when executed by the Grantee, constitutes an agreement between the Company and the Grantee. Capitalized terms not defined in this Agreement shall have the meaning ascribed to them in the Plan.

2.Restricted Period; Vesting. The Restricted Units granted pursuant to the Award will vest in accordance with the following terms and conditions:

(a)Grantee’s rights with respect to the Restricted Units shall be restricted during the period beginning February [__], 2014 (the “Grant Date”), and ending on February [__], 2017 (the “Restricted Period”).

(b)Except as otherwise provided in this Agreement or under the Plan, the Grantee shall vest in the Restricted Units granted by this Award (including any Dividend Equivalents, as described below) at the end of the Restricted Period if the Grantee’s employment by the Company does not terminate during the Restricted Period. Upon vesting, the Grantee shall become entitled to one (1) share of the Company’s common stock (“Common Stock”) for each such Restricted Unit. No fractional shares shall be issued, and any amount attributable to a fractional share shall instead be paid to the Grantee in cash.

(c)If the Grantee’s employment with the Company terminates prior to the end of the Restricted Period by reason of (i) voluntary termination or (ii) involuntary Termination for Cause, the Grantee shall forfeit all right, title and interest in the Restricted Units and any Common Stock otherwise payable pursuant to this Agreement. For purposes of this Agreement, employment with any Subsidiary of the Company shall be treated as employment with the Company. Likewise, a termination of employment shall not be deemed to occur by reason of a transfer of employment between the Company and any Subsidiary.

(d)In the event of termination of the Grantee’s employment with the Company during the Restricted Period by reason of (i) involuntary termination other than a Termination for Cause, (ii) Retirement, (iii) Total Disability or (iv) the death, then the Grantee shall be partially vested in, and the Grantee (including his or her legatees, designated Beneficiary, personal representative or heirs, as applicable) shall be entitled to receive, the percentage of the Restricted Units which is determined by dividing the number of full months which have elapsed under the

Restricted Period at the time of such event by the number of full months in the Restricted Period. Restricted Units will vest immediately upon a Change in Control, as defined in the Plan.

(e)For purposes of this Agreement, the term “voluntary termination” shall mean that the Grantee had an opportunity to continue employment with the Company, but did not do so. An “involuntary termination” shall mean that the Company has ended the Grantee’s employment without the Grantee having an opportunity to continue employment with the Company. A “Termination for Cause” of the Grantee’s employment shall mean that the Company has ended such employment by reason of (i) the Grantee’s conviction in a court of law of a felony, or any crime or offense involving misuse or misappropriation of money or property, (ii) the Grantee’s violation of any covenant, agreement or obligation not to disclose confidential information regarding the business of the Company, (iii) any violation by the Grantee of any covenant not to compete with the Company, (iv) any act of dishonesty by the Grantee which adversely effects the business of the Company, (v) any willful or intentional act of the Grantee which adversely affects the business of, or reflects unfavorably on the reputation of the Company, (vi) the Grantee’s use of alcohol or drugs which interferes with the Grantee’s duties as an employee of the Company, or (vii) the Grantee’s failure or refusal to perform the specific directives of the Company’s Board of Directors or officers. “Retirement” shall mean a voluntary termination of employment with the Company if the Grantee has both completed five (5) years of service with the Company and attained age fifty (50). “Total Disability” shall mean that the Grantee is permanently and totally disabled and unable to engage in any substantial gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than twelve (12) months and has established such disability to the extent and in the manner and form as may be required by the Committee.

3.Dividend Equivalents. During the Restricted Period, the Award will be increased by a number of additional Restricted Units (“Dividend Equivalents”) representing all cash dividends that would have been paid to the Grantee if one share of Common Stock had been issued to the Grantee on the Grant Date for each Restricted Unit granted pursuant to this Agreement. The Dividend Equivalents credited during the Restricted Period will include fractional shares; provided, however, the shares of Common Stock actually issued upon vesting of the Dividend Equivalents shall be paid only in whole shares of Common Stock, and any fractional shares of Common Stock shall be paid in an amount of cash equal to the Fair Market Value of such fractional shares of Common Stock. Except as provided above, Dividend Equivalents shall be subject to the same vesting provisions and other terms and conditions of this Agreement, and shall be paid on the same date, as the Restricted Units to which they are attributable. Moreover, references in this Agreement to Restricted Units shall be deemed to include any Restricted Units attributable to Dividend Equivalents.

4.Non-Transferability of Restricted Units.

(a)Except as provided below, the Restricted Units may not be sold, assigned, transferred, pledged, encumbered or otherwise disposed of by Grantee or any other person until the expiration of the Restricted Period. Any such attempt shall be wholly ineffective and will result in immediate forfeiture of all such amounts.

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(b)Notwithstanding the foregoing, the Grantee may transfer any part or all rights in the Restricted Units to members of the Grantee’s immediate family, to one or more trusts for the benefit of such immediate family members or to partnerships in which such immediate family members are the only partners, in each case only if the Grantee does not receive any consideration for the transfer. In the event of any such transfer, the Restricted Units shall remain subject to the terms and conditions of this Agreement. For any such transfer to be effective, the Grantee must provide prior written notice thereof to the Committee, unless otherwise authorized and approved by the Committee, in its sole discretion; and the Grantee shall furnish to the Committee such information as it may request with respect to the transferee and the terms and conditions of any such transfer. For purposes of this Agreement, “immediate family” shall mean the Grantee’s spouse, children and grandchildren.

(c)The Grantee also may designate a Beneficiary to receive any rights of the Grantee which may become vested in the event of the death of the Grantee under procedures and in the form established by the Committee. In the absence of such designation of a beneficiary, any such rights shall be deemed to be transferred to the estate of the Grantee.

5.Distribution of Common Stock.

(a)The Common Stock or cash the Grantee becomes entitled to receive upon vesting of any Restricted Units shall be distributed to the Grantee as soon as practicable after the vesting date for such Restricted Units, as determined by the Committee in its discretion, but in no event later than March 15 of the first year beginning after the vesting date.

(b)The distribution of Common Stock and cash upon the Grantee’s Retirement prior to the end of the Restricted Period shall be distributed to the Grantee in a single payment, at the Specified Time of the Grantee’s Retirement or as soon as practicable thereafter as determined by the Committee, but in no event later than the 15th day of the third calendar month after the date of such Retirement. The Specified Time of payment of any other compensation that is deferred under this Agreement shall be the last day of the Restricted Period, or as soon as practicable thereafter as determined by the Committee, but in no event later than the 15th day of the third calendar month after the date of end of the Restricted Period. The Grantee shall not be permitted, directly or indirectly, to designate the form of payment or the taxable year in which any payment is to be made.

(c)To the extent required to satisfy Code Section 409A, the Specified Time of payment and form of payment specified in paragraph 5(b), above shall be considered as the irrevocable deferral election of the Company and the Grantee of the time and form of payment. No other election to defer compensation, or subsequent election or acceleration of the time and form of payment of compensation is intended or shall be allowed.

(d)To the extent that an Award is or becomes subject to Code Section 409A and Grantee is a Specified Employee who becomes entitled to distribution on account of a Separation from Service (within the meaning of Code Section 409A), no payment shall be made before the date which is six (6) months after the date of the Grantee’s Separation from Service, or, if earlier, the date of death of the Grantee.

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(e)No acceleration of the time or schedule of any distribution or payment under the plan under which compensation is deferred shall be permitted or allowed, except to the extent provided in Treasury Regulations issued under Code section 409A.

(f)For purposes of this Agreement, the term “Specified Employee” shall mean a key employee (as defined in Code section 416(i) without regard to paragraph (5) thereof) of the Company; and the term “Specified Time” shall mean a specified date at which compensation deferred by or for the Grantee pursuant to this Agreement is required to be paid and which is specified at the time of the election of deferral of such compensation.

6.Administration of Award. The Award shall be subject to such other rules as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof. This Agreement shall be subject to discretionary interpretation and construction by the Committee. Day-to-day authority and responsibility for administration of the Plan, the Award and this Agreement have been delegated to the Company’s Benefit Plan Administration Committee and its authorized representatives, and all actions taken thereby shall be entitled to the same deference as if taken by the Committee itself. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof.

7.Tax Liability and Withholding. The Grantee agrees to pay to the Company any applicable federal, state or local income, employment, social security, Medicare or other withholding tax obligation arising in connection with the Award to the Grantee, which the Company shall determine; and the Company shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the Common Stock that would otherwise be distributed to the Grantee (not to exceed the minimum amount of taxes required to be withheld from supplemental wage payments), with any shares of Common Stock so withheld to be valued at the Fair Market Value on the date of such withholding. The Grantee, with the consent of the Company, may satisfy such withholding tax by transferring cash or Common Stock to the Company, with any shares of Common Stock so transferred to be valued at the Fair Market Value on the date of such transfer. Notwithstanding the foregoing, the ultimate liability for Grantee’s share of all tax withholding is the Grantee’s responsibility, and the Company makes no tax-related representations in connection with the grant or vesting of Restricted Units or the distribution of Common Stock or cash to Grantee.

8.Adjustment Provisions. If, prior to the expiration of the Restricted Period, any change is made to the outstanding Common Stock or in the capitalization of the Company, the Restricted Units granted pursuant to this Award shall be equitably adjusted or terminated to the extent and in the manner provided under the terms of the Plan.

9.Required Grantee Repayment/Reduction Provision. Notwithstanding anything in the Plan or this Agreement to the contrary, all or a portion of the Award made to the Grantee under this Agreement is subject to being called for repayment to the Company or reduced in any situation where the Board of Directors or a Committee thereof determines that fraud, negligence, or intentional misconduct by the Grantee was a contributing factor to the Company having to restate all or a portion of its financial statement(s). The Committee may determine whether the Company shall effect any such repayment or reduction: (i) by seeking repayment from the

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Grantee, (ii) by reducing (subject to applicable law and the terms and conditions of the Plan or any other applicable plan, program, or arrangement) the amount that would otherwise be awarded or payable to the Grantee under the Award, the Plan or any other compensatory plan, program, or arrangement maintained by the Company, (iii) by withholding payment of future increases in compensation (including the payment of any discretionary bonus amount) or grants of compensatory awards that would otherwise have been made in accordance with the Company’s otherwise applicable compensation practices, or (iv) by any combination of the foregoing. The determination regarding the Grantee’s conduct, and repayment or reduction under this provision shall be within the sole discretion of the Committee and shall be final and binding on the Grantee and the Company. The Grantee, in consideration of the grant of the Award, and by the Grantee’s execution of this Agreement, acknowledges the Grantee’s understanding of the agreement to this provision, and hereby agrees to make and allow an immediate and complete repayment or reduction in accordance with this provision in the event of a call for repayment or other action by the Company or Committee to effect its terms with respect to the Grantee, the Award and/or any other compensation described in this Agreement.

10.Stock Reserved. The Company shall at all times during the term of the Award reserve and keep available such number of shares of its Common Stock as will be sufficient to satisfy the Award issued and granted to Grantee and the terms stated in this Agreement. It is intended by the Company that the Plan and shares of Common Stock covered by the Award are to be registered under the Securities Act of 1933, as amended, prior to the grant date; provided, that in the event such registration is for any reason not effective for such shares, the Grantee agrees that all shares acquired pursuant to the grant will be acquired for investment and will not be available for sale or tender to any third party.

11.No Rights as Shareholder. Except as otherwise provided in this Agreement, the Grantee shall have no rights as a shareholder of the Company in respect of the Restricted Units or Common Stock for which the Award is granted. The Grantee shall not be considered a record owner of shares of Common Stock with respect to the Restricted Units until the Common Stock is actually distributed to Grantee.

12.Continued Employment; Employment at Will. In consideration of the Company’s granting the Award as incentive compensation to Grantee pursuant to this Agreement, the Grantee agrees to all of the terms of this Agreement and to continue to perform services for the Company in a satisfactory manner as directed by the Company. Provided, however, no provision in this Agreement shall confer any right to the Grantee’s continued employment, limit the right of the Company to terminate the Grantee’s employment at any time or create any contractual right to receive any future awards under the Plan. Moreover, unless specifically provided under the terms thereof, the value of the Award will not be included as compensation or earnings when calculating the Grantee’s benefits under any employee benefit plan sponsored by the Company.

13.Section 409A. This Agreement is intended to comply with Section 409A of the Code or an exemption therefrom and shall be construed and interpreted in a manner that is consistent with the requirements for avoiding additional taxes or penalties under Section 409A of the Code. Notwithstanding the foregoing, the Company makes no representations that the payments and benefits provided under this Agreement comply with Section 409A of the Code

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and shall not be liable for all or any taxes, penalties, interest or other expenses that may be incurred by the Grantee on account of non-compliance with Section 409A of the Code.

14.Entire Agreement; Severability; Conflicts. This Agreement contains the entire terms of the Award, and may not be changed other than by a written instrument executed by both parties or an amendment of the Plan. This Agreement supersedes any prior agreements or understandings, and there are no other agreements or understandings relating to its subject matter. The invalidity or unenforceability of any provision of the Plan or this Agreement shall not affect any other provision of the Plan or this Agreement, and each provision of the Plan and this Agreement shall be severable and enforceable to the extent permitted by law. Should there be any inconsistency between the provisions of this Agreement and the terms of the Award as stated in the resolutions and records of the Board of Directors or the Plan, the provisions of such resolutions and records of the Board of Directors and the Plan shall control.

15.Successors and Assigns. The Award evidenced by this Agreement shall inure to the benefit of and be binding upon the heirs, legatees, legal representatives, successors, and assigns of the parties hereto.

The Grantee hereby acknowledges receipt of this Agreement, the Notice of Restricted Unit Award and Agreement and a copy of the Plan, and accepts the Award under the terms and conditions stated in this Agreement, subject to all terms and provisions of the Plan, by signing this Agreement as of the date indicated.

Date	«Officer_Name»
	Grantee

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EX-10.55

Exhibit 10.55

PERFORMANCE UNIT AWARD AGREEMENT

This Performance Unit Award Agreement (the “Agreement”) is entered into as of the [____] day of February, 2014, by and between ONEOK, Inc. (the “Company”) and «Officer_Name» (the “Grantee”), an employee of the Company or Subsidiary thereof, pursuant to the terms of the ONEOK, Inc. Equity Compensation Plan (the “Plan”).

1.Performance Unit Award. This Performance Unit Award Agreement and the Notice of Performance Unit Award and Agreement dated February [__], 2014, a copy of which is attached hereto and incorporated herein by reference, establishes the terms and conditions for the Company’s grant of an award of «No of_Perf_Units» Performance Units (the “Award”) to the Grantee pursuant to the Plan. This Agreement, when executed by the Grantee, constitutes an agreement between the Company and the Grantee. Capitalized terms not defined in this Agreement shall have the meaning ascribed to them in the Plan.

2.Performance Period; Vesting. The Performance Units granted pursuant to the Award will vest in accordance with the following terms and conditions:

(a)Grantee’s rights with respect to the Performance Units shall be restricted during the period beginning February [__], 2014, (the “Grant Date”), and ending on February [__], 2017, (the “Performance Period”).

(b)Except as otherwise provided in this Agreement, the Grantee shall vest in a percentage of the number of Performance Units granted by this Award (including any Dividend Equivalents, as described below) at the end of the Performance Period, as provided for in Exhibit A and Exhibit B attached hereto, based upon the Company’s ranking for Total Stockholder Return against the ONEOK Peer Group listed in Exhibit C attached hereto, all as determined by the Committee in its sole discretion. Upon vesting, the Grantee shall be entitled to receive one (1) share of the Company’s common stock (“Common Stock”) for each such Performance Unit. No fractional shares shall be issued, and any amount attributable to a fractional share shall instead be paid to the Grantee in cash.

(c)If the Grantee’s employment with the Company terminates prior to the end of the Performance Period other than by reason of Retirement, Total Disability, death or Change in Control, the Grantee shall forfeit all right, title and interest in the Performance Units and any Common Stock otherwise payable pursuant to this Agreement. For purposes of this Agreement, employment with any Subsidiary of the Company shall be treated as employment with the Company. Likewise, a termination of employment shall not be deemed to occur by reason of a transfer of employment between the Company and any Subsidiary.

(d)If the Grantee’s employment with the Company is terminated during the Performance Period by reason of (i) Retirement, (ii) Total Disability or (iii) death, then the Grantee shall be partially vested in, and the Grantee (including his or her legatees, designated Beneficiary, personal representative or heirs, as applicable) shall be entitled to receive, a prorated amount of Performance Units. The prorated amount is determined by multiplying the original Award times the percentage certified by the Committee at the end of the Performance

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Period, which is then multiplied by a fraction consisting of the number of full months that have elapsed under the Performance Period at the time of such event divided by the total number of months in the Performance Period. Performance Units will vest immediately upon a Change in Control, as defined in the Plan.

(e)For purposes of the Award and this Agreement, “Retirement” shall mean a voluntary termination of employment if the Grantee has both completed five (5) years of service with the Company and attained age fifty (50); and “voluntary termination” shall mean that the Grantee had an opportunity to continue employment with the Company, but did not do so. “Total Disability” shall mean that the Grantee is permanently and totally disabled and unable to engage in any substantial gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or which has lasted or can be expected to last for a continuous period of not less than twelve (12) months, and has established such disability to the extent and in the manner and form as may be required by the Committee.

3.Dividend Equivalents.During the Performance Period, the Award will be increased by a number of additional Performance Units (“Dividend Equivalents”) representing all cash dividends that would have been paid to Grantee if one share of Common Stock had been issued to the Grantee on the Grant Date for each Performance Unit granted pursuant to this Agreement. The Dividend Equivalents credited during the Performance Period will include fractional shares; provided, however, the shares of Common Stock actually issued upon vesting of the Dividend Equivalents shall be paid only in whole shares of Common Stock, and any fractional shares of Common Stock shall be paid in an amount of cash equal to the Fair Market Value of such fractional shares of Common Stock. Except as provided above, Dividend Equivalents shall be subject to the same vesting provisions and other terms and conditions of this Agreement, and shall be paid on the same date, as the Performance Units to which they are attributable. Moreover, references in this Agreement to Performance Units shall be deemed to include any Performance Units attributable to Dividend Equivalents.

4.Non-Transferability of Performance Units.

(a)Except as provided below, the Performance Units may not be sold, assigned, transferred, pledged, encumbered or otherwise disposed of by Grantee or any other person until the end of the Performance Period. Any such attempt shall be wholly ineffective and will result in immediate forfeiture of all such amounts.

(b)Notwithstanding the foregoing, the Grantee may transfer any part or all rights in and to the Performance Units to members of the Grantee’s immediate family, to one or more trusts for the benefit of such immediate family members or to partnerships in which such immediate family members are the only partners, in each case only if the Grantee does not receive any consideration for the transfer. In the event of any such transfer, the Performance Units shall remain subject to the terms and conditions of this Agreement. For any such transfer to be effective, the Grantee must provide prior written notice thereof to the Committee, unless otherwise authorized and approved by the Committee in its sole discretion; and the Grantee shall furnish to the Committee such information as it may request with respect to the transferee and the terms and conditions of any such transfer. For purposes of this Agreement, “immediate family” shall mean the Grantee’s spouse, children and grandchildren.

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(c)    The Grantee also may designate a Beneficiary to receive any rights of the Grantee which may become vested in the event of the death of the Grantee under procedures and in the form established by the Committee. In the absence of such designation of a Beneficiary, any such rights shall be deemed to be transferred to the estate of the Grantee.

5.Distribution of Common Stock.The Common Stock or cash the Grantee becomes entitled to receive upon vesting of the Performance Units shall be distributed to the Grantee as soon as reasonably practicable after the vesting date for such Performance Units, as determined by the Committee in its discretion. Except as provided in Section 6 below, all Common Stock and cash the Grantee becomes entitled to receive pursuant to the Award shall be distributed to the Grantee after the expiration of the Performance Period, but in no event later than the 15th day of the third month after the end of the Performance Period. Except as provided in Section 6 below, the Grantee shall not be permitted, directly or indirectly, to designate the form of payment or the taxable year in which it is to be made.

6.Deferral Feature for Officers.

(a)    If the Grantee is an officer of the Company, the Grantee may irrevocably elect to defer the time of payment of Performance Units, Common Stock and cash that the Grantee becomes entitled to receive under this Agreement by filing with the Committee, on or before the Election Date (as defined below), a signed written irrevocable election (the “Election”), which shall be in the form attached hereto as Exhibit D or as otherwise approved by the Committee. Such Election must be filed with the Committee on or prior to the last business day that is at least six (6) months before the end of the Performance Period (the “Election Date”).

(b)    In no event may the Grantee elect to defer the payment of Performance Units, Common Stock or cash after any such amount has become readily ascertainable and is substantially certain to be paid to the Grantee. For this purpose, performance-based compensation during the Performance Period is to be bifurcated between the portion, if any, that is readily ascertainable and the amount that is not readily ascertainable, and any amount that is both calculable and substantially certain to be paid shall be treated as readily ascertainable.

(c)    An Election may provide for payment at a Specified Time, which shall be either (i) the later of (A) the date of the Grantee’s separation from service with the Company, or (B) a specified calendar date; or (ii) the date of the Grantee’s separation from service with the Company. An Election also may provide for a specified form of payment, which shall be either (i) a single lump sum payment; or (ii) a payment in two, three, four or five equal annual installments commencing at the Specified Time, as elected by the Grantee, and continuing until fully distributed.

(d)    The provisions of this Agreement providing for the deferral of payment of Performance Units, Common Stock or cash shall be applicable solely to the Award, and shall not apply to any other compensation payable to Grantee under the Plan or otherwise. The right to make a deferral election under this Section 6 is expressly limited to officers of the Company or any subset thereof as determined by the Committee from time to time.

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(e)Notwithstanding anything in the Plan or this Agreement to the contrary, the following terms and conditions shall apply to all Elections and subsequent elections made by the Grantee pursuant to this Agreement:

(1)Any election to defer payment of Common Stock, cash or other compensation (other than an Election as described above, which must be filed by the Election Date) must be made by the end of the calendar year before the compensation otherwise would be payable, or such other time as provided in Treasury Regulations under Code section 409A.

(2)No deferred amounts may be distributed earlier than (i) Separation from Service of the Grantee; (ii) the date the Grantee becomes Disabled; (iii) death of the Grantee; (iv) a Specified Time (or pursuant to a Fixed Schedule) specified under the plan under which the compensation is deferred at the date of deferral of such compensation; (v) a Change in Ownership or Control; or (vi) the occurrence of an Unforeseeable Emergency.

(3)To the extent that an Award is or becomes subject to Code Section 409A and Grantee is a Specified Employee who becomes entitled to a distribution on account of a Separation from Service (within the meaning of Code Section 409A), no payment shall be made before the date which is six (6) months after the date of the Grantee’s Separation from Service, or, if earlier, the date of death of the Grantee.

(4)No acceleration of the time or schedule of any distribution or payment under the plan under which compensation is deferred shall be permitted or allowed, except to the extent provided in Treasury Regulations issued under Code section 409A.

(5)This Agreement shall not permit a subsequent election to delay or modify the form of payment unless authorized and agreed upon in writing by the Company and Grantee, which subsequent election shall not take effect until at least twelve (12) months after the date on which it is made. In the case of a subsequent election related to a payment to be made upon Separation from Service of the Grantee, at a Specified Time or pursuant to a Fixed Schedule, or upon a Change in Ownership or Control, the first payment with respect to which such subsequent election is made shall be deferred for a period of not less than five (5) years from the date such payment would otherwise have been made. Any such subsequent election related to a payment at a Specified Time or pursuant to a Fixed Schedule may not be made less than twelve (12) months prior to the date of the first scheduled payment to which it relates.

(6)For purposes of this Agreement, the following definitions shall apply with respect to any election to delay or modify the form of any payment:

(i)“Change of Ownership or Control” means a change in the ownership or effective control of the Company, or in the ownership of a substantial portion of the assets of the Company, which shall be if (i) a person acquires more than 50 percent of the Company’s stock; (ii) a person acquires during a 12-month period at least 30 percent of the Company’s stock; (iii) a majority of the members of the Board of Directors are replaced during a 12-month period; or (iv) a person acquires during a 12-month period at least 40 percent of the gross fair market value of the Company’s assets.

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(ii)“Disabled” means that an individual (i) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, or (ii) is, by reason of any medically determinable physical or mental impairment which can be expected to result in death or can be expected to last for a continuous period of not less than 12 months, receiving Company-provided sick leave or disability benefits for a period of not less than 3 months.

(iii)“Fixed Schedule” means the distribution or payment of compensation deferred under this Agreement and Award in a fixed schedule of distributions or payments that are determined and fixed at the time the deferral of such compensation is first elected by the Grantee or the Company.

(iv)“Specified Employee” means a key employee (as defined in Code section 416(i) without regard to paragraph (5) thereof) of the Company.

(v)“Specified Time” means a specified date at which compensation deferred by or for the Grantee pursuant to this Agreement is required to be paid and which is specified at the time of the election of deferral of such compensation.

(vi)“Unforeseeable Emergency” means a severe financial hardship to the participant resulting from an illness or accident of the participant, the participant’s spouse or a dependent (as defined in Code section 152(a)), loss of the participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. The amounts distributed with respect to an emergency shall not exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as a result of the distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the participant’s assets (to the extent the liquidation of such assets would not itself cause severe financial hardship).

7.Administration of Award. The Award shall be subject to such other rules as the Committee, in its sole discretion, may determine to be appropriate with respect to administration thereof. This Agreement shall be subject to discretionary interpretation and construction by the Committee. Day-to-day authority and responsibility for administration of the Plan, the Award and this Agreement have been delegated to the Company’s Benefit Plan Administration Committee and its authorized representatives, and all actions taken thereby shall be entitled to the same deference as if taken by the Committee itself. The Grantee shall take all actions and execute and deliver all documents as may from time to time be requested by the Committee in connection with such restrictions and in furtherance hereof.

8.Tax Liability and Withholding. The Grantee agrees to pay to the Company any applicable federal, state or local income, employment, social security, Medicare or other withholding tax obligation arising in connection with the Award to the Grantee, which the Company shall determine; and the Company shall have the right, without the Grantee’s prior approval or direction, to satisfy such withholding tax by withholding all or any part of the shares of Common Stock or cash that would otherwise be paid to the Grantee (not to exceed the

5

minimum amount of taxes required to be withheld from supplemental wage payments), with any shares of Common Stock so withheld to be valued at the Fair Market Value on the date of such withholding. The Grantee, with the consent of the Company, may satisfy such withholding tax by transferring cash or Common Stock to the Company, with any shares so transferred to be valued at the Fair Market Value on the date of such delivery. Notwithstanding the foregoing, the ultimate liability for Grantee’s share of all tax withholding is the Grantee’s responsibility, and the Company makes no tax-related representations in connection with the grant or vesting of Performance Units or the distribution of Common Stock or cash to the Grantee.

9.Adjustment Provisions. If, prior to the expiration of the Performance Period, any change is made to the outstanding Common Stock or in the capitalization of the Company, the Performance Units granted pursuant to this Award shall be equitably adjusted or terminated to the extent and in the manner provided under the terms of the Plan.

10.Required Grantee Repayment/Reduction Provision. Notwithstanding anything in the Plan or this Agreement to the contrary, all or a portion of the Award made to the Grantee under this Agreement is subject to being called for repayment to the Company or reduced in any situation where the Board of Directors or a Committee thereof determines that fraud, negligence, or intentional misconduct by the Grantee was a contributing factor to the Company having to restate all or a portion of its financial statement(s). The Committee may determine whether the Company shall effect any such repayment or reduction: (i) by seeking repayment from the Grantee, (ii) by reducing (subject to applicable law and the terms and conditions of the Plan or any other applicable plan, program, or arrangement) the amount that would otherwise be awarded or payable to the Grantee under the Award, the Plan or any other compensatory plan, program, or arrangement maintained by the Company, (iii) by withholding payment of future increases in compensation (including the payment of any discretionary bonus amount) or grants of compensatory awards that would otherwise have been made in accordance with the Company’s otherwise applicable compensation practices, or (iv) by any combination of the foregoing. The determination regarding the Grantee’s conduct, and repayment or reduction under this provision shall be within the sole discretion of the Committee and shall be final and binding on the Grantee and the Company. The Grantee, in consideration of the grant of the Award, and by the Grantee’s execution of this Agreement, acknowledges the Grantee’s understanding of the agreement to this provision, and hereby agrees to make and allow an immediate and complete repayment or reduction in accordance with this provision in the event of a call for repayment or other action by the Company or Committee to effect its terms with respect to the Grantee, the Award and/or any other compensation described in this Agreement.

11.Stock Reserved. The Company shall at all times during the term of the Award reserve and keep available such number of shares of its Common Stock as will be sufficient to satisfy the Award issued and granted to Grantee and the requirements thereof as evidenced by this Agreement. It is intended by the Company that the Plan and the shares of Common Stock covered by the Award are to be registered under the Securities Act of 1933, as amended, prior to the grant date; provided, that in the event such registration is for any reason not made effective for such shares, the Grantee agrees that all shares acquired pursuant to the grant will be acquired for investment and will not be available for sale or tender to any third party.

6

12.No Rights as Shareholder. Except as otherwise provided in this Agreement, the Grantee shall have no rights as a shareholder of the Company in respect of the Performance Units or Common Stock for which the Award is granted. The Grantee shall not be considered a record owner of shares of Common Stock with respect to the Performance Units until the Performance Units are fully vested and Common Stock is actually distributed to the Grantee.

13.Continued Employment; Employment at Will. In consideration of the Company’s granting the Award as incentive compensation to Grantee pursuant to this Agreement, the Grantee agrees to all of the terms of this Agreement and to continue to perform services for the Company in a satisfactory manner as directed by the Company. Provided, however, no provision in this Agreement shall confer any right to the Grantee’s continued employment, limit the right of the Company to terminate the Grantee’s employment at any time or create any contractual right to receive any future awards under the Plan. Moreover, unless specifically provided under the terms thereof, the value of the Award will not be included as compensation or earnings when calculating the Grantee’s benefits under any employee benefit plan sponsored by the Company.

14.Section 409A. This Agreement is intended to comply with Section 409A of the Code or an exemption therefrom and shall be construed and interpreted in a manner that is consistent with the requirements for avoiding additional taxes or penalties under Section 409A of the Code. Notwithstanding the foregoing, the Company makes no representations that the payments and benefits provided under this Agreement comply with Section 409A of the Code and shall not be liable for all or any taxes, penalties, interest or other expenses that may be incurred by the Grantee on account of non-compliance with Section 409A of the Code.

15.Entire Agreement; Severability; Conflicts. This Agreement contains the entire terms of the Award, and may not be changed other than by a written instrument executed by both parties or an amendment of the Plan. This Agreement supersedes any prior agreements or understandings, and there are no other agreements or understandings relating to its subject matter. The invalidity or unenforceability of any provision of the Plan or this Agreement shall not affect any other provision of the Plan or this Agreement, and each provision of the Plan and this Agreement shall be severable and enforceable to the extent permitted by law. Should there be any inconsistency between the provisions of this Agreement and the terms of the Award as stated in the resolutions and records of the Board of Directors or the Plan, the provisions of such resolutions and records of the Board of Directors and the Plan shall control.

16.Successors and Assigns. The Award shall inure to the benefit of and be binding upon the heirs, legatees, legal representatives, successors, and assigns of the parties thereto.

The Grantee hereby acknowledges receipt of this Agreement, the Notice of Performance Unit Award and Agreement and a copy of the Plan, and accepts the Award under the terms and conditions stated in this Agreement, subject to all terms and provisions of the Plan, by signing this Agreement as of the date indicated.

Date	«Officer_Name»
	Grantee

7

Exhibit A

Performance Unit Criteria

2014-17 Performance Period

ONEOK Total Stockholder Return (TSR) Ranking vs. ONEOK Peer Group	Percentage of Performance Units Earned (Performance Multiplier)
90th percentile and above 75th percentile 50th percentile 25th percentile Below 25th percentile	200% 150% 100% 50% 0%

IF ONEOK’s TSR ranking within the ONEOK Peer Group at the end of the performance period is between any two of the stated percentile levels in the above table, the percentage of the performance units earned (the performance multiplier) will be interpolated between the earning levels. No Performance Units are earned if ONEOK’s TSR ranking at the end of the performance period is below the 25^th percentile within its Peer Group.

8

Exhibit B

Illustration of Hypothetical 2014-17 Performance Period

Performance Unit Award Calculation

The illustrations below assume that 500 Performance Units are awarded to Grantee in February 2014.

ONEOK Total Stockholder Return (TSR) Ranking vs. ONEOK Peer Group

Hypothetical 1: If ONEOK’s TSR Ranking for 2014-17 is at the 40^th percentile within the ONEOK Peer Group, then the performance multiplier would be 80 percent, as interpolated between a 50 percent multiplier (25^th percentile within Peer Group) and a 100 percent multiplier (50^th percentile within Peer Group) from Exhibit A.

Hypothetical 2: If ONEOK’s TSR Ranking for 2014-17 is at the 60^th percentile within the ONEOK Peer Group, then the performance multiplier would be 120 percent, as interpolated between a 100 percent multiplier (50^th percentile within Peer Group) and a 150 percent multiplier (75^th percentile within Peer Group) from Exhibit A.

Percentage of Performance Units Earned

Hypothetical 1: 80% x 500 PUs = 400 shares of Common Stock payable to Grantee in 2017.

Hypothetical 2: 120% x 500 PUs = 600 shares of Common Stock payable to Grantee in 2017.

9

Exhibit C

2014-17 ONEOK TSR Peer Group

Company Name	Sym
Boardwalk Pipeline Partners LP	BWP
Buckeye Partners LP	BPL
CenterPoint Energy Inc.	CNP
Energy Transfer Partners LP	ETP
EQT Corporation	EQT
MDU Resources Corp	MDU
Magellan Midstream Partners LP	MMP
MarkWest Energy Partners LP	MWE
National Fuel Gas Company	NFG
NiSource Inc.	NI
NuStar Energy LP	NS
OGE Energy Corp	OGE
ONEOK, Inc.	OKE
Plains All American Pipeline, LP	PAA
SEMPRA Energy	SRE
Spectra Energy Corporation	SE
Targa Resources Partners LP	NGLS
Williams Companies Inc.	WMB

10

Exhibit D

ONEOK, Inc. Equity Compensation Plan

Performance Unit Deferral Election

This Election is made by the undersigned Grantee pursuant to that certain Notice of Performance Unit Award and Agreement issued to me under the ONEOK, Inc. Equity Compensation Plan, on the [___] day of February, 2014, a copy of which is attached hereto (the “Award”).

This Election is made on or before the date of August [__], 2016, which is six (6) months before the end of the Performance Period on February [__], 2017.

I hereby irrevocably elect to defer the payment and my receipt of all Performance Units, Common Stock and cash that I may become entitled to receive from the regularly scheduled time of payment of the Award, until a later date as follows:

A.     Election of Specified Time of Payment (Initial one election of time of payment)

___    I elect to have all Common Stock, cash or other compensation which I become entitled to receive under the Award deferred and paid to me on the later of (i) the date of my separation from service as an employee of the Company, or (ii) [________, 20__] in the form specified below.

___    I elect to have all Common Stock, cash or other compensation which I earn or become entitled to receive under the Award deferred and paid to me on the date of my separation from service as an employee of the Company.

B.     Election of Form of Payment (Initial one election of form of payment)

___    I elect to receive payment of all Common Stock, cash or other compensation which I become entitled to receive under the Award in a single lump sum payment.

____    I elect to receive payment of all Common Stock, cash or other compensation which I become entitled to receive under the Award in ______(specify 2, 3, 4 or 5) equal annual installments commencing on the specified date of payment elected in Part A above, until fully paid. The number of shares of Common Stock or cash received in each installment will equal the number and amount, respectively, that have not been paid as of the date immediately preceding the installment payment date, divided by the number of installments remaining to be paid as of the date immediately preceding the installment payment date. The resulting number shall be rounded down to the next whole number, except that the final installment shall be rounded up to the next whole number.

C.    Election for Death Prior to, or after, the Specified Time of Payment (Put initials by your choice)

___    In the event of my death prior to, or after, the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation in a single lump sum within 60 days following my death.

___    In the event of my death prior to, or after, the Specified Time of Payment that I have elected above, I elect to have my named beneficiaries receive payment and transfer of the Common Stock, cash or other deferred compensation be paid and transferred in ______ (specify 2, 3, 4 or 5) equal annual installments commencing within 60 days following my death, until fully paid. The number of shares of Common Stock or cash received in each installment will equal the number and amount, respectively, that have not been paid as of the date immediately preceding the installment payment date, divided by the number of installments remaining to be paid as of the date immediately preceding the installment payment date. The resulting number shall be rounded down to the next whole number, except that the final installment shall be rounded up to the next whole number.

D.    Designation of Beneficiary (List each beneficiary and percentage)

11

I designate the following individuals (or entities) as my beneficiaries to receive the following share(s) of my Common Stock, cash or other deferred compensation, as indicated below:

Name of Beneficiary	Percent
	100% (total must equal 100%)

E.    Change in Ownership or Control

Notwithstanding the foregoing, immediately following a Change in Ownership or Control the Common Stock, cash or other deferred compensation that have not been paid and transferred will be paid and transferred. In the event shares of Common Stock no longer exist at the time of payment and transfer, each of the deferred Performance Units shall be converted in a manner that is consistent with the manner in which shareholders of Common Stock were treated with respect to the Change in Ownership or Control.

Solely for purposes of this election, a “Change in Ownership or Control” shall mean and shall have occurred if one of the following has occurred: A person acquires more than 50 percent of the Company’s stock; a person acquires during a 12-month period at least 30 percent of the Company’s stock; a majority of the members of the Board of Directors of the Company are replaced during a 12-month period; or a person acquires during a 12-month period at least 40 percent of the gross fair market value of the Company’s assets.

Made and executed by me as Grantee of the Award pursuant to the terms and provisions of Section 6 of the Award Agreement, on this [____] day of [________, 20__].

_____________________________________

Grantee

Received this [____] day of [________, 20__],

______________________________________

For the Committee

12

EX-12

Exhibit 12
ONEOK, Inc.
Computation of Ratio of Earnings to Fixed Charges
			Years Ended December 31,
(Unaudited)			2013			2012			2011			2010			2009
		(Thousands of dollars)
Fixed Charges, as defined
	Interest on long-term debt		$	374,520		$	326,206		$	305,523		$	287,910		$	292,768
	Other interest		10,397			12,045			8,374			4,594			20,411
	Amortization of debt discount, premium    and expense		7,064			5,830			7,070			4,623			4,597
	Interest on lease agreements		1,494			539			1,515			19,289			20,221
	Total Fixed Charges		393,475			344,620			322,482			316,416			337,997
Earnings before income taxes and undistributed    income of equity method investees			694,998			909,650			970,746			745,354			718,656
Earnings available for fixed charges			$	1,088,473		$	1,254,270		$	1,293,228		$	1,061,770		$	1,056,653
Ratio of earnings to fixed charges			2.77		x	3.64		x	4.01		x	3.36		x	3.13		x
For purposes of computing the ratio of earnings to fixed charges, "earnings" consists of pre-tax income from continuing operations before adjustment for income or loss from equity investees plus fixed charges and distributed income of equity investees, less interest capitalized. "Fixed charges" consists of interest charges, the amortization of debt discounts and issue costs and the representative interest portion of operating leases.

EX-21

Exhibit 21

ONEOK, Inc.

SUBSIDIARIES OF THE COMPANY

AS OF DECEMBER 31, 2013

Divisions

Kansas Gas Service Company, a division of ONEOK, Inc.

Oklahoma Natural Gas Company, a division of ONEOK, Inc.

Texas Gas Service Company, a division of ONEOK, Inc.

Subsidiaries	State of Incorporation or Organization
Kansas Gas Marketing Company	Kansas
NBP Services, LLC	Delaware
ONEOK Energy Services Canada, Ltd.	Yukon
ONEOK Energy Services Company, II	Delaware
ONEOK Energy Services Company, L.P.	Texas
ONEOK Energy Services Holdings, L.L.C.	Oklahoma
ONE Gas, Inc.	Oklahoma
ONE Gas Properties, L.L.C.	Oklahoma
ONEOK Kansas Company	Kansas
ONEOK Kansas Properties, L.L.C.	Kansas
ONEOK Leasing Company	Delaware
ONEOK Parking Company, L.L.C.	Delaware
ONEOK Partners GP, L.L.C.	Delaware
ONEOK Partners, L.P. (42.8%)	Delaware
ONEOK Services Company, L.L.C.	Oklahoma
ONEOK Texas Resources, Inc.	Delaware

1

ONEOK Partners, L.P.

Subsidiaries of ONEOK Partners, L.P.	State of Incorporation or Organization
Bighorn Gas Gathering, L.L.C. (49.0%)	Delaware
Black Mesa Holdings, Inc.	Delaware
Black Mesa Pipeline, Inc.	Delaware
Black Mesa Pipeline Operations, L.L.C.	Delaware
Black Mesa Technologies, Inc.	Oklahoma
Border Midwestern Company	Delaware
Border Minnesota Pipeline, LLC	Delaware
Border Viking Company	Delaware
Chisholm Pipeline Company (50%)	Delaware
Chisholm Pipeline Holdings, L.L.C.	Delaware
Crestone Bighorn, L.L.C.	Delaware
Crestone Energy Ventures, L.L.C.	Delaware
Crestone Gathering Services, L.L.C.	Delaware
Crestone Powder River, L.L.C.	Delaware
Crestone Wind River, L.L.C.	Delaware
Fort Union Gas Gathering, L.L.C. (37.04%)	Delaware
Guardian Pipeline, L.L.C.	Delaware
Heartland Pipeline Company (general partnership) (50%)	Texas
Lost Creek Gathering Company, L.L.C. (35%)	Delaware
Mid Continent Market Center, L.L.C.	Kansas
Midwestern Gas Transmission Company	Delaware
Mont Belvieu I Fractionation Facility (joint venture) (80%)	Texas
Northern Border Pipeline Company (general partnership) (50%)	Texas
OkTex Pipeline Company, L.L.C.	Delaware
ONEOK Arbuckle North Pipeline, L.L.C.	Delaware
ONEOK Arbuckle Pipeline, L.L.C.	Delaware
ONEOK Bakken Pipeline, L.L.C.	Delaware
ONEOK Bushton Processing, L.L.C.	Delaware
ONEOK Field Services Company, L.L.C.	Oklahoma
ONEOK Gas Storage Holdings, L.L.C.	Delaware
ONEOK Gas Storage, L.L.C.	Oklahoma
ONEOK Gas Transportation, L.L.C.	Oklahoma
ONEOK Hydrocarbon GP, L.L.C.	Delaware
ONEOK Hydrocarbon Holdings, L.L.C.	Delaware
ONEOK Hydrocarbon Southwest, L.L.C.	Delaware
ONEOK Hydrocarbon, L.L.C.	Delaware
ONEOK Hydrocarbon, L.P.	Delaware
ONEOK ILP GP, L.L.C.	Delaware
ONEOK MB I, L.P.	Delaware
ONEOK Midstream Gas Supply, L.L.C.	Oklahoma
ONEOK Mont Belvieu Storage Company, L.L.C.	Delaware
ONEOK NGL Gathering, L.L.C.	Delaware
ONEOK NGL Pipeline, L.L.C.	Delaware
ONEOK North System, L.L.C.	Delaware

2

ONEOK Overland Pass Holdings, L.L.C.	Oklahoma
ONEOK Partners Intermediate Limited Partnership	Delaware
ONEOK Pipeline Holdings, L.L.C.	Delaware
ONEOK Rockies Enterprises, L.L.C.	Delaware
ONEOK Rockies Investments, L.L.C.	Delaware
ONEOK Rockies Midstream, L.L.C.	Delaware
ONEOK Rockies Processing Company (Canada) Ltd.	Alberta
ONEOK Sterling III Pipeline, L.L.C.	Oklahoma
ONEOK Texas Gas Storage, L.L.C.	Texas
ONEOK Transmission Company, L.L.C.	Delaware
ONEOK Underground Storage Company, L.L.C.	Kansas
ONEOK VESCO Holdings, L.L.C.	Delaware
ONEOK WesTex Transmission, L.L.C.	Delaware
Overland Pass Pipeline Company LLC (50%)	Delaware
Potato Hills Gas Gathering System (general partnership) (51%)	Oklahoma
Sycamore Gas System (general partnership) (48.445%)	Oklahoma
Venice Energy Services Company, L.L.C. (10.1765%)	Delaware
Viking Gas Transmission Company	Delaware

3

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-177044 and 333-177048) and Form S-8 (Nos. 333-185633, 333-182991, 333-41263, 333-54274, 333-75768, 333-121769, 333-140629, 333-152748, 333-157584, 333-165044, 333-171308 and 333-178622) of ONEOK, Inc. of our report dated February 25, 2014, relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 25, 2014

EX-31.1

Exhibit 31.1

Certification

I, Terry K. Spencer, certify that:

I have reviewed this annual report on Form 10-K of ONEOK, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2014

/s/ Terry K. Spencer

Terry K. Spencer

Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification

I, Derek S. Reiners, certify that:

I have reviewed this annual report on Form 10-K of ONEOK, Inc.;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 25, 2014

/s/ Derek S. Reiners

Derek S. Reiners

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of ONEOK, Inc. (the “Registrant”) for the period ending December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Terry K. Spencer, Chief Executive Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Terry K. Spencer

Terry K. Spencer

Chief Executive Officer

February 25, 2014

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONEOK, Inc. and will be retained by ONEOK, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of ONEOK, Inc. (the “Registrant”) for the period ending December 31, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Derek S. Reiners, Chief Financial Officer of the Registrant, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Derek S. Reiners

Derek S. Reiners

Chief Financial Officer

February 25, 2014

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to ONEOK, Inc. and will be retained by ONEOK, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

XML

FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Recurring Fair Value Measurments

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

	December 31, 2013
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	4,477		$	647		$	3,094		$	8,218		$	(2,850	)	$	5,368
Physical contracts	—			4			1,764			1,768			(1,157		)	611
Interest-rate contracts	—			54,503			—			54,503			—			54,503
Total derivative assets	4,477			55,154			4,858			64,489			(4,007		)	60,482
Fair value of firm commitments (b)	—			—			599			599			—			599
Available-for-sale investment securities (b)	1,569			—			—			1,569			—			1,569
Total assets	$	6,046		$	55,154		$	5,457		$	66,657		$	(4,007	)	$	62,650
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(7,624	)	$	(776	)	$	(3,435	)	$	(11,835	)	$	10,767		$	(1,068	)
Physical contracts	—			(4		)	(4,117		)	(4,121		)	1,157			(2,964		)
Total derivative liabilities	$	(7,624	)	$	(780	)	$	(7,552	)	$	(15,956	)	$	11,924		$	(4,032	)

(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2013, we held no cash collateral and had posted $15.7 million of cash collateral with various counterparties.

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

	December 31, 2012
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	69,957		$	10,780		$	7,107		$	87,844		$	(51,602	)	$	36,242
Physical contracts	—			2,083			2,032			4,115			(151		)	3,964
Interest-rate contracts	—			10,923			—			10,923			—			10,923
Total derivative assets	69,957			23,786			9,139			102,882			(51,753		)	51,129
Trading securities (b)	5,978			—			—			5,978			—			5,978
Available-for-sale investment securities (c)	2,027			—			—			2,027			—			2,027
Total assets	$	77,962		$	23,786		$	9,139		$	110,887		$	(51,753	)	$	59,134
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(35,172	)	$	(1,737	)	$	(7,177	)	$	(44,086	)	$	33,878		$	(10,208	)
Physical contracts	—			—			(279		)	(279		)	151			(128		)
Total derivative liabilities	(35,172		)	(1,737		)	(7,456		)	(44,365		)	34,029			(10,336		)
Fair value of firm commitments (d)	—			—			(1,280		)	(1,280		)	—			(1,280		)
Total liabilities	$	(35,172	)	$	(1,737	)	$	(8,736	)	$	(45,645	)	$	34,029		$	(11,616	)

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

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

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

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

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation

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

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2013	$	1,683		$	(1,280	)	$	403
Total realized/unrealized gains (losses):
Included in earnings (a)	(5,627		)	1,879			(3,748		)
Included in other comprehensive income (loss)	800			—			800
Settlements	450			—			450
December 31, 2013	$	(2,694	)	$	599		$	(2,095	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2013 (a)	$	(804	)	$	670		$	(134	)

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

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)	(13,503		)	6,003			(7,500		)
Included in other comprehensive income (loss)	(5,587		)	—			(5,587		)
Sale of discontinued operations	(3,636		)	—			(3,636		)
Transfers out of Level 3	(695		)	—			(695		)
December 31, 2012	$	1,683		$	(1,280	)	$	403
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2012 (a)	$	1,971		$	(112	)	$	1,859

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

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QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

Quarterly financial disclosure

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2013
	(Thousands of dollars except per share amounts)
Total revenues	$	3,541,445	$	3,349,236	$	3,571,925	$	4,140,111
Net margin	$	623,452	$	453,389	$	561,188	$	651,654
Income from continuing operations	$	165,705	$	79,495	$	147,698	$	184,063
Net income	$	165,705	$	79,495	$	147,698	$	184,063
Net income attributable to ONEOK	$	112,521	$	919	$	62,356	$	90,737
Earnings per share total
Basic	$	0.55	$	—	$	0.30	$	0.44
Diluted	$	0.54	$	—	$	0.30	$	0.43

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2012
	(Thousands of dollars except per share amounts)
Total revenues	$	3,414,600	$	2,529,260	$	3,028,775	$	3,659,924
Net margin	$	643,587	$	548,962	$	553,972	$	604,320
Income from continuing operations	$	219,450	$	148,938	$	164,988	$	195,875
Income from discontinued operations and gain on sale, net of tax	$	14,012	$	267	$	—	$	—
Net income	$	233,462	$	149,205	$	164,988	$	195,875
Net income attributable to ONEOK	$	122,865	$	60,993	$	65,219	$	111,542
Earnings per share total
Basic	$	0.59	$	0.29	$	0.32	$	0.55
Diluted	$	0.58	$	0.29	$	0.31	$	0.53

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EMPLOYEE BENEFIT PLANS (Tables)

12 Months Ended

Dec. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Pension and postretirement benefit plans obligations and fair value of plan assets

Obligations and Funded Status - The following tables set forth our pension and postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated:

	Pension Benefits						Postretirement Benefits
	December 31,						December 31,
	2013			2012			2013			2012
Change in Benefit Obligation	(Thousands of dollars)
Benefit obligation, beginning of period	$	1,313,560		$	1,215,932		$	299,172		$	286,044
Service cost	22,968			21,301			4,612			4,960
Interest cost	54,449			59,237			11,713			13,893
Plan participants’ contributions	—			—			4,293			5,851
Actuarial loss (gain)	(110,552		)	105,732			(29,460		)	9,935
Benefits paid	(58,976		)	(88,642		)	(18,411		)	(21,380		)
Plan amendment	—			—			17,228			(131		)
Benefit obligation, end of period	1,221,449			1,313,560			289,147			299,172
Change in Plan Assets
Fair value of plan assets, beginning of period	995,264			902,235			148,162			124,163
Actual return on plan assets	176,889			90,026			27,483			14,273
Employer contributions	—			91,881			866			10,728
Benefits paid	(59,404		)	(88,878		)	(876		)	(1,002		)
Fair value of assets, end of period	1,112,749			995,264			175,635			148,162
Balance at December 31	$	(108,700	)	$	(318,296	)	$	(113,512	)	$	(151,010	)
Current liabilities	$	(5,457	)	$	(4,695	)	$	—		$	—
Noncurrent liabilities	(103,243		)	(313,601		)	(113,512		)	(151,010		)
Balance at December 31	$	(108,700	)	$	(318,296	)	$	(113,512	)	$	(151,010	)

Components of net periodic benefit cost for pension and postretirement benefit plans

Components of Net Periodic Benefit Cost -The following tables set forth the components of net periodic benefit cost for our pension and postretirement benefit plans for the periods indicated:

	Pension Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	22,968		$	21,301		$	20,013
Interest cost	54,449			59,237			58,757
Expected return on assets	(81,272		)	(82,756		)	(75,500		)
Amortization of unrecognized prior service cost	920			969			1,018
Amortization of net loss	66,282			48,439			35,708
Settlements	1,338			1,401			—
Net periodic benefit cost	$	64,685		$	48,591		$	39,996

	Postretirement Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	4,612		$	4,960		$	4,987
Interest cost	11,713			13,893			15,632
Expected return on assets	(12,259		)	(10,687		)	(10,272		)
Amortization of unrecognized net asset at adoption	284			2,874			3,189
Amortization of unrecognized prior service cost	(6,442		)	(8,252		)	(2,518		)
Amortization of net loss	12,605			13,184			8,123
Net periodic benefit cost	$	10,513		$	15,972		$	19,141

Amounts recognized in other comprehensive income (loss)

Other Comprehensive Income (Loss) - The following tables set forth the amounts recognized in other comprehensive income (loss) related to our pension benefits and postretirement benefits for the periods indicated:

	Pension Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Regulatory asset gain (loss)	$	(110,437	)	$	67,472		$	114,625
Net gain (loss) arising during the period	201,251			(103,199		)	(182,987		)
Amortization of regulatory asset	(44,378		)	(32,527		)	(23,265		)
Amortization of prior service credit	920			969			1,018
Amortization of loss	67,620			49,839			35,708
Deferred income taxes	(44,473		)	6,748			21,236
Total recognized in other comprehensive income (loss)	$	70,503		$	(10,698	)	$	(33,665	)

	Postretirement Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Regulatory asset gain (loss)	$	(7,674	)	$	4,376		$	7,389
Net gain (loss) arising during the period	44,685			(6,348		)	(40,765		)
Amortization of regulatory asset	(5,643		)	(6,557		)	(7,214		)
Amortization of transition obligation	284			2,874			3,189
Amortization of prior service cost	(6,442		)	(8,252		)	(2,518		)
Amortization of loss	12,605			13,184			8,123
Plan amendment	(17,228		)	131			44,562
Deferred income taxes	(7,964		)	229			(4,938		)
Total recognized in other comprehensive income (loss)	$	12,623		$	(363	)	$	7,828

Amounts in accumulated other comprehensive income (loss)

The table below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense for the periods indicated:

	Pension Benefits						Postretirement Benefits
	December 31,						December 31,
	2013			2012			2013			2012
	(Thousands of dollars)
Transition obligation	$	—		$	—		$	—		$	(283	)
Prior service credit (cost)	(1,102		)	(2,022		)	14,631			38,301
Accumulated loss	(415,375		)	(684,245		)	(59,362		)	(116,652		)
Accumulated other comprehensive loss before regulatory assets	(416,477		)	(686,267		)	(44,731		)	(78,634		)
Regulatory asset for regulated entities	288,017			442,833			43,254			56,571
Accumulated other comprehensive loss after regulatory assets	(128,460		)	(243,434		)	(1,477		)	(22,063		)
Deferred income taxes	49,689			94,161			572			8,534
Accumulated other comprehensive loss, net of tax	$	(78,771	)	$	(149,273	)	$	(905	)	$	(13,529	)

Amounts in either accumulated comprehensive income (loss) or regulatory assets expected to be recognized as components of net periodic benefit expense

The following table sets forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets expected to be recognized as components of net periodic benefit expense in the next fiscal year. The table does not include amounts applicable to employees of ONE Gas, as those amounts are expected to be recognized by ONE Gas as a result of the separation of the natural gas distribution business.

	Pension Benefits		Postretirement Benefits
Amounts to be recognized in 2014	(Thousands of dollars)
Transition obligation	$	—	$	—
Prior service credit (cost)	$	193	$	(1,662	)
Net loss	$	15,021	$	833

Weighted-average assumptions used to determine benefit obligations and net periodic benefit costs

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for pension and postretirement benefits for the periods indicated:

	Pension Benefits		Postretirement Benefits
	December 31,		December 31,
	2013	2012	2013	2012
Discount rate	5.25%	4.25%	5.00%	4.00%
Compensation increase rate	3.35% - 3.40%	3.45% - 3.50%	3.35% - 3.40%	3.45% - 3.50%

The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated:

	Years Ended December 31,
	2013	2012	2011
Discount rate - pension plans	4.25%	5.00%	5.50%
Discount rate - postretirement plans	4.00%	5.00%	5.50%
Expected long-term return on plan assets	8.25%	8.25%	8.25%
Compensation increase rate	3.45% - 3.50%	3.20% - 3.80%	3.30% - 3.90%

Assumed health care cost trend rates

Health Care Cost Trend Rates -The following table sets forth the assumed health care cost-trend rates for the periods indicated:

	2013	2012
Health care cost-trend rate assumed for next year	4.0% - 8.25%	4.0% - 9.0%
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate)	4.0% - 5.0%	4.0% - 5.0%
Year that the rate reaches the ultimate trend rate	2022	2022

Effects of a one percentage point change in assumed health care costs trend rates

Assumed health care cost-trend rates have an impact on the amounts reported for our health care 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
	(Thousands of dollars)
Effect on total of service and interest cost	$	1,136	$	(1,022	)
Effect on postretirement benefit obligation	$	15,152	$	(14,350	)

Schedule of allocation of plan assets

Plan Assets -Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals.  The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations.  The plan’s investments include a diverse blend of various domestic and international equities, investments in various classes of debt securities, insurance contracts and venture capital.  The target allocation for the assets of our pension plan is as follows:

U.S. large-cap equities	37	%
Aggregate bonds	24	%
Developed foreign large-cap equities	10	%
Alternative investments	8	%
Mid-cap equities	6	%
Emerging markets equities	5	%
Small-cap equities	4	%
High-yield bonds	3	%
Developed foreign bonds	2	%
Emerging market bonds	1	%
Total	100	%

As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.

The following tables set forth our pension benefits and postretirement benefits plan assets by fair value category as of the measurement date:

	Pension Benefits
	December 31, 2013
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	680,590	$	60,336	$	—	$	740,926
Government obligations	—		111,288		—		111,288
Corporate obligations (b)	—		95,432		—		95,432
Cash and money market funds (c)	27,699		—		—		27,699
Insurance and group annuity contracts	—		—		63,458		63,458
Other investments (d)	—		—		73,946		73,946
Total assets	$	708,289	$	267,056	$	137,404	$	1,112,749

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Pension Benefits
	December 31, 2012
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	541,539	$	61,242	$	—	$	602,781
Government obligations	—		116,936		—		116,936
Corporate obligations (b)	—		104,078		—		104,078
Cash and money market funds (c)	33,296		—		—		33,296
Insurance and group annuity contracts	—		—		70,411		70,411
Other investments (d)	—		—		67,762		67,762
Total assets	$	574,835	$	282,256	$	138,173	$	995,264

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Postretirement Benefits
	December 31, 2013
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	37,796	$	90	$	—	$	37,886
Government obligations	—		166		—		166
Corporate obligations (b)	17,207		142		—		17,349
Cash and money market funds (c)	13,936		—		—		13,936
Insurance and group annuity contracts	—		106,189		—		106,189
Other investments (d)	—		—		109		109
Total assets	$	68,939	$	106,587	$	109	$	175,635

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Postretirement Benefits
	December 31, 2012
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	21,548	$	140	$	—	$	21,688
Government obligations	—		268		—		268
Corporate obligations (b)	17,522		238		—		17,760
Cash and money market funds (c)	18,311		—		—		18,311
Insurance and group annuity contracts	—		89,979		—		89,979
Other investments (d)	—		—		156		156
Total assets	$	57,381	$	90,625	$	156	$	148,162

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category represents money market funds.

(d) - This category represents alternative investments.

Reconciliation of Level 3 fair value measurements of pension plan

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

	Pension Benefits
	December 31, 2013
	Insurance and Group Annuity Contracts			Other Investments		Total
	(Thousands of dollars)
January 1, 2013	$	70,411		$	67,762	$	138,173
Net realized and unrealized gains (losses)	(6,953		)	6,184		(769		)
December 31, 2013	$	63,458		$	73,946	$	137,404

	Pension Benefits
	December 31, 2012
	Insurance and Group Annuity Contracts			Other Investments		Total
	(Thousands of dollars)
January 1, 2012	$	70,818		$	66,243	$	137,061
Net realized and unrealized gains (losses)	(407		)	1,519		1,112
December 31, 2012	$	70,411		$	67,762	$	138,173

Pension benefits and postretirement benefit payments expected to be paid

The following table sets forth the pension benefits and postretirement benefits payments expected to be paid in 2014-2023:

	Pension Benefits		Postretirement Benefits
Benefits to be paid in:	(Thousands of dollars)
2014	$	63,856	$	16,251
2015	$	64,588	$	17,135
2016	$	66,477	$	18,142
2017	$	68,626	$	19,095
2018	$	70,873	$	19,875
2019 through 2023	$	386,366	$	106,346

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EQUITY (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended													12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Equity [Abstract]
Accelerated share repurchases price paid						$ 150				$ 300					$ 150	$ 300
Accelerated share repurchases (in shares)						3.4				8.6					3.4	8.6
Common stock authorized and unreserved common stock available for issuance. (in shares)		362.4												362.4
Dividends paid														304.7	262.0	227.0
Dividend paid (in dollars per share)		$ 0.38	$ 0.38	$ 0.36	$ 0.36	$ 0.33	$ 0.33	$ 0.305	$ 0.305	$ 0.28	$ 0.28	$ 0.26	$ 0.26	$ 1.48	$ 1.27	$ 1.08
Dividend declared (in dollars per share)	$ 0.40													$ 1.48	$ 1.27	$ 1.08
Accelerated Share Repurchases authorized amount																$ 750

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SUBSEQUENT EVENTS (Tables) (ONE Gas [Member])

3 Months Ended

Mar. 31, 2014

ONE Gas [Member]

Debt Instrument [Line Items]

Schedule of Long-term Debt Instruments [Table Text Block]

The following table details information about each of the three series of Senior Notes:

	(In millions)
2.07% notes due February 1, 2019	$	300
3.61% notes due February 1, 2024	300
4.658% notes due February 1, 2044	600
	$	1,200

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ONEOK PARTNERS Schedule of purchase price allocation (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013
Business Combination, Separately Recognized Transactions [Line Items]
Business Acquisition, Purchase Price Allocation, Amortizable Intangible Assets	$ 103,000
Business Acquisition, Purchase Price Allocation, Assets Acquired	212,889
Business Acquisition, Purchase Price Allocation, Goodwill Amount	92,000
Business Acquisition, Cost of Acquired Entity, Purchase Price	304,889
Gathering pipelines and related equipment [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment	59,174
Processing and fractionation and related equipment [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment	50,595
General plant and other [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Acquisition, Purchase Price Allocation, Property, Plant and Equipment	$ 120

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EARNINGS PER SHARE (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share

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

	Year Ended December 31, 2013
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	266,533	206,044	$	1.29
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		3,651
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	266,533	209,695	$	1.27

	Year Ended December 31, 2012
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	346,340	206,140	$	1.68
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		4,570
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	346,340	210,710	$	1.64

	Year Ended December 31, 2011
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	358,364	209,344	$	1.71
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		5,154
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	358,364	214,498	$	1.67

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LONG-TERM DEBT Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Debt, Policy [Policy Text Block]

We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.

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COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 Y
Commitments and Contingencies Disclosure [Abstract]
Number of former manufactured gas sites in Kansas where we own or retain legal responsibility for environmental conditions	12
Number of sites where soil remediation has begun	11
Number of sites where regulatory closure has been achieved	3
Number of sites soil remediation is completed or near completion	8
Number of years of consideration for EPA lowering threshold levels for greenhouse gas emissions	5
Minimum percentage yield of high consequence pipeline areas	30.00%
Operating Leases, Future Minimum Payments Due [Abstract]
2014	$ 2.0
2015	0.5
2016	0.3
2017	0.2
2018	0.2
Thereafter	0.7
Firm Transportation and Storage Contracts, Future Minimum Payments Due [Abstract]
2014	18.4
2015	16.3
2016	14.4
2017	12.8
2018	11.9
Thereafter	30.2
ONE Gas [Member]
Operating Leased Assets [Line Items]
Unrecorded Unconditional Purchase Obligation	900.0
ONEOK [Member]
Operating Leased Assets [Line Items]
Unrecorded Unconditional Purchase Obligation	11.2
Partnership Interest [Member]
Operating Leases, Future Minimum Payments Due [Abstract]
Total	3.9
Firm Transportation and Storage Contracts, Future Minimum Payments Due [Abstract]
Total	104.0
Total Commitments and Contingencies [Abstract]
2014	20.4
2015	16.8
2016	14.7
2017	13.0
2018	12.1
Thereafter	30.9
Total Commitments and Contingencies	107.9
Parent Company [Member]
Operating Leases, Future Minimum Payments Due [Abstract]
2014	3.4
2015	2.9
2016	2.5
2017	2.1
2018	1.9
Thereafter	3.3
Total	$ 16.1

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SHARE-BASED PAYMENTS (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jan. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross		0	0	0
Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding awards vesting period (in years)		3 years
Share-based compensation arrangement by share-based payment award, equity instruments other than options, reduction due to separation of ONE Gas	77,000
Employee service share-based compensation, nonvested awards, total compensation cost not yet recognized, reduction due to separation of subsidiary					$ 2,400,000
Weighted Average Price [Abstract]
Nonvested beginning balance (in dollars per share)	$ 35.27	$ 27.21
Granted (in dollars per share)		$ 47.46	$ 36.65	$ 28.50
Released to participants (in dollars per share)		$ 19.06
Forfeited (in dollars per share)		$ 37.23
Nonvested ending balance (in dollars per share)		$ 35.27	$ 27.21
Fair value of shares granted		7,940,000	11,030,000	11,728,000
Unrecognized compensation cost related to our nonvested restricted stock unit awards		9,300,000
Period over which compensation cost related to nonvested restricted stock will be recognized (in years)		1 year 8 months 4 days
Restricted stock units and performance stock units activity [Roll forward]
Nonvested beginning balance (in shares)	776,596	1,020,600
Granted (in shares)		167,301
Released to participants (in shares)		(384,883)
Forfeited (in shares)		(26,422)
Nonvested ending balance (in shares)		776,596	1,020,600
Stock Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock reserved for issuance under the Plan. (in shares)		10,000,000
Shares reserved for issuance under the plan (in shares)		2,000,000
Forfeiture rate maximum (in hundredths)		3.00%
Share based compensation expense		28,600,000	22,600,000	40,700,000
Share based compensation tax benefit		17,600,000	14,200,000	25,700,000
Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock reserved for issuance under the Plan. (in shares)		15,600,000
Shares reserved for issuance under the plan (in shares)		900,000
Performance Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding awards vesting period (in years)		3 years
Share-based compensation arrangement by share-based payment award, equity instruments other than options, reduction due to separation of ONE Gas	151,000
Employee service share-based compensation, nonvested awards, total compensation cost not yet recognized, reduction due to separation of subsidiary					5,600,000
Weighted Average Price [Abstract]
Nonvested beginning balance (in dollars per share)	$ 41.10	$ 32.74
Granted (in dollars per share)		$ 52.34	$ 42.39	$ 34.68
Released to participants (in dollars per share)		$ 24.05
Forfeited (in dollars per share)		$ 42.53
Nonvested ending balance (in dollars per share)		$ 41.10	$ 32.74
Fair value of shares granted		19,742,000	25,466,000	29,186,000
Unrecognized compensation cost related to our nonvested restricted stock unit awards		22,500,000
Period over which compensation cost related to nonvested restricted stock will be recognized (in years)		1 year 8 months 8 days
Restricted stock units and performance stock units activity [Roll forward]
Nonvested beginning balance (in shares)	1,652,145	2,133,157
Granted (in shares)		377,200
Released to participants (in shares)		(801,354)
Forfeited (in shares)		(56,858)
Nonvested ending balance (in shares)		1,652,145	2,133,157
Volatility (in hundredths)		22.27%	27.00%	39.91%
Dividend Yield (in hundredths)		3.04%	2.86%	3.30%
Risk-free Interest Rate (in hundredths)		0.42%	0.38%	1.33%
Non-employees and Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock reserved for issuance under the Plan. (in shares)		1,400,000
Shares reserved for issuance under the plan (in shares)		1,000,000
The maximum number of shares for which options or other awards may be granted to any employee during any year (in shares)		40,000
Employee Stock Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock reserved for issuance under the Plan. (in shares)		11,600,000
Restricted stock units and performance stock units activity [Roll forward]
Maximum allowable percentage of annual base pay withheld to purchase our common stock (in hundredths)		10.00%
Maximum allowable percentage of annual base pay from all means to purchase our common stock (in hundredths)		10.00%
Purchase price percentage of the lower of its grant date or exercise date market price (in hundredths)		85.00%
Percentage of employees participating in the Employee Stock Purchase Plan (in hundredths)		52.00%	55.00%	56.00%
Compensation expense for the Employee Stock Purchase Plan		6,600,000		7,200,000
Shares sold under the Employee Stock Purchase Plan (in shares)		254,960	256,490	365,116
Share price of shares sold under the Employee Stock Purchase Plan (in dollars per share)		35.97	35.97	23.70
Employee Stock Award Program [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock reserved for issuance under the Plan. (in shares)		900,000
Shares reserved for issuance under the plan (in shares)		63,975	42,467	295,694
Share based compensation expense		$ 3,600,000	$ 1,900,000	$ 16,000,000
Description of the Plan		Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $13 per share.

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EXIT ACTIVITIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 MMcf	Dec. 31, 2012	Dec. 31, 2011
Restructuring Cost and Reserve [Line Items]
Assigned storage capacity	18,000
Noncash charges	$ 138,600,000	$ 0
Settlements of business exit costs	(17,700,000)
Accretion	1,100,000
Charges attributable to exit activities, net of settlements	121,971,000	0	0
Expected future noncash charge	1,700,000
Expected future cash payments associated with released transportation and storage capacity from the wind-down of our Energy Services segment	80,000,000
2014 [Member]
Restructuring Cost and Reserve [Line Items]
Expected future cash payments associated with released transportation and storage capacity from the wind-down of our Energy Services segment	33,000,000
2015 [Member]
Restructuring Cost and Reserve [Line Items]
Expected future cash payments associated with released transportation and storage capacity from the wind-down of our Energy Services segment	24,000,000
2016 [Member]
Restructuring Cost and Reserve [Line Items]
Expected future cash payments associated with released transportation and storage capacity from the wind-down of our Energy Services segment	13,000,000
2017 - 2023 [Member]
Restructuring Cost and Reserve [Line Items]
Expected future cash payments associated with released transportation and storage capacity from the wind-down of our Energy Services segment	$ 10,000,000

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UNCONSOLIDATED AFFILIATES (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	$ 1,229,838,000	$ 1,221,405,000	$ 1,223,398,000
Equity earnings from investments	110,517,000	123,024,000	127,246,000
Equity method goodwill	224,300,000
Payments to Acquire Other Investments	35,308,000	30,768,000	64,491,000
Balance Sheet [Abstract]
Current assets	155,310,000	175,930,000
Property, plant and equipment, net	2,557,571,000	2,593,122,000
Other noncurrent assets	34,478,000	35,005,000
Current liabilities	98,967,000	145,147,000
Long-term debt	442,103,000	472,630,000
Other noncurrent liabilities	58,221,000	42,451,000
Accumulated other comprehensive income (loss)	(2,291,000)	(2,503,000)
Owners' equity	2,150,359,000	2,146,332,000
Income Statement [Abstract]
Operating revenues	528,665,000	573,197,000	496,158,000
Cost and expenses	256,292,000	269,858,000	221,261,000
Net income	248,998,000	279,766,000	249,559,000
Distributions paid to us	137,498,000	155,741,000	156,385,000
Overland Pass Pipeline Company [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	466,671,000	468,710,000
Equity earnings from investments	20,461,000	20,043,000	19,535,000
Net ownership percentage	50.00%
Northern Border Pipeline [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	404,803,000	393,317,000
Equity earnings from investments	65,046,000	72,705,000	76,365,000
Net ownership percentage	50.00%
Percentage decrease in long-term transportation rates	11.00%
Payments to Acquire Other Investments	30,800,000
Fort Union Gas Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	125,220,000	120,782,000
Equity earnings from investments	15,826,000	17,218,000	15,280,000
Net ownership percentage	37.00%
Bighorn Gas Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	87,837,000	90,428,000
Equity earnings from investments	1,952,000	3,820,000	5,990,000
Equity method goodwill	53,400,000
Net ownership percentage	49.00%
Other Unconsolidated Affiliate [Member]
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	145,307,000	148,168,000
Equity earnings from investments	7,232,000	9,238,000	10,076,000
Unconsolidated Affiliates [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 53,800,000	$ 36,500,000	$ 33,700,000

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QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 4,140,111	$ 3,571,925	$ 3,349,236	$ 3,541,445	$ 3,659,924	$ 3,028,775	$ 2,529,260	$ 3,414,600	$ 14,602,717	$ 12,632,559	$ 14,805,794
Net margin	651,654	561,188	453,389	623,452	604,320	553,972	548,962	643,587	2,289,683	2,350,841	2,380,359
Income from continuing operations	184,063	147,698	79,495	165,705	195,875	164,988	148,938	219,450	576,961	729,251	757,514
Income from discontinued operations and gain on sale, net of tax					0	0	267	14,012	0	762	2,230
Net income	184,063	147,698	79,495	165,705	195,875	164,988	149,205	233,462	576,961	743,530	759,744
Net income attributable to ONEOK	$ 90,737	$ 62,356	$ 919	$ 112,521	$ 111,542	$ 65,219	$ 60,993	$ 122,865	$ 266,533	$ 360,619	$ 360,594
Earnings per share total
Basic (in dollars per share)	$ 0.44	$ 0.30	$ 0.00	$ 0.55	$ 0.55	$ 0.32	$ 0.29	$ 0.59	$ 1.29	$ 1.68	$ 1.71
Diluted (in dollars per share)	$ 0.43	$ 0.30	$ 0.00	$ 0.54	$ 0.53	$ 0.31	$ 0.29	$ 0.58	$ 1.27	$ 1.64	$ 1.67

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ONEOK PARTNERS (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 Rate	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Business Acquisition, Cost of Acquired Entity, Purchase Price	$ 304,889,000
Business Acquisition, Purchase Price Allocation, Goodwill Amount	92,000,000
Previously unowned share in Maysville natural gas processing facility	30.00%
Payment to acquire unowned interest in Maysville natural gas processing facilities	90,000,000
Asset acquisition, effective date of acquisition	Dec. 01, 2013
Current ownership share in Maysville natural gas processing facility	100.00%
Aggregate amount of common units available for issuance and sale under the Equity Distribution Agreement.	300,000,000
Partners capital account units sold under equity distribution agreement	681,000
Partners' Capital Account, Units, Sold in Public Offering	11,500,000	8,000,000
Public offering price of common units	$ 49.61	$ 59.27
Proceeds from Sale of Interest in Partnership Unit		460,000,000
Partners' Capital Account, Units, Sold in Private Placement		8,000,000
Proceeds from Issuance of Private Placement		460,000,000
Partners' Capital Account, Contributions		19,000,000
Repayment on line of credit facility		295,000,000
Ownership interest	41.20%	43.40%	42.80%
Common units	19,800,000
Class B units	73,000,000
Payment to acquire OBPI			94,200,000
Partnership agreement	Cash Distributions - We receive distributions from ONEOK Partners on our common and Class B units and our 2 percent general partner interest, which includes our incentive distribution rights.  Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in the ONEOK Partners partnership agreement (Partnership Agreement), as amended.  Available cash generally will be distributed 98 percent to limited partners and 2 percent to the general partner.  The general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter.  In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among the general partner and limited partners to reflect the two-for-one unit split of ONEOK Partners’ common units.  Under the incentive distribution provisions, as set forth in ONEOK Partners’ partnership agreement, as amended, the general partner receives: 15 percent of amounts distributed in excess of $0.3025 per unit; 25 percent of amounts distributed in excess of $0.3575 per unit; and 50 percent of amounts distributed in excess of $0.4675 per unit.
Expenses [Abstract]
Noncontrolling Interest, Increase from Equity Issuance or Sale of Parent Equity Interest	533,824,000	459,587,000
ONEOK, Inc. [Member]
Related Party Transaction [Line Items]
Revenues		352,099,000	403,603,000
Expenses [Abstract]
Cost of sales and fuel		33,094,000	48,163,000
Administrative and general expenses		246,050,000	251,239,000
Total expenses	303,411,000	279,144,000	299,402,000
General Partner [Member]
Related Party Transaction [Line Items]
Ownership interest	2.00%	2.00%
Limited Partner [Member]
Related Party Transaction [Line Items]
Ownership interest	39.20%
Dividend Paid [Member]
Related Party Transaction [Line Items]
Total distributions	909,713,000	760,912,000	609,446,000
Distribution (in dollars per unit)	$ 2.870	$ 2.590	$ 2.325
Dividend Paid [Member] | General Partner [Member]
Related Party Transaction [Line Items]
General partner distributions	18,193,000	15,217,000	12,189,000
Incentive distributions	251,664,000	186,130,000	123,386,000
Distributions to general partner	269,857,000	201,347,000	135,575,000
Dividend Paid [Member] | Limited Partner [Member]
Related Party Transaction [Line Items]
Limited partner distributions to ONEOK	266,302,000	235,442,000	197,132,000
Limited partner distributions to noncontrolling interest	373,554,000	324,123,000	276,739,000
Dividend Declared [Member]
Related Party Transaction [Line Items]
Total distributions	931,236,000	817,754,000	625,751,000
Distribution (in dollars per unit)	$ 2.890	$ 2.690	$ 2.365
Dividend Declared [Member] | General Partner [Member]
Related Party Transaction [Line Items]
General partner distributions	18,625,000	16,355,000	12,515,000
Incentive distributions	259,466,000	210,095,000	131,212,000
Distributions to general partner	278,091,000	226,450,000	143,727,000
Dividend Declared [Member] | Limited Partner [Member]
Related Party Transaction [Line Items]
Limited partner distributions to ONEOK	268,157,000	249,600,000	200,524,000
Limited partner distributions to noncontrolling interest	384,988,000	341,704,000	281,500,000
Notes Payables due 2012 [Member] | Partnership Interest [Member]
Related Party Transaction [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.90%
Debt Instrument, Maturity Date		Apr. 01, 2012
Issued under public offering [Member]
Related Party Transaction [Line Items]
Proceeds from Sale of Interest in Partnership Unit	553,300,000
Partners' Capital Account, Contributions	11,600,000
Additional Paid-in Capital [Member]
Expenses [Abstract]
Noncontrolling Interest, Increase from Equity Issuance or Sale of Parent Equity Interest	87,295,000	(51,100,000)
issued under equity distribution agreement [Member]
Related Party Transaction [Line Items]
Proceeds from Sale of Interest in Partnership Unit	$ 36,100,000
Minimum [Member]
Related Party Transaction [Line Items]
Useful Life	20 years
Maximum [Member]
Related Party Transaction [Line Items]
Useful Life	30 years

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	$ (43,168)	$ (55,030)	$ (55,367)
Accumulated Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	857	1,034	987
Other comprehensive income (loss) before reclassifications	8,842	16,709
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, before Reclassification Adjustments, Net of Tax	(177)	47
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, before Tax, Portion Attributable to Parent	37,144	(47,004)
Other comprehensive income (loss) before reclassifications	45,809	(30,248)
Other Comprehensive Income Loss, Reclassification Adjustment on Derivatives	3,020	(16,372)
Other Comprehensive Income (Loss), Reclassification Adjustment for Sale of Securities Included in Net Income, Net of Tax	0	0
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Net of Tax	45,982	35,943
Other Comprehensive Income (Loss), Reclassification Adjustment included in Net Income, Net of Tax	49,002	19,571
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Parent	11,862	337
Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax, Portion Attributable to Parent	(177)	47
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax, Portion Attributable to Parent	83,126	(11,061)
Income tax expense	1,905	(10,327)	(53,714)
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	(7,926)	49,499	84,025
Balance of accumulated other comprehensive income (loss) [Abstract]
Pension and Postretirement Benefit Plan Obligations	(79,676)	(162,802)	(151,741)
Accumulated Other Comprehensive Income (Loss)	(121,987)	(216,798)	(206,121)
Other comprehensive income (loss) attributable to ONEOK [Abstract]
Unrealized Holding Gains (Losses) on Investment Securities	(177)	47	(384)
Pension and Postretirement Benefit Plan Obligations	(83,126)	11,061	25,837
Accumulated Other Comprehensive Income (Loss)	94,811	(10,677)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Total before tax [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	9,831
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Tax benefit [Member]
Income tax expense	(1,905)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Commodity Contract [Member] | Sales [Member]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	(19,049)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Commodity Contract [Member] | Cost of Sales [Member]
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion	14,320
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion	14,560
Accumulated Defined Benefit Plans Adjustment [Member]
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Net of Tax	45,982
Defined Benefit Plan, Amortization of Net Gains (Losses)	78,887
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	(5,522)
Amortization of unrecognized net asset at adoption	284
Defined Benefit Plan, Recognized Net Gain (Loss) Due to Settlements	1,338
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, before Tax	74,987
Other Comprehensive Income (Loss), Reclassification, Pension and Other Postretirement Benefit Plans, Net Gain (Loss) Recognized in Net Periodic Benefit Cost, Tax	(29,005)
Cash Flow Hedging [Member]
Other comprehensive income (loss) before reclassifications	31,183	33,427	(11,158)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	9,831	(59,826)	(137,739)
Cash Flow Hedging [Member] | Commodity Contract [Member]
Other comprehensive income (loss) before reclassifications	(15,433)	62,898	117,508
Cash Flow Hedging [Member] | Commodity Contract [Member] | Sales [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(19,049)	(140,862)	(48,601)
Cash Flow Hedging [Member] | Commodity Contract [Member] | Cost of Sales [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	14,320	73,881	(89,618)
Cash Flow Hedging [Member] | Interest Rate Contract [Member]
Other comprehensive income (loss) before reclassifications	46,616	(29,471)	(128,666)
Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Interest Expense [Member]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	14,560	7,155	480
Cash Flow Hedging [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Net of tax [Member]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	7,926
Cash Flow Hedging [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Net income attributable to noncontrolling interest [Member]
Other Comprehensive Income (Loss), Reclassification Adjustment on Derivatives Included in Net Income, Net of Tax	3,020
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Noncontrolling Interest	$ 4,906

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INCOME TAXES

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

O. INCOME TAXES

The following table sets forth our provisions for income taxes for the periods indicated:

	Years Ended December 31,
	2013		2012			2011
Current income taxes	(Thousands of dollars)
Federal	$	7,313	$	(16,083	)	$	(32,291	)
State	4,554		1,798			1,707
Total current income taxes from continuing operations	11,867		(14,285		)	(30,584		)	(a)
Deferred income taxes
Federal	137,654		213,127			228,257
State	13,861		16,353			28,375
Total deferred income taxes from continuing operations	151,515		229,480			256,632			(a)
Total provision for income taxes from continuing operations	163,382		215,195			226,048
Discontinued operations	—		8,749			1,255
Total provision for income taxes	$	163,382	$	223,944		$	227,303

(a) Includes a $37.7 million reclassification from current income taxes to deferred related to revisions of estimated depreciation in our filed tax returns compared with our 2010 tax provision.

The following table is a reconciliation of our income tax provision from continuing operations for the periods indicated:

	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Income from continuing operations before income taxes	$	740,343		$	944,446		$	983,562
Less: Net income attributable to noncontrolling interest	310,428			382,911			399,150
Income from continuing operations attributable to ONEOK before income taxes	429,915			561,535			584,412
Federal statutory income tax rate	35		%	35		%	35		%
Provision for federal income taxes	150,470			196,537			204,543
State income taxes, net of federal tax benefit	11,970			11,799			20,334
Other, net	942			6,859			1,171
Income tax provision from continuing operations	$	163,382		$	215,195		$	226,048

The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated:

	December 31, 2013		December 31, 2012
Deferred tax assets	(Thousands of dollars)
Employee benefits and other accrued liabilities	$	78,793	$	128,418
Federal net operating loss	12,484		—
State net operating loss and benefits	38,322		31,990
Energy Services capacity release	46,726		—
Other comprehensive income	78,369		140,802
Other	20,872		1,446
Total deferred tax assets	275,566		302,656
Deferred tax liabilities
Excess of tax over book depreciation and depletion	822,706		760,211
Investment in partnerships	1,217,605		969,347
Regulatory assets	132,676		204,625
Total deferred tax liabilities	2,172,987		1,934,183
Net deferred tax liabilities	$	1,897,421	$	1,631,527

We had income taxes receivable of approximately $15.6 million and $30.8 million at December 31, 2013 and 2012, respectively.

Tax benefits related to net operating loss (NOL) carryforwards will begin expiring in 2032. We believe that it is more likely than not that the tax benefits of the net operating loss carryforwards will be utilized prior to their expirations; therefore, no valuation allowance is necessary.

Deferred tax assets related to tax benefits of employee share-based compensation have been reduced for performance share units and restricted share units that vested in periods in which ONEOK was in an NOL position.  This vesting resulted in tax deductions in excess of previously recorded benefits based on the performance share unit and restricted share unit value at the time of grant.  Although these additional tax benefits are reflected in NOL carryforwards in the tax return, the additional tax benefit is not recognized until the deduction reduces taxes payable.  A portion of the tax benefit does not reduce ONEOK’s current taxes payable due to NOL carryforwards; accordingly, these tax benefits are not reflected in ONEOK’s NOLs in deferred tax assets.  Tax benefits included in NOL carryforwards but not reflected in deferred tax assets were $35.9 million as of December 31, 2013, and $11.0 million as of December 31, 2012.

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UNCONSOLIDATED AFFILIATES (Tables)

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

Equity Earnings from Investments [Table Text Block]

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

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Northern Border Pipeline	$	65,046	$	72,705	$	76,365
Overland Pass Pipeline Company	20,461		20,043		19,535
Fort Union Gas Gathering, L.L.C.	15,826		17,218		15,280
Bighorn Gas Gathering	1,952		3,820		5,990
Other	7,232		9,238		10,076
Equity earnings from investments	$	110,517	$	123,024	$	127,246

Schedule of Equity Method Investments

Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated:

	Net Ownership Interest	December 31, 2013		December 31, 2012
		(Thousands of dollars)
Northern Border Pipeline	50%	$	404,803	$	393,317
Overland Pass Pipeline Company	50%	466,671		468,710
Fort Union Gas Gathering, L.L.C.	37%	125,220		120,782
Bighorn Gas Gathering	49%	87,837		90,428
Other	Various	145,307		148,168
Investments in unconsolidated affiliates (a)		$	1,229,838	$	1,221,405

(a) - Equity method goodwill (Note A) was $224.3 million at December 31, 2013 and 2012.

Unconsolidated Affiliates Financial Information

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

	December 31, 2013			December 31, 2012
	(Thousands of dollars)
Balance Sheet
Current assets	$	155,310		$	175,930
Property, plant and equipment, net	$	2,557,571		$	2,593,122
Other noncurrent assets	$	34,478		$	35,005
Current liabilities	$	98,967		$	145,147
Long-term debt	$	442,103		$	472,630
Other noncurrent liabilities	$	58,221		$	42,451
Accumulated other comprehensive loss	$	(2,291	)	$	(2,503	)
Owners’ equity	$	2,150,359		$	2,146,332

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	528,665	$	573,197	$	496,158
Costs and expenses	$	256,292	$	269,858	$	221,261
Net income	$	248,998	$	279,766	$	249,559
Distributions paid to us	$	137,498	$	155,741	$	156,385

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GOODWILL AND INTANGIBLE ASSETS (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill by Segment

Goodwill - The following table sets forth our goodwill by segment for the periods indicated:

	ONEOK Partners		Natural Gas Distribution		Energy Services		Total
	(Thousands of dollars)
December 31, 2012	$	433,535	$	157,953	$	—	$	591,488
Acquisitions	92,000		—		—		92,000
December 31, 2013	$	525,535	$	157,953	$	—	$	683,488

Gross Carrying Amount and Accumulated Amortization of Intangible Assets

Intangible Assets - The following table sets forth the gross carrying amount and accumulated amortization of intangible assets for the periods indicated:

	December 31,			December 31,
	2013			2012
	(Thousands of dollars)
Gross intangible assets	$	565,215		$	462,214
Accumulated amortization	(66,188		)	(57,496		)
Net intangible assets	$	499,027		$	404,718

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INCOME TAXES (Details) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax [Line Items]
Excess Tax Benefit (Tax Deficiency) from Share-based Compensation, Operating Activities		$ 35,900,000	$ 11,000,000
Current income taxes
Federal		7,313,000	(16,083,000)	(32,291,000)
State		4,554,000	1,798,000	1,707,000
Total current income taxes from continuing operations		11,867,000	(14,285,000)	(30,584,000)
Deferred income taxes
Federal		137,654,000	213,127,000	228,257,000
State		13,861,000	16,353,000	28,375,000
Total deferred income taxes from continuing operations		151,515,000	229,480,000	256,632,000
Total provision for income taxes from continuing operations		163,382,000	215,195,000	226,048,000
Discontinued operations	468,000	0	8,749,000	1,255,000
Total provision for income taxes		163,382,000	223,944,000	227,303,000
Reclassification from current income taxes				37,700,000
Reconciliation for income tax provision [Abstract]
Income from continuing operations before income taxes		740,343,000	944,446,000	983,562,000
Less: Net income attributable to noncontrolling interests		310,428,000	382,911,000	399,150,000
Income from continuing operations attributable to ONEOK before income taxes		429,915,000	561,535,000	584,412,000
Federal statutory income tax rate		35.00%	35.00%	35.00%
Provision for federal income taxes		150,470,000	196,537,000	204,543,000
State income taxes, net of federal tax benefit		11,970,000	11,799,000	20,334,000
Other, net		942,000	6,859,000	1,171,000
Total provision for income taxes from continuing operations		163,382,000	215,195,000	226,048,000
Deferred tax assets
Employee benefits and other accrued liabilities		78,793,000	128,418,000
Federal net operating loss		12,484,000	0
State net operating loss and benefits		38,322,000	31,990,000
Energy Services capacity release		46,726,000	0
Other comprehensive income		78,369,000	140,802,000
Other		20,872,000	1,446,000
Total deferred tax assets		275,566,000	302,656,000
Deferred tax liabilities
Excess of tax over book depreciation and depletion		822,706,000	760,211,000
Investment in partnerships		1,217,605,000	969,347,000
Regulatory assets		132,676,000	204,625,000
Total deferred tax liabilities		2,172,987,000	1,934,183,000
Deferred Tax Liabilities, Net		1,897,421,000	1,631,527,000
Income taxes receivable		$ 15,600,000	$ 30,800,000

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EXIT ACTIVITIES (Tables)

12 Months Ended

Dec. 31, 2013

EXIT ACTIVITIES [Abstract]

Schedule of Restructuring and Related Costs [Table Text Block]

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

	Year Ended
	December 31, 2013
	(Millions of dollars)
Beginning balance	$	—
Noncash charges	138.6
Settlements	(17.7		)
Accretion	1.1
Ending balance	$	122.0

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Future Minimum Rental Payments for Operating Lease ad Firm Transportation and Storage Contracts

ONEOK	Operating Leases
	(Millions of dollars)
2014	$	3.4
2015	2.9
2016	2.5
2017	2.1
2018	1.9
Thereafter	3.3
Total	$	16.1

Our former Natural Gas Distribution segment is a party to fixed-price contracts providing it with firm transportation and storage capacity. The costs associated with these contracts are recovered through rates. Future commitments related to these contracts are $900.0 million. These contracts are obligations of ONE Gas as the result of the separation.

Our Energy Services segment also is a party to fixed-price contracts related to firm transportation and storage that are not being released as part of the wind down process and will expire before April 2014. Future commitments related to these contracts are $11.2 million.

ONEOK Partners	Operating Leases		Firm Transportation and Storage Contracts		Total
	(Millions of dollars)
2014	$	2.0	$	18.4	$	20.4
2015	0.5		16.3		16.8
2016	0.3		14.4		14.7
2017	0.2		12.8		13.0
2018	0.2		11.9		12.1
Thereafter	0.7		30.2		30.9
Total	$	3.9	$	104.0	$	107.9

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GOODWILL AND INTANGIBLE ASSETS (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss	$ 0	$ 10,255,000	$ 0
Goodwill	683,488,000	591,488,000
Acquisitions	92,000,000
Amortization expense for intangible assets	8,700,000	7,700,000	7,700,000
Business Acquisition, Purchase Price Allocation, Amortizable Intangible Assets	103,000,000
Gross Intangible Assets	565,215,000	462,214,000
Accumulated Amortization	(66,188,000)	(57,496,000)
Net Intangible Assets	499,027,000	404,718,000
Future amortization expense for next five years [Abstract]
Future amortization expense, year one	11,300,000
Future amortization expense, year two	11,300,000
Future amortization expense, year three	11,300,000
Future amortization expense, year four	11,300,000
Future amortization expense, year five	11,300,000
Energy Services [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss		10,255,000
Goodwill	0	0
Acquisitions	0
Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss		0
Goodwill	157,953,000	157,953,000
Acquisitions	0
Oneok Partners [Member]
Segment Reporting Information [Line Items]
Goodwill, Impairment Loss		0
Goodwill	525,535,000	433,535,000
Acquisitions	92,000,000
Net Intangible Assets	$ 343,500,000	$ 249,200,000
Minimum [Member]
Segment Reporting Information [Line Items]
Finite-Lived Intangible Asset, Useful Life	20 years
Maximum [Member]
Segment Reporting Information [Line Items]
Finite-Lived Intangible Asset, Useful Life	40 years

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FAIR VALUE MEASUREMENTS FAIR VALUE MEASUREMENTS - Part 3 (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including current maturities, fair value	$ 8,200,000,000	$ 7,500,000,000
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, including current maturities, carrying value	$ 7,800,000,000	$ 6,500,000,000

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SHARE-BASED PAYMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Restricted Stock Unit and Performance Unit Activity

The following tables set forth activity and various statistics for our restricted stock unit awards:

	Number of Shares		Weighted Average Price
Nonvested December 31, 2012	1,020,600		$	27.21
Granted	167,301		$	47.46
Released to participants	(384,883	)	$	19.06
Forfeited	(26,422	)	$	37.23
Nonvested December 31, 2013	776,596		$	35.27

	2013		2012		2011
Weighted-average grant date fair value (per share)	$	47.46	$	36.65	$	28.50
Fair value of shares granted (thousands of dollars)	$	7,940	$	11,030	$	11,728

Performance-Unit Activity

As of December 31, 2013, we had $22.5 million of total unrecognized compensation cost related to the nonvested performance-unit awards, which is expected to be recognized over a weighted-average period of 1.7 years.  The following tables set forth activity and various statistics related to the performance-unit awards and the assumptions used in the valuations of the 2013, 2012 and 2011 grants at the grant date:

	Number of Units		Weighted Average Price
Nonvested December 31, 2012	2,133,157		$	32.74
Granted	377,200		$	52.34
Released to participants	(801,354	)	$	24.05
Forfeited	(56,858	)	$	42.53
Nonvested December 31, 2013	1,652,145		$	41.10

	2013	2012	2011
Volatility (a)	22.27%	27.00%	39.91%
Dividend Yield	3.04%	2.86%	3.30%
Risk-free Interest Rate	0.42%	0.38%	1.33%

(a) - Volatility was based on historical volatility over three years using daily stock price observations.

	2013		2012		2011
Weighted-average grant date fair value (per share)	$	52.34	$	42.39	$	34.68
Fair value of shares granted (thousands of dollars)	$	19,742	$	25,466	$	29,186

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CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Noncontrolling Interests in Consolidated Subsidiaries [Member]
Shareholders' equity, beginning balance at Dec. 31, 2010	$ 3,920,841	$ 2,456	$ 1,391,443	$ (108,802)	$ 1,826,800	$ (663,274)	$ 1,472,218
Common stock issued, beginning balance (in shares) at Dec. 31, 2010		245,631,272
Net income	759,744	0	0	0	360,594	0	399,150
Other comprehensive income (loss)	(130,153)	0	0	(97,319)	0	0	(32,834)
Repurchase of common stock	(300,108)	0	0	0	0	(300,108)	0
Common stock issued (in shares)		178,576
Common stock issued	53,803	2	25,742	0	0	28,059	0
Common stock dividends - $1.08, $1.27, and $1.48 per share	(227,020)	0	0	0	(227,020)	0	0
Distributions to noncontrolling interests	(277,375)	0	0	0	0	0	(277,375)
Shareholders' equity, ending balance at Dec. 31, 2011	3,799,732	2,458	1,417,185	(206,121)	1,960,374	(935,323)	1,561,159
Common stock issued, ending balance (in shares) at Dec. 31, 2011		245,809,848
Net income	743,530	0	0	0	360,619	0	382,911
Other comprehensive income (loss)	(37,687)	0	0	(10,677)	0	0	(27,010)
Repurchase of common stock	(150,000)	0	0	0	0	(150,000)	0
Common stock issued (in shares)		1,332
Common stock issued	22,146	0	(23,404)	0	0	45,550	0
Common stock dividends - $1.08, $1.27, and $1.48 per share	(261,969)	0	0	0	(261,969)	0	0
Issuance of common units of ONEOK Partners	459,587	0	(51,100)	0	0	0	510,687
Distributions to noncontrolling interests	(324,906)	0	0	0	0	0	(324,906)
Other	(17,983)	0	(17,983)	0	0	0	0
Shareholders' equity, ending balance at Dec. 31, 2012	4,232,450	2,458	1,324,698	(216,798)	2,059,024	(1,039,773)	2,102,841
Common stock issued, ending balance (in shares) at Dec. 31, 2012		245,811,180
Net income	576,961	0	0	0	266,533	0	310,428
Other comprehensive income (loss)	116,484	0	0	94,811	0	0	21,673
Common stock issued (in shares)		0
Common stock issued	26,189	0	(16,549)	0	0	42,738	0
Common stock dividends - $1.08, $1.27, and $1.48 per share	(304,742)	0	0	0	(304,742)	0	0
Issuance of common units of ONEOK Partners	533,824	0	87,295	0	0	0	446,529
Distributions to noncontrolling interests	(374,142)	0	0	0	0	0	(374,142)
Other	38,156	0	38,156	0	0	0	0
Shareholders' equity, ending balance at Dec. 31, 2013	$ 4,845,180	$ 2,458	$ 1,433,600	$ (121,987)	$ 2,020,815	$ (997,035)	$ 2,507,329
Common stock issued, ending balance (in shares) at Dec. 31, 2013		245,811,180

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES - Part 1 (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Assets		$ 64,489,000	$ 102,882,000
(Liabilities)		(15,956,000)	(44,365,000)
Inventory cash flow hedges derivative assets		5,800,000	16,900,000
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets		63,578,000	58,495,000
(Liabilities)		(14,036,000)	(5,011,000)
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets		911,000	44,387,000
(Liabilities)		(1,920,000)	(39,354,000)
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Financial Derivative Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets		8,011,000	47,516,000
(Liabilities)		(10,573,000)	(4,885,000)
Commodity Contract [Member] | Designated as Hedging Instrument [Member] | Physical Derivative Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets		1,064,000	56,000
(Liabilities)		(3,463,000)	(126,000)
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Financial Derivative Instrument [Member] | Non Trading [Member]
Derivatives, Fair Value [Line Items]
Assets		202,000	24,970,000
(Liabilities)		(1,262,000)	(25,009,000)
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Financial Derivative Instrument [Member] | Trading [Member]
Derivatives, Fair Value [Line Items]
Assets		5,000	15,358,000
(Liabilities)		0	(14,192,000)
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | Physical Derivative Instrument [Member] | Non Trading [Member]
Derivatives, Fair Value [Line Items]
Assets		704,000	4,059,000
(Liabilities)		(658,000)	(153,000)
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Assets		54,503,000	10,923,000
(Liabilities)		0	0
Cash Flow Hedging [Member] | Forward Starting Interest Rate Swap [Member] | Oneok Partners [Member]
Derivatives, Fair Value [Line Items]
Notional Amount Of Cash Flow Hedge Instruments Greater Than 12 Months		400,000,000	400,000,000
Notional Amount Of Cash Flow Hedge Instruments Less Than 12 Months	$ 500,000,000

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

Long-Term Debt

	December 31,			December 31,
	2013			2012
	(Thousands of dollars)
ONEOK
$400,000 at 5.2% due 2015	$	400,000		$	400,000
$700,000 at 4.25% due 2022	700,000			700,000
$100,000 at 6.5% due 2028	87,649			87,662
$100,000 at 6.875% due 2028	100,000			100,000
$400,000 at 6.0% due 2035	400,000			400,000
Other	1,323			1,528
Total ONEOK senior notes payable	1,688,972			1,689,190
ONEOK Partners
$650,000 at 3.25% due 2016	650,000			650,000
$450,000 at 6.15% due 2016	450,000			450,000
$400,000 at 2.0% due 2017	400,000			400,000
$425,000 at 3.2% due 2018	425,000			—
$500,000 at 8.625% due 2019	500,000			500,000
$900,000 at 3.375 % due 2022	900,000			900,000
$425,000 at 5.0 % due 2023	425,000			—
$600,000 at 6.65% due 2036	600,000			600,000
$600,000 at 6.85% due 2037	600,000			600,000
$650,000 at 6.125% due 2041	650,000			650,000
$400,000 at 6.2% due 2043	400,000			—
Guardian Pipeline
Average 7.85%, due 2022	67,208			74,857
Total ONEOK Partners senior notes payable	6,067,208			4,824,857
Total long-term notes payable	7,756,180			6,514,047
Unamortized portion of terminated swaps	25,340			27,058
Unamortized debt discount	(15,889		)	(14,878		)
Current maturities	(10,656		)	(10,855		)
Long-term debt	$	7,754,975		$	6,515,372

Aggregate maturities of long-term debt outstanding

	ONEOK		ONEOK Partners		Guardian Pipeline		Total
	(Millions of dollars)
2014	$	3.0	$	—	$	7.7	$	10.7
2015	$	403.0	$	—	$	7.7	$	410.7
2016	$	3.0	$	1,100.0	$	7.7	$	1,110.7
2017	$	3.0	$	400.0	$	7.7	$	410.7
2018	$	3.0	$	425.0	$	7.7	$	435.7

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SEGMENTS

12 Months Ended

Dec. 31, 2013

Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]

SEGMENTS

S. SEGMENTS

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

• our ONEOK Partners segment reflects the consolidated operations of ONEOK Partners.  At December 31, 2013, we have a 41.2 percent ownership interest and control ONEOK Partners through our ownership of its general partner interest.  ONEOK Partners gathers, processes, treats, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs.  We and ONEOK Partners maintain significant financial and corporate governance separations.  We seek to receive increasing cash distributions as a result of our investment in ONEOK Partners, and our investment decisions are made based on the anticipated returns from ONEOK Partners in total, not specific to any of its businesses individually;

• our former Natural Gas Distribution segment, which we separated into a standalone publicly traded company, ONE Gas, on January 31, 2014, was comprised of regulated public utilities that deliver natural gas to residential, commercial and industrial customers, and transport natural gas; and

• our Energy Services segment, which we are winding down, markets natural gas to wholesale customers.

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

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

Customers - In 2013, 2012 and 2011, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.

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

Year Ended December 31, 2013	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	11,528,530	$	1,689,945	$	1,381,636		$	2,606		$	14,602,717
Intersegment revenues	340,743		7		195,926			(536,676		)	—
Total revenues	$	11,869,273	$	1,689,952	$	1,577,562		$	(534,070	)	$	14,602,717
Net margin	$	1,647,060	$	813,008	$	(172,985	)	$	2,600		$	2,289,683
Operating costs	521,513		444,866		13,133			10,941			990,453
Depreciation and amortization	236,743		144,758		277			2,599			384,377
Gain on sale of assets	11,881		—		—			—			11,881
Operating income	$	900,685	$	223,384	$	(186,395	)	$	(10,940	)	$	926,734
Equity earnings from investments	$	110,517	$	—	$	—		$	—		$	110,517
Investments in unconsolidated affiliates	$	1,229,838	$	—	$	—		$	—		$	1,229,838
Total assets	$	12,862,608	$	3,857,722	$	347,470		$	639,758		$	17,707,558
Noncontrolling interests in consolidated subsidiaries	$	4,536	$	—	$	—		$	2,502,793		$	2,507,329
Capital expenditures	$	1,939,326	$	292,080	$	—		$	25,179		$	2,256,585

(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $781.7 million, net margin of $545.0 million and operating income of $281.0 million.

Year Ended December 31, 2012	ONEOK Partners (a)		Natural Gas Distribution			Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	9,830,052	$	1,379,366		$	1,421,171		$	1,970		$	12,632,559
Intersegment revenues	352,099		(2,717		)	105,402			(454,784		)	—
Total revenues	$	10,182,151	$	1,376,649		$	1,526,573		$	(452,814	)	$	12,632,559
Net margin	$	1,641,832	$	756,389		$	(49,344	)	$	1,964		$	2,350,841
Operating costs	482,540		410,572			17,950			(2,084		)	908,978
Depreciation and amortization	203,101		130,150			361			2,232			335,844
Goodwill impairment	—		—			10,255			—			10,255
Gain on sale of assets	6,736		—			—			—			6,736
Operating income	$	962,927	$	215,667		$	(77,910	)	$	1,816		$	1,102,500
Equity earnings from investments	$	123,024	$	—		$	—		$	—		$	123,024
Investments in unconsolidated affiliates	$	1,221,405	$	—		$	—		$	—		$	1,221,405
Total assets	$	10,959,230	$	3,535,489		$	493,006		$	867,550		$	15,855,275
Noncontrolling interests in consolidated subsidiaries	$	4,767	$	—		$	—		$	2,098,074		$	2,102,841
Capital expenditures	$	1,560,513	$	280,294		$	—		$	25,346		$	1,866,153

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $722.1 million, net margin of $618.0 million and operating income of $375.6 million.

Year Ended December 31, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	10,919,004		$	1,609,628	$	2,274,799	$	2,363		$	14,805,794
Intersegment revenues	403,603			11,706		502,418		(917,727		)	—
Total revenues	$	11,322,607		$	1,621,334	$	2,777,217	$	(915,364	)	$	14,805,794
Net margin	$	1,577,380		$	751,835	$	48,740	$	2,404		$	2,380,359
Operating costs	459,364			422,073		24,527		2,359			908,323
Depreciation and amortization	177,549			132,212		445		1,954			312,160
Loss on sale of assets	(963		)	—		—		—			(963		)
Operating income	939,504			197,550		23,768		(1,909		)	1,158,913
Equity earnings from investments	$	127,246		$	—	$	—	$	—		$	127,246
Investments in unconsolidated affiliates	$	1,223,398		$	—	$	—	$	—		$	1,223,398
Total assets	$	8,946,676		$	3,392,475	$	562,728	$	794,756		$	13,696,635
Noncontrolling interests in consolidated subsidiaries	$	5,112		$	—	$	—	$	1,556,047		$	1,561,159
Capital expenditures	$	1,063,383		$	242,590	$	41	$	30,053		$	1,336,067

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $658.5 million, net margin of $469.0 million and operating income of $232.8 million.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

R. COMMITMENTS AND CONTINGENCIES

Commitments - Operating leases represent future minimum lease payments under noncancelable equipment leases covering office space, pipeline equipment, rights of way and vehicles.  Firm transportation and storage contracts are fixed-price contracts that provide us with firm transportation and storage capacity.  Rental expense in 2013, 2012 and 2011 was not material.  The following table sets forth our operating lease and firm transportation and storage contract payments for the periods indicated:

ONEOK	Operating Leases
	(Millions of dollars)
2014	$	3.4
2015	2.9
2016	2.5
2017	2.1
2018	1.9
Thereafter	3.3
Total	$	16.1

Our former Natural Gas Distribution segment is a party to fixed-price contracts providing it with firm transportation and storage capacity. The costs associated with these contracts are recovered through rates. Future commitments related to these contracts are $900.0 million. These contracts are obligations of ONE Gas as the result of the separation.

Our Energy Services segment also is a party to fixed-price contracts related to firm transportation and storage that are not being released as part of the wind down process and will expire before April 2014. Future commitments related to these contracts are $11.2 million.

ONEOK Partners	Operating Leases		Firm Transportation and Storage Contracts		Total
	(Millions of dollars)
2014	$	2.0	$	18.4	$	20.4
2015	0.5		16.3		16.8
2016	0.3		14.4		14.7
2017	0.2		12.8		13.0
2018	0.2		11.9		12.1
Thereafter	0.7		30.2		30.9
Total	$	3.9	$	104.0	$	107.9

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

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

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

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

Our expenditures for environmental assessment, mitigation, remediation and compliance to date have not been significant in relation to our financial position, results of operations or cash flows, and our expenditures related to environmental matters have had no material effects on earnings or cash flows during 2013, 2012 or 2011.

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.

In July 2011, the EPA issued a proposed rule that would change the air emissions New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and natural gas industry, including natural gas production, processing, transmission and underground storage sectors. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The EPA’s final rule reflects significant changes from the proposal issued in 2011 and allows for more manageable compliance options. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification.

In March 2013, the EPA issued proposed rulemaking to amend the NSPS for the crude oil and natural gas industry, pursuant to various industry comments, administrative petitions for reconsideration and/or judicial appeals of portions of the NSPS final rule. The rule was most recently amended in September 2013, and the EPA has indicated that further amendments may be issued in 2014. Based on the amendments and our understanding of pending stakeholder responses to the NSPS rule, we anticipate a reduction in our anticipated capital, operations and maintenance costs resulting from compliance with the regulation. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rule, which could alter our present expectations. Generally, the NSPS rule will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities in the crude oil and natural gas industry. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

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

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

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

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

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

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

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

Legal Proceedings - Gas Index Pricing Litigation - As previously reported, ONEOK and its subsidiary, ONEOK Energy Services Company L.P. (OESC), along with several other energy companies, are defending multiple lawsuits arising from alleged market manipulation or false reporting of natural gas prices to natural gas-index publications. On April 10, 2013, the United States Court of Appeals for the Ninth Circuit reversed the summary judgments that had been granted in favor of ONEOK, OESC and other unaffiliated defendants in the following cases: Reorganized FLI, Learjet, Arandell, Heartland and NewPage. The Ninth Circuit also reversed the summary judgment that had been granted in favor of OESC on all state law claims asserted in the Sinclair case. The Ninth Circuit remanded the cases back to the United States District Court for the District of Nevada for further proceedings. ONEOK, OESC and the other unaffiliated defendants filed a Petition for Writ of Certiorari with the United States Supreme Court on August 26, 2013. The Ninth Circuit has ordered the cases stayed until the final disposition of the Petition for Writ of Certiorari.

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

Other Legal Proceedings - We are a party to various other litigation matters and claims that have arisen in the normal course of our operations. While the results of these various other litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses on such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013 Y	Dec. 31, 2012	Dec. 31, 2011
Entity [Line Items]
Noncash charges	$ 10,200,000
Ownership interest		41.20%	43.40%	42.80%
Goodwill, Impairment Loss		0	10,255,000	0
Equity Method Investments	1,229,838,000	1,229,838,000	1,221,405,000	1,223,398,000
Equity method goodwill	224,300,000	224,300,000
Reportable business segments		3
Number of natural gas distribution services customers	2,000,000	2,000,000
Regulatory assets	383,600,000	383,600,000	585,000,000
Time period regulatory assets are being recovered (in years)		25
Number of years of service employees must work to be entitled to postretirement medical and life insurance benefits (in years)		5
Bighorn Gas Gathering LLC [Member]
Entity [Line Items]
Net ownership percentage	49.00%	49.00%
Equity Method Investments	87,837,000	87,837,000	90,428,000
Equity method goodwill	53,400,000	53,400,000
Other Powder River Basin Investments [Member]
Entity [Line Items]
Equity Method Investments	204,000,000	204,000,000
Equity method goodwill	130,000,000	130,000,000
Natural Gas Distribution [Member]
Entity [Line Items]
Goodwill, Impairment Loss			0
Equity Method Investments	0	0	0	0
Regulatory assets	376,800,000	376,800,000	577,100,000
Pension Costs [Member] | Natural Gas Distribution [Member]
Entity [Line Items]
Regulatory assets	$ 341,100,000	$ 341,100,000	$ 499,400,000

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EQUITY (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Quarterly dividends per share paid on common stock

Dividends - Dividends paid totaled $304.7 million, $262.0 million and $227.0 million for 2013, 2012 and 2011, respectively. The following table sets forth the quarterly dividends per share declared and paid on our common stock for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
First Quarter	$	0.36	$	0.305	$	0.26
Second Quarter	$	0.36	$	0.305	$	0.26
Third Quarter	$	0.38	$	0.33	$	0.28
Fourth Quarter	$	0.38	$	0.33	$	0.28
Total	$	1.48	$	1.27	$	1.08

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QUARTERLY FINANCIAL DATA (UNAUDITED)

12 Months Ended

Dec. 31, 2013

Quarterly Financial Information Disclosure [Abstract]

QUARTERLY FINANCIAL DATA (UNAUDITED)

T. QUARTERLY FINANCIAL DATA (UNAUDITED)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2013
	(Thousands of dollars except per share amounts)
Total revenues	$	3,541,445	$	3,349,236	$	3,571,925	$	4,140,111
Net margin	$	623,452	$	453,389	$	561,188	$	651,654
Income from continuing operations	$	165,705	$	79,495	$	147,698	$	184,063
Net income	$	165,705	$	79,495	$	147,698	$	184,063
Net income attributable to ONEOK	$	112,521	$	919	$	62,356	$	90,737
Earnings per share total
Basic	$	0.55	$	—	$	0.30	$	0.44
Diluted	$	0.54	$	—	$	0.30	$	0.43

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Year Ended December 31, 2012
	(Thousands of dollars except per share amounts)
Total revenues	$	3,414,600	$	2,529,260	$	3,028,775	$	3,659,924
Net margin	$	643,587	$	548,962	$	553,972	$	604,320
Income from continuing operations	$	219,450	$	148,938	$	164,988	$	195,875
Income from discontinued operations and gain on sale, net of tax	$	14,012	$	267	$	—	$	—
Net income	$	233,462	$	149,205	$	164,988	$	195,875
Net income attributable to ONEOK	$	122,865	$	60,993	$	65,219	$	111,542
Earnings per share total
Basic	$	0.59	$	0.29	$	0.32	$	0.55
Diluted	$	0.58	$	0.29	$	0.31	$	0.53

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SUBSEQUENT EVENTS (Notes)

3 Months Ended

Mar. 31, 2014

Subsequent Event [Line Items]

Subsequent Events [Text Block]

U. Subsequent Events

On January 8, 2014, our Board of Directors unanimously approved the distribution of all the shares of common stock of ONE Gas, our wholly owned subsidiary, to our shareholders. On January 14, 2014, we entered into the following agreements with ONE Gas which provide a framework for our relationship with ONE Gas after the distribution:

• Separation and Distribution Agreement - sets forth the agreements between us and ONE Gas regarding the principal transactions necessary to effect the distribution. This agreement also sets forth other agreements that govern certain aspects of our relationship with ONE Gas after the completion of the distribution.

• Tax Matters Agreement - governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and other matters regarding taxes.

• Transition Services Agreement - provides for an orderly transition to ONE Gas being an independent, publicly traded company. Under this agreement, ONEOK and ONE Gas have agreed to provide each other with various services, including services relating to treasury and risk management, human resources and payroll management, tax compliance, telecommunications services and information technology services.

• Employee Matters Agreement - allocates liabilities and responsibilities relating to employee compensation and benefit plans and programs and other related matters in connection with the separation, including the treatment of outstanding incentive awards and certain retirement and welfare benefit obligations.

On January 27, 2014, ONE Gas, which at the time was our wholly owned subsidiary, completed a private placement of three series of Senior Notes totaling $1.2 billion. The following table details information about each of the three series of Senior Notes:

	(In millions)
2.07% notes due February 1, 2019	$	300
3.61% notes due February 1, 2024	300
4.658% notes due February 1, 2044	600
	$	1,200

Our obligations related to the ONE Gas Senior Notes and Credit Agreement terminated in connection with the completion of the separation of ONE Gas.

ONE Gas made a cash payment to us of approximately $1.13 billion from the proceeds of this offering. In February 2014, we retired approximately $152.5 million of the 4.25 percent senior notes due 2022 through a tender offer. The total amount paid, including fees and other charges, was approximately $150 million. We also repaid all commercial paper outstanding, which totaled approximately $600.5 million.

On January 31, 2014, the separation of ONE Gas was completed through a stock dividend distribution of ONE Gas shares to our shareholders after the market closed. We distributed one share of common stock of ONE Gas for every four shares of ONEOK common stock held by ONEOK shareholders of record as of the close of business on January 21, 2014, the record date for the distribution.  We retained no ownership interest in ONE Gas.

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.

In connection with the separation, John W. Gibson retired as Chief Executive Officer of ONEOK and remained Chairman of the Board of ONEOK and ONEOK Partners, effective January 31, 2014. Our Board of Directors approved the expansion of the number of directors of the Board of Directors of ONEOK to 11 from 10 and elected Terry K. Spencer to serve as a member of the Board of Directors effective January 31, 2014. Mr. Spencer serves on the Executive Committee. Mr. Spencer also was elected President and Chief Executive Officer of ONEOK and ONEOK Partners. Also in connection with the separation, Pierce H. Norton II resigned as an officer of ONEOK effective January 31, 2014, to become President and Chief Executive Officer of ONE Gas.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities
Net income	$ 576,961	$ 743,530	$ 759,744
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	384,377	335,852	312,288
Charges attributable to exit activities, net of settlements	121,971	0	0
Impairment of goodwill	0	10,255	0
Gain on sale of discontinued operations	0	(13,517)	0
Equity earnings from investments	(110,517)	(123,024)	(127,246)
Distributions received from unconsolidated affiliates	106,364	120,442	132,741
Deferred income taxes	151,515	229,398	256,688
Share-based compensation expense	46,194	36,692	66,371
Pension and other postretirement benefit expense, net of contributions	56,600	(57,073)	(29,863)
Allowance for equity funds used during construction	(30,522)	(13,648)	(2,335)
Loss (gain) on sale of assets	(11,881)	(6,736)	963
Other	(5,656)	27,982	(1,471)
Changes in assets and liabilities:
Accounts receivable	(189,809)	(14,774)	(55,861)
Gas and natural gas liquids in storage	99,937	33,343	65,845
Accounts payable	165,076	(30,981)	102,621
Commodity imbalances, net	(52,233)	43,471	(54,886)
Energy marketing and risk management assets and liabilities	25,072	(174,953)	(31,999)
Other assets and liabilities	(38,682)	(162,264)	(37,434)
Cash provided by operating activities	1,294,767	983,995	1,356,166
Investing Activities
Capital expenditures (less allowance for equity funds used during construction)	(2,256,585)	(1,866,153)	(1,336,067)
Acquisitions	(394,889)	0	0
Proceeds from sale of discontinued operations, net of cash sold	0	32,946	0
Contributions to unconsolidated affiliates	(35,308)	(30,768)	(64,491)
Distributions received from unconsolidated affiliates	31,134	35,299	23,644
Proceeds from sale of assets	13,617	12,240	1,288
Other	0	2,237	4,000
Cash used in investing activities	(2,642,031)	(1,814,199)	(1,371,626)
Financing Activities
Borrowing (repayment) of notes payable, net	(252,708)	(24,812)	285,127
Issuance of debt, net of discounts	1,247,822	1,994,693	1,295,450
Long-term debt financing costs	(10,246)	(15,036)	(10,986)
Repayment of debt	(7,868)	(361,464)	(727,562)
Repurchase of common stock	0	(150,000)	(300,108)
Issuance of common stock	20,602	15,969	17,906
Issuance of common units, net of issuance costs	583,929	459,587	0
Dividends paid	(304,742)	(261,969)	(227,020)
Distributions to noncontrolling interests	(374,142)	(324,906)	(277,375)
Excess tax benefit from stock-based awards	10,312	6,948	3,806
Cash provided by financing activities	912,959	1,339,010	59,238
Change in cash and cash equivalents	(434,305)	508,806	43,778
Change in cash and cash equivalents included in discontinued operations	0	8,859	(8,166)
Change in cash and cash equivalents from continuing operations	(434,305)	517,665	35,612
Cash and cash equivalents at beginning of period	583,618	65,953	30,341
Cash and cash equivalents at end of period	149,313	583,618	65,953
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized	294,240	439,398	278,162
Cash paid (refunds received) for income taxes	$ (16,640)	$ 872	$ (68,696)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2013

Entity [Line Items]

Consolidation

Consolidation - Our consolidated financial statements include the accounts of ONEOK and our subsidiaries over which we have control or are the primary beneficiary.  We have recorded noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheets to recognize the portion of ONEOK Partners that we do not own.  We reflected our ownership interest in ONEOK Partners’ accumulated other comprehensive income (loss) in our consolidated accumulated other comprehensive income (loss).  The remaining portion is reflected as an adjustment to noncontrolling interests in consolidated subsidiaries.  All significant intercompany balances and transactions have been eliminated in consolidation. We have recast prior period amounts in the Consolidated Statements of Cash Flows to revise the classification of the excess tax benefit of share-based compensation to financing from operating activities.

Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive income. For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Impairment of equity investments is recorded when the impairments are other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment.  The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows. See Note P for disclosures of our unconsolidated affiliates.

Use of Estimates

Use of Estimates - 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 amount 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.  Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, gas purchased expense for natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances.  Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

Fair Value Measurements

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 over a reasonable period of time under current market conditions.  We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitor the credit default swap markets.  Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.

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.

We recognize transfers into and out of Level 3 as of the end of each reporting period.  Transfers into Level 3 represent existing assets or liabilities that were categorized previously at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

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. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.  See Note D for additional disclosures of our fair value measurements.

Cash and Cash Equivalents

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

Revenue Recognition

Revenue Recognition - Our operating segments recognize revenue when services are rendered or product is delivered. ONEOK Partners’ natural gas gathering and processing operations record revenue when gas is processed in or transported through its facilities.  ONEOK Partners’ natural gas liquids operations record revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the period services are provided.  Revenue for ONEOK Partners’ natural gas pipelines and a portion of its natural gas liquids operations is recognized based upon contracted capacity and contracted volumes transported and stored under service agreements in the period services are provided.

Our former Natural Gas Distribution segment’s major industrial and commercial natural gas distribution customers are invoiced at the end of each month.  All natural gas distribution residential customers and some commercial customers are invoiced on a cyclical basis throughout the month, and the utilities accrue unbilled revenues at the end of each month.

Our revenues from sales to our Energy Services segment’s wholesale customers are accrued in the month of physical delivery based on contracted sales price and estimated volumes.  Demand payments received for requirements contracts are recognized in the period in which the service is provided.  Our fixed-price physical sales are accounted for as derivatives and are recorded at fair value.  See discussion below in “Derivative and Risk Management Activities” for additional information.

Accounts Receivable

Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services rendered, net of allowances for doubtful accounts.  We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate.  Outstanding customer receivables are reviewed regularly for possible nonpayment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date.  At December 31, 2013 and 2012, our allowance for doubtful accounts was not material.

Inventories

Inventories - The values of current natural gas and NGLs in storage are determined using the lower of weighted-average cost or market method.  Noncurrent natural gas and NGLs are classified as property and valued at cost.  Materials and supplies are valued at average cost.

Commodity Imbalances

Commodity Imbalances -Commodity imbalances represent amounts payable or receivable for NGL exchange contracts and natural gas pipeline imbalances and are valued at fair value.  Under the majority of our NGL exchange agreements, we physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the exchange counterparty.  In turn, we deliver NGL products back to the customer and charge them gathering and fractionation fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a net exchange receivable or payable position with the counterparties.  These net exchange receivables and payables are settled with movements of NGL products rather than with cash.  Natural gas pipeline imbalances are settled in cash or in-kind, subject to the terms of the pipelines’ tariffs or by agreement.

Derivatives and Risk Management Activities

Derivatives 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.  The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.

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

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in earnings
Cash flow hedge	-	Recorded at fair value	-	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	-	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	-	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
Fair value hedge	-	Recorded at fair value	-	The gain or loss on the derivative instrument is recognized in earnings
	-	Change in fair value of the hedged item is recorded as an adjustment to book value	-	Change in fair value of the hedged item is recognized in earnings

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

We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item.  We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our cash flow and fair value hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis.  We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts.  All financially settled derivative instruments, as well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income.  The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and nonderivative contracts are reported on a gross basis.  Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on a gross basis.

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

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

See Notes D and E for more discussion of our fair value measurements and risk management and hedging activities using derivatives.

Property, Plant and Equipment

Property, Plant and Equipment - Our properties are stated at cost, including AFUDC.  Generally, the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation.  Gains and losses from sales or retirement of nonregulated properties or an entire operating unit or system of our regulated properties are recognized in income. Maintenance and repairs are charged directly to expense.

The interest portion of AFUDC represents the cost of borrowed funds used to finance construction activities.  We capitalize interest costs during the construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction.

Our properties are depreciated using the straight-line method over their estimated useful lives.  Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances.  We periodically conduct depreciation studies to assess the economic lives of our assets.  For our regulated assets, these depreciation studies are completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are billed.  For our nonregulated assets, if it is determined that the estimated economic life changes, the changes are made prospectively.  Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or results of operations.

Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated.  Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.

See Note F for disclosures of our property, plant and equipment.

Impairment of Goodwill and Long-Lived Assets, including Intangible Assets

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 Energy Services segment’s 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. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services. There were also no impairment charges resulting from our 2012 and 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 and 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 in the Powder River Basin.  The reduced coal-bed methane development activities and natural production declines in the dry natural gas formation of the Powder River Basin resulted in lower volumes available to be gathered.  While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects.  Bighorn Gas Gathering, in which ONEOK Partners owns a 49 percent equity interest, has operations in the coal-bed methane areas of the Powder River Basin. Due to declines in volumes gathered on Bighorn Gas Gathering’s system, 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 estimate reasonably 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 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.

A continued decline in coal-bed methane natural gas volumes in the coal-bed methane production 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. 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 F, G and P for our long-lived assets, goodwill and intangible assets and investment in unconsolidated affiliates disclosures.

Regulation

Regulation - Our former natural gas distribution operations and ONEOK Partners’ intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. ONEOK Partners’ interstate natural gas and natural gas liquids pipelines are subject to regulation by the FERC.  In Kansas and Texas, natural gas storage may be regulated by the state and the FERC for certain types of services.  Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK Partners segment follow the accounting and reporting guidance for regulated operations.  During the rate-making process, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time, as opposed to expensing such costs as incurred. Examples include costs for fuel and fuel losses, acquisition costs and contributions in aid of construction. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery.  Actions by regulatory authorities could have an effect on the amount recovered from rate payers.  Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action.  A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer:

• established by independent, third-party regulators;

• designed to recover the specific entity’s costs of providing regulated services; and

• set at levels that will recover our costs when considering the demand and competition for our services.

In December 2013, the KCC approved a settlement agreement for the separation of our Kansas Gas Service natural gas distribution business to ONE Gas from ONEOK. The terms of the settlement agreement provided that amounts previously recorded as a regulatory asset related to ONEOK’s acquisition of Kansas Gas Service in 1997 would no longer be recovered in rates. As a result, the carrying amount of the regulatory asset was written off, and we recorded a noncash charge to income of approximately $10.2 million in the fourth quarter 2013.

At December 31, 2013 and 2012, we recorded regulatory assets of approximately $383.6 million and $585.0 million, respectively, which are being recovered or are expected to be recovered as a result of various approved rate proceedings.  Of these amounts, the total regulatory assets related to our natural gas distribution business were $376.8 million and $577.1 million at December 31, 2013 and 2012, respectively. The natural gas distribution balances included approximately $341.1 million and $499.4 million related to our pension and postretirement benefit plans at December 31, 2013 and 2012, respectively, which are discussed in Note N.  Regulatory assets are being recovered as a result of approved rate proceedings over varying time periods up to 25 years.  These assets are reflected in other assets on our Consolidated Balance Sheets.

Pension and Postretirement Employee Benefits

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 N for more discussion of pension and postretirement employee benefits.

We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and economic growth models.

We determine our discount rates annually.  We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our pension and postretirement obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows.  Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds.  Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.

Income Taxes

Income Taxes - Deferred income taxes are recorded for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse.  The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas, if, as a result of an action by a regulator, it is probable that the effect of the change in tax rates will be recovered from or returned to customers through future rates.  For all other operations, the effect is recognized in income in the period that includes the enactment date.  We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.

We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return.  We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute.  During 2013, 2012 and 2011, our tax positions did not require an establishment of a material reserve.

We file numerous consolidated and separate income tax returns with federal tax authorities of the United States and Canada, along with the tax authorities of several states.  There are no United States federal audits or statute waivers at this time. See Note O for additional discussion of income taxes.

Asset Retirement Obligations

Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.  Certain long-lived assets that comprise our natural gas distribution systems and ONEOK Partners’ natural gas gathering and processing, natural gas liquids and pipeline facilities are subject to agreements or regulations that give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the assets. We recognize the fair value of a liability for an asset-retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made.  We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our and ONEOK Partners’ assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. We expect our former natural gas distribution assets and ONEOK Partners’ pipeline assets, for which we are unable to estimate reasonably the fair value of the asset retirement obligation, will continue to operate as long as natural gas supply and demand for natural gas and natural gas liquids exists. Based on the widespread use of natural gas for heating and cooking activities by residential users and electric-power generation by commercial users, as well as use of natural gas liquids by the petrochemical industry, we and ONEOK Partners expect supply and demand to exist for the foreseeable future.

For our assets where we are able to make an estimate, the fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset.  The liability is accreted at the end of each period through charges to operating expense.  If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.  The depreciation and accretion expense are immaterial to our consolidated financial statements.

In accordance with long-standing regulatory treatment, we collect, through rates, the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs collected through our rates include costs attributable to legal and nonlegal removal obligations; however, the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory liability for financial reporting purposes. Historically, with the exception of the regulatory authority in Kansas, the regulatory authorities that have jurisdiction over our regulated operations have not required us to quantify or disclose this amount; rather, these costs are addressed prospectively in depreciation rates and are set in each general rate order. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our jurisdictions; however, for financial reporting purposes, significant uncertainty exists regarding the future disposition of this regulatory liability, pending, among other issues, clarification of regulatory intent.  We continue to monitor the regulatory requirements, and the liability may be adjusted as more information is obtained.  We record the estimated asset removal obligation in noncurrent liabilities in other deferred credits on our Consolidated Balance Sheets.  To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on earnings.

Contingencies

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 estimated reasonably.  We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates 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.  Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.  See Note R for additional discussion of contingencies.

Share-Based Payments

Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures.  We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.

Earnings per Common Share

Earnings per Common Share - Basic EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period.  Diluted EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period plus potentially dilutive components.  The dilutive components are calculated based on the dilutive effect for each quarter.  For fiscal-year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.

Recently Issued Accounting Standards Update

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

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires presentation in a single location, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source.  We adopted this guidance with our March 31, 2013, Quarterly Report, and it did not impact our financial position or results of operations. See Note K for additional disclosures.

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

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” which increases disclosures about offsetting assets and liabilities. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards related to the offsetting of financial instruments, including derivatives. The existing GAAP guidance allowing balance sheet offsetting remains unchanged. This guidance was effective for interim and annual periods beginning on January 1, 2013, and was applied retrospectively for all comparative periods presented. The adoption of this guidance beginning with our March 31, 2013, Quarterly Report did not affect our financial condition, results of operations or cash flows.

Accounting Standards Update 2013-10 [Member]

Entity [Line Items]

New Accounting Pronouncement or Change in Accounting Principle, Description

In July 2013, the FASB issued ASU 2013-10, “Inclusion of the Fed Funds Effective Swap Rate (or Overnight Index Swap Rate) as a Benchmark Interest Rate for Hedge Accounting Purposes,” which allows an entity to designate the Fed Funds Effective Swap rate (also known as the Overnight Index Swap rate, or OIS rate, in the United States) as a benchmark interest rate for hedge accounting purposes in addition to the interest rates on direct Treasury obligations of the United States government and LIBOR. In addition, this guidance removes the restriction on using different benchmark interest rates for similar hedges. This guidance was effective prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013.

Accounting Standards Update 2013-02 [Member]

Entity [Line Items]

New Accounting Pronouncement or Change in Accounting Principle, Description

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires presentation in a single location, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source. 

Accounting Standards Update 2012-02 [Member]

Entity [Line Items]

New Accounting Pronouncement or Change in Accounting Principle, Description

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

Accounting Standards Update 2011-11 [Member]

Entity [Line Items]

New Accounting Pronouncement or Change in Accounting Principle, Description

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” which increases disclosures about offsetting assets and liabilities. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards related to the offsetting of financial instruments, including derivatives. The existing GAAP guidance allowing balance sheet offsetting remains unchanged. This guidance was effective for interim and annual periods beginning on January 1, 2013, and was applied retrospectively for all comparative periods presented.

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivatives

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

	December 31, 2013						December 31, 2012
	Fair Values of Derivatives (a)						Fair Values of Derivatives (a)
	Assets			(Liabilities)			Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	8,011	(b)	$	(10,573	)	$	47,516	(c)	$	(4,885	)
Physical contracts	1,064			(3,463		)	56			(126		)
Interest-rate contracts	54,503			—			10,923			—
Total derivatives designated as hedging instruments	63,578			(14,036		)	58,495			(5,011		)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts	202			(1,262		)	24,970			(25,009		)
Physical contracts	704			(658		)	4,059			(153		)
Trading instruments
Financial contracts	5			—			15,358			(14,192		)
Total derivatives not designated as hedging instruments	911			(1,920		)	44,387			(39,354		)
Total derivatives	$	64,489		$	(15,956	)	$	102,882		$	(44,365	)

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

(b) - Includes $5.8 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive income (loss).

(c) - Includes $16.9 million

Notional amounts of derivative instruments

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

		December 31, 2013				December 31, 2012
	Contract Type	Purchased/ Payor		Sold/ Receiver		Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
-Natural gas (Bcf)	Futures, forwards and swaps	—		(65.0	)	—		(85.1	)
-Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	—		(4.0	)	—		(1.1	)
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	—		(57.4	)	—		(56.3	)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	400.0	—		$	400.0	—
Fair value hedges
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	1.1		(1.1	)	59.1		(59.1	)
Derivatives not designated as hedging instruments:
Fixed price
-Natural gas (Bcf)	Futures, forwards and swaps	5.8		(9.7	)	60.7		(60.4	)
	Options	—		—		102.1		(100.8	)
-Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	0.3		(0.3	)	—		—
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	8.5		(11.2	)	80.2		(81.7	)
Index
-Natural gas (Bcf)	Futures, forwards and swaps	1.8		—		20.3		(22.3	)

Schedule of cash flow hedging instruments effect on comprehensive income (loss)

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

Derivatives in Cash Flow Hedging Relationships	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Commodity contracts	$	(15,433	)	$	62,898		$	117,508
Interest-rate contracts	46,616			(29,471		)	(128,666		)
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	31,183		$	33,427		$	(11,158	)

Schedule of cash flow hedging instruments effect on income

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

	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships		Years Ended December 31,
		2013			2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	19,049		$	140,862		$	48,601
Commodity contracts	Cost of sales and fuel	(14,320		)	(73,881		)	89,618
Interest-rate contracts	Interest expense	(14,560		)	(7,155		)	(480		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(9,831	)	$	59,826		$	137,739

Schedule of derivatives not designated as hedging effect on income

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

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	Years Ended December 31,
		2013				2012		2011
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	(2,051	)		$	2,413	$	1,796
Commodity contracts - non-trading (a)	Cost of sales and fuel	(2,266		)	(b)	5,956		16,178
Total gain (loss) recognized in income on derivatives		$	(4,317	)		$	8,369	$	17,974

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

(b) - Includes losses of $2.2 million for the year ended December 31, 2013, on certain derivatives derecognized that were designated previously as fair value hedges of firm transportation commitments that no longer meet the definition of a firm commitment.

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SEGMENTS (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]

Segments

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

Year Ended December 31, 2013	ONEOK Partners (a)		Natural Gas Distribution		Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	11,528,530	$	1,689,945	$	1,381,636		$	2,606		$	14,602,717
Intersegment revenues	340,743		7		195,926			(536,676		)	—
Total revenues	$	11,869,273	$	1,689,952	$	1,577,562		$	(534,070	)	$	14,602,717
Net margin	$	1,647,060	$	813,008	$	(172,985	)	$	2,600		$	2,289,683
Operating costs	521,513		444,866		13,133			10,941			990,453
Depreciation and amortization	236,743		144,758		277			2,599			384,377
Gain on sale of assets	11,881		—		—			—			11,881
Operating income	$	900,685	$	223,384	$	(186,395	)	$	(10,940	)	$	926,734
Equity earnings from investments	$	110,517	$	—	$	—		$	—		$	110,517
Investments in unconsolidated affiliates	$	1,229,838	$	—	$	—		$	—		$	1,229,838
Total assets	$	12,862,608	$	3,857,722	$	347,470		$	639,758		$	17,707,558
Noncontrolling interests in consolidated subsidiaries	$	4,536	$	—	$	—		$	2,502,793		$	2,507,329
Capital expenditures	$	1,939,326	$	292,080	$	—		$	25,179		$	2,256,585

(a) - Our ONEOK Partners segment has regulated and nonregulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $781.7 million, net margin of $545.0 million and operating income of $281.0 million.

Year Ended December 31, 2012	ONEOK Partners (a)		Natural Gas Distribution			Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	9,830,052	$	1,379,366		$	1,421,171		$	1,970		$	12,632,559
Intersegment revenues	352,099		(2,717		)	105,402			(454,784		)	—
Total revenues	$	10,182,151	$	1,376,649		$	1,526,573		$	(452,814	)	$	12,632,559
Net margin	$	1,641,832	$	756,389		$	(49,344	)	$	1,964		$	2,350,841
Operating costs	482,540		410,572			17,950			(2,084		)	908,978
Depreciation and amortization	203,101		130,150			361			2,232			335,844
Goodwill impairment	—		—			10,255			—			10,255
Gain on sale of assets	6,736		—			—			—			6,736
Operating income	$	962,927	$	215,667		$	(77,910	)	$	1,816		$	1,102,500
Equity earnings from investments	$	123,024	$	—		$	—		$	—		$	123,024
Investments in unconsolidated affiliates	$	1,221,405	$	—		$	—		$	—		$	1,221,405
Total assets	$	10,959,230	$	3,535,489		$	493,006		$	867,550		$	15,855,275
Noncontrolling interests in consolidated subsidiaries	$	4,767	$	—		$	—		$	2,098,074		$	2,102,841
Capital expenditures	$	1,560,513	$	280,294		$	—		$	25,346		$	1,866,153

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $722.1 million, net margin of $618.0 million and operating income of $375.6 million.

Year Ended December 31, 2011	ONEOK Partners (a)			Natural Gas Distribution		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	10,919,004		$	1,609,628	$	2,274,799	$	2,363		$	14,805,794
Intersegment revenues	403,603			11,706		502,418		(917,727		)	—
Total revenues	$	11,322,607		$	1,621,334	$	2,777,217	$	(915,364	)	$	14,805,794
Net margin	$	1,577,380		$	751,835	$	48,740	$	2,404		$	2,380,359
Operating costs	459,364			422,073		24,527		2,359			908,323
Depreciation and amortization	177,549			132,212		445		1,954			312,160
Loss on sale of assets	(963		)	—		—		—			(963		)
Operating income	939,504			197,550		23,768		(1,909		)	1,158,913
Equity earnings from investments	$	127,246		$	—	$	—	$	—		$	127,246
Investments in unconsolidated affiliates	$	1,223,398		$	—	$	—	$	—		$	1,223,398
Total assets	$	8,946,676		$	3,392,475	$	562,728	$	794,756		$	13,696,635
Noncontrolling interests in consolidated subsidiaries	$	5,112		$	—	$	—	$	1,556,047		$	1,561,159
Capital expenditures	$	1,063,383		$	242,590	$	41	$	30,053		$	1,336,067

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had

revenues of $658.5 million, net margin of $469.0 million and operating income of $232.8 million.

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EARNINGS PER SHARE (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basic EPS from continuing operations [Abstract]
Income from continuing operations attributable to ONEOK available for common stock									$ 266,533	$ 346,340	$ 358,364
Shares									206,044	206,140	209,344
Per share amount	$ 0.44	$ 0.30	$ 0.00	$ 0.55	$ 0.55	$ 0.32	$ 0.29	$ 0.59	$ 1.29	$ 1.68	$ 1.71
Diluted EPS from continuing operations [Abstract]
Effect of options and other dilutive securities									0	0	0
Effect of options and other dilutive securities, shares									3,651	4,570	5,154
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents									$ 266,533	$ 346,340	$ 358,364
Shares									209,695	210,710	214,498
Per share amount	$ 0.43	$ 0.30	$ 0.00	$ 0.54	$ 0.53	$ 0.31	$ 0.29	$ 0.58	$ 1.27	$ 1.64	$ 1.67

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CONSOLIDATED STATEMENTS OF INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]
Revenues	$ 14,602,717	$ 12,632,559	$ 14,805,794
Cost of sales and fuel	12,313,034	10,281,718	12,425,435
Net margin	2,289,683	2,350,841	2,380,359
Operating expenses
Operations and maintenance	872,125	806,087	813,666
Depreciation and amortization	384,377	335,844	312,160
Goodwill impairment	0	10,255	0
General taxes	118,328	102,891	94,657
Total operating expenses	1,374,830	1,255,077	1,220,483
Gain (loss) on sale of assets	11,881	6,736	(963)
Operating income	926,734	1,102,500	1,158,913
Equity earnings from investments (Note P)	110,517	123,024	127,246
Allowance for equity funds used during construction	30,522	13,648	2,335
Other income	24,483	12,504	1,410
Other expense	(17,707)	(4,925)	(9,336)
Interest expense (net of capitalized interest of $57,775, $41,776 and $23,960, respectively)	(334,206)	(302,305)	(297,006)
Income before income taxes	740,343	944,446	983,562
Income taxes (Note O)	(163,382)	(215,195)	(226,048)
Income from continuing operations	576,961	729,251	757,514
Income from discontinued operations, net of tax (Note C)	0	762	2,230
Gain on sale of discontinued operations, net of tax (Note C)	0	13,517	0
Net income	576,961	743,530	759,744
Less: Net income attributable to noncontrolling interests	310,428	382,911	399,150
Net income attributable to ONEOK	266,533	360,619	360,594
Amounts attributable to ONEOK:
Income from continuing operations	266,533	346,340	358,364
Income from discontinued operations	0	14,279	2,230
Net Income	$ 266,533	$ 360,619	$ 360,594
Basic earnings per share:
Income from continuing operations (Note L)	$ 1.29	$ 1.68	$ 1.71
Income from discontinued operations	$ 0.00	$ 0.07	$ 0.01
Net Income	$ 1.29	$ 1.75	$ 1.72
Diluted earnings per share:
Income from continuing operations (Note L)	$ 1.27	$ 1.64	$ 1.67
Income from discontinued operations	$ 0.00	$ 0.07	$ 0.01
Net Income	$ 1.27	$ 1.71	$ 1.68
Average shares (thousands)
Basic	206,044	206,140	209,344
Diluted	209,695	210,710	214,498
Dividends declared per share of common stock	$ 1.48	$ 1.27	$ 1.08

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Tables)

12 Months Ended

Dec. 31, 2013

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated other comprehensive income (loss)

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

	Unrealized Gains (Losses) on Energy Marketing and Risk-Management Assets/Liabilities (a)			Unrealized Holding Gains (Losses) on Investment Securities (a)			Pension and Postretirement Benefit Plan Obligations (a)			Accumulated Other Comprehensive Income (Loss) (a)
	(Thousands of dollars)
January 1, 2012	$	(55,367	)	$	987		$	(151,741	)	$	(206,121	)
Other comprehensive income (loss) before reclassifications	16,709			47			(47,004		)	(30,248		)
Amounts reclassified from accumulated other comprehensive income (loss)	(16,372		)	—			35,943			19,571
Other comprehensive income (loss) attributable to ONEOK	337			47			(11,061		)	(10,677		)
December 31, 2012	(55,030		)	1,034			(162,802		)	(216,798		)
Other comprehensive income (loss) before reclassifications	8,842			(177		)	37,144			45,809
Amounts reclassified from accumulated other comprehensive income (loss)	3,020			—			45,982			49,002
Other comprehensive income (loss) attributable to ONEOK	11,862			(177		)	83,126			94,811
December 31, 2013	$	(43,168	)	$	857		$	(79,676	)	$	(121,987	)

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 149,313	$ 583,618
Accounts receivable, net	1,549,563	1,349,371
Gas and natural gas liquids in storage	417,077	517,014
Commodity imbalances	82,144	90,211
Energy marketing and risk management assets (Notes D and E)	1,687	48,577
Other current assets	171,018	175,869
Total current assets	2,370,802	2,764,660
Property, plant and equipment
Property, plant and equipment	15,536,156	13,088,991
Accumulated depreciation and amortization	3,238,652	2,974,651
Net property, plant and equipment (Note F)	12,297,504	10,114,340
Investments and other assets
Investments in unconsolidated affiliates (Note P)	1,229,838	1,221,405
Goodwill and intangible assets (Note G)	1,182,515	996,206
Other assets	626,899	758,664
Total investments and other assets	3,039,252	2,976,275
Total assets	17,707,558	15,855,275
Current liabilities
Current maturities of long-term debt (Note I)	10,656	10,855
Notes payable (Note H)	564,462	817,170
Accounts payable	1,503,699	1,333,489
Commodity imbalances	212,136	272,436
Energy marketing and risk management liabilities (Notes D and E)	4,032	9,990
Other current liabilities	401,422	369,054
Total current liabilities	2,696,407	2,812,994
Long-term debt, excluding current maturities (Note I)	7,754,975	6,515,372
Deferred credits and other liabilities
Deferred income taxes (Note O)	1,938,262	1,592,802
Other deferred credits	472,734	701,657
Total deferred credits and other liabilities	2,410,996	2,294,459
Commitments and contingencies (Note R)
ONEOK shareholders' equity:
Common stock, $0.01 par value: authorized 600,000,000 shares; issued 245,811,180 shares and outstanding 206,618,877 shares at December 31, 2013; issued 245,811,180 shares and outstanding 204,935,043 shares at December 31, 2012	2,458	2,458
Paid-in capital	1,433,600	1,324,698
Accumulated other comprehensive loss (Note K)	(121,987)	(216,798)
Retained earnings	2,020,815	2,059,024
Treasury stock, at cost: 39,192,303 shares at December 31, 2013 and 40,876,137 shares at December 31, 2012	(997,035)	(1,039,773)
Total ONEOK shareholders' equity	2,337,851	2,129,609
Noncontrolling interests in consolidated subsidiaries	2,507,329	2,102,841
Total equity	4,845,180	4,232,450
Total liabilities and equity	$ 17,707,558	$ 15,855,275

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FAIR VALUE MEASUREMENTS - Part 1 (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Commodity contracts
Cash collateral held	$ 0	$ 17,700,000
Cash collateral posted	15,700,000	4,500,000
Fair Value, Measurements, Recurring [Member]
Commodity contracts
Financial contracts	5,368,000	36,242,000
Physical contracts	611,000	3,964,000
Interest-rate contracts	54,503,000	10,923,000
Total derivatives	60,482,000	51,129,000
Trading securities		5,978,000
Fair value of firm commitments	599,000
Available-for-sale investment securities	1,569,000	2,027,000
Total assets	62,650,000	59,134,000
Commodity contracts
Financial contracts	(1,068,000)	(10,208,000)
Physical contracts	(2,964,000)	(128,000)
Total derivatives		(10,336,000)
Fair value of firm commitments		(1,280,000)
Total liabilities	(4,032,000)	(11,616,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Commodity contracts
Financial contracts	4,477,000	69,957,000
Physical contracts	0	0
Interest-rate contracts	0	0
Total derivatives	4,477,000	69,957,000
Trading securities		5,978,000
Fair value of firm commitments	0
Available-for-sale investment securities	1,569,000	2,027,000
Total assets	6,046,000	77,962,000
Commodity contracts
Financial contracts	(7,624,000)	(35,172,000)
Physical contracts	0	0
Total derivatives		(35,172,000)
Fair value of firm commitments		0
Total liabilities	(7,624,000)	(35,172,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Commodity contracts
Financial contracts	647,000	10,780,000
Physical contracts	4,000	2,083,000
Interest-rate contracts	54,503,000	10,923,000
Total derivatives	55,154,000	23,786,000
Trading securities		0
Fair value of firm commitments	0
Available-for-sale investment securities	0	0
Total assets	55,154,000	23,786,000
Commodity contracts
Financial contracts	(776,000)	(1,737,000)
Physical contracts	(4,000)	0
Total derivatives		(1,737,000)
Fair value of firm commitments		0
Total liabilities	(780,000)	(1,737,000)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Commodity contracts
Financial contracts	3,094,000	7,107,000
Physical contracts	1,764,000	2,032,000
Interest-rate contracts	0	0
Total derivatives	4,858,000	9,139,000
Trading securities		0
Fair value of firm commitments	599,000
Available-for-sale investment securities	0	0
Total assets	5,457,000	9,139,000
Commodity contracts
Financial contracts	(3,435,000)	(7,177,000)
Physical contracts	(4,117,000)	(279,000)
Total derivatives		(7,456,000)
Fair value of firm commitments		(1,280,000)
Total liabilities	(7,552,000)	(8,736,000)
Fair Value, Measurements, Recurring [Member] | Netting and Collateral [Member]
Commodity contracts
Financial contracts	(2,850,000)	(51,602,000)
Physical contracts	(1,157,000)	(151,000)
Interest-rate contracts	0	0
Total derivatives	(4,007,000)	(51,753,000)
Trading securities		0
Fair value of firm commitments	0
Available-for-sale investment securities	0	0
Total assets	(4,007,000)	(51,753,000)
Commodity contracts
Financial contracts	10,767,000	33,878,000
Physical contracts	1,157,000	151,000
Total derivatives		34,029,000
Fair value of firm commitments		0
Total liabilities	11,924,000	34,029,000
Fair Value, Measurements, Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Commodity contracts
Financial contracts	8,218,000	87,844,000
Physical contracts	1,768,000	4,115,000
Interest-rate contracts	54,503,000	10,923,000
Total derivatives	64,489,000	102,882,000
Trading securities		5,978,000
Fair value of firm commitments	599,000
Available-for-sale investment securities	1,569,000	2,027,000
Total assets	66,657,000	110,887,000
Commodity contracts
Financial contracts	(11,835,000)	(44,086,000)
Physical contracts	(4,121,000)	(279,000)
Total derivatives		(44,365,000)
Fair value of firm commitments		(1,280,000)
Total liabilities	$ (15,956,000)	$ (45,645,000)

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ONEOK PARTNERS Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Business Combinations Policy [Policy Text Block]

ONEOK Partners accounted for this acquisition as a business combination, which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of the purchase price over the fair values of the identifiable assets acquired was recorded as goodwill.

Incentive Distribution Policy, Managing Member or General Partner, Description [Policy Text Block]

We receive distributions from ONEOK Partners on our common and Class B units and our 2 percent general partner interest, which includes our incentive distribution rights.  Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in the ONEOK Partners partnership agreement (Partnership Agreement), as amended.  Available cash generally will be distributed 98 percent to limited partners and 2 percent to the general partner.  The general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter.  In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among the general partner and limited partners to reflect the two-for-one unit split of ONEOK Partners’ common units.  Under the incentive distribution provisions, as set forth in ONEOK Partners’ partnership agreement, as amended, the general partner receives:

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

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

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

Consolidation, Subsidiaries or Other Investments, Consolidated Entities, Policy [Policy Text Block]

We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction.  If ONEOK Partners issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital.  As a result of ONEOK Partners’ issuance of common units, we recognized an increase to paid-in capital of approximately $87.3 million, net of taxes, in 2013 and a decrease to paid-in capital of approximately $51.1 million, net of taxes, in 2012.

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES - Part 4 (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Derivative Credit Exposure [Line Items]
Fair value of collateral	$ 1.1

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EARNINGS PER SHARE

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

EARNINGS PER SHARE

L. EARNINGS PER SHARE

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

	Year Ended December 31, 2013
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	266,533	206,044	$	1.29
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		3,651
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	266,533	209,695	$	1.27

	Year Ended December 31, 2012
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	346,340	206,140	$	1.68
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		4,570
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	346,340	210,710	$	1.64

	Year Ended December 31, 2011
	Income		Shares	Per Share Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Income from continuing operations attributable to ONEOK available for common stock	$	358,364	209,344	$	1.71
Diluted EPS from continuing operations
Effect of options and other dilutive securities	—		5,154
Income from continuing operations attributable to ONEOK available for common stock and common stock equivalents	$	358,364	214,498	$	1.67

There were no option shares excluded from the calculation of diluted EPS for 2013, 2012 and 2011.

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SEGMENTS Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Segment Accounting Policy [Text Block]

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

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EMPLOYEE BENEFIT PLANS

12 Months Ended

Dec. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

EMPLOYEE BENEFIT PLANS

N. EMPLOYEE BENEFIT PLANS

Retirement and Postretirement Benefit Plans

Retirement Plans - We have a defined benefit pension plan covering nonbargaining unit employees hired before January 1, 2005, and certain bargaining-unit employees hired before December 15, 2011.  Nonbargaining unit employees hired after December 31, 2004; employees represented by Local No. 304 of the IBEW hired on or after July 1, 2010; employees represented by the United Steelworkers hired on or after December 15, 2011; and employees who accepted a one-time opportunity to opt out of our pension plan, are covered by our Profit-Sharing Plan.  In addition, we have a supplemental executive retirement plan for the benefit of certain officers.  No new participants in our supplemental executive retirement plan have been approved since 2005, and effective January 2014 the plan formally was closed to new participants.  We fund our pension costs at a level needed to maintain or exceed the minimum funding levels required by the Employee Retirement Income Security Act of 1974, as amended, and the Pension Protection Act of 2006.

Postretirement Benefit Plans - We sponsor health and welfare plans that provide postretirement medical and life insurance benefits to certain employees who retire with at least five years of service.  The postretirement medical plan is contributory based on hire date, age and years of service, with retiree contributions adjusted periodically, and contains other cost-sharing features such as deductibles and coinsurance.

In December 2011, we announced to participants a change from a self-insured postretirement medical plan to a fully insured solution for plan participants who are medicare eligible.  This announcement resulted in a $44.6 million reduction in our accumulated postretirement benefit obligation that was recognized in other comprehensive income and will be amortized to net periodic benefit cost over the expected remaining years of service for plan participants.

Regulatory Treatment - The OCC, KCC and regulatory authorities in Texas have approved the recovery of pension costs and postretirement benefits costs through rates for Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively. The costs recovered through rates are based on current funding requirements and the net periodic benefit cost for pension and postretirement costs.  Differences, if any, between the expense and the amount recovered through rates are reflected in earnings, net of authorized deferrals.

Our regulated entities historically have recovered pension and postretirement benefit costs through rates.  We believe it is probable that regulators will continue to include the net periodic pension and postretirement benefit costs in our regulated entities’ cost of service.  Accordingly, we have recorded a regulatory asset for the minimum liability associated with our regulated entities’ pension and postretirement benefit obligations that otherwise would have been recorded in accumulated other comprehensive income.

Obligations and Funded Status - The following tables set forth our pension and postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated:

	Pension Benefits						Postretirement Benefits
	December 31,						December 31,
	2013			2012			2013			2012
Change in Benefit Obligation	(Thousands of dollars)
Benefit obligation, beginning of period	$	1,313,560		$	1,215,932		$	299,172		$	286,044
Service cost	22,968			21,301			4,612			4,960
Interest cost	54,449			59,237			11,713			13,893
Plan participants’ contributions	—			—			4,293			5,851
Actuarial loss (gain)	(110,552		)	105,732			(29,460		)	9,935
Benefits paid	(58,976		)	(88,642		)	(18,411		)	(21,380		)
Plan amendment	—			—			17,228			(131		)
Benefit obligation, end of period	1,221,449			1,313,560			289,147			299,172
Change in Plan Assets
Fair value of plan assets, beginning of period	995,264			902,235			148,162			124,163
Actual return on plan assets	176,889			90,026			27,483			14,273
Employer contributions	—			91,881			866			10,728
Benefits paid	(59,404		)	(88,878		)	(876		)	(1,002		)
Fair value of assets, end of period	1,112,749			995,264			175,635			148,162
Balance at December 31	$	(108,700	)	$	(318,296	)	$	(113,512	)	$	(151,010	)
Current liabilities	$	(5,457	)	$	(4,695	)	$	—		$	—
Noncurrent liabilities	(103,243		)	(313,601		)	(113,512		)	(151,010		)
Balance at December 31	$	(108,700	)	$	(318,296	)	$	(113,512	)	$	(151,010	)

The accumulated benefit obligation for our pension plans was $1,159.0 million and $1,240.3 million at December 31, 2013 and 2012, respectively.

There are no plan assets expected to be withdrawn and returned to us in 2014.

Components of Net Periodic Benefit Cost -The following tables set forth the components of net periodic benefit cost for our pension and postretirement benefit plans for the periods indicated:

	Pension Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	22,968		$	21,301		$	20,013
Interest cost	54,449			59,237			58,757
Expected return on assets	(81,272		)	(82,756		)	(75,500		)
Amortization of unrecognized prior service cost	920			969			1,018
Amortization of net loss	66,282			48,439			35,708
Settlements	1,338			1,401			—
Net periodic benefit cost	$	64,685		$	48,591		$	39,996

	Postretirement Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	4,612		$	4,960		$	4,987
Interest cost	11,713			13,893			15,632
Expected return on assets	(12,259		)	(10,687		)	(10,272		)
Amortization of unrecognized net asset at adoption	284			2,874			3,189
Amortization of unrecognized prior service cost	(6,442		)	(8,252		)	(2,518		)
Amortization of net loss	12,605			13,184			8,123
Net periodic benefit cost	$	10,513		$	15,972		$	19,141

Other Comprehensive Income (Loss) - The following tables set forth the amounts recognized in other comprehensive income (loss) related to our pension benefits and postretirement benefits for the periods indicated:

	Pension Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Regulatory asset gain (loss)	$	(110,437	)	$	67,472		$	114,625
Net gain (loss) arising during the period	201,251			(103,199		)	(182,987		)
Amortization of regulatory asset	(44,378		)	(32,527		)	(23,265		)
Amortization of prior service credit	920			969			1,018
Amortization of loss	67,620			49,839			35,708
Deferred income taxes	(44,473		)	6,748			21,236
Total recognized in other comprehensive income (loss)	$	70,503		$	(10,698	)	$	(33,665	)

	Postretirement Benefits
	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Regulatory asset gain (loss)	$	(7,674	)	$	4,376		$	7,389
Net gain (loss) arising during the period	44,685			(6,348		)	(40,765		)
Amortization of regulatory asset	(5,643		)	(6,557		)	(7,214		)
Amortization of transition obligation	284			2,874			3,189
Amortization of prior service cost	(6,442		)	(8,252		)	(2,518		)
Amortization of loss	12,605			13,184			8,123
Plan amendment	(17,228		)	131			44,562
Deferred income taxes	(7,964		)	229			(4,938		)
Total recognized in other comprehensive income (loss)	$	12,623		$	(363	)	$	7,828

The table below sets forth the amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense for the periods indicated:

	Pension Benefits						Postretirement Benefits
	December 31,						December 31,
	2013			2012			2013			2012
	(Thousands of dollars)
Transition obligation	$	—		$	—		$	—		$	(283	)
Prior service credit (cost)	(1,102		)	(2,022		)	14,631			38,301
Accumulated loss	(415,375		)	(684,245		)	(59,362		)	(116,652		)
Accumulated other comprehensive loss before regulatory assets	(416,477		)	(686,267		)	(44,731		)	(78,634		)
Regulatory asset for regulated entities	288,017			442,833			43,254			56,571
Accumulated other comprehensive loss after regulatory assets	(128,460		)	(243,434		)	(1,477		)	(22,063		)
Deferred income taxes	49,689			94,161			572			8,534
Accumulated other comprehensive loss, net of tax	$	(78,771	)	$	(149,273	)	$	(905	)	$	(13,529	)

The following table sets forth the amounts recognized in either accumulated comprehensive income (loss) or regulatory assets expected to be recognized as components of net periodic benefit expense in the next fiscal year. The table does not include amounts applicable to employees of ONE Gas, as those amounts are expected to be recognized by ONE Gas as a result of the separation of the natural gas distribution business.

	Pension Benefits		Postretirement Benefits
Amounts to be recognized in 2014	(Thousands of dollars)
Transition obligation	$	—	$	—
Prior service credit (cost)	$	193	$	(1,662	)
Net loss	$	15,021	$	833

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for pension and postretirement benefits for the periods indicated:

	Pension Benefits		Postretirement Benefits
	December 31,		December 31,
	2013	2012	2013	2012
Discount rate	5.25%	4.25%	5.00%	4.00%
Compensation increase rate	3.35% - 3.40%	3.45% - 3.50%	3.35% - 3.40%	3.45% - 3.50%

The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated:

	Years Ended December 31,
	2013	2012	2011
Discount rate - pension plans	4.25%	5.00%	5.50%
Discount rate - postretirement plans	4.00%	5.00%	5.50%
Expected long-term return on plan assets	8.25%	8.25%	8.25%
Compensation increase rate	3.45% - 3.50%	3.20% - 3.80%	3.30% - 3.90%

We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and economic growth models.

We determine our discount rates annually.  We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our pension and postretirement obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows.  Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds.  Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.

Health Care Cost Trend Rates -The following table sets forth the assumed health care cost-trend rates for the periods indicated:

	2013	2012
Health care cost-trend rate assumed for next year	4.0% - 8.25%	4.0% - 9.0%
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate)	4.0% - 5.0%	4.0% - 5.0%
Year that the rate reaches the ultimate trend rate	2022	2022

Assumed health care cost-trend rates have an impact on the amounts reported for our health care 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
	(Thousands of dollars)
Effect on total of service and interest cost	$	1,136	$	(1,022	)
Effect on postretirement benefit obligation	$	15,152	$	(14,350	)

Plan Assets -Our investment strategy is to invest plan assets in accordance with sound investment practices that emphasize long-term fundamentals.  The goal of this strategy is to maximize investment returns while managing risk in order to meet the plan’s current and projected financial obligations.  The plan’s investments include a diverse blend of various domestic and international equities, investments in various classes of debt securities, insurance contracts and venture capital.  The target allocation for the assets of our pension plan is as follows:

U.S. large-cap equities	37	%
Aggregate bonds	24	%
Developed foreign large-cap equities	10	%
Alternative investments	8	%
Mid-cap equities	6	%
Emerging markets equities	5	%
Small-cap equities	4	%
High-yield bonds	3	%
Developed foreign bonds	2	%
Emerging market bonds	1	%
Total	100	%

As part of our risk management for the plans, minimums and maximums have been set for each of the asset classes listed above. All investment managers for the plan are subject to certain restrictions on the securities they purchase and, with the exception of indexing purposes, are prohibited from owning our stock.

The following tables set forth our pension benefits and postretirement benefits plan assets by fair value category as of the measurement date:

	Pension Benefits
	December 31, 2013
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	680,590	$	60,336	$	—	$	740,926
Government obligations	—		111,288		—		111,288
Corporate obligations (b)	—		95,432		—		95,432
Cash and money market funds (c)	27,699		—		—		27,699
Insurance and group annuity contracts	—		—		63,458		63,458
Other investments (d)	—		—		73,946		73,946
Total assets	$	708,289	$	267,056	$	137,404	$	1,112,749

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Pension Benefits
	December 31, 2012
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	541,539	$	61,242	$	—	$	602,781
Government obligations	—		116,936		—		116,936
Corporate obligations (b)	—		104,078		—		104,078
Cash and money market funds (c)	33,296		—		—		33,296
Insurance and group annuity contracts	—		—		70,411		70,411
Other investments (d)	—		—		67,762		67,762
Total assets	$	574,835	$	282,256	$	138,173	$	995,264

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Postretirement Benefits
	December 31, 2013
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	37,796	$	90	$	—	$	37,886
Government obligations	—		166		—		166
Corporate obligations (b)	17,207		142		—		17,349
Cash and money market funds (c)	13,936		—		—		13,936
Insurance and group annuity contracts	—		106,189		—		106,189
Other investments (d)	—		—		109		109
Total assets	$	68,939	$	106,587	$	109	$	175,635

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category is primarily money market funds.

(d) - This category represents alternative investments.

	Postretirement Benefits
	December 31, 2012
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Investments:
Equity securities (a)	$	21,548	$	140	$	—	$	21,688
Government obligations	—		268		—		268
Corporate obligations (b)	17,522		238		—		17,760
Cash and money market funds (c)	18,311		—		—		18,311
Insurance and group annuity contracts	—		89,979		—		89,979
Other investments (d)	—		—		156		156
Total assets	$	57,381	$	90,625	$	156	$	148,162

(a) - This category represents securities of the respective market sector from diverse industries.

(b) - This category represents bonds from diverse industries.

(c) - This category represents money market funds.

(d) - This category represents alternative investments.

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

	Pension Benefits
	December 31, 2013
	Insurance and Group Annuity Contracts			Other Investments		Total
	(Thousands of dollars)
January 1, 2013	$	70,411		$	67,762	$	138,173
Net realized and unrealized gains (losses)	(6,953		)	6,184		(769		)
December 31, 2013	$	63,458		$	73,946	$	137,404

	Pension Benefits
	December 31, 2012
	Insurance and Group Annuity Contracts			Other Investments		Total
	(Thousands of dollars)
January 1, 2012	$	70,818		$	66,243	$	137,061
Net realized and unrealized gains (losses)	(407		)	1,519		1,112
December 31, 2012	$	70,411		$	67,762	$	138,173

Contributions -During 2013, we made no contributions to our defined benefit pension plans and $11.8 million in contributions to our postretirement benefit plans.  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 plans and postretirement plans in 2014.

Pension and Postretirement Benefit Payments - Benefit payments for our pension and postretirement benefit plans for the period ending December 31, 2013, were $59.0 million and $18.4 million, respectively.  The following table sets forth the pension benefits and postretirement benefits payments expected to be paid in 2014-2023:

	Pension Benefits		Postretirement Benefits
Benefits to be paid in:	(Thousands of dollars)
2014	$	63,856	$	16,251
2015	$	64,588	$	17,135
2016	$	66,477	$	18,142
2017	$	68,626	$	19,095
2018	$	70,873	$	19,875
2019 through 2023	$	386,366	$	106,346

The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2013, and include estimated future employee service.

Other Employee Benefit Plans

Thrift Plan - We have a Thrift Plan covering all full-time employees, and employee contributions are discretionary.  We match 100 percent of employee contributions up to 6 percent of each participant’s eligible compensation, subject to certain limits. Our contributions made to the plan were $17.0 million, $16.4 million and $15.9 million in 2013, 2012 and 2011, respectively.

Profit-Sharing Plan - We have a profit-sharing plan (Profit-Sharing Plan) for all nonbargaining unit employees hired after December 31, 2004, and employees covered by the IBEW collective bargaining agreement hired after June 30, 2010.  Nonbargaining unit employees who were employed prior to January 1, 2005, and employees covered by the IBEW collective bargaining agreement employed prior to July 1, 2010, were given a one-time opportunity to make an irrevocable election to participate in the Profit-Sharing Plan and not accrue any additional benefits under our defined benefit pension plan after December 31, 2004, and June 30, 2010, respectively.  Employees covered by the United Steelworker collective bargaining agreement employed prior to December 16, 2011, were given a one-time opportunity to make an irrevocable election to participate in the Profit-Sharing Plan.  We plan to make a contribution to the Profit-Sharing Plan each quarter equal to 1 percent of each participant’s eligible compensation during the quarter.  Additional discretionary employer contributions may be made at the end of each year.  Employee contributions are not allowed under the plan.  Our contributions made to the plan were $5.1 million, $6.6 million and $6.7 million in 2013, 2012 and 2011, respectively.

Employee Deferred Compensation Plan -The ONEOK, Inc. 2005 Nonqualified Deferred Compensation Plan provides select employees, as approved by our Board of Directors, with the option to defer portions of their compensation and provides nonqualified deferred compensation benefits that are not available due to limitations on employer and employee contributions to qualified defined contribution plans under the federal tax laws.  Our contributions made to the plan were not material in 2013, 2012 and 2011.

ONE Gas Employee Benefit Plans

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.

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CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE (Details) (USD $)	12 Months Ended				12 Months Ended			12 Months Ended
	Dec. 31, 2014 ONEOK Credit Agreement [Member]	Jan. 31, 2014 ONEOK Credit Agreement [Member]	Dec. 31, 2013 ONEOK Credit Agreement [Member]	Dec. 31, 2012 ONEOK Credit Agreement [Member]	Dec. 31, 2014 Partnership 2014 Credit Agreement [Member]	Jan. 31, 2014 Partnership 2014 Credit Agreement [Member]	Dec. 31, 2013 Partnership 2014 Credit Agreement [Member]	Dec. 31, 2013 Partnership Credit Agreement [Member]	Dec. 31, 2014 ONE Gas credit agreement [Member]	Jan. 31, 2014 ONE Gas credit agreement [Member]
Line of Credit Facility [Line Items]
Interest Rate Description	Borrowings, if any, will accrue at LIBOR plus 125 basis points				Borrowings, if any, will accrue at LIBOR plus 117.5 basis points.			Borrowings, if any, will accrue at LIBOR plus 130 basis points.	Borrowings, if any, will accrue at LIBOR plus 79.5 basis points
Line of credit facility annual fee description	Annual facility fee is 25 basis points				Annual facility fee is 20 basis points based on our current credit rating.			Annual facility fee is 20 basis points based on our current credit rating.	Annual facility fee is 8 basis points
Maximum debt-to-capital ratio (in hundredths)			67.50%							70.00%
Current debt-to-capital ratio			48.30%
Commercial paper			$ 564,500,000					$ 0
Weighted-average interest rate on short-term debt outstanding (in hundredths)			0.39%	0.46%
Letters of credit issued			2,200,000					0
Indebtedness To Adjusted Ebitda Maximum		4.0					5.0
Indebtedness To Adjusted Ebitda From Acquisitions Maximum							5.5
Indebtedness To Adjusted Ebitda Current							4.0
Acquisition price threshold for increase in permitted debt to EBITDA covenant ratio							25,000,000
Partnership Credit Agreement sublimit for issuance of standby letters of credit		50,000,000				100,000,000				50,000,000
Line of credit facility swingline subfacility		50,000,000				150,000,000
Maximum borrowing capacity		300,000,000	1,200,000,000			1,700,000,000		1,200,000,000		700,000,000
Option to increase borrowing capacity		500,000,000				2,400,000,000				1,200,000,000
Short-term Bank Loans and Notes Payable								$ 0

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CONSOLIDATED BALANCE SHEETS Parenthetical (USD $)	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Common stock, shares, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares, authorized (in shares)	600,000,000	600,000,000
Common stock, shares, issued (in shares)	245,811,180	245,811,180
Common stock, shares, outstanding (in shares)	206,618,877	204,935,043
Treasury stock, shares (in shares)	39,192,203	40,876,137

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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest Costs, Capitalized During Period	$ 57,775	$ 41,776	$ 23,960

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GOODWILL AND INTANGIBLE ASSETS

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL AND INTANGIBLE ASSETS

G. GOODWILL AND INTANGIBLE ASSETS

Goodwill - The following table sets forth our goodwill by segment for the periods indicated:

	ONEOK Partners		Natural Gas Distribution		Energy Services		Total
	(Thousands of dollars)
December 31, 2012	$	433,535	$	157,953	$	—	$	591,488
Acquisitions	92,000		—		—		92,000
December 31, 2013	$	525,535	$	157,953	$	—	$	683,488

As a result of our 2012 interim impairment assessment of our Energy Services segment’s goodwill, 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. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services. There were no impairment charges resulting from our 2013 or 2011 annual impairment tests.

Intangible Assets - The following table sets forth the gross carrying amount and accumulated amortization of intangible assets for the periods indicated:

	December 31,			December 31,
	2013			2012
	(Thousands of dollars)
Gross intangible assets	$	565,215		$	462,214
Accumulated amortization	(66,188		)	(57,496		)
Net intangible assets	$	499,027		$	404,718

At December 31, 2013 and 2012, our ONEOK Partners segment has $343.5 million and $249.2 million, respectively, of intangible assets related primarily to contracts acquired through acquisition, which are being amortized over a period of 20 to 40 years.  The remaining intangible asset balance has an indefinite life.  Amortization expense for intangible assets for 2013, 2012 and 2011 was $8.7 million, $7.7 million and $7.7 million, respectively, and the aggregate amortization expense for each of the next five years is estimated to be approximately $11.3 million.

Acquisition - On September 30, 2013, ONEOK Partners completed the acquisition of a business, the Sage Creek acquisition. Included in this acquisition were supply contracts with acreage dedications and customer relationships that were included as intangible assets of $103 million in the purchase price allocation. The $92 million excess of purchase price over the fair value of the identifiable assets acquired was recorded as goodwill. For additional information related to the acquisition, see Note Q of the Notes to Consolidated Financial Statements in this Annual Report.

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Document And Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Feb. 19, 2014	Jun. 30, 2013
Document Information [Line Items]
Entity Registrant Name	ONEOK INC /NEW/
Entity Central Index Key	0001039684
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 8.1
Entity Common Stock, Shares Outstanding		207,814,086
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013

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CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE (Notes)

12 Months Ended

Dec. 31, 2013

CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE [Abstract]

Short-term Debt [Text Block]

H. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK Credit Agreement - At December 31, 2013, the ONEOK Credit Agreement contained certain financial, operational and legal covenants.  Among other things, these covenants included maintaining ONEOK’s stand-alone debt-to-capital ratio of no more than 67.5 percent at the end of any calendar quarter, limitations on the ratio of indebtedness secured by liens and indebtedness of subsidiaries to consolidated net tangible assets, a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners, and a limit on new investments in master limited partnerships. The ONEOK Credit Agreement also contained customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that limits ONEOK’s ability to restrict its subsidiaries’ ability to pay dividends.  The debt covenant calculations in the ONEOK Credit Agreement excluded the debt of ONEOK Partners.  In the event of a breach of certain covenants by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become due and payable immediately. At December 31, 2013, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 48.3 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

At December 31, 2013, ONEOK had $564.5 million of commercial paper outstanding and $2.2 million in letters of credit issued. ONEOK is terminating its commercial paper program in conjunction with the separation of its natural gas distribution business.

The weighted-average interest rate on ONEOK’s short-term debt outstanding was 0.39 percent and 0.46 percent at December 31, 2013 and 2012, respectively.

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. This 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.

This amendment 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, as amended, ONEOK may request an increase 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 rating, borrowings, if any, will accrue at LIBOR plus 125 basis points, and the annual facility fee is 25 basis points.

ONEOK Partners Credit Agreement - The ONEOK Partners Credit Agreement is available for general partnership purposes, including repayment of ONEOK Partners’ commercial paper notes, if necessary. Amounts outstanding under ONEOK Partners’ commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement. At December 31, 2013, ONEOK Partners had no commercial paper outstanding, no letters of credit issued and no borrowings under the ONEOK Partners Credit Agreement.

In December 2013, ONEOK Partners amended and restated the ONEOK Partners Credit Agreement effective on January 31, 2014, to increase the size of the facility to $1.7 billion from $1.2 billion. 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 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 ONEOK Partners Credit Agreement are nonrecourse to ONEOK.

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 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 on September 30, 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 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.

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

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 include maintaining ONE Gas’s 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.

Upon completion of the separation on January 31, 2014, ONEOK’s obligations related to the ONE Gas Credit Agreement terminated.

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SEGMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Segment Reporting, Disclosure of Major Customers									we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.	we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.	we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.
Ownership interest									41.20%	43.40%	42.80%
Sales to unaffiliated customers									$ 14,602,717	$ 12,632,559	$ 14,805,794
Intersegment revenues									0	0	0
Total revenues	4,140,111	3,571,925	3,349,236	3,541,445	3,659,924	3,028,775	2,529,260	3,414,600	14,602,717	12,632,559	14,805,794
Net margin	651,654	561,188	453,389	623,452	604,320	553,972	548,962	643,587	2,289,683	2,350,841	2,380,359
Operating costs									990,453	908,978	908,323
Depreciation and amortization									384,377	335,844	312,160
Goodwill, Impairment Loss									0	10,255	0
Gain (loss) on sale of assets									11,881	6,736	(963)
Operating income									926,734	1,102,500	1,158,913
Equity earnings from investments									110,517	123,024	127,246
Investments in unconsolidated affiliates	1,229,838				1,221,405				1,229,838	1,221,405	1,223,398
Total assets	17,707,558				15,855,275				17,707,558	15,855,275	13,696,635
Noncontrolling interests in consolidated subsidiaries	2,507,329				2,102,841				2,507,329	2,102,841	1,561,159
Capital expenditures									2,256,585	1,866,153	1,336,067
Natural Gas Distribution [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers									1,689,945	1,379,366	1,609,628
Intersegment revenues									7	(2,717)	11,706
Total revenues									1,689,952	1,376,649	1,621,334
Net margin									813,008	756,389	751,835
Operating costs									444,866	410,572	422,073
Depreciation and amortization									144,758	130,150	132,212
Goodwill, Impairment Loss										0
Gain (loss) on sale of assets									0	0	0
Operating income									223,384	215,667	197,550
Equity earnings from investments									0	0	0
Investments in unconsolidated affiliates	0				0				0	0	0
Total assets	3,857,722				3,535,489				3,857,722	3,535,489	3,392,475
Noncontrolling interests in consolidated subsidiaries	0				0				0	0	0
Capital expenditures									292,080	280,294	242,590
Energy Services [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers									1,381,636	1,421,171	2,274,799
Intersegment revenues									195,926	105,402	502,418
Total revenues									1,577,562	1,526,573	2,777,217
Net margin									(172,985)	(49,344)	48,740
Operating costs									13,133	17,950	24,527
Depreciation and amortization									277	361	445
Goodwill, Impairment Loss										10,255
Gain (loss) on sale of assets									0	0	0
Operating income									(186,395)	(77,910)	23,768
Equity earnings from investments									0	0	0
Investments in unconsolidated affiliates	0				0				0	0	0
Total assets	347,470				493,006				347,470	493,006	562,728
Noncontrolling interests in consolidated subsidiaries	0				0				0	0	0
Capital expenditures									0	0	41
Corporate Elimination [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers									2,606	1,970	2,363
Intersegment revenues									(536,676)	(454,784)	(917,727)
Total revenues									(534,070)	(452,814)	(915,364)
Net margin									2,600	1,964	2,404
Operating costs									10,941	(2,084)	2,359
Depreciation and amortization									2,599	2,232	1,954
Goodwill, Impairment Loss										0
Gain (loss) on sale of assets									0	0	0
Operating income									(10,940)	1,816	(1,909)
Equity earnings from investments									0	0	0
Investments in unconsolidated affiliates	0				0				0	0	0
Total assets	639,758				867,550				639,758	867,550	794,756
Noncontrolling interests in consolidated subsidiaries	2,502,793				2,098,074				2,502,793	2,098,074	1,556,047
Capital expenditures									25,179	25,346	30,053
Oneok Partners [Member]
Segment Reporting Information [Line Items]
Sales to unaffiliated customers									11,528,530	9,830,052	10,919,004
Intersegment revenues									340,743	352,099	403,603
Total revenues									11,869,273	10,182,151	11,322,607
Net margin									1,647,060	1,641,832	1,577,380
Operating costs									521,513	482,540	459,364
Depreciation and amortization									236,743	203,101	177,549
Goodwill, Impairment Loss										0
Gain (loss) on sale of assets									11,881	6,736	(963)
Operating income									900,685	962,927	939,504
Equity earnings from investments									110,517	123,024	127,246
Investments in unconsolidated affiliates	1,229,838				1,221,405				1,229,838	1,221,405	1,223,398
Total assets	12,862,608				10,959,230				12,862,608	10,959,230	8,946,676
Noncontrolling interests in consolidated subsidiaries	4,536				4,767				4,536	4,767	5,112
Capital expenditures									1,939,326	1,560,513	1,063,383
Oneok Partners [Member] | Regulated Segment [Member]
Segment Reporting Information [Line Items]
Total revenues									781,700	722,100	658,500
Net margin									545,000	618,000	469,000
Operating income									$ 281,000	$ 375,600	$ 232,800

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]
Net income	$ 576,961	$ 743,530	$ 759,744
Other comprehensive income (loss), net of tax
Unrealized gains (losses) on energy marketing and risk management assets/liabilities, net of tax of $(5,574), $(10,061) and $(8,670), respectively	25,609	22,826	(19,828)
Realized (gains) losses in net income, net of tax of $(1,905), $10,327 and $53,714, respectively	7,926	(49,499)	(84,025)
Unrealized holding gains (losses) on available-for-sale securities, net of tax of $112, $(30) and $242, respectively	(177)	47	(384)
Change in pension and postretirement benefit plan liability, net of tax of $(52,436), $6,977 and $16,298, respectively	83,126	(11,061)	(25,837)
Other, net of tax of $0, $0 and $50, respectively	0	0	(79)
Total other comprehensive income (loss), net of tax	116,484	(37,687)	(130,153)
Comprehensive income	693,445	705,843	629,591
Less: Comprehensive income attributable to noncontrolling interests	332,101	355,901	366,316
Comprehensive income attributable to ONEOK	$ 361,344	$ 349,942	$ 263,275

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EXIT ACTIVITIES (Notes)

12 Months Ended

Dec. 31, 2013

EXIT ACTIVITIES [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

B. EXIT ACTIVITIES

Wind down of Energy Services Business - In June 2013, we announced we would exit the operations of our Energy Services segment through an accelerated wind down process. Our Energy Services segment has faced challenging industry conditions that show no signs of improving. Increased natural gas supply and infrastructure, coupled with lower natural gas price volatility and narrowed seasonal and location natural gas price differentials, has resulted in limited opportunities to generate revenues to cover our fixed costs on our contracted storage and transportation capacity. We executed agreements in 2013 to release a significant portion of our nonaffiliated natural gas transportation and storage contracts to third parties between July 1 and December 31, 2013, at current market rates that resulted in noncash charges of $138.6 million. In addition, pursuant to a request for proposal, our Energy Services segment assigned contracts for 18.0 Bcf of affiliated storage capacity to our Natural Gas Distribution segment in June 2013. Our Energy Services segment will continue to serve its existing contracted premium-services customers during the wind down, and we expect the Energy Services segment to be classified as discontinued operations, effective April 1, 2014, when substantially all operations of the segment have ceased.

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

	Year Ended
	December 31, 2013
	(Millions of dollars)
Beginning balance	$	—
Noncash charges	138.6
Settlements	(17.7		)
Accretion	1.1
Ending balance	$	122.0

We recorded these noncash charges in cost of sales and fuel in our Consolidated Statements of Income. We expect to record an additional noncash charge of approximately $1.7 million before taxes in the first quarter 2014, to reflect the assignment of our remaining natural gas storage contract that extends beyond March 31, 2014. We do not expect the total charge attributable to any severance benefits will be material. We expect future cash payments associated with released transportation and storage capacity from the wind down of our Energy Services segment to total approximately $80 million on an after-tax basis, which consist of approximately $33 million paid in 2014, $24 million in 2015, $13 million in 2016, and $10 million during the period from 2017 through 2023.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations - We are a diversified energy company and successor to the company founded in 1906 known as Oklahoma Natural Gas Company.  We are a corporation incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.”  We are the sole general partner and own 41.2 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest publicly traded master limited partnerships.

At December 31, 2013, we have divided our operations into three reportable business segments as follows:

• ONEOK Partners;

• Natural Gas Distribution; and

• Energy Services.

On January 31, 2014, we completed the separation of our natural gas distribution business into a standalone publicly traded company, ONE Gas. In addition, we expect to complete an accelerated wind down of our Energy Services business on March 31, 2014. ONEOK and its subsidiaries will continue to be the sole general partner and own 41.2 percent of ONEOK Partners as of December 31, 2013. Following the separation of the natural gas distribution business and the wind down of our energy services business, our cash flows will be derived from the cash distributions we receive from ONEOK Partners associated with our limited and general partner interests, including incentive distribution rights. See Note U for additional discussion of the separation of the natural gas distribution business. See Note B for additional discussion of the exit activities associated with the wind down of the energy services business.

ONEOK Partners is a publicly traded master limited partnership involved in the gathering, processing, storage and transportation of natural gas in the United States.  In addition, ONEOK Partners owns one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent and Rocky Mountain regions with key market centers.  To aid in understanding the important business and financial characteristics of our ONEOK Partners segment, the following describes its business with reference to its underlying activities.

ONEOK Partners gathers and/or processes natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming, which includes the NGL-rich Frontier, Turner, Sussex and Niobrara Shale formations.  Coal-bed methane, or dry natural gas, in the Powder River Basin does not require processing or NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee. ONEOK Partners also gathers and processes natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale, Woodford Shale, Granite Wash area and the Mississippian Lime formation of Oklahoma and Kansas and the Hugoton and Central Kansas Uplift Basins of Kansas.  The natural gas ONEOK Partners gathers from its Sage Creek plant contains NGL-rich natural gas from the Niobrara Shale area of the Powder River Basin.

ONEOK Partners’ natural gas liquids business consists of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas, Texas and the Rocky Mountain region where it provides nondiscretionary services to producers for NGLs.  Its natural gas liquids business owns or has an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, Wyoming, Colorado, North Dakota and Montana, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois.  It also owns FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect its Mid-Continent assets with Midwest markets, including Chicago, Illinois.  ONEOK Partners’ natural gas liquids business also owns and operates truck- and rail-loading and -unloading facilities that interconnect with its NGL fractionation and pipeline assets.

ONEOK Partners’ natural gas pipeline business operates interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.  ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico.  ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states, including the Cana-Woodford, Woodford Shale, Granite Wash and Mississippian Lime areas.  ONEOK Partners owns underground natural gas storage facilities in Oklahoma and Texas, which are connected to its intrastate natural gas pipeline assets, as well as underground natural gas storage facilities in Kansas.

Our former Natural Gas Distribution segment provides natural gas distribution services to more than 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. The natural gas utilities serve residential, commercial, industrial and transportation customers in all three states.  In addition, the natural gas distribution companies serve wholesale and public authority customers.

Our Energy Services segment is a provider of nonuniform natural gas supply and risk-management services for natural gas and electric utilities and industrial customers with natural gas needs.  We use a network of leased storage and transportation capacity to supply natural gas to our customers.  This network connects major supply and demand centers and, coupled with our industry knowledge and market intelligence, allows us to provide our customers with customized services in a more efficient and reliable manner than they can achieve independently. Our customers are primarily LDCs, electric utilities and industrial end-users.  Our customers’ natural gas needs vary with seasonal changes in weather and are therefore somewhat unpredictable.

Consolidation - Our consolidated financial statements include the accounts of ONEOK and our subsidiaries over which we have control or are the primary beneficiary.  We have recorded noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheets to recognize the portion of ONEOK Partners that we do not own.  We reflected our ownership interest in ONEOK Partners’ accumulated other comprehensive income (loss) in our consolidated accumulated other comprehensive income (loss).  The remaining portion is reflected as an adjustment to noncontrolling interests in consolidated subsidiaries.  All significant intercompany balances and transactions have been eliminated in consolidation. We have recast prior period amounts in the Consolidated Statements of Cash Flows to revise the classification of the excess tax benefit of share-based compensation to financing from operating activities.

Investments in unconsolidated affiliates are accounted for using the equity method if we have the ability to exercise significant influence over operating and financial policies of our investee. Under this method, an investment is carried at its acquisition cost and adjusted each period for contributions made, distributions received and our share of the investee’s comprehensive income. For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Impairment of equity investments is recorded when the impairments are other than temporary. These amounts are recorded as investments in unconsolidated affiliates on our accompanying Consolidated Balance Sheets. Distributions paid to us from our unconsolidated affiliates are classified as operating activities on our Consolidated Statements of Cash Flows until the cumulative distributions exceed our proportionate share of income from the unconsolidated affiliate since the date of our initial investment.  The amount of cumulative distributions paid to us that exceeds our cumulative proportionate share of income in each period represents a return of investment and is classified as an investing activity on our Consolidated Statements of Cash Flows. See Note P for disclosures of our unconsolidated affiliates.

Use of Estimates - 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 amount 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.  Items that may be estimated include, but are not limited to, the economic useful life of assets, fair value of assets and liabilities, obligations under employee benefit plans, provisions for uncollectible accounts receivable, unbilled revenues for natural gas delivered but for which meters have not been read, gas purchased expense for natural gas purchased but for which no invoice has been received, provision for income taxes, including any deferred tax valuation allowances, the results of litigation and various other recorded or disclosed amounts.

We evaluate these estimates on an ongoing basis using historical experience, consultation with experts and other methods we consider reasonable based on the particular circumstances.  Nevertheless, actual results may differ significantly from the estimates. Any effects on our financial position or results of operations from revisions to these estimates are recorded in the period when the facts that give rise to the revision become known.

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 over a reasonable period of time under current market conditions.  We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using specific and sector bond yields and also monitor the credit default swap markets.  Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ from our estimates, and the differences could be material.

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.

We recognize transfers into and out of Level 3 as of the end of each reporting period.  Transfers into Level 3 represent existing assets or liabilities that were categorized previously at a higher level for which the unobservable inputs became a more significant portion of the fair value estimates. Transfers out of Level 3 represent existing assets and liabilities that were classified previously as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

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. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.  See Note D for additional disclosures of our fair value measurements.

Cash and Cash Equivalents - Cash equivalents consist of highly liquid investments, which are readily convertible into cash and have original maturities of three months or less.

Revenue Recognition - Our operating segments recognize revenue when services are rendered or product is delivered. ONEOK Partners’ natural gas gathering and processing operations record revenue when gas is processed in or transported through its facilities.  ONEOK Partners’ natural gas liquids operations record revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the period services are provided.  Revenue for ONEOK Partners’ natural gas pipelines and a portion of its natural gas liquids operations is recognized based upon contracted capacity and contracted volumes transported and stored under service agreements in the period services are provided.

Our former Natural Gas Distribution segment’s major industrial and commercial natural gas distribution customers are invoiced at the end of each month.  All natural gas distribution residential customers and some commercial customers are invoiced on a cyclical basis throughout the month, and the utilities accrue unbilled revenues at the end of each month.

Our revenues from sales to our Energy Services segment’s wholesale customers are accrued in the month of physical delivery based on contracted sales price and estimated volumes.  Demand payments received for requirements contracts are recognized in the period in which the service is provided.  Our fixed-price physical sales are accounted for as derivatives and are recorded at fair value.  See discussion below in “Derivative and Risk Management Activities” for additional information.

Accounts Receivable - Accounts receivable represent valid claims against nonaffiliated customers for products sold or services rendered, net of allowances for doubtful accounts.  We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate.  Outstanding customer receivables are reviewed regularly for possible nonpayment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date.  At December 31, 2013 and 2012, our allowance for doubtful accounts was not material.

Inventories - The values of current natural gas and NGLs in storage are determined using the lower of weighted-average cost or market method.  Noncurrent natural gas and NGLs are classified as property and valued at cost.  Materials and supplies are valued at average cost.

Commodity Imbalances -Commodity imbalances represent amounts payable or receivable for NGL exchange contracts and natural gas pipeline imbalances and are valued at fair value.  Under the majority of our NGL exchange agreements, we physically receive volumes of unfractionated NGLs, including the risk of loss and legal title to such volumes, from the exchange counterparty.  In turn, we deliver NGL products back to the customer and charge them gathering and fractionation fees. To the extent that the volumes we receive under such agreements differ from those we deliver, we record a net exchange receivable or payable position with the counterparties.  These net exchange receivables and payables are settled with movements of NGL products rather than with cash.  Natural gas pipeline imbalances are settled in cash or in-kind, subject to the terms of the pipelines’ tariffs or by agreement.

Derivatives 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.  The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it.

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

The table below summarizes the various ways in which we account for our derivative instruments and the impact on our consolidated financial statements:

		Recognition and Measurement
Accounting Treatment		Balance Sheet		Income Statement
Normal purchases and normal sales	-	Fair value not recorded	-	Change in fair value not recognized in earnings
Mark-to-market	-	Recorded at fair value	-	Change in fair value recognized in earnings
Cash flow hedge	-	Recorded at fair value	-	Ineffective portion of the gain or loss on the derivative instrument is recognized in earnings
	-	Effective portion of the gain or loss on the derivative instrument is reported initially as a component of accumulated other comprehensive income (loss)	-	Effective portion of the gain or loss on the derivative instrument is reclassified out of accumulated other comprehensive income (loss) into earnings when the forecasted transaction affects earnings
Fair value hedge	-	Recorded at fair value	-	The gain or loss on the derivative instrument is recognized in earnings
	-	Change in fair value of the hedged item is recorded as an adjustment to book value	-	Change in fair value of the hedged item is recognized in earnings

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

We formally document all relationships between hedging instruments and hedged items, as well as risk-management objectives, strategies for undertaking various hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. We specifically identify the asset, liability, firm commitment or forecasted transaction that has been designated as the hedged item.  We assess the effectiveness of hedging relationships quarterly by performing an effectiveness analysis on our cash flow and fair value hedging relationships to determine whether the hedge relationships are highly effective on a retrospective and prospective basis.  We also document our normal purchases and normal sales transactions that we expect to result in physical delivery and that we elect to exempt from derivative accounting treatment.

The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on the relevant facts and circumstances of our different types of activities rather than based solely on the terms of the individual contracts.  All financially settled derivative instruments, as well as derivative instruments considered held for trading purposes that result in physical delivery, are reported on a net basis in revenues in our Consolidated Statements of Income.  The realized revenues and purchase costs of derivative instruments that are not considered held for trading purposes and nonderivative contracts are reported on a gross basis.  Derivatives that qualify as normal purchases or normal sales that are expected to result in physical delivery are also reported on a gross basis.

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

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

See Notes D and E for more discussion of our fair value measurements and risk management and hedging activities using derivatives.

Property, Plant and Equipment - Our properties are stated at cost, including AFUDC.  Generally, the cost of regulated property retired or sold, plus removal costs, less salvage, is charged to accumulated depreciation.  Gains and losses from sales or retirement of nonregulated properties or an entire operating unit or system of our regulated properties are recognized in income. Maintenance and repairs are charged directly to expense.

The interest portion of AFUDC represents the cost of borrowed funds used to finance construction activities.  We capitalize interest costs during the construction or upgrade of qualifying assets. Capitalized interest is recorded as a reduction to interest expense. The equity portion of AFUDC represents the capitalization of the estimated average cost of equity used during the construction of major projects and is recorded in the cost of our regulated properties and as a credit to the allowance for equity funds used during construction.

Our properties are depreciated using the straight-line method over their estimated useful lives.  Generally, we apply composite depreciation rates to functional groups of property having similar economic circumstances.  We periodically conduct depreciation studies to assess the economic lives of our assets.  For our regulated assets, these depreciation studies are completed as a part of our rate proceedings or tariff filings, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are billed.  For our nonregulated assets, if it is determined that the estimated economic life changes, the changes are made prospectively.  Changes in the estimated economic lives of our property, plant and equipment could have a material effect on our financial position or results of operations.

Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been placed in service and therefore are not being depreciated.  Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use.

See Note F for disclosures of our property, plant and equipment.

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 Energy Services segment’s 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. For the remaining segments, Natural Gas Distribution and ONEOK Partners, there were no impairment indicators as the cash flows generated from each of these segments are derived from predominately fee-based, nondiscretionary services. There were also no impairment charges resulting from our 2012 and 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 and 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 in the Powder River Basin.  The reduced coal-bed methane development activities and natural production declines in the dry natural gas formation of the Powder River Basin resulted in lower volumes available to be gathered.  While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and producers’ alternative prospects.  Bighorn Gas Gathering, in which ONEOK Partners owns a 49 percent equity interest, has operations in the coal-bed methane areas of the Powder River Basin. Due to declines in volumes gathered on Bighorn Gas Gathering’s system, 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 estimate reasonably 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 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.

A continued decline in coal-bed methane natural gas volumes in the coal-bed methane production 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. 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 F, G and P for our long-lived assets, goodwill and intangible assets and investment in unconsolidated affiliates disclosures.

Regulation - Our former natural gas distribution operations and ONEOK Partners’ intrastate natural gas transmission pipelines are subject to the rate regulation and accounting requirements of the OCC, KCC, RRC and various municipalities in Texas. ONEOK Partners’ interstate natural gas and natural gas liquids pipelines are subject to regulation by the FERC.  In Kansas and Texas, natural gas storage may be regulated by the state and the FERC for certain types of services.  Oklahoma Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK Partners segment follow the accounting and reporting guidance for regulated operations.  During the rate-making process, regulatory authorities set the framework for what we can charge customers for our services and establish the manner that our costs are accounted for, including allowing us to defer recognition of certain costs and permitting recovery of the amounts through rates over time, as opposed to expensing such costs as incurred. Examples include costs for fuel and fuel losses, acquisition costs and contributions in aid of construction. This allows us to stabilize rates over time rather than passing such costs on to the customer for immediate recovery.  Actions by regulatory authorities could have an effect on the amount recovered from rate payers.  Any difference in the amount recoverable and the amount deferred is recorded as income or expense at the time of the regulatory action.  A write-off of regulatory assets and costs not recovered may be required if all or a portion of the regulated operations have rates that are no longer:

• established by independent, third-party regulators;

• designed to recover the specific entity’s costs of providing regulated services; and

• set at levels that will recover our costs when considering the demand and competition for our services.

In December 2013, the KCC approved a settlement agreement for the separation of our Kansas Gas Service natural gas distribution business to ONE Gas from ONEOK. The terms of the settlement agreement provided that amounts previously recorded as a regulatory asset related to ONEOK’s acquisition of Kansas Gas Service in 1997 would no longer be recovered in rates. As a result, the carrying amount of the regulatory asset was written off, and we recorded a noncash charge to income of approximately $10.2 million in the fourth quarter 2013.

At December 31, 2013 and 2012, we recorded regulatory assets of approximately $383.6 million and $585.0 million, respectively, which are being recovered or are expected to be recovered as a result of various approved rate proceedings.  Of these amounts, the total regulatory assets related to our natural gas distribution business were $376.8 million and $577.1 million at December 31, 2013 and 2012, respectively. The natural gas distribution balances included approximately $341.1 million and $499.4 million related to our pension and postretirement benefit plans at December 31, 2013 and 2012, respectively, which are discussed in Note N.  Regulatory assets are being recovered as a result of approved rate proceedings over varying time periods up to 25 years.  These assets are reflected in other assets on our Consolidated Balance Sheets.

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 N for more discussion of pension and postretirement employee benefits.

Income Taxes - Deferred income taxes are recorded for the difference between the financial statement and income tax basis of assets and liabilities and carryforward items, based on income tax laws and rates existing at the time the temporary differences are expected to reverse.  The effect on deferred taxes of a change in tax rates is deferred and amortized for operations regulated by the OCC, KCC, RRC and various municipalities in Texas, if, as a result of an action by a regulator, it is probable that the effect of the change in tax rates will be recovered from or returned to customers through future rates.  For all other operations, the effect is recognized in income in the period that includes the enactment date.  We continue to amortize previously deferred investment tax credits for ratemaking purposes over the period prescribed by the OCC, KCC, RRC and various municipalities in Texas.

We utilize a more-likely-than-not recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position that is taken or expected to be taken in a tax return.  We reflect penalties and interest as part of income tax expense as they become applicable for tax provisions that do not meet the more-likely-than-not recognition threshold and measurement attribute.  During 2013, 2012 and 2011, our tax positions did not require an establishment of a material reserve.

We file numerous consolidated and separate income tax returns with federal tax authorities of the United States and Canada, along with the tax authorities of several states.  There are no United States federal audits or statute waivers at this time. See Note O for additional discussion of income taxes.

Asset Retirement Obligations - Asset retirement obligations represent legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.  Certain long-lived assets that comprise our natural gas distribution systems and ONEOK Partners’ natural gas gathering and processing, natural gas liquids and pipeline facilities are subject to agreements or regulations that give rise to an asset retirement obligation for removal or other disposition costs associated with retiring the assets in place upon the discontinued use of the assets. We recognize the fair value of a liability for an asset-retirement obligation in the period when it is incurred if a reasonable estimate of the fair value can be made.  We are not able to estimate reasonably the fair value of the asset retirement obligations for portions of our and ONEOK Partners’ assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. We expect our former natural gas distribution assets and ONEOK Partners’ pipeline assets, for which we are unable to estimate reasonably the fair value of the asset retirement obligation, will continue to operate as long as natural gas supply and demand for natural gas and natural gas liquids exists. Based on the widespread use of natural gas for heating and cooking activities by residential users and electric-power generation by commercial users, as well as use of natural gas liquids by the petrochemical industry, we and ONEOK Partners expect supply and demand to exist for the foreseeable future.

For our assets where we are able to make an estimate, the fair value of the liability is added to the carrying amount of the associated asset, and this additional carrying amount is depreciated over the life of the asset.  The liability is accreted at the end of each period through charges to operating expense.  If the obligation is settled for an amount other than the carrying amount of the liability, we will recognize a gain or loss on settlement.  The depreciation and accretion expense are immaterial to our consolidated financial statements.

In accordance with long-standing regulatory treatment, we collect, through rates, the estimated costs of removal on certain regulated properties through depreciation expense, with a corresponding credit to accumulated depreciation and amortization. These removal costs collected through our rates include costs attributable to legal and nonlegal removal obligations; however, the amounts collected that are in excess of these nonlegal asset-removal costs incurred are accounted for as a regulatory liability for financial reporting purposes. Historically, with the exception of the regulatory authority in Kansas, the regulatory authorities that have jurisdiction over our regulated operations have not required us to quantify or disclose this amount; rather, these costs are addressed prospectively in depreciation rates and are set in each general rate order. We have made an estimate of our regulatory liability using current rates since the last general rate order in each of our jurisdictions; however, for financial reporting purposes, significant uncertainty exists regarding the future disposition of this regulatory liability, pending, among other issues, clarification of regulatory intent.  We continue to monitor the regulatory requirements, and the liability may be adjusted as more information is obtained.  We record the estimated asset removal obligation in noncurrent liabilities in other deferred credits on our Consolidated Balance Sheets.  To the extent this estimated liability is adjusted, such amounts will be reclassified between accumulated depreciation and amortization and other deferred credits and therefore will not have an impact on earnings.

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 estimated reasonably.  We expense legal fees as incurred and base our legal liability estimates on currently available facts and our estimates 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.  Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings.  See Note R for additional discussion of contingencies.

Share-Based Payments - We expense the fair value of share-based payments net of estimated forfeitures.  We estimate forfeiture rates based on historical forfeitures under our share-based payment plans.

Earnings per Common Share - Basic EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period.  Diluted EPS is calculated based on the daily weighted-average number of shares of common stock outstanding during the period plus potentially dilutive components.  The dilutive components are calculated based on the dilutive effect for each quarter.  For fiscal-year periods, the dilutive components for each quarter are averaged to arrive at the fiscal year-to-date dilutive component.

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

In February 2013, the FASB issued ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income,” which requires presentation in a single location, either in a single note or parenthetically on the face of the financial statements, the effect of significant amounts reclassified from each component of accumulated other comprehensive income based on its source.  We adopted this guidance with our March 31, 2013, Quarterly Report, and it did not impact our financial position or results of operations. See Note K for additional disclosures.

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

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” which increases disclosures about offsetting assets and liabilities. In January 2013, the FASB issued ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities,” which clarifies that the scope of ASU 2011-11 applies to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards related to the offsetting of financial instruments, including derivatives. The existing GAAP guidance allowing balance sheet offsetting remains unchanged. This guidance was effective for interim and annual periods beginning on January 1, 2013, and was applied retrospectively for all comparative periods presented. The adoption of this guidance beginning with our March 31, 2013, Quarterly Report did not affect our financial condition, results of operations or cash flows.

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SHARE-BASED PAYMENTS

12 Months Ended

Dec. 31, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

SHARE-BASED PAYMENTS

M. SHARE-BASED PAYMENTS

The ONEOK, Inc. Equity Compensation Plan (ECP) and the ONEOK, Inc. Long-Term Incentive Plan (LTIP) provide for the granting of stock-based compensation, including incentive stock options, nonstatutory stock options, stock bonus awards, restricted stock awards, restricted stock-unit awards, performance stock awards and performance-unit awards to eligible employees and the granting of stock awards to nonemployee directors. We have reserved 10.0 million and 15.6 million shares of common stock for issuance under the ECP and LTIP, respectively. At December 31, 2013, we had approximately 2.0 million and 0.9 million shares available for issuance under the ECP and LTIP, respectively, which reflect shares issued and estimated shares expected to be issued upon vesting of outstanding awards granted under these plans, less forfeitures.  These plans allow for the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code section 409A requirements.

Restricted Stock Units - We have granted restricted stock units to key employees that vest over a three-year period and entitle the grantee to receive shares of our common stock.  Restricted stock unit awards are measured at fair value as if they were vested and issued on the grant date, reduced by expected dividend payments and adjusted for estimated forfeitures. No dividends were paid prior to vesting on the restricted stock units granted prior to 2013.  Beginning in 2013, restricted stock unit awards granted accrue dividend equivalents in the form of additional restricted stock units prior to vesting. Compensation expense is recognized on a straight-line basis over the vesting period of the award.

Performance-Unit Awards -We have granted performance-unit awards to key employees.  The shares of our common stock underlying the performance units vest at the expiration of a period determined by the Executive Compensation Committee if certain performance criteria are met by the company.  Outstanding performance units vest at the expiration of a three-year period.  Upon vesting, a holder of performance units is entitled to receive a number of shares of our common stock equal to a percentage (0 percent to 200 percent) of the performance units granted, based on our total shareholder return over the vesting period, compared with the total shareholder return of a peer group of other energy companies over the same period. Compensation expense is recognized on a straight-line basis over the period of the award.

If paid, the outstanding performance unit awards entitle the grantee to receive the grant in shares of our common stock.  Our outstanding performance unit awards are equity awards with a market-based condition, which results in the compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is fulfilled, regardless of when, if ever, the market condition is satisfied.  The fair value of these performance units was estimated on the grant date based on a Monte Carlo model. No dividends were paid prior to vesting on performance stock units granted prior to 2013. Beginning in 2013, performance stock unit awards granted accrue dividend equivalents in the form of additional performance units prior to vesting. The compensation expense on these awards only will be adjusted for changes in forfeitures.

Options - No stock options have been granted since 2003. Stock option activity was not material in 2013, 2012 and 2011. All previously issued stock options expired or were exercised as of February 2013.

Stock Compensation Plan for Non-Employee Directors

The ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP) provides for the granting of stock options, stock bonus awards, including performance-unit awards, restricted stock awards and restricted stock unit awards. Under the DSCP, these awards may be granted by the Executive Compensation Committee at any time, until grants have been made for all shares authorized under the DSCP.  We have reserved a total of 1.4 million shares of common stock for issuance under the DSCP, and at December 31, 2013, we had approximately 1.0 million shares available for issuance under the plan. The maximum number of shares of common stock that can be issued to a participant under the DSCP during any year is 40,000. No performance unit awards or restricted stock awards have been made to nonemployee directors under the DSCP.

General

For all awards outstanding, we used a 3 percent forfeiture rate based on historical forfeitures under our share-based payment plans. We primarily use treasury stock to satisfy our share-based payment obligations.

Compensation cost expensed for our share-based payment plans described above was $28.6 million, $22.6 million and $40.7 million during 2013, 2012 and 2011, respectively, which is $17.6 million, $14.2 million and $25.7 million, net of tax benefits, respectively. Capitalized share-based compensation cost was not material for 2013, 2012 and 2011.

Cash received from the exercise of awards under all share-based payment arrangements was not material for 2013, 2012 and 2011.  The tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements was not material for 2013, 2012 and 2011.

Restricted Stock Unit Activity

As of December 31, 2013, we had $9.3 million of total unrecognized compensation cost related to our nonvested restricted stock unit awards, which is expected to be recognized over a weighted-average period of 1.7 years years.  The following tables set forth activity and various statistics for our restricted stock unit awards:

	Number of Shares		Weighted Average Price
Nonvested December 31, 2012	1,020,600		$	27.21
Granted	167,301		$	47.46
Released to participants	(384,883	)	$	19.06
Forfeited	(26,422	)	$	37.23
Nonvested December 31, 2013	776,596		$	35.27

	2013		2012		2011
Weighted-average grant date fair value (per share)	$	47.46	$	36.65	$	28.50
Fair value of shares granted (thousands of dollars)	$	7,940	$	11,030	$	11,728

Performance-Unit Activity

As of December 31, 2013, we had $22.5 million of total unrecognized compensation cost related to the nonvested performance-unit awards, which is expected to be recognized over a weighted-average period of 1.7 years.  The following tables set forth activity and various statistics related to the performance-unit awards and the assumptions used in the valuations of the 2013, 2012 and 2011 grants at the grant date:

	Number of Units		Weighted Average Price
Nonvested December 31, 2012	2,133,157		$	32.74
Granted	377,200		$	52.34
Released to participants	(801,354	)	$	24.05
Forfeited	(56,858	)	$	42.53
Nonvested December 31, 2013	1,652,145		$	41.10

	2013	2012	2011
Volatility (a)	22.27%	27.00%	39.91%
Dividend Yield	3.04%	2.86%	3.30%
Risk-free Interest Rate	0.42%	0.38%	1.33%

(a) - Volatility was based on historical volatility over three years using daily stock price observations.

	2013		2012		2011
Weighted-average grant date fair value (per share)	$	52.34	$	42.39	$	34.68
Fair value of shares granted (thousands of dollars)	$	19,742	$	25,466	$	29,186

Employee Stock Purchase Plan

We have reserved a total of 11.6 million shares of common stock for issuance under our ONEOK, Inc. Employee Stock Purchase Plan (the ESPP).  Subject to certain exclusions, all full-time employees are eligible to participate in the ESPP. Employees can choose to have up to 10 percent of their annual base pay withheld to purchase our common stock, subject to terms and limitations of the plan.  The Executive Compensation Committee may allow contributions to be made by other means, provided that in no event will contributions from all means exceed 10 percent of the employee’s annual base pay.  The purchase price of the stock is 85 percent of the lower of its grant date or exercise date market price.  Approximately 52 percent, 55 percent and 56 percent of employees participated in the plan in 2013, 2012 and 2011, respectively. Compensation expense for the ESPP was $6.6 million and $7.2 million in 2013 and 2011, respectively, and was not material in 2012. Under the plan, we sold 254,960 shares at $35.97 in 2013, 256,490 shares at $35.97 per share in 2012 and 365,116 shares at $23.70 per share in 2011.

Employee Stock Award Program

Under our Employee Stock Award Program, we issued, for no monetary consideration, to all eligible employees one share of our common stock when the per-share closing price of our common stock on the NYSE was for the first time at or above $13 per share.  The total number of shares of our common stock available for issuance under this program was 900,000.  Shares issued to employees under this program during 2013, 2012 and 2011 totaled 63,975, 42,467 and 295,694 respectively, and compensation expense related to the Employee Stock Award Plan was $3.6 million, $1.9 million and $16.0 million in 2013, 2012 and 2011, respectively.

Deferred Compensation Plan for Non-Employee Directors

The ONEOK, Inc. Nonqualified Deferred Compensation Plan for Non-Employee Directors provides our nonemployee directors the option to defer all or a portion of their compensation for their service on our Board of Directors.  Under the plan, directors may elect either a cash deferral option or a phantom stock option.  Under the cash deferral option, directors may defer the receipt of all or a portion of their annual retainer fees, plus accrued interest.  Under the phantom stock option, directors may defer all or a portion of their annual retainer fees and receive such fees on a deferred basis in the form of shares of common stock under our Long-Term Incentive Plan or Equity Compensation Plan.  Shares are distributed to nonemployee directors at the fair market value of our common stock at the date of distribution.

Impact of ONE Gas Separation on Stock Compensation Plans

In connection with the separation of the natural gas distribution business on January 31, 2014, ONEOK entered into an Employee Matters Agreement with ONE Gas, which provides that employees of ONE Gas no longer participate in stock compensation plans sponsored or maintained by ONEOK. Pursuant to the Employee Matters Agreement, we made certain adjustments to the number of our share-based compensation awards, with the intention of preserving the intrinsic value of each award immediately prior to the separation.

Restricted Stock Units - Restricted stock units were converted to awards in shares of the entity where the employee holding them was assigned following the separation. Therefore, restricted stock units held by an employee who separated with ONE Gas were surrendered as a result of the separation; these ONE Gas employees were granted awards by ONE Gas that are equal in value to their surrendered ONEOK shares. The number of restricted stock units held by employees who remained with ONEOK was adjusted by issuing additional units to preserve the intrinsic value of the awards immediately prior to the separation. The additional shares granted by ONEOK and the shares surrendered by ONE Gas employees resulted in a net decrease of approximately 77 thousand nonvested, restricted stock unit awards and a decrease of approximately $2.4 million in unrecognized compensation costs.

Performance-Unit Awards -Performance-unit awards held by an employee who separated with ONE Gas were surrendered as a result of the separation, and new performance-unit awards were concurrently granted by ONE Gas with an equivalent intrinsic value of the intrinsic value of the ONEOK awards immediately prior to the separation. The number of performance unit awards held by employees who remained with ONEOK was adjusted by issuing additional units to preserve the intrinsic value of the awards immediately prior to the separation. The additional shares granted by ONEOK and the shares surrendered by ONE Gas employees resulted in a net decrease of approximately 151 thousand nonvested performance-unit awards and a decrease of approximately $5.6 million in unrecognized compensation costs.

Employee Stock Purchase Plan - For those employees who separated with ONE Gas, enrollment in the plan was terminated upon the separation. Employees who separated with ONE Gas will receive shares of ONEOK common stock at the end of the offering period based upon the contributions made while employed at ONEOK. There was no impact to enrollment for those employees who remained at ONEOK. The grant date market price for ONEOK stock will be adjusted to reflect the impact of the distribution of ONE Gas shares.

Deferred Awards - Deferred shares associated with vested restricted stock unit awards or performance unit awards held by directors or employees were treated in the same manner as regular shareholders, by crediting one deferred share of ONE Gas stock for every four deferred shares of ONEOK stock.

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2013

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBT

I. LONG-TERM DEBT

All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.  The following table sets forth our long-term debt for the periods indicated:

	December 31,			December 31,
	2013			2012
	(Thousands of dollars)
ONEOK
$400,000 at 5.2% due 2015	$	400,000		$	400,000
$700,000 at 4.25% due 2022	700,000			700,000
$100,000 at 6.5% due 2028	87,649			87,662
$100,000 at 6.875% due 2028	100,000			100,000
$400,000 at 6.0% due 2035	400,000			400,000
Other	1,323			1,528
Total ONEOK senior notes payable	1,688,972			1,689,190
ONEOK Partners
$650,000 at 3.25% due 2016	650,000			650,000
$450,000 at 6.15% due 2016	450,000			450,000
$400,000 at 2.0% due 2017	400,000			400,000
$425,000 at 3.2% due 2018	425,000			—
$500,000 at 8.625% due 2019	500,000			500,000
$900,000 at 3.375 % due 2022	900,000			900,000
$425,000 at 5.0 % due 2023	425,000			—
$600,000 at 6.65% due 2036	600,000			600,000
$600,000 at 6.85% due 2037	600,000			600,000
$650,000 at 6.125% due 2041	650,000			650,000
$400,000 at 6.2% due 2043	400,000			—
Guardian Pipeline
Average 7.85%, due 2022	67,208			74,857
Total ONEOK Partners senior notes payable	6,067,208			4,824,857
Total long-term notes payable	7,756,180			6,514,047
Unamortized portion of terminated swaps	25,340			27,058
Unamortized debt discount	(15,889		)	(14,878		)
Current maturities	(10,656		)	(10,855		)
Long-term debt	$	7,754,975		$	6,515,372

The aggregate maturities of long-term debt outstanding for the years 2014 through 2018 are shown below:

	ONEOK		ONEOK Partners		Guardian Pipeline		Total
	(Millions of dollars)
2014	$	3.0	$	—	$	7.7	$	10.7
2015	$	403.0	$	—	$	7.7	$	410.7
2016	$	3.0	$	1,100.0	$	7.7	$	1,110.7
2017	$	3.0	$	400.0	$	7.7	$	410.7
2018	$	3.0	$	425.0	$	7.7	$	435.7

Additionally, our senior notes due 2028 (6.5 percent) are callable at par at our option from now until maturity.

ONE Gas Debt Issuance - In January 2014, ONE Gas completed a private placement of three series of senior notes aggregating $1.2 billion, consisting of $300 million of five-year senior notes at 2.07 percent; $300 million of 10-year senior notes at 3.61 percent; and $600 million of 30-year senior notes at 4.658 percent. ONE Gas received approximately $1.19 billion from the offering, net of issuance costs.

ONEOK Debt Repayment - ONE Gas made a cash payment to ONEOK of approximately $1.13 billion from the proceeds of the ONE Gas senior notes offering. In February 2014, we retired approximately $152.5 million of the 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, including accrued but unpaid interest to the redemption date.

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 Covenants - The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full. 

ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest.  ONEOK may redeem the remaining balance of its 4.25 percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

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

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

ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to any of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.

ONEOK Partners’ Debt Guarantee - ONEOK Partners’ senior notes are guaranteed on a senior unsecured basis by the Intermediate Partnership.  The Intermediate Partnership’s guarantee is full and unconditional, subject to certain customary automatic release provisions.  The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness.  ONEOK Partners, L.P. has no significant assets or operations other than its investment in the Intermediate Partnership, which is also consolidated.  At December 31, 2013, the Intermediate Partnership held the equity of ONEOK Partners’ subsidiaries, as well as a 50 percent interest in Northern Border Pipeline.  ONEOK Partners’ long-term debt is nonrecourse to ONEOK.

Guardian Pipeline Senior Notes - These senior notes were issued under a master shelf agreement dated November 8, 2001, with certain financial institutions.  Principal payments are due quarterly through 2022. These senior notes contain financial covenants that require the maintenance of certain ratios defined in the master shelf agreement based on Guardian Pipeline’s financial position and results of operations.  Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately.  At December 31, 2013, Guardian Pipeline was in compliance with its financial covenants.

Interest-rate Swaps - See Note E for a discussion of our interest-rate swaps.

Other - We amortize premiums, discounts and expenses incurred in connection with the issuance of long-term debt consistent with the terms of the respective debt instrument.

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

E. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

Our Energy Services and ONEOK Partners segments are exposed to various risks that we manage by periodically entering into derivative instruments. In June 2013, we announced we will exit the operations of our Energy Services segment. As a result, the use of derivative instruments will decrease significantly within our Energy Services segment. See Note C for additional information. These risks include the following:

• Commodity-price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate.  We use commodity derivative instruments such as futures, physical-forward contracts, swaps and options to mitigate the commodity-price risk associated with a portion of the forecasted purchases and sales of commodities and natural gas and natural gas liquids in storage.  Commodity-price volatility may have a significant impact on the fair value of our derivative instruments as of a given date;

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

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

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

• Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;

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

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

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

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

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

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

• reducing our exposure to fluctuations in interest rates; and

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

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

Our former Natural Gas Distribution segment also used derivative instruments to hedge the cost of a portion of anticipated natural gas purchases during the winter heating months to protect our customers from upward volatility in the market price of natural gas. The use of these derivative instruments and the associated recovery of these costs have been approved by the OCC, KCC and regulatory authorities in certain Texas jurisdictions.

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

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

	December 31, 2013						December 31, 2012
	Fair Values of Derivatives (a)						Fair Values of Derivatives (a)
	Assets			(Liabilities)			Assets			(Liabilities)
	(Thousands of dollars)
Derivatives designated as hedging instruments
Commodity contracts
Financial contracts	$	8,011	(b)	$	(10,573	)	$	47,516	(c)	$	(4,885	)
Physical contracts	1,064			(3,463		)	56			(126		)
Interest-rate contracts	54,503			—			10,923			—
Total derivatives designated as hedging instruments	63,578			(14,036		)	58,495			(5,011		)
Derivatives not designated as hedging instruments
Commodity contracts
Nontrading instruments
Financial contracts	202			(1,262		)	24,970			(25,009		)
Physical contracts	704			(658		)	4,059			(153		)
Trading instruments
Financial contracts	5			—			15,358			(14,192		)
Total derivatives not designated as hedging instruments	911			(1,920		)	44,387			(39,354		)
Total derivatives	$	64,489		$	(15,956	)	$	102,882		$	(44,365	)

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

(b) - Includes $5.8 million of derivative assets associated with cash flow hedges of inventory that were adjusted to reflect the lower of cost or market value. The deferred gains associated with these assets have been reclassified from accumulated other comprehensive income (loss).

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

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

		December 31, 2013				December 31, 2012
	Contract Type	Purchased/ Payor		Sold/ Receiver		Purchased/ Payor		Sold/ Receiver
Derivatives designated as hedging instruments:
Cash flow hedges
Fixed price
-Natural gas (Bcf)	Futures, forwards and swaps	—		(65.0	)	—		(85.1	)
-Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	—		(4.0	)	—		(1.1	)
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	—		(57.4	)	—		(56.3	)
Interest-rate contracts (Millions of dollars)	Forward-starting swaps	$	400.0	—		$	400.0	—
Fair value hedges
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	1.1		(1.1	)	59.1		(59.1	)
Derivatives not designated as hedging instruments:
Fixed price
-Natural gas (Bcf)	Futures, forwards and swaps	5.8		(9.7	)	60.7		(60.4	)
	Options	—		—		102.1		(100.8	)
-Crude oil and NGLs (MMBbl)	Futures, forwards and swaps	0.3		(0.3	)	—		—
Basis
-Natural gas (Bcf)	Futures, forwards and swaps	8.5		(11.2	)	80.2		(81.7	)
Index
-Natural gas (Bcf)	Futures, forwards and swaps	1.8		—		20.3		(22.3	)

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

Cash Flow Hedges -Our Energy Services and ONEOK Partners segments use derivative instruments to hedge the cash flows associated with anticipated purchases and sales of natural gas, NGLs and condensate and cost of fuel used in the transportation of natural gas.  Accumulated other comprehensive income (loss) at December 31, 2013, includes losses of approximately $5.8 million, net of tax, related to these hedges that will be recognized within the next 24 months as the forecasted transactions affect earnings.  If prices remain at current levels, we will recognize $7.0 million in net losses over the next 12 months and net gains of $1.2 million thereafter.  The amount deferred in accumulated other comprehensive income (loss) attributable to our settled interest-rate swaps is a loss of $49.6 million, net of tax, which will be recognized over the life of the long-term, fixed-rate debt. We expect that losses of $5.3 million, net of tax, will be reclassified into earnings during the next 12 months as the hedged items affect earnings. The remaining amounts in accumulated other comprehensive income (loss) are attributable primarily to ONEOK Partners’ forward-starting interest-rate swaps with settlement dates greater than 12 months, which will be amortized to interest expense over the life of long-term, fixed-rate debt upon issuance of ONEOK Partners debt.

For the year ended December 31, 2013, cost of sales and fuel in our Consolidated Statements of Income includes $10.1 million reflecting an adjustment to natural gas inventory at the lower of cost or market value. We reclassified $8.0 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings. For the year ended December 31, 2012, net margin in our Consolidated Statement of Income included losses of $29.9 million related to certain financial contracts that were used to hedge forecasted purchases of natural gas.  As a result of the continued decline in natural gas prices, the combination of the cost basis of the forecasted purchases of inventory and the financial contracts exceeded the amount expected to be recovered through sales of that inventory after considering related sales hedges, which required reclassification of the loss from accumulated other comprehensive loss to current period earnings. In 2011, cost of sales and fuel in our Consolidated Statements of Income included $91.1 million, reflecting an adjustment to natural gas inventory at the lower of cost or market value.  We also reclassified $91.1 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.

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

Derivatives in Cash Flow Hedging Relationships	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Commodity contracts	$	(15,433	)	$	62,898		$	117,508
Interest-rate contracts	46,616			(29,471		)	(128,666		)
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	31,183		$	33,427		$	(11,158	)

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

	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)
Derivatives in Cash Flow Hedging Relationships		Years Ended December 31,
		2013			2012			2011
		(Thousands of dollars)
Commodity contracts	Revenues	$	19,049		$	140,862		$	48,601
Commodity contracts	Cost of sales and fuel	(14,320		)	(73,881		)	89,618
Interest-rate contracts	Interest expense	(14,560		)	(7,155		)	(480		)
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	(9,831	)	$	59,826		$	137,739

Ineffectiveness related to our cash flow hedges was not material for the years ended December 31, 2013, 2012 and 2011.  In the event that it becomes probable that a forecasted transaction will not occur, we will discontinue cash flow hedge treatment, which will affect earnings.  For the year ended December 31, 2013, we recorded immaterial gains due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable. For the years ended December 31, 2012 and 2011, there were no gains or losses due to the discontinuance of cash flow hedge treatment as a result of the underlying transactions being no longer probable.

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

Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	Years Ended December 31,
		2013				2012		2011
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	(2,051	)		$	2,413	$	1,796
Commodity contracts - non-trading (a)	Cost of sales and fuel	(2,266		)	(b)	5,956		16,178
Total gain (loss) recognized in income on derivatives		$	(4,317	)		$	8,369	$	17,974

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

(b) - Includes losses of $2.2 million for the year ended December 31, 2013, on certain derivatives derecognized that were designated previously as fair value hedges of firm transportation commitments that no longer meet the definition of a firm commitment.

Our former Natural Gas Distribution segment held natural gas call options with fair values of $8.7 million and $1.8 million at December 31, 2013 and 2012, respectively.  The premiums are recorded in other current assets as these contracts are included in, and recoverable through, the monthly purchased-gas cost mechanism.  We recorded losses of $4.5 million, $5.9 million and $14.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, which are deferred as part of our unrecovered purchased-gas costs.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements that had been designated as fair value hedges. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged.  Interest expense savings from the amortization of terminated swaps for 2013, 2012 and 2011, were $1.7 million, $1.7 million and $4.3 million, respectively.

Our Energy Services segment uses basis swaps to hedge the fair value of location price differentials related to certain firm transportation commitments.  Cost of sales and fuel in our Consolidated Statements of Income includes losses of $1.4 million, and gains of $0.4 million and $14.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, related to the change in fair value of derivatives designated as fair value hedges.  Revenues include gains of $1.6 million and $0.5 million, and losses of $13.8 million for the years ended December 31, 2013, 2012 and 2011, respectively, to recognize the change in fair value of the related hedged firm commitments.  The ineffectiveness related to these hedges was not material for the years ended December 31, 2013, 2012 and 2011.

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

Some of our derivative instruments contain provisions that require us to maintain an investment-grade credit rating from S&P and/or Moody’s.  If our credit ratings on senior unsecured long-term debt were to decline below investment-grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. The aggregate fair value of all financial derivative instruments with contingent features related to credit risk that were in a net liability position as of December 31, 2013, was $1.1 million.  On February 3, 2014, S&P reduced our credit rating below investment grade as a result of the ONE Gas separation. Moody’s also downgraded our credit rating; however, our credit rating with Moody’s remained investment-grade.

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

At December 31, 2013, the net credit exposure from our derivative assets is primarily with investment-grade companies in the financial services sector.

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FAIR VALUE MEASUREMENTS FAIR VALUE MEASUREMENTS - Part 2 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, beginning	$ 403	$ 17,821
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31	(134)	1,859
Included in earnings	(3,748)	(7,500)
Included in other comprehensive income (loss)	800	(5,587)
Transfers into Level 3		(3,636)
Transfers out of Level 3		(695)
Settlements	450
Balance, ending	(2,095)	403
Derivative Financial Instruments, Assets Liabilities [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, beginning	1,683	25,104
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31	(804)	1,971
Included in earnings	(5,627)	(13,503)
Included in other comprehensive income (loss)	800	(5,587)
Transfers into Level 3		(3,636)
Transfers out of Level 3		(695)
Settlements	450
Balance, ending	(2,694)	1,683
Firm Commitments [Member]
Fair Value, Assets And Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance, beginning	(1,280)	(7,283)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31	670	(112)
Included in earnings	1,879	6,003
Included in other comprehensive income (loss)	0	0
Transfers into Level 3		0
Transfers out of Level 3		0
Settlements	0
Balance, ending	$ 599	$ (1,280)

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DISCONTINUED OPERATIONS

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

DISCONTINUED OPERATIONS

C. DISCONTINUED OPERATIONS

On February 1, 2012, we sold ONEOK Energy Marketing Company, our Natural Gas Distribution segment’s retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital.  We received net proceeds of approximately $32.9 million and recognized a gain on the sale of approximately $13.5 million, net of taxes of $8.3 million. The proceeds from the sale were used to reduce short-term borrowings.  The financial information of ONEOK Energy Marketing Company is reflected as discontinued operations in this Annual Report.  All prior periods presented have been recast to reflect the discontinued operations.

The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated:

	One Month Ended			Year Ended
	January 31,			December 31,
	2012			2011
	(Thousands of dollars)
Revenues	$	27,607		$	313,371
Cost of sales and fuel	25,961			302,561
Net margin	1,646			10,810
Operating costs	408			7,147
Depreciation and amortization	8			128
Operating income	1,230			3,535
Other income (expense), net	—			(50		)
Income taxes	(468		)	(1,255		)
Income from discontinued operations, net	$	762		$	2,230

Separation of Natural Gas Distribution Business - On January 31, 2014, we completed the separation of our natural gas distribution business into a standalone publicly traded company, ONE Gas.  ONE Gas consists of ONEOK’s former Natural Gas Distribution segment that includes Kansas Gas Service, Oklahoma Natural Gas and Texas Gas Service.  The Natural Gas Distribution segment was classified as discontinued operations, effective February 1, 2014. See additional discussion in Note U of the Notes to the Consolidated Financial Statements.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

D. FAIR VALUE MEASUREMENTS

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

	December 31, 2013
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	4,477		$	647		$	3,094		$	8,218		$	(2,850	)	$	5,368
Physical contracts	—			4			1,764			1,768			(1,157		)	611
Interest-rate contracts	—			54,503			—			54,503			—			54,503
Total derivative assets	4,477			55,154			4,858			64,489			(4,007		)	60,482
Fair value of firm commitments (b)	—			—			599			599			—			599
Available-for-sale investment securities (b)	1,569			—			—			1,569			—			1,569
Total assets	$	6,046		$	55,154		$	5,457		$	66,657		$	(4,007	)	$	62,650
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(7,624	)	$	(776	)	$	(3,435	)	$	(11,835	)	$	10,767		$	(1,068	)
Physical contracts	—			(4		)	(4,117		)	(4,121		)	1,157			(2,964		)
Total derivative liabilities	$	(7,624	)	$	(780	)	$	(7,552	)	$	(15,956	)	$	11,924		$	(4,032	)

(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities, other assets and other deferred credits on a net basis. We net derivative assets and liabilities, including cash collateral, when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2013, we held no cash collateral and had posted $15.7 million of cash collateral with various counterparties.

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

	December 31, 2012
	Level 1			Level 2			Level 3			Total - Gross			Netting			Total - Net
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	69,957		$	10,780		$	7,107		$	87,844		$	(51,602	)	$	36,242
Physical contracts	—			2,083			2,032			4,115			(151		)	3,964
Interest-rate contracts	—			10,923			—			10,923			—			10,923
Total derivative assets	69,957			23,786			9,139			102,882			(51,753		)	51,129
Trading securities (b)	5,978			—			—			5,978			—			5,978
Available-for-sale investment securities (c)	2,027			—			—			2,027			—			2,027
Total assets	$	77,962		$	23,786		$	9,139		$	110,887		$	(51,753	)	$	59,134
Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(35,172	)	$	(1,737	)	$	(7,177	)	$	(44,086	)	$	33,878		$	(10,208	)
Physical contracts	—			—			(279		)	(279		)	151			(128		)
Total derivative liabilities	(35,172		)	(1,737		)	(7,456		)	(44,365		)	34,029			(10,336		)
Fair value of firm commitments (d)	—			—			(1,280		)	(1,280		)	—			(1,280		)
Total liabilities	$	(35,172	)	$	(1,737	)	$	(8,736	)	$	(45,645	)	$	34,029		$	(11,616	)

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

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

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

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

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

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

Our Level 3 fair value amounts are based on inputs that may include one or more unobservable inputs including internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties.  We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes.  These balances categorized as Level 3 are comprised of derivatives for natural gas and NGLs.  Also included in Level 3 are the fair values of firm commitments.  We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material.  The significant unobservable inputs used are the unpublished forward basis and index curves.  Significant increases or decreases in either of those inputs in isolation would not have a material impact on our fair value measurements.

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

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2013	$	1,683		$	(1,280	)	$	403
Total realized/unrealized gains (losses):
Included in earnings (a)	(5,627		)	1,879			(3,748		)
Included in other comprehensive income (loss)	800			—			800
Settlements	450			—			450
December 31, 2013	$	(2,694	)	$	599		$	(2,095	)
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2013 (a)	$	(804	)	$	670		$	(134	)

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

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Total
	(Thousands of dollars)
January 1, 2012	$	25,104		$	(7,283	)	$	17,821
Total realized/unrealized gains (losses):
Included in earnings (a)	(13,503		)	6,003			(7,500		)
Included in other comprehensive income (loss)	(5,587		)	—			(5,587		)
Sale of discontinued operations	(3,636		)	—			(3,636		)
Transfers out of Level 3	(695		)	—			(695		)
December 31, 2012	$	1,683		$	(1,280	)	$	403
Total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of December 31, 2012 (a)	$	1,971		$	(112	)	$	1,859

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

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

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

Other Financial Instruments -The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and notes payable is equal to book value, due to the short-term nature of these items. Our cash and cash equivalents are comprised of bank and money market accounts and are classified as Level 1.  Our notes payable are classified as Level 2 since the estimated fair value of the notes payable can be determined using information available in the commercial paper market.

The estimated fair value of our consolidated long-term debt, including current maturities, was $8.2 billion and $7.5 billion at December 31, 2013 and 2012, respectively.  The book value of long-term debt, including current maturities, was $7.8 billion and $6.5 billion at December 31, 2013 and 2012, respectively.  The estimated fair value of the aggregate of ONEOK’s and ONEOK Partners’ senior notes outstanding was determined using quoted market prices for similar issues with similar terms and maturities.  The estimated fair value of our consolidated long-term debt is classified as Level 2.

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PROPERTY, PLANT AND EQUIPMENT

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

PROPERTY, PLANT AND EQUIPMENT

F. PROPERTY, PLANT AND EQUIPMENT

The following table sets forth our property, plant and equipment by property type, for the periods indicated:

	Estimated Useful Lives (Years)	December 31, 2013			December 31, 2012
		(Thousands of dollars)
Non-Regulated
Gathering pipelines and related equipment	5 to 40	$	2,173,271		$	1,638,037
Processing and fractionation and related equipment	5 to 40	2,295,983			1,625,146
Storage and related equipment	5 to 54	362,704			335,237
Transmission pipelines and related equipment	22 to 54	302,718			311,038
General plant and other	2 to 60	402,523			348,636
Construction work in process	—	1,112,182			881,788
Regulated
Natural gas distribution pipelines and related equipment	15 to 80	3,703,593			3,512,660
Storage and related equipment	5 to 54	135,922			136,938
Natural gas transmission pipelines and related equipment	5 to 77	1,850,559			1,796,683
Natural gas liquids transmission pipelines and related equipment	5 to 80	2,049,461			1,490,511
General plant and other	2 to 85	324,703			309,119
Construction work in process	—	822,537			703,198
Property, plant and equipment		15,536,156			13,088,991
Accumulated depreciation and amortization - non-regulated		(1,112,192		)	(954,398		)
Accumulated depreciation and amortization - regulated		(2,126,460		)	(2,020,253		)
Net property, plant and equipment		$	12,297,504		$	10,114,340

The average depreciation rates for our regulated property are set forth, by segment, in the following table for the periods indicated:

	Years Ended December 31,
Regulated Property	2013	2012	2011
ONEOK Partners	2.0% - 2.2%	1.9% - 2.2%	1.9% - 2.2%
Natural Gas Distribution	2.0% - 3.0%	2.0% - 3.0%	2.0% - 2.9%

We and ONEOK Partners incurred liabilities for construction work in process that had not been paid at December 31, 2013, 2012 and 2011 of $237.2 million, $228.5 million and $155.7 million, respectively. Such amounts are not included in capital expenditures (less allowance for equity funds used during construction) on the Consolidated Statements of Cash Flows.

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES - Part 3 (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Discontinuation of Interest Rate Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net	$ 0	$ 0	$ 0
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	8,842,000	16,709,000
Net unrealized gain (loss) in accumulated other comprehensive income (loss)	(5,800,000)
Amount recognized in the next 12 months	(7,000,000)
Amount recognized after the next 12 months	1,200,000
Losses associated with the change in value of natural gas contracts held deferred in other current assets	4,500,000	5,900,000	14,500,000
Gains (losses) related to the change in fair value of derivatives	(1,400,000)	400,000	14,600,000
Change in fair value of the related hedged firm commitments for transportation contracts	1,600,000	500,000	(13,800,000)
Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(4,317,000)	8,369,000	17,974,000
Fair value of natural gas call options held	8,700,000	1,800,000
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	(9,831,000)	59,826,000	137,739,000
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	31,183,000	33,427,000	(11,158,000)
Adjustment to natural gas inventory at the lower of cost or market value.			91,100,000
Cash Flow Hedge Gain Reclassified to Earnings	8,000,000		91,100,000
Fair Value Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest expense savings from the amortization of terminated swaps	1,700,000	1,700,000	4,300,000
Cost of Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Adjustment to natural gas inventory at the lower of cost or market value.	10,100,000
Losses related to financial hedging contracts recognized in net margin		29,900,000
Commodity Contract [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	(15,433,000)	62,898,000	117,508,000
Commodity Contract [Member] | Sales [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	19,049,000	140,862,000	48,601,000
Commodity Contract [Member] | Cost of Sales [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	(14,320,000)	(73,881,000)	89,618,000
Interest Rate Contract [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	(5,300,000)
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	46,616,000	(29,471,000)	(128,666,000)
Amount of accumulated other comprehensive income (loss) attributable primarily to settled interest-rate swaps.	(49,600,000)
Interest Rate Contract [Member] | Interest Expense [Member] | Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)	(14,560,000)	(7,155,000)	(480,000)
Trading [Member] | Commodity Contract [Member] | Sales [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(2,051,000)	2,413,000	1,796,000
Non Trading [Member] | Commodity Contract [Member] | Cost of Sales [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(2,266,000)	5,956,000	16,178,000
Non Trading [Member] | Commodity Contract [Member] | Cost of Sales [Member] | Recently dedesignated [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) recognized in income on derivatives	$ 2,200,000

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PROPERTY, PLANT AND EQUIPMENT - Part 1 (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Construction in Progress Expenditures Incurred but Not yet Paid	$ 237,200,000	$ 228,500,000	$ 155,700,000
Property, plant and equipment by type [Abstract]
Property, plant and equipment	15,536,156,000	13,088,991,000
Accumulated Depreciation	(3,238,652,000)	(2,974,651,000)
Net property, plant and equipment	12,297,504,000	10,114,340,000
Non-Regulated Property, Plant and Equipment [Member]
Property, plant and equipment by type [Abstract]
Accumulated Depreciation	(1,112,192,000)	(954,398,000)
Non-Regulated Property, Plant and Equipment [Member] | Gathering pipelines and related equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	2,173,271,000	1,638,037,000
Non-Regulated Property, Plant and Equipment [Member] | Processing and fractionation and related equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	2,295,983,000	1,625,146,000
Non-Regulated Property, Plant and Equipment [Member] | Storage and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	362,704,000	335,237,000
Non-Regulated Property, Plant and Equipment [Member] | Transmission Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	302,718,000	311,038,000
Non-Regulated Property, Plant and Equipment [Member] | General plant and other [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	402,523,000	348,636,000
Non-Regulated Property, Plant and Equipment [Member] | Construction Work in Process [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	1,112,182,000	881,788,000
Regulated Property Plant and Equipment [Member]
Property, plant and equipment by type [Abstract]
Accumulated Depreciation	(2,126,460,000)	(2,020,253,000)
Regulated Property Plant and Equipment [Member] | ONEOK Partners [Member]
Property, plant and equipment by type [Abstract]
Average depreciation rates, minimum	2.00%	1.90%	1.90%
Average depreciation rates, maximum	2.20%	2.20%	2.20%
Regulated Property Plant and Equipment [Member] | Natural Gas Distribution [Member]
Property, plant and equipment by type [Abstract]
Average depreciation rates, minimum	2.00%	2.00%	2.00%
Average depreciation rates, maximum	3.00%	3.00%	2.90%
Regulated Property Plant and Equipment [Member] | Storage and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	135,922,000	136,938,000
Regulated Property Plant and Equipment [Member] | General plant and other [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	324,703,000	309,119,000
Regulated Property Plant and Equipment [Member] | Construction Work in Process [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	822,537,000	703,198,000
Regulated Property Plant and Equipment [Member] | Natural Gas Distribution Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	3,703,593,000	3,512,660,000
Regulated Property Plant and Equipment [Member] | Natural Gas Transmission Pipelines and Regulated Equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	1,850,559,000	1,796,683,000
Regulated Property Plant and Equipment [Member] | Natural Gas Liquids Transmission Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Property, plant and equipment	$ 2,049,461,000	$ 1,490,511,000
Minimum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Gathering pipelines and related equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	5 years
Minimum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Processing and fractionation and related equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	5 years
Minimum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Storage and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	5 years
Minimum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Transmission Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	22 years
Minimum [Member] | Non-Regulated Property, Plant and Equipment [Member] | General plant and other [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	2 years
Minimum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Construction Work in Process [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	0 years
Minimum [Member] | Regulated Property Plant and Equipment [Member] | Storage and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	5 years
Minimum [Member] | Regulated Property Plant and Equipment [Member] | General plant and other [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	2 years
Minimum [Member] | Regulated Property Plant and Equipment [Member] | Construction Work in Process [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	0 years
Minimum [Member] | Regulated Property Plant and Equipment [Member] | Natural Gas Distribution Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	15 years
Minimum [Member] | Regulated Property Plant and Equipment [Member] | Natural Gas Transmission Pipelines and Regulated Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	5 years
Minimum [Member] | Regulated Property Plant and Equipment [Member] | Natural Gas Liquids Transmission Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	5 years
Maximum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Gathering pipelines and related equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	40 years
Maximum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Processing and fractionation and related equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	40 years
Maximum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Storage and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	54 years
Maximum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Transmission Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	54 years
Maximum [Member] | Non-Regulated Property, Plant and Equipment [Member] | General plant and other [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	60 years
Maximum [Member] | Non-Regulated Property, Plant and Equipment [Member] | Construction Work in Process [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	0 years
Maximum [Member] | Regulated Property Plant and Equipment [Member] | Storage and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	54 years
Maximum [Member] | Regulated Property Plant and Equipment [Member] | General plant and other [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	85 years
Maximum [Member] | Regulated Property Plant and Equipment [Member] | Construction Work in Process [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	0 years
Maximum [Member] | Regulated Property Plant and Equipment [Member] | Natural Gas Distribution Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	80 years
Maximum [Member] | Regulated Property Plant and Equipment [Member] | Natural Gas Transmission Pipelines and Regulated Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	77 years
Maximum [Member] | Regulated Property Plant and Equipment [Member] | Natural Gas Liquids Transmission Pipelines and Related Equipment [Member]
Property, plant and equipment by type [Abstract]
Estimated Useful Lives	80 years

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RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES - Part 2 (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 MMcf	Dec. 31, 2012 MMcf
Fixed Price [Member] | Natural Gas [Member] | Cash Flow Hedging [Member] | Sold [Member] | Exchange Futures [Member]
Derivative [Line Items]
Notional amount	(65,000.0)	(85,100.0)
Fixed Price [Member] | Natural Gas [Member] | Cash Flow Hedging [Member] | Purchased [Member] | Exchange Futures [Member]
Derivative [Line Items]
Notional amount	0	0
Fixed Price [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Sold [Member] | Options [Member]
Derivative [Line Items]
Notional amount	0	(100,800.0)
Fixed Price [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Sold [Member] | Exchange Futures [Member]
Derivative [Line Items]
Notional amount	(9,700.0)	(60,400.0)
Fixed Price [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Purchased [Member] | Options [Member]
Derivative [Line Items]
Notional amount	0	102,100.0
Fixed Price [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Purchased [Member] | Exchange Futures [Member]
Derivative [Line Items]
Notional amount	5,800.0	60,700.0
Fixed Price [Member] | Crude oil and NGLs [Member] | Cash Flow Hedging [Member] | Sold [Member] | Swaps [Member]
Derivative [Line Items]
Notional amount	(4.0)	(1.1)
Fixed Price [Member] | Crude oil and NGLs [Member] | Cash Flow Hedging [Member] | Purchased [Member] | Swaps [Member]
Derivative [Line Items]
Notional amount	0.0	0.0
Fixed Price [Member] | Crude oil and NGLs [Member] | Not Designated as Hedging Instrument [Member] | Sold [Member] | Exchange Futures [Member]
Derivative [Line Items]
Notional amount	(0.3)	0.0
Fixed Price [Member] | Crude oil and NGLs [Member] | Not Designated as Hedging Instrument [Member] | Purchased [Member] | Exchange Futures [Member]
Derivative [Line Items]
Notional amount	0.3	0.0
Basis [Member] | Natural Gas [Member] | Cash Flow Hedging [Member] | Sold [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	(57,400.0)	(56,300.0)
Basis [Member] | Natural Gas [Member] | Cash Flow Hedging [Member] | Purchased [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	0	0
Basis [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Sold [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	(1,100.0)	(59,100.0)
Basis [Member] | Natural Gas [Member] | Fair Value Hedging [Member] | Purchased [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	1,100.0	59,100.0
Basis [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Sold [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	(11,200.0)	(81,700.0)
Basis [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Purchased [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	8,500.0	80,200.0
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | Sold [Member] | Forward Starting Contracts [Member]
Derivative [Line Items]
Notional amount of cash flow hedge instruments	$ 0	$ 0
Interest Rate Contract [Member] | Cash Flow Hedging [Member] | Purchased [Member] | Forward Starting Contracts [Member]
Derivative [Line Items]
Notional amount of cash flow hedge instruments	$ 400.0	$ 400.0
Index [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Sold [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	0	(22,300.0)
Index [Member] | Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | Purchased [Member] | Forward and Swaps Contracts [Member]
Derivative [Line Items]
Notional amount	1,800.0	20,300.0

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EMPLOYEE BENEFIT PLANS Rate of return and discount rates accounting policy (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Pension and Other Postretirement Plans, Policy [Policy Text Block]

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 N for more discussion of pension and postretirement employee benefits.

We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and economic growth models.

We determine our discount rates annually.  We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our pension and postretirement obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows.  Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds.  Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.

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ONEOK PARTNERS (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill [Line Items]

Goodwill by Segment

Goodwill - The following table sets forth our goodwill by segment for the periods indicated:

	ONEOK Partners		Natural Gas Distribution		Energy Services		Total
	(Thousands of dollars)
December 31, 2012	$	433,535	$	157,953	$	—	$	591,488
Acquisitions	92,000		—		—		92,000
December 31, 2013	$	525,535	$	157,953	$	—	$	683,488

Transactions With Related Parties [Table Text Block]

Ownership Interestin ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of December 31, 2013:

General partner interest	2.0	%
Limited partner interest (a)	39.2	%
Total ownership interest	41.2	%

Ownership interest in ONEOK Partners

The following table shows ONEOK Partners’ transactions with us for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Revenues	$	340,743	$	352,099	$	403,603
Expenses
Cost of sales and fuel	$	37,963	$	33,094	$	48,163
Administrative and general expenses	265,448		246,050		251,239
Total expenses	$	303,411	$	279,144	$	299,402

ONEOK Partners' Distributions Paid

The following table shows ONEOK Partners’ distributions paid during the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	2.870	$	2.590	$	2.325
General partner distributions	$	18,193	$	15,217	$	12,189
Incentive distributions	251,664		186,130		123,386
Distributions to general partner	269,857		201,347		135,575
Limited partner distributions to ONEOK	266,302		235,442		197,132
Limited partner distributions to noncontrolling interest	373,554		324,123		276,739
Total distributions paid	$	909,713	$	760,912	$	609,446

ONEOK Partners' Distributions Declared

The following table shows ONEOK Partners’ distributions declared for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	2.890	$	2.690	$	2.365
General partner distributions	$	18,625	$	16,355	$	12,515
Incentive distributions	259,466		210,095		131,212
Distributions to general partner	278,091		226,450		143,727
Limited partner distributions to ONEOK	268,157		249,600		200,524
Limited partner distributions to noncontrolling interest	384,988		341,704		281,500
Total distributions declared	$	931,236	$	817,754	$	625,751

Oneok Partners [Member]

Goodwill [Line Items]

Goodwill by Segment

The purchase price and assessment of the fair value of the assets acquired and liabilities assumed were as follows (in thousands):

	Total
Property, plant and equipment
Gathering pipelines and related equipment	$	59,174
Processing and fractionation and related equipment	50,595
General plant and other	120
Intangible assets	103,000
Identifiable assets acquired	212,889
Goodwill	92,000
Total purchase price	$	304,889

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ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

12 Months Ended

Dec. 31, 2013

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

K. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

	Unrealized Gains (Losses) on Energy Marketing and Risk-Management Assets/Liabilities (a)			Unrealized Holding Gains (Losses) on Investment Securities (a)			Pension and Postretirement Benefit Plan Obligations (a)			Accumulated Other Comprehensive Income (Loss) (a)
	(Thousands of dollars)
January 1, 2012	$	(55,367	)	$	987		$	(151,741	)	$	(206,121	)
Other comprehensive income (loss) before reclassifications	16,709			47			(47,004		)	(30,248		)
Amounts reclassified from accumulated other comprehensive income (loss)	(16,372		)	—			35,943			19,571
Other comprehensive income (loss) attributable to ONEOK	337			47			(11,061		)	(10,677		)
December 31, 2012	(55,030		)	1,034			(162,802		)	(216,798		)
Other comprehensive income (loss) before reclassifications	8,842			(177		)	37,144			45,809
Amounts reclassified from accumulated other comprehensive income (loss)	3,020			—			45,982			49,002
Other comprehensive income (loss) attributable to ONEOK	11,862			(177		)	83,126			94,811
December 31, 2013	$	(43,168	)	$	857		$	(79,676	)	$	(121,987	)

(a) All amounts are presented net of tax.

The following table sets forth the effect of reclassifications from accumulated other comprehensive income (loss) on our Consolidated Statements of Income for the period indicated:

Details about Accumulated Other Comprehensive Income (Loss) Components	Year Ended December 31, 2013			Affected Line Item in the Consolidated Statements of Income
	(Thousands of dollars)
Unrealized (gains) losses on energy marketing and risk- management assets/liabilities
Commodity contracts	$	(19,049	)	Revenues
Commodity contracts	14,320			Cost of sales and fuel
Interest-rate contracts	14,560			Interest expense
	9,831			Income before income taxes
	(1,905		)	Income tax expense
	7,926			Net income
Noncontrolling interest	4,906			Less: Net income attributable to noncontrolling interest
	$	3,020		Net income attributable to ONEOK
Pension and postretirement benefit plan obligations (a)
Amortization of net loss	$	78,887
Amortization of unrecognized prior service cost	(5,522		)
Amortization of unrecognized net asset at adoption	284
Settlement charge	1,338
	74,987			Income before income taxes
	(29,005		)	Income tax expense
	$	45,982		Net income attributable to ONEOK
Total reclassifications for the period attributable to ONEOK	$	49,002		Net income attributable to ONEOK

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

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UNCONSOLIDATED AFFILIATES

12 Months Ended

Dec. 31, 2013

Equity Method Investments and Joint Ventures [Abstract]

UNCONSOLIDATED AFFILIATES

P. UNCONSOLIDATED AFFILIATES

Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated:

	Net Ownership Interest	December 31, 2013		December 31, 2012
		(Thousands of dollars)
Northern Border Pipeline	50%	$	404,803	$	393,317
Overland Pass Pipeline Company	50%	466,671		468,710
Fort Union Gas Gathering, L.L.C.	37%	125,220		120,782
Bighorn Gas Gathering	49%	87,837		90,428
Other	Various	145,307		148,168
Investments in unconsolidated affiliates (a)		$	1,229,838	$	1,221,405

(a) - Equity method goodwill (Note A) was $224.3 million at December 31, 2013 and 2012.

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

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Northern Border Pipeline	$	65,046	$	72,705	$	76,365
Overland Pass Pipeline Company	20,461		20,043		19,535
Fort Union Gas Gathering, L.L.C.	15,826		17,218		15,280
Bighorn Gas Gathering	1,952		3,820		5,990
Other	7,232		9,238		10,076
Equity earnings from investments	$	110,517	$	123,024	$	127,246

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

	December 31, 2013			December 31, 2012
	(Thousands of dollars)
Balance Sheet
Current assets	$	155,310		$	175,930
Property, plant and equipment, net	$	2,557,571		$	2,593,122
Other noncurrent assets	$	34,478		$	35,005
Current liabilities	$	98,967		$	145,147
Long-term debt	$	442,103		$	472,630
Other noncurrent liabilities	$	58,221		$	42,451
Accumulated other comprehensive loss	$	(2,291	)	$	(2,503	)
Owners’ equity	$	2,150,359		$	2,146,332

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Income Statement
Operating revenues	$	528,665	$	573,197	$	496,158
Costs and expenses	$	256,292	$	269,858	$	221,261
Net income	$	248,998	$	279,766	$	249,559
Distributions paid to us	$	137,498	$	155,741	$	156,385

We incurred expenses in transactions with unconsolidated affiliates of $53.8 million, $36.5 million, and $33.7 million for 2013, 2012, and 2011, respectively, primarily related to Overland Pass Pipeline Company. Accounts payable to our equity method investees at December 31, 2013 and 2012, were not material.

Overland Pass Pipeline Company - 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 percentage interest.  The Overland Pass Pipeline Company Management Committee determines the amount and timing of such distributions.  Any changes to, or suspensions 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.

Northern Border Pipeline - 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.

During 2013, ONEOK Partners made equity contributions to Northern Border Pipeline Company of approximately $30.8 million.

In September 2012, Northern Border Pipeline filed with the FERC a settlement with its customers to modify its transportation rates. In January 2013, the settlement was approved and the new rates are effective January 1, 2013. The new long-term transportation rates are approximately 11 percent lower compared with previous rates.

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Provisions for Income Taxes

The following table sets forth our provisions for income taxes for the periods indicated:

	Years Ended December 31,
	2013		2012			2011
Current income taxes	(Thousands of dollars)
Federal	$	7,313	$	(16,083	)	$	(32,291	)
State	4,554		1,798			1,707
Total current income taxes from continuing operations	11,867		(14,285		)	(30,584		)	(a)
Deferred income taxes
Federal	137,654		213,127			228,257
State	13,861		16,353			28,375
Total deferred income taxes from continuing operations	151,515		229,480			256,632			(a)
Total provision for income taxes from continuing operations	163,382		215,195			226,048
Discontinued operations	—		8,749			1,255
Total provision for income taxes	$	163,382	$	223,944		$	227,303

(a) Includes a $37.7 million reclassification from current income taxes to deferred related to revisions of estimated depreciation in our filed tax returns compared with our 2010 tax provision.

Reconciliation of Income Tax Provision

The following table is a reconciliation of our income tax provision from continuing operations for the periods indicated:

	Years Ended December 31,
	2013			2012			2011
	(Thousands of dollars)
Income from continuing operations before income taxes	$	740,343		$	944,446		$	983,562
Less: Net income attributable to noncontrolling interest	310,428			382,911			399,150
Income from continuing operations attributable to ONEOK before income taxes	429,915			561,535			584,412
Federal statutory income tax rate	35		%	35		%	35		%
Provision for federal income taxes	150,470			196,537			204,543
State income taxes, net of federal tax benefit	11,970			11,799			20,334
Other, net	942			6,859			1,171
Income tax provision from continuing operations	$	163,382		$	215,195		$	226,048

Schedule of Deferred Tax Assets and Liabilities

The following table sets forth the tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities for the periods indicated:

	December 31, 2013		December 31, 2012
Deferred tax assets	(Thousands of dollars)
Employee benefits and other accrued liabilities	$	78,793	$	128,418
Federal net operating loss	12,484		—
State net operating loss and benefits	38,322		31,990
Energy Services capacity release	46,726		—
Other comprehensive income	78,369		140,802
Other	20,872		1,446
Total deferred tax assets	275,566		302,656
Deferred tax liabilities
Excess of tax over book depreciation and depletion	822,706		760,211
Investment in partnerships	1,217,605		969,347
Regulatory assets	132,676		204,625
Total deferred tax liabilities	2,172,987		1,934,183
Net deferred tax liabilities	$	1,897,421	$	1,631,527

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PROPERTY, PLANT AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Components of Property, Plant and Equipment

The following table sets forth our property, plant and equipment by property type, for the periods indicated:

	Estimated Useful Lives (Years)	December 31, 2013			December 31, 2012
		(Thousands of dollars)
Non-Regulated
Gathering pipelines and related equipment	5 to 40	$	2,173,271		$	1,638,037
Processing and fractionation and related equipment	5 to 40	2,295,983			1,625,146
Storage and related equipment	5 to 54	362,704			335,237
Transmission pipelines and related equipment	22 to 54	302,718			311,038
General plant and other	2 to 60	402,523			348,636
Construction work in process	—	1,112,182			881,788
Regulated
Natural gas distribution pipelines and related equipment	15 to 80	3,703,593			3,512,660
Storage and related equipment	5 to 54	135,922			136,938
Natural gas transmission pipelines and related equipment	5 to 77	1,850,559			1,796,683
Natural gas liquids transmission pipelines and related equipment	5 to 80	2,049,461			1,490,511
General plant and other	2 to 85	324,703			309,119
Construction work in process	—	822,537			703,198
Property, plant and equipment		15,536,156			13,088,991
Accumulated depreciation and amortization - non-regulated		(1,112,192		)	(954,398		)
Accumulated depreciation and amortization - regulated		(2,126,460		)	(2,020,253		)
Net property, plant and equipment		$	12,297,504		$	10,114,340

Average Depreciation Rates for Regulated Property

The average depreciation rates for our regulated property are set forth, by segment, in the following table for the periods indicated:

	Years Ended December 31,
Regulated Property	2013	2012	2011
ONEOK Partners	2.0% - 2.2%	1.9% - 2.2%	1.9% - 2.2%
Natural Gas Distribution	2.0% - 3.0%	2.0% - 3.0%	2.0% - 2.9%

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Other Comprehensive Income [Abstract]
Unrealized gain (losses) on energy marketing and risk management assets/liabilities, tax	$ (5,574)	$ (10,601)	$ (8,670)
Realized (gains) losses in net income, tax	(1,905)	10,327	53,714
Unrealized holding gains (losses) on available-for-sale securities, tax	112	(30)	242
Change in pension and postretirement benefit plan liability, tax	(52,436)	6,977	16,298
Other, tax	$ 0	$ 0	$ 50

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CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (Parenthetical) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Stockholders' Equity [Abstract]
Dividends declared per share of common stock	$ 0.40	$ 1.48	$ 1.27	$ 1.08

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DISCONTINUED OPERATIONS (Details) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses and Interests in Affiliates		$ 32,900,000
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax		0	13,517,000	0
Gain on sale of business, tax impact		8,300,000
Description and timing of discontinued operations		On February 1, 2012, we sold ONEOK Energy Marketing Company, our Natural Gas Distribution segment’s retail natural gas marketing business, to Constellation Energy Group, Inc. for $22.5 million plus working capital.
Revenues	27,607,000			313,371,000
Cost of sales and fuel	25,961,000			302,561,000
Net margin	1,646,000			10,810,000
Operating costs	408,000			7,147,000
Depreciation and amortization	8,000			128,000
Operating income	1,230,000			3,535,000
Other income (expense), net	0			(50,000)
Income taxes	(468,000)	0	(8,749,000)	(1,255,000)
Income from discontinued operations, net	$ 762,000			$ 2,230,000

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SUBSEQUENT EVENTS (Details) (USD $)			3 Months Ended							3 Months Ended			3 Months Ended			3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014 ONE Gas [Member]	Jan. 31, 2014 ONE Gas [Member]	Jan. 31, 2014 ONE Gas [Member] 2.07% notes due February 1, 2019	Jan. 31, 2014 ONE Gas [Member] 3.61% notes due February 1, 2024	Jan. 31, 2014 ONE Gas [Member] 4.658% notes due February 1, 2044	Dec. 31, 2013 Parent Company [Member]	Dec. 31, 2012 Parent Company [Member]	Mar. 31, 2014 Parent Company [Member] Note Payable from Public Offering Due 2022 [Member]	Dec. 31, 2013 Parent Company [Member] Note Payable from Public Offering Due 2022 [Member]	Dec. 31, 2012 Parent Company [Member] Note Payable from Public Offering Due 2022 [Member]	Mar. 31, 2014 Parent Company [Member] Notes Payables due 2015 [Member]	Dec. 31, 2013 Parent Company [Member] Notes Payables due 2015 [Member]	Dec. 31, 2012 Parent Company [Member] Notes Payables due 2015 [Member]	Mar. 31, 2014 ONEOK [Member]
Subsequent Event [Line Items]
Extinguishment of Debt, Amount										$ 152,500,000			$ 400,000,000
Long-term Debt, Gross	7,756,180,000	6,514,047,000		1,200,000,000	300,000,000	300,000,000	600,000,000	1,688,972,000	1,689,190,000		700,000,000	700,000,000		400,000,000	400,000,000
Related Party Transaction, Amounts of Transaction			1,130,000,000
Debt Instrument, Interest Rate, Stated Percentage					2.07%	3.61%	4.658%				4.25%			5.20%
Early Repayment of Senior Debt										150,000,000			429,000,000
Repayments of Commercial Paper																$ 600,500,000

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LONG-TERM DEBT (Details) (USD $)					3 Months Ended	12 Months Ended		3 Months Ended	12 Months Ended						12 Months Ended		12 Months Ended		3 Months Ended					12 Months Ended					12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended				12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Oneok [Member]	Dec. 31, 2012 Oneok [Member]	Mar. 31, 2014 Oneok [Member] Notes Payables due 2015 [Member]	Dec. 31, 2013 Oneok [Member] Notes Payables due 2015 [Member]	Dec. 31, 2012 Oneok [Member] Notes Payables due 2015 [Member]	Mar. 31, 2014 Oneok [Member] Note Payable from Public Offering Due 2022 [Member]	Dec. 31, 2013 Oneok [Member] Note Payable from Public Offering Due 2022 [Member]	Dec. 31, 2012 Oneok [Member] Note Payable from Public Offering Due 2022 [Member]	Dec. 31, 2013 Oneok [Member] Notes Payables due 2035 [Member]	Dec. 31, 2012 Oneok [Member] Notes Payables due 2035 [Member]	Dec. 31, 2013 Oneok [Member] Other Long Term Debt [Member]	Dec. 31, 2012 Oneok [Member] Other Long Term Debt [Member]	Dec. 31, 2013 Oneok [Member] Note Payables 1 due 2028 [Member]	Dec. 31, 2012 Oneok [Member] Note Payables 1 due 2028 [Member]	Dec. 31, 2013 Oneok [Member] Note Payables 2 due 2028 [Member]	Dec. 31, 2012 Oneok [Member] Note Payables 2 due 2028 [Member]	Mar. 31, 2014 ONE Gas [Member]	Jan. 31, 2014 ONE Gas [Member]	Jan. 31, 2014 ONE Gas [Member] Note Payables 2 due 2028 [Member]	Jan. 31, 2014 ONE Gas [Member] Note Payables due 2024 [Member]	Jan. 31, 2014 ONE Gas [Member] Note Payables due 2044 [Member]	Dec. 31, 2013 Guardian Pipeline [Member]	Dec. 31, 2013 Guardian Pipeline [Member] Notes Payables 1 due 2022 [Member]	Dec. 31, 2012 Guardian Pipeline [Member] Notes Payables 1 due 2022 [Member]	Dec. 31, 2013 Partnership Interest [Member]	Dec. 31, 2012 Partnership Interest [Member]	Dec. 31, 2013 Partnership Interest [Member] Note Payable from Public Offering Due 2023 [Member]	Dec. 31, 2012 Partnership Interest [Member] Note Payable from Public Offering Due 2023 [Member]	Dec. 31, 2013 Partnership Interest [Member] Note Payable from Public Offering Due 2043 [Member]	Dec. 31, 2012 Partnership Interest [Member] Note Payable from Public Offering Due 2043 [Member]	Dec. 31, 2013 Partnership Interest [Member] Notes Payables due 2019 [Member]	Dec. 31, 2012 Partnership Interest [Member] Notes Payables due 2019 [Member]	Dec. 31, 2013 Partnership Interest [Member] Note Payable from Public Offering Due 2016 [Member]	Dec. 31, 2012 Partnership Interest [Member] Note Payable from Public Offering Due 2016 [Member]	Dec. 31, 2013 Partnership Interest [Member] Notes Payable due 2016 [Member]	Dec. 31, 2012 Partnership Interest [Member] Notes Payable due 2016 [Member]	Dec. 31, 2013 Partnership Interest [Member] Note Payable from Public Offering Due 2017 [Member]	Dec. 31, 2012 Partnership Interest [Member] Note Payable from Public Offering Due 2017 [Member]	Dec. 31, 2012 Partnership Interest [Member] Notes Payables due 2012 [Member]	Dec. 31, 2012 Partnership Interest [Member] Notes Payable due 2011 [Member]	Dec. 31, 2013 Partnership Interest [Member] Note Payable from Public Offering Due 2022 [Member]	Dec. 31, 2012 Partnership Interest [Member] Note Payable from Public Offering Due 2022 [Member]	Dec. 31, 2013 Partnership Interest [Member] Notes Payables due 2036 [Member]	Dec. 31, 2012 Partnership Interest [Member] Notes Payables due 2036 [Member]	Dec. 31, 2013 Partnership Interest [Member] Notes Payables due 2037 [Member]	Dec. 31, 2012 Partnership Interest [Member] Notes Payables due 2037 [Member]	Dec. 31, 2013 Partnership Interest [Member] Note Payable from Public Offering Due 2041 [Member]	Dec. 31, 2012 Partnership Interest [Member] Note Payable from Public Offering Due 2041 [Member]	Dec. 31, 2013 Partnership Interest [Member] Note Payable from Public Offering Due 2018 [Member]	Dec. 31, 2012 Partnership Interest [Member] Note Payable from Public Offering Due 2018 [Member]	Dec. 31, 2012 Notes Payables due 2012 [Member] Partnership Interest [Member]	Mar. 31, 2012 Notes Payables due 2012 [Member] Partnership Interest [Member] Note Payable from Public Offering Due 2017 [Member]	Dec. 31, 2013 Senior Notes [Member] Partnership Interest [Member]	Dec. 31, 2012 Senior Notes [Member] Partnership Interest [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date																								Sep. 30, 2022																	Apr. 01, 2012	Mar. 15, 2011												Apr. 01, 2012
Long-term Debt, Gross	$ 7,756,180,000	$ 6,514,047,000	$ 1,688,972,000	$ 1,689,190,000		$ 400,000,000	$ 400,000,000		$ 700,000,000	$ 700,000,000	$ 400,000,000	$ 400,000,000	$ 1,323,000	$ 1,528,000	$ 87,649,000	$ 87,662,000	$ 100,000,000	$ 100,000,000		$ 1,200,000,000	$ 300,000,000	$ 300,000,000	$ 600,000,000		$ 67,208,000	$ 74,857,000	$ 6,067,208,000	$ 4,824,857,000	$ 425,000,000	$ 0	$ 400,000,000	$ 0	$ 500,000,000	$ 500,000,000	$ 650,000,000	$ 650,000,000	$ 450,000,000	$ 450,000,000	$ 400,000,000	$ 400,000,000	$ 350,000,000		$ 900,000,000	$ 900,000,000	$ 600,000,000	$ 600,000,000	$ 600,000,000	$ 600,000,000	$ 650,000,000	$ 650,000,000	$ 425,000,000	$ 0	$ 350,000,000
Long-term Debt, Weighted Average Interest Rate																									7.85%
Interest Rate (in hundredths)						5.20%			4.25%		6.00%				6.50%		6.875%				2.07%	3.61%	4.658%						5.00%		6.20%		8.625%		3.25%		6.15%		2.00%		5.90%		3.375%		6.65%		6.85%		6.125%		3.20%		5.90%
Unamortized portion of terminated swaps	25,340,000	27,058,000
Unamortized debt discount	(15,889,000)	(14,878,000)
Current maturities	(10,656,000)	(10,855,000)
Debt instrument call feature						ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest.  ONEOK may redeem the remaining balance of its 4.25-percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.			ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest.  ONEOK may redeem the remaining balance of its 4.25-percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.		ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest.  ONEOK may redeem the remaining balance of its 4.25-percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.				ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest.  ONEOK may redeem the remaining balance of its 4.25-percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.		ONEOK may redeem the senior notes due 2015, 2028 (6.875 percent) and 2035, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK may redeem the senior notes due 2028 (6.5 percent), in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest.  ONEOK may redeem the remaining balance of its 4.25-percent senior notes due 2022 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting three months before the maturity date.  Prior to this date, ONEOK may redeem these senior notes on the same basis as its other senior notes due 2015, 2028 (6.875 percent) and 2035.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK’s senior notes due 2015, 2022, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.												ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.				ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.		ONEOK Partners may redeem its senior notes due 2016 (6.15 percent), 2019, 2036 and 2037, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium.  The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date.  ONEOK Partners may redeem its senior notes due 2017 and its senior notes due 2022 at par starting one month and three months, respectively, before their maturity dates. ONEOK Partners may redeem its senior notes due 2016 (3.25 percent) and 2041 at a redemption price equal to the principal amount, plus accrued and unpaid interest, starting one month and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners may redeem these senior notes in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. ONEOK Partners’ may redeem its senior notes due 2018, 2023, and 2043 at par, plus accrued and unpaid interest to the redemption date, starting one month, three months, and six months, respectively, before their maturity dates. Prior to these dates, ONEOK Partners’ may redeem these notes, in whole or in part, at a redemption price equal to the principal amount, plus accrued and unpaid interest and a make-whole premium. The redemption price will never be less than 100 percent of the principal amount of the respective note plus accrued and unpaid interest to the redemption date. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and are structurally subordinate to all of the existing and future debt and other liabilities of any nonguarantor subsidiaries.  ONEOK Partners’ senior notes are nonrecourse to ONEOK.
Debt instrument covenant description						The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full.			The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full.		The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full.				The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full.		The indentures governing ONEOK’s senior notes due 2028 (6.5 percent and 6.875 percent) include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015, 2022 and 2035 include an event of default upon the acceleration of other indebtedness of $100 million or more.  Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2015, 2022, 2028 and 2035 to declare those senior notes immediately due and payable in full.								The Guardian Pipeline senior notes were issued under a master shelf agreement dated November 8, 2001, with certain financial institutions.  Principal payments are due quarterly through 2022. These senior notes contain financial covenants that require the maintenance of certain ratios defined in the master shelf agreement based on Guardian Pipeline’s financial position and results of operations.  Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately.  At December 31, 2013, Guardian Pipeline was in compliance with its financial covenants.				ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.				ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.		ONEOK Partners senior notes are governed by an indenture, dated as of September 25, 2006, between ONEOK Partners and Wells Fargo Bank, N.A., the trustee, as supplemented. The indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and to sell and lease back its property. The indenture includes an event of default upon acceleration of other indebtedness of $100 million or more. Such events of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of any of ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.
2014	10,700,000		3,000,000																						7,700,000		0
2015	410,700,000		403,000,000																						7,700,000		0
2016	1,110,700,000		3,000,000																						7,700,000		1,100,000,000
2017	410,700,000		3,000,000																						7,700,000		400,000,000
2018	435,700,000		3,000,000																						7,700,000		425,000,000
Underwritten public offering																																																							1,250,000,000	1,300,000,000
Net proceeds from public offering										694,300,000									1,190,000,000																																				1,240,000,000	1,290,000,000
Related Party Transaction, Amounts of Transaction																			1,130,000,000
Extinguishment of Debt, Amount					400,000,000			152,500,000
Early Repayment of Senior Debt					429,000,000			150,000,000
Long-term debt	$ 7,754,975,000	$ 6,515,372,000
MasterShelfAgreementInitiationDate																								November 8, 2001

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ONEOK PARTNERS

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

ONEOK PARTNERS

Q. ONEOK PARTNERS

Ownership Interestin ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below as of December 31, 2013:

General partner interest	2.0	%
Limited partner interest (a)	39.2	%
Total ownership interest	41.2	%

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

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 its 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 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.

As a result of these transactions, ONEOK’s 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 its 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.  As a result of these transactions, our aggregate ownership interest in ONEOK Partners increased to 43.4 percent at December 31, 2012, from 42.8 percent at December 31, 2011.

We account for the difference between the carrying amount of our investment in ONEOK Partners and the underlying book value arising from issuance of common units by ONEOK Partners as an equity transaction.  If ONEOK Partners issues common units at a price different than our carrying value per unit, we account for the premium or deficiency as an adjustment to paid-in capital.  As a result of ONEOK Partners’ issuance of common units, we recognized an increase to paid-in capital of approximately $87.3 million, net of taxes, in 2013 and a decrease to paid-in capital of approximately $51.1 million, net of taxes, in 2012.

Cash Distributions - We receive distributions from ONEOK Partners on our common and Class B units and our 2 percent general partner interest, which includes our incentive distribution rights.  Under ONEOK Partners’ partnership agreement, as amended, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash as defined in the ONEOK Partners partnership agreement (Partnership Agreement), as amended.  Available cash generally will be distributed 98 percent to limited partners and 2 percent to the general partner.  The general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter.  In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among the general partner and limited partners to reflect the two-for-one unit split of ONEOK Partners’ common units.  Under the incentive distribution provisions, as set forth in ONEOK Partners’ partnership agreement, as amended, the general partner receives:

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

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

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

The following table shows ONEOK Partners’ distributions paid during the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	2.870	$	2.590	$	2.325
General partner distributions	$	18,193	$	15,217	$	12,189
Incentive distributions	251,664		186,130		123,386
Distributions to general partner	269,857		201,347		135,575
Limited partner distributions to ONEOK	266,302		235,442		197,132
Limited partner distributions to noncontrolling interest	373,554		324,123		276,739
Total distributions paid	$	909,713	$	760,912	$	609,446

ONEOK Partners’ distributions are declared and paid within 45 days of the end of each quarter. The following table shows ONEOK Partners’ distributions declared for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands, except per unit amounts)
Distribution per unit	$	2.890	$	2.690	$	2.365
General partner distributions	$	18,625	$	16,355	$	12,515
Incentive distributions	259,466		210,095		131,212
Distributions to general partner	278,091		226,450		143,727
Limited partner distributions to ONEOK	268,157		249,600		200,524
Limited partner distributions to noncontrolling interest	384,988		341,704		281,500
Total distributions declared	$	931,236	$	817,754	$	625,751

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

ONEOK Partners accounted for this acquisition as a business combination, which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition-date fair values. The excess of the purchase price over the fair values of the identifiable assets acquired was recorded as goodwill.

The purchase price and assessment of the fair value of the assets acquired and liabilities assumed were as follows (in thousands):

	Total
Property, plant and equipment
Gathering pipelines and related equipment	$	59,174
Processing and fractionation and related equipment	50,595
General plant and other	120
Intangible assets	103,000
Identifiable assets acquired	212,889
Goodwill	92,000
Total purchase price	$	304,889

Identifiable intangible assets recognized in the Sage Creek acquisition are primarily related to natural gas gathering and processing and natural gas liquids supply contracts and customer relationships. The basis for determining the value of these intangible assets is the estimated future net cash flows to be derived from acquired supply contracts and customer relationships, which are offset with appropriate charges for the use of contributory assets and discounted using a risk-adjusted discount rate. Those intangible assets are being amortized on a straight-line basis over a period ranging from 20 to 30 years, which represents the periods during which the customer contracts and relationships are expected to contribute to ONEOK Partners’ cash flows.

Revenues and earnings related to the Sage Creek acquisition are included within ONEOK Partners’ Consolidated Statement of Comprehensive Income since the acquisition dates. Supplemental pro forma revenue and earnings reflecting this acquisition as if it had occurred as of January 1, 2013, are not materially different from the information presented in ONEOK Partners’ accompanying Consolidated Statement of Comprehensive Income since the historical operations of this acquisition were insignificant relative to ONEOK Partners’ historical operations and are, therefore, not presented.

In December 2013, ONEOK Partners acquired the remaining 30 percent undivided interest in its Maysville natural gas processing facility for $90 million. Beginning December 1, 2013, the results of operations for its 100 percent interest are included in our ONEOK Partners segment.

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

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

ONEOK Partners sells natural gas from its natural gas gathering and processing operations to our Energy Services segment.  In addition, a portion of ONEOK Partners’ revenues from its natural gas pipelines business is from our Energy Services and Natural Gas Distribution segments, which contract with ONEOK Partners for natural gas transportation and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and its natural gas gathering and processing operations. As a result of the wind down activities discussed in Note B, our Energy Services segment will not execute affiliate transactions with ONEOK Partners after the wind down is completed. ONEOK Partners expects to continue providing midstream services, including marketing natural gas, NGLs and condensate as a service for third parties or other ONEOK affiliates. ONEOK Partners expects to enter into future commodity derivative financial contracts with unaffiliated third parties or ONEOK affiliates.

Previously, ONEOK Partners had a Processing and Services Agreement with us and OBPI, under which it 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. In June 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.

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

The following table shows ONEOK Partners’ transactions with us for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
	(Thousands of dollars)
Revenues	$	340,743	$	352,099	$	403,603
Expenses
Cost of sales and fuel	$	37,963	$	33,094	$	48,163
Administrative and general expenses	265,448		246,050		251,239
Total expenses	$	303,411	$	279,144	$	299,402

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EMPLOYEE BENEFIT PLANS (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Deferred tax liabilities		$ 2,172,987,000	$ 1,934,183,000
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	0
Description of plan amendment		In December 2011, we announced to participants a change from a self-insured postretirement medical plan to a fully insured solution for plan participants who are medicare eligible.  This announcement resulted in a $44.6 million reduction in our accumulated postretirement benefit obligation that was recognized in other comprehensive income and will be amortized to net periodic benefit cost over the expected remaining years of service for plan participants.
Amounts recognized in other comprehensive income (loss) [Abstract]
Total recognized in other comprehensive income (loss)		83,126,000	(11,061,000)	(25,837,000)
Amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense [Abstract]
Regulatory asset for regulated entities		(383,600,000)	(585,000,000)
Accumulated other comprehensive income (loss), net of tax		(79,676,000)	(162,802,000)	(151,741,000)
Weighted average assumptions used to determine benefit obligations [Abstract]
Compensation increase rate - benefit obligation - minimum (in hundredths)		3.35%	3.45%	3.20%
Compensation increase rate, maximum (in hundredths)		3.40%	3.50%	3.80%
Weighted-average assumptions used to determine net periodic benfit costs [Abstract]
Expected long-term return on plan assets (in hundredths)		8.25%	8.25%	8.25%
Compensation increase rate, minimum (in hundredths)		3.45%	3.20%	3.30%
Compensation increase rate, maximum (in hundredths)		3.50%	3.80%	3.90%
Description of basis used to determine overall expected long-term rate of return on plan assets		We determine our overall expected long-term rate of return on plan assets, based on our review of historical returns and economic growth models. We determine our discount rates annually.  We estimate our discount rate based upon a comparison of the expected cash flows associated with our future payments under our pension and postretirement obligations to a hypothetical bond portfolio created using high-quality bonds that closely match expected cash flows.  Bond portfolios are developed by selecting a bond for each of the next 60 years based on the maturity dates of the bonds.  Bonds selected to be included in the portfolios are only those rated by Moody’s as AA- or better and exclude callable bonds, bonds with less than a minimum issue size, yield outliers and other filtering criteria to remove unsuitable bonds.
Assumed health care cost trend rates [Abstract]
Year that the rate reaches the ultimate trend rate		2022	2022
One percentage point change in assumed healthcare cost trend rates [Abstract]
Effect of a one percentage point increase on total of service and interest cost		1,136,000
Effect of a one percentage point increase on postretirement benefit obligation		15,152,000
Effect of a one percentage point decrease on total of service and interest cost		(1,022,000)
Effect of a one percentage point decrease on postretirement benefit obligation		(14,350,000)
Target allocation for assets of the pension plan [Abstract]
U.S. large-cap equities		37.00%
Aggregate bonds		24.00%
Developed foreign large-cap equities		10.00%
Alternative investments		8.00%
Mid-cap equities		6.00%
Emerging markets equities		5.00%
Small-cap equities		4.00%
High yield bonds		3.00%
Developed foreign bonds		2.00%
Emerging market bonds		1.00%
Total		100.00%
Other Employee Benefit Plans - Thrift Plan [Abstract]
Contributions made to the Thrift Plan		17,000,000	16,400,000	15,900,000
Percent of employee contributions matched of eligible compensation (in hundredths)		100.00%
Maximum percentage of each participant's eligible compensation, subject to certain limits, matching (in hundredths)		6.00%
Profit-Sharing Plan [Abstract]
Contributions made to the Profit-Sharing Plan		5,100,000	6,600,000	6,700,000
Profit sharing contribution percentage		1.00%
Natural Gas Distribution [Member]
Defined Benefit Plan Disclosure [Line Items]
Deferred tax liabilities		86,000,000
Defined Benefit Plan, Fair Value of Plan Assets		1,000,000,000
Change in Benefit Obligation [Roll Forward]
Benefit obligation, end of period		1,100,000,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		1,000,000,000
Amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense [Abstract]
Regulatory asset for regulated entities		(376,800,000)	(577,100,000)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		1,112,749,000	995,264,000	902,235,000
Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	1,221,449,000	1,313,560,000	1,215,932,000
Service cost		22,968,000	21,301,000	20,013,000
Interest cost		54,449,000	59,237,000	58,757,000
Plan participants' contributions		0	0
Actuarial (gain) loss		(110,552,000)	105,732,000
Benefits paid		(58,976,000)	(88,642,000)
Plan amendment		0	0
Benefit obligation, end of period		1,221,449,000	1,313,560,000	1,215,932,000
Change in Plan Assets [Roll Forward]
Fair value of plan assets, beginning of period	1,112,749,000	995,264,000	902,235,000
Actual return on plan assets		176,889,000	90,026,000
Employer contributions		0	91,881,000
Benefits paid		(59,404,000)	(88,878,000)
Fair value of assets, end of period		1,112,749,000	995,264,000	902,235,000
Balance at December 31		(108,700,000)	(318,296,000)
Current liabilities		(5,457,000)	(4,695,000)
Non-current liabilities		(103,243,000)	(313,601,000)
Balance at December 31		(108,700,000)	(318,296,000)
Accumulated benefit obligation for pension plans		1,159,000,000	1,240,300,000
Components of net periodic benefit cost [Abstract]
Service cost		22,968,000	21,301,000	20,013,000
Interest cost		54,449,000	59,237,000	58,757,000
Expected return on assets		(81,272,000)	(82,756,000)	(75,500,000)
Amortization of unrecognized prior service cost		920,000	969,000	1,018,000
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0
Amortization of net loss		66,282,000	48,439,000	35,708,000
Settlements		1,338,000	1,401,000	0
Net periodic benefit cost		64,685,000	48,591,000	39,996,000
Amounts recognized in other comprehensive income (loss) [Abstract]
Regulatory asset gain (loss)		(110,437,000)	67,472,000	114,625,000
Net gain (loss) arising during the period		201,251,000	(103,199,000)	(182,987,000)
Amortization of regulatory asset		(44,378,000)	(32,527,000)	(23,265,000)
Prior service credit (cost)	193,000	920,000	969,000	1,018,000
Amortization of loss		67,620,000	49,839,000	35,708,000
Deferred income taxes		(44,473,000)	6,748,000	21,236,000
Total recognized in other comprehensive income (loss)		70,503,000	(10,698,000)	(33,665,000)
Amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense [Abstract]
Transition obligation		0	0
Prior service credit (cost)		(1,102,000)	(2,022,000)
Accumulated gain (loss)		(415,375,000)	(684,245,000)
Accumulated other comprehensive income (loss) before regulatory assets		(416,477,000)	(686,267,000)
Regulatory asset for regulated entities		288,017,000	442,833,000
Accumulated other comprehensive income (loss) after regulatory assets		(128,460,000)	(243,434,000)
Deferred income taxes		49,689,000	94,161,000
Accumulated other comprehensive income (loss), net of tax		(78,771,000)	(149,273,000)
Amounts to be recognized in 2014 [Abstract]
Prior service credit (cost)	193,000	920,000	969,000	1,018,000
Net loss	15,021,000
Weighted average assumptions used to determine benefit obligations [Abstract]
Discount rate (in hundredths)		5.25%	4.25%
Weighted-average assumptions used to determine net periodic benfit costs [Abstract]
Discount rate (in hundredths)		4.25%	5.00%	5.50%
Level 3 fair value measurements [Roll Forward]
Balance at beginning of period	137,404,000	138,173,000	137,061,000
Actual return on plan assets held at the reporting date		(769,000)	1,112,000
Balance at end of period		137,404,000	138,173,000	137,061,000
Benefits to be paid in: [Abstract]
2014		63,856,000
2015		64,588,000
2016		66,477,000
2017		68,626,000
2018		70,873,000
2019 through 2023		386,366,000
Pension Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		708,289,000	574,835,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		708,289,000	574,835,000
Pension Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		267,056,000	282,256,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		267,056,000	282,256,000
Pension Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		137,404,000	138,173,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		137,404,000	138,173,000
Pension Benefits [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		1,112,749,000	995,264,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		1,112,749,000	995,264,000
Pension Benefits [Member] | Corporate Obligations [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Corporate Obligations [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		95,432,000	104,078,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		95,432,000	104,078,000
Pension Benefits [Member] | Corporate Obligations [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Corporate Obligations [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		95,432,000	104,078,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		95,432,000	104,078,000
Pension Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member]
Level 3 fair value measurements [Roll Forward]
Balance at beginning of period		70,411,000	70,818,000
Actual return on plan assets held at the reporting date		(6,953,000)	(407,000)
Balance at end of period		63,458,000	70,411,000
Pension Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		63,458,000	70,411,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		63,458,000	70,411,000
Pension Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		63,458,000	70,411,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		63,458,000	70,411,000
Pension Benefits [Member] | Other Investments [Member]
Level 3 fair value measurements [Roll Forward]
Balance at beginning of period		67,762,000	66,243,000
Actual return on plan assets held at the reporting date		6,184,000	1,519,000
Balance at end of period		73,946,000	67,762,000
Pension Benefits [Member] | Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Other Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Other Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		73,946,000	67,762,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		73,946,000	67,762,000
Pension Benefits [Member] | Other Investments [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		73,946,000	67,762,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		73,946,000	67,762,000
Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		680,590,000	541,539,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		680,590,000	541,539,000
Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		60,336,000	61,242,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		60,336,000	61,242,000
Pension Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		740,926,000	602,781,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		740,926,000	602,781,000
Pension Benefits [Member] | Government Obligations [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Government Obligations [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		111,288,000	116,936,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		111,288,000	116,936,000
Pension Benefits [Member] | Government Obligations [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Government Obligations [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		111,288,000	116,936,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		111,288,000	116,936,000
Pension Benefits [Member] | Cash and Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		27,699,000	33,296,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		27,699,000	33,296,000
Pension Benefits [Member] | Cash and Money Market Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Cash and Money Market Funds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Pension Benefits [Member] | Cash and Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		27,699,000	33,296,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		27,699,000	33,296,000
Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Minimum number of years of service for certain employees to be eligible to participate in welfare plans that provide postretirement medical and life insurance benefits		5
Defined Benefit Plan, Fair Value of Plan Assets		175,635,000	148,162,000	124,163,000
Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of period	289,147,000	299,172,000	286,044,000
Service cost		4,612,000	4,960,000	4,987,000
Interest cost		11,713,000	13,893,000	15,632,000
Plan participants' contributions		4,293,000	5,851,000
Actuarial (gain) loss		(29,460,000)	9,935,000
Benefits paid		(18,411,000)	(21,380,000)
Plan amendment		17,228,000	(131,000)
Benefit obligation, end of period		289,147,000	299,172,000	286,044,000
Change in Plan Assets [Roll Forward]
Fair value of plan assets, beginning of period	175,635,000	148,162,000	124,163,000
Actual return on plan assets		27,483,000	14,273,000
Employer contributions		866,000	10,728,000
Benefits paid		(876,000)	(1,002,000)
Fair value of assets, end of period		175,635,000	148,162,000	124,163,000
Balance at December 31		(113,512,000)	(151,010,000)
Current liabilities		0	0
Non-current liabilities		(113,512,000)	(151,010,000)
Balance at December 31		(113,512,000)	(151,010,000)
Defined Benefit Plan, Contributions by Employer Including Claims Paid Directly		11,800,000
Components of net periodic benefit cost [Abstract]
Service cost		4,612,000	4,960,000	4,987,000
Interest cost		11,713,000	13,893,000	15,632,000
Expected return on assets		(12,259,000)	(10,687,000)	(10,272,000)
Amortization of unrecognized prior service cost		(6,442,000)	(8,252,000)	(2,518,000)
Defined Benefit Plan, Amortization of Transition Obligations (Assets)		284,000	2,874,000	3,189,000
Amortization of net loss		12,605,000	13,184,000	8,123,000
Net periodic benefit cost		10,513,000	15,972,000	19,141,000
Amounts recognized in other comprehensive income (loss) [Abstract]
Regulatory asset gain (loss)		(7,674,000)	4,376,000	7,389,000
Net gain (loss) arising during the period		44,685,000	(6,348,000)	(40,765,000)
Amortization of regulatory asset		(5,643,000)	(6,557,000)	(7,214,000)
Amortization of transition obligation	0	284,000	2,874,000	3,189,000
Prior service credit (cost)	(1,662,000)	(6,442,000)	(8,252,000)	(2,518,000)
Amortization of loss		12,605,000	13,184,000	8,123,000
Defined Benefit Plan, Plan Amendments		(17,228,000)	131,000	44,562,000
Deferred income taxes		(7,964,000)	229,000	(4,938,000)
Total recognized in other comprehensive income (loss)		12,623,000	(363,000)	7,828,000
Amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense [Abstract]
Transition obligation		0	(283,000)
Prior service credit (cost)		14,631,000	38,301,000
Accumulated gain (loss)		(59,362,000)	(116,652,000)
Accumulated other comprehensive income (loss) before regulatory assets		(44,731,000)	(78,634,000)
Regulatory asset for regulated entities		43,254,000	56,571,000
Accumulated other comprehensive income (loss) after regulatory assets		(1,477,000)	(22,063,000)
Deferred income taxes		572,000	8,534,000
Accumulated other comprehensive income (loss), net of tax		(905,000)	(13,529,000)
Amounts to be recognized in 2014 [Abstract]
Transition obligation	0	284,000	2,874,000	3,189,000
Prior service credit (cost)	(1,662,000)	(6,442,000)	(8,252,000)	(2,518,000)
Net loss	833,000
Weighted average assumptions used to determine benefit obligations [Abstract]
Discount rate (in hundredths)		5.00%	4.00%
Weighted-average assumptions used to determine net periodic benfit costs [Abstract]
Discount rate (in hundredths)		4.00%	5.00%	5.50%
Benefits to be paid in: [Abstract]
2014		16,251,000
2015		17,135,000
2016		18,142,000
2017		19,095,000
2018		19,875,000
2019 through 2023		106,346,000
Assumed health care cost trend rates [Abstract]
Health care cost-trend rate assumed for next year - minimum (in hundredths)		4.00%	4.00%
Health care cost-trend rate assumed for next year - maximum (in hundredths)		8.25%	9.00%
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate) - minimum (in hundredths)		4.00%	4.00%
Rate to which the cost-trend rate is assumed to decline (the ultimate trend rate) - maximum (in hundredths)		5.00%	5.00%
Postretirement Benefits [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		68,939,000	57,381,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		68,939,000	57,381,000
Postretirement Benefits [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		106,587,000	90,625,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		106,587,000	90,625,000
Postretirement Benefits [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		109,000	156,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		109,000	156,000
Postretirement Benefits [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		175,635,000	148,162,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		175,635,000	148,162,000
Postretirement Benefits [Member] | Corporate Obligations [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		17,207,000	17,522,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		17,207,000	17,522,000
Postretirement Benefits [Member] | Corporate Obligations [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		142,000	238,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		142,000	238,000
Postretirement Benefits [Member] | Corporate Obligations [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Corporate Obligations [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		17,349,000	17,760,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		17,349,000	17,760,000
Postretirement Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		106,189,000	89,979,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		106,189,000	89,979,000
Postretirement Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Insurance Contracts and Group Annuity Contracts [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		106,189,000	89,979,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		106,189,000	89,979,000
Postretirement Benefits [Member] | Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Other Investments [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Other Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		109,000	156,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		109,000	156,000
Postretirement Benefits [Member] | Other Investments [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		109,000	156,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		109,000	156,000
Postretirement Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		37,796,000	21,548,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		37,796,000	21,548,000
Postretirement Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		90,000	140,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		90,000	140,000
Postretirement Benefits [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Equity Securities [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		37,886,000	21,688,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		37,886,000	21,688,000
Postretirement Benefits [Member] | Government Obligations [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Government Obligations [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		166,000	268,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		166,000	268,000
Postretirement Benefits [Member] | Government Obligations [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Government Obligations [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		166,000	268,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		166,000	268,000
Postretirement Benefits [Member] | Cash and Money Market Funds [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		13,936,000	18,311,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		13,936,000	18,311,000
Postretirement Benefits [Member] | Cash and Money Market Funds [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Cash and Money Market Funds [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0	0
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		0	0
Postretirement Benefits [Member] | Cash and Money Market Funds [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		13,936,000	18,311,000
Change in Plan Assets [Roll Forward]
Fair value of assets, end of period		13,936,000	18,311,000
Pension and postretirement unrecognized losses [Member] | Natural Gas Distribution [Member]
Amounts in accumulated other comprehensive income (loss) that had not yet been recognized as components of net periodic benefit expense [Abstract]
Regulatory asset for regulated entities		$ (331,100,000)

XML

DISCONTINUED OPERATIONS (Tables)

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

The amounts of revenue, costs and income taxes reported in discontinued operations are set forth in the table below for the periods indicated:

	One Month Ended			Year Ended
	January 31,			December 31,
	2012			2011
	(Thousands of dollars)
Revenues	$	27,607		$	313,371
Cost of sales and fuel	25,961			302,561
Net margin	1,646			10,810
Operating costs	408			7,147
Depreciation and amortization	8			128
Operating income	1,230			3,535
Other income (expense), net	—			(50		)
Income taxes	(468		)	(1,255		)
Income from discontinued operations, net	$	762		$	2,230

XML

EQUITY

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

EQUITY

J. EQUITY

Series A and B Convertible Preferred Stock - There are no shares of Series A or Series B Preferred Stock currently issued or outstanding.

Series C Preferred Stock - The Series C Preferred Stock (Series C) was issuable in connection with our now expired ONEOK Rights Agreement, which was designed to protect our shareholders from coercive or unfair takeover tactics.  No shares of Series C were issued, and the ONEOK Rights Agreement expired February 4, 2013, and was not renewed.

Common Stock - At December 31, 2013, we had approximately 362.4 million shares of authorized and unreserved common stock available for issuance.

Dividends - Dividends paid totaled $304.7 million, $262.0 million and $227.0 million for 2013, 2012 and 2011, respectively. The following table sets forth the quarterly dividends per share declared and paid on our common stock for the periods indicated:

	Years Ended December 31,
	2013		2012		2011
First Quarter	$	0.36	$	0.305	$	0.26
Second Quarter	$	0.36	$	0.305	$	0.26
Third Quarter	$	0.38	$	0.33	$	0.28
Fourth Quarter	$	0.38	$	0.33	$	0.28
Total	$	1.48	$	1.27	$	1.08

Additionally, a quarterly dividend of $0.40 per share was declared in January 2014, payable in the first quarter 2014.

Stock Repurchase Program - Our three-year stock repurchase program, which expired on December 31, 2013, was authorized by our Board of Directors in October 2010 to buy up to $750 million of our common stock.  We executed a $300 million repurchase of approximately 8.6 million shares in 2011, a $150 million repurchase of approximately 3.4 million shares in September 2012 and did not repurchase any shares of our common stock in 2013.

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