Edgar Filing: ONEOK INC /NEW/

form_10-k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2010.

__ 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. __

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition 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, 2010, was $4.6 billion.

On February 14, 2011, the Company had 107,021,170 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 25, 2011, are incorporated by reference in Part III.

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ONEOK, Inc.

2010 ANNUAL REPORT

Part I.		Page No.
Item 1. Item 1A. Item 1B.	Business Risk Factors Unresolved Staff Comments	5-18 18-30 30
Item 2.	Properties	30-32
Item 3.	Legal Proceedings	32-33
Item 4.	Submission of Matters to a Vote of Security Holders	33
Part II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33-35
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	36-62
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	62-65
Item 8.	Financial Statements and Supplementary Data	66-116
Item 9. Item 9A. Item 9B.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information	117 117 117
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance	117-118
Item 11.	Executive Compensation	118
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	118-119
Item 13.	Certain Relationships and Related Transactions, and Director Independence	119
Item 14.	Principal Accounting Fees and Services	119
Part IV.
Item 15.	Exhibits, Financial Statement Schedules	119-126
Signatures		127

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, 2010

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

Btu(s)

British thermal units, a measure of the amount of heat required to raise the

temperature of one pound of water one degree Fahrenheit

Bushton Plant

Bushton Gas Processing 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

EBITDA

Earnings before interest expense, income taxes, depreciation and amortization

EBITDAR

Earnings before interest expense, income taxes, depreciation and amortization and

rent expense

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.

Heartland

Heartland Pipeline Company

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

Mcf

Thousand cubic feet

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

OCC

Oklahoma Corporation Commission

ONEOK

ONEOK, Inc.

ONEOK Credit Agreement

ONEOK’s amended and restated $1.2 billion revolving credit agreement dated

July 14, 2006

ONEOK Partners

ONEOK Partners, L.P.

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ONEOK Partners Credit Agreement

ONEOK Partners’ $1.0 billion amended and restated revolving credit agreement

dated March 30, 2007

ONEOK Partners GP

ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the sole

general partner of ONEOK Partners

OPIS

Oil Price Information Service

Overland Pass Pipeline Company

Overland Pass Pipeline Company LLC

Quarterly Report

Quarterly Report(s) on Form 10-Q

RRC

Railroad Commission of Texas

S&P

Standard & Poor’s Rating Group

SEC

Securities and Exchange Commission

Securities Act

Securities Act of 1933, as amended

TransCanada

TransCanada Corporation

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 known as Oklahoma Natural Gas Company. Our common stock is listed on the NYSE under the trading symbol “OKE.” We are the sole general partner and own 42.8 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest publicly traded master limited partnerships. 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. We are 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. Our largest distribution markets are Oklahoma City and Tulsa, Oklahoma; Kansas City, Wichita and Topeka, Kansas; and Austin and El Paso, Texas. Our energy services business is engaged in providing premium natural gas marketing services to its customers across the United States.

DESCRIPTION OF BUSINESS

We report operations in the following business segments:

·	ONEOK Partners;

·	Distribution; and

·	Energy Services.

Business Strategy

Our primary business strategy is to deliver consistent growth and sustainable earnings, while focusing on safe, reliable, environmentally responsible and legally compliant operations for our customers, employees, contractors and the public through the following:

·	Operate in a safe, reliable and environmentally responsible manner - environmental, safety and health issues continue to be a primary focus for us; our emphasis on environmental, safety and health initiatives has produced improvements in the key indicators we track;

Increase distributable cash flow at our ONEOK Partners segment through a combination of internal growth projects and strategic acquisitions - during 2010 ONEOK Partners’ cash distributions increased by 1 cent per unit each quarter, approximately a 3-percent increase compared with 2009; ONEOK Partners has added to its fee-based earnings with the completion of its more than $2.0 billion of capital projects in 2009, which generate predominantly fee-based earnings; ONEOK Partners has announced in 2010 and early 2011 an additional $1.8 billion to $2.1 billion in new capital projects in the Bakken Shale, the Cana-Woodford Shale and the Granite Wash areas, which, when completed, ONEOK Partners anticipates will provide additional earnings and cash flows;

Increase operating income in our Distribution segment - our Distribution segment benefited 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; our Distribution segment’s operating efficiencies include investments in automated meters in Oklahoma, upgrades to service-order scheduling and dispatch systems and a driver-monitoring system;

·	Continue our focus on our key markets in our Energy Services segment - our Energy Services segment continues its focus on providing customer-specific premium services and continues to realign its contracted storage and transportation capacity with its customers’ premium-service requirements;

·	Execute strategic acquisitions that provide long-term value - we remain a disciplined buyer of assets and continue to evaluate assets that come to market. We did not consummate any acquisitions in 2010;

·	Manage our balance sheet to maintain strong credit ratings - our balance sheet remains strong, ending 2010 with a capitalization structure of 40-percent debt and 60-percent equity, excluding the debt of ONEOK Partners; we will seek to maintain our investment-grade credit ratings; and

·	Attract, develop and retain 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 development efforts with our current employees.

EXECUTIVE SUMMARY

Our 2010 operating results include the benefits from a full year of operation of more than $2.0 billion in growth projects completed by ONEOK Partners in 2009, reflecting increases in NGL volumes gathered, fractionated and sold, natural gas

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transportation capacity contracted and natural gas volumes processed in the Williston Basin. ONEOK Partners expects continued development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas as drilling activities increase in these areas. Additionally, we benefited from the new rate design that was implemented in Oklahoma in our Distribution segment. Our Energy Services segment continues to align its contracted natural gas transportation and storage capacity with the needs of its premium-services customers to reduce annual earnings volatility.

ONEOK Partners has announced approximately $1.8 billion to $2.1 billion in growth projects, primarily in the Williston Basin in North Dakota and the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas that will enable it to meet the rapidly growing needs of crude oil and natural gas producers as they increase their drilling activities.

Drilling rig counts in Dunn, McKenzie and Williams counties in North Dakota have increased dramatically since the beginning of 2010. The development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin are being driven primarily by crude oil economics, with the associated natural gas production having a high NGL content. Current natural gas processing and natural gas liquids infrastructure in the Williston Basin is being expanded to accommodate the additional production from the increased development activities. ONEOK Partners has announced plans to invest $1.5 to $1.8 billion in the Williston Basin in North Dakota.

In addition to the growth projects in the Williston Basin, ONEOK Partners has announced plans to invest approximately $270 million to $330 million in its existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. The expansions and upgrades will increase its ability to accommodate the growing natural gas and NGL supply from producers and natural gas processors as drilling activities increase in these areas. These investments will expand its ability to transport raw NGLs from these supply areas to fractionation facilities in Kansas, Oklahoma and Texas and distribute NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. A portion of these investments will also allow ONEOK Partners to increase the utilization of its natural gas processing capacity in Oklahoma.

During 2010, we paid cash dividends of $1.82 per share, an increase of approximately 11.0 percent from the $1.64 per share paid during 2009. In January 2011, we declared a dividend of $0.52 per share ($2.08 per share on an annualized basis), an increase of approximately 18.2 percent from the $0.44 declared in January 2010.

During 2010, ONEOK Partners paid cash distributions to its limited partners totaling $4.46 per unit, an increase of approximately 3.0 percent from the $4.33 per unit paid during 2009. In January 2011, a cash distribution to ONEOK Partners’ limited partners of $1.14 per unit ($4.56 per unit on an annualized basis) was declared, an increase of approximately 3.6 percent from the $1.10 declared in January 2010.

During 2010, we relied primarily on operating cash flow, commercial paper and distributions from ONEOK Partners to fund our liquidity and capital requirements. ONEOK Partners utilized available cash, its ONEOK Partners Credit Agreement, commercial paper and the proceeds from the sale of a 49-percent ownership interest in Overland Pass Pipeline Company to fund its liquidity needs, repay $250 million of its maturing senior notes and fund its capital expenditures. Additionally, ONEOK Partners accessed the public equity markets in February 2010, generating net proceeds of approximately $322.7 million for its long-term financing needs.

In January 2011, ONEOK Partners completed an underwritten public offering of senior notes generating net proceeds of approximately $1.28 billion. ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on market conditions and their respective financial condition and credit ratings. We anticipate that our cash flow generated from operations, existing capital resources and distributions from ONEOK Partners will enable us to maintain our current level of operations, our planned operations and fund our three-year, $750 million stock repurchase program. ONEOK Partners anticipates that its cash flow generated from operations, existing capital resources and ability to obtain financing will enable it to maintain its current level of operations and its planned operations, as well as fund its capital expenditures.

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.

SEGMENT FINANCIAL INFORMATION

Operating Income, Customers and Total Assets - See Note Q 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.

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NARRATIVE DESCRIPTION OF BUSINESS

ONEOK Partners

Ownership - We own approximately 42.4 million common and Class B limited partner units, and the entire 2-percent general partner interest, which, together, represents a 42.8-percent ownership interest in ONEOK Partners. 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 O of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our incentive distribution rights.

Description of Business

Natural gas gathering and processing business - ONEOK Partners’ natural gas gathering and processing business is engaged in the gathering and processing of natural gas produced from crude oil and natural gas wells, primarily in the Mid-Continent and Rocky Mountain regions, which include the Anadarko Basin of Oklahoma that contains the NGL-rich Cana-Woodford Shale formation, Hugoton and Central Kansas Uplift Basins of Kansas, the Williston Basin of Montana and North Dakota that includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations, and the Powder River Basin of Wyoming. Through gathering systems, natural gas is aggregated and treated or processed for removal of water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream. In the Powder River Basin, the natural gas that ONEOK Partners gathers is coal-bed methane, or dry natural gas, that does not require processing or NGL extraction, in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

Revenue from the natural gas gathering and processing business is derived primarily from the following three types of contracts:

Percent of proceeds - ONEOK Partners retains a percentage of the NGLs and/or a percentage of the residue gas as payment for gathering, treating, compressing and processing the producer’s natural gas. This type of contract represented approximately 35 percent and 32 percent of gathering and processing contracted volumes for 2010 and 2009, respectively.

·	Fee - ONEOK Partners is paid a fee for the services it provides based on Btus gathered, treated, compressed and/or processed. This type of contract represented approximately 61 percent and 63 percent of gathering and processing contracted volumes for 2010 and 2009, respectively.

Keep-whole - ONEOK Partners extracts NGLs from unprocessed natural gas and returns to the producer volumes of residue gas containing the same amount of Btus as the unprocessed natural gas that was originally delivered. This type of contract represented approximately 4 percent and 5 percent of gathering and processing contracted volumes for 2010 and 2009, respectively, with approximately 85 percent and 84 percent of that contracted volume containing language that effectively converts these contracts into fee contracts when the gross processing spread is negative.

Natural gas pipelines business - ONEOK Partners’ natural gas pipeline business operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners also provides natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act. ONEOK Partners’ FERC-regulated interstate assets transport natural gas through pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.

ONEOK Partners’ revenues from its natural gas pipelines are derived typically from fee-based services provided to its customers. ONEOK Partners’ revenues from its natural gas pipelines are generated under 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 contracts. Under this type of contract, the customer pays a fixed fee for a specified quantity regardless of their actual usage and is generally guaranteed access to the capacity they reserve; and

·	Interruptible service - Customers may utilize available capacity after firm-service requests are satisfied or on an as-available basis. Under the interruptible service contract, the customer is not guaranteed use of our pipelines and storage facilities unless excess capacity is available.

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Natural gas liquids business - ONEOK Partners’ natural gas liquids business gathers, treats, fractionates and transports NGLs and distributes and stores NGL products. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas, as well as to third-party fractionators and third-party pipelines. The NGLs are then separated through the fractionation process into the individual NGL products that realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to petrochemical manufacturers, heating-fuel users, refineries and propane distributors through ONEOK Partners’ FERC-regulated distribution pipelines that move NGL products from Oklahoma and Kansas to the Mid-Continent and Gulf Coast NGL market centers, as well as the Midwest markets near Chicago, Illinois.

Revenue for the natural gas liquids business is derived primarily from fee-based services provided to ONEOK Partners’ customers and physical optimization of its assets. The sources of revenue are categorized as follows:

·	Exchange services - ONEOK Partners gathers and transports unfractionated NGLs to owned and third-party fractionators and third-party pipelines, where they are separated into marketable NGL products and redelivered to a market center for a fee;

Optimization and marketing - ONEOK Partners uses its asset base, portfolio of contracts and market knowledge to capture location and seasonal price differentials through transactions that optimize the flow and value of its NGL products between the major market centers in the Mid-Continent and the Gulf Coast, as well as markets near Chicago, Illinois;

·	Isomerization - ONEOK Partners converts normal butane to the more valuable iso-butane used by the refining industry to increase the octane of motor gasoline;

·	Storage services - ONEOK Partners stores NGLs for a fee; and

·	Transportation - ONEOK Partners transports NGLs under its FERC-regulated tariffs.

The main factors that affect ONEOK Partners’ margins from its natural gas liquids business are:

·	NGL transportation and fractionation volumes and associated fees;

·	natural gas processing, gathering, transportation and storage volumes and associated fees;

·	weather impacts on demand and operations;

·	the differences between the Mid-Continent, Gulf Coast and Rocky Mountain natural gas prices, the crude oil and the daily average prices for its NGL products sold;

·	the relative value of ethane to natural gas; and

·	location and seasonal natural gas and NGL product price differentials.

Market Conditions and Seasonality - Supply - ONEOK Partners’ business is affected by the economy, commodity price volatility and weather. The strength of the economy has a direct relationship on manufacturing and industrial companies’ demand for natural gas and NGL products. Volatility in the commodity markets impacts the decisions of ONEOK Partners’ producers and customers related to the output from natural gas wells, storage activity for natural gas and natural gas liquids, and demand for the various NGL products. In addition, its natural gas liquids pipelines and fractionation facilities are affected by operational or market-driven changes in the output of the natural gas processing plants to which they are connected. Natural gas and NGL output from gas processing plants may increase or decrease, affecting the quality of natural gas and volume of NGLs transported through the systems, as a result of the gross processing spread, which is the difference between the relative Btu value of the composite price of NGLs and the Btu value of natural gas, primarily ethane and natural gas. In addition, volumes delivered through the system may increase or decrease as a result of the relative NGL price fluctuations between the Mid-Continent and Gulf Coast NGL market centers. Natural gas transportation throughput fluctuates due to rainfall that impacts irrigation demand, warmer temperatures that affect power generation demand and cooler temperatures that affect heating demand.

Natural gas and NGL supply is affected by drilling rig availability, operating capability and producer drilling activity, which is sensitive to commodity prices, exploration success, access to capital and regulations. Higher crude oil prices and advances in horizontal drilling and completion technology are having a positive impact on drilling activity in the shale areas, providing an offset to the less favorable supply development in the non-shale areas.

Additionally, significant factors that can impact the supply of Canadian natural gas transported by certain ONEOK Partners’ pipelines are the Canadian natural gas available for export, Canadian storage capacity and United States demand for Canadian natural gas.

Demand - Demand for natural gas gathering and processing services is typically aligned with the production of natural gas. ONEOK Partners’ natural gas processing plant operations can be adjusted to respond to market conditions, such as demand

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for ethane. By changing operating parameters at certain plants, ONEOK Partners can reduce, to some extent, the amount of ethane and propane recovered if prices or processing margins are unfavorable.

Demand for natural gas pipeline transportation service and natural gas storage is related directly to demand for natural gas in the markets that the natural gas pipelines and storage facilities serve, and is affected by weather, the economy and natural gas price volatility. Demand for services can also be impacted as coal-fired electric generators consider natural gas as an alternative fuel. The effect of weather on ONEOK Partners’ natural gas pipelines operations is discussed below under “Seasonality.” The strength of the economy impacts directly manufacturing and industrial companies that consume natural gas. Commodity price volatility can influence customers’ decisions related to the usage of natural gas versus alternative fuels and natural gas storage injection and withdrawal activity.

Demand for NGLs and the ability of natural gas processors to sustain successful and economical operations impacts the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for natural gas liquids gathering, fractionation, storage 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, which are used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil. Ethane/propane mix, propane, normal butane and natural gasoline are used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fiber.

Commodity Prices - Crude oil, natural gas and NGL prices can be volatile due to market conditions. Commodity prices can also be impacted by demand for products by the petrochemical industry and other consumers, storage injection and withdrawal rates and available storage capacity. 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 percent-of-proceeds contracts and in its natural gas liquids business from the NGLs it purchases and sells. ONEOK Partners is also exposed to market risk associated with the price differentials between receipt and delivery points along its natural gas and natural gas liquids pipelines, also known as basis differentials. Fluctuations in basis differentials impact the rates its natural gas pipelines’ customers with competitive alternatives are willing to pay and the optimization opportunities for its natural gas liquids business. ONEOK Partners’ natural gas and NGL storage revenues are impacted by the differential between the forward price of natural gas and NGLs and the price of natural gas and NGLs on the spot market. Additionally, fluctuations in the relative price differential between natural gas, NGLs and individual NGL products impacts ONEOK Partners’ natural gas liquids exchange services and transportation revenues and, to a lesser extent, margins on its natural gas gathering and processing keep-whole contracts.

Seasonality - Our ONEOK Partners segment’s products 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. Warm temperatures typically drive demand for natural gas used for gas-fired electric generation needed to meet the electricity-generation demand required to cool residential and commercial properties. Precipitation levels 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 butane and natural gasoline, which are primarily used 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 as automotive travel increases and as seasonal gasoline formulation standards are implemented. During periods of peak demand for a certain commodity, prices for that product typically increase, which may influence processing and fractionation decisions.

Competition - ONEOK Partners’ natural gas and natural gas liquids businesses compete directly with other companies for natural gas and NGL supplies, 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 its assets enable it to compete effectively.

ONEOK Partners’ natural gas gathering and processing business competes for natural gas supplies with 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, 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 supplies are:

·	fees charged under its contracts;

·	pressures maintained on its gathering systems;

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

·	location of its assets relative to drilling activity;

·	efficiency and reliability of its operations; and

·	receipt and delivery capabilities that exist in each system, plant, fractionator and storage location.

ONEOK Partners is responding to these industry conditions by making capital investments to access new supplies; increasing gathering, fractionation, storage and transportation capacity; increasing storage, withdrawal and injection capabilities; and improving natural gas processing efficiency and reduce operating costs. ONEOK Partners is also evaluating asset consolidation opportunities to maximize earnings and renegotiating low-margin contracts. The principal goal of the contract renegotiation effort is to improve margins and reduce risk.

Government Regulation - The FERC has traditionally 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 removing 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 non-jurisdictional gathering facility status. However, ONEOK Partners is subject to newly adopted FERC regulations that require it to publicly post certain natural gas flow information on ONEOK Partners’ website. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished 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.

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.

ONEOK Partners’ proprietary natural gas liquids gathering pipelines, fractionation and storage facilities in Oklahoma, Kansas and Texas are not regulated by the FERC or the states’ respective corporation commissions. ONEOK Partners’ remaining natural gas liquids gathering and distribution pipelines are interstate pipelines regulated by the FERC. ONEOK Partners transports unfractionated NGLs and NGL products pursuant to filed tariffs.

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

Unconsolidated Affiliates - Our ONEOK Partners segment has investments in unconsolidated affiliates which 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 N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of ONEOK Partners’ unconsolidated affiliates.

Distribution

Business Strategy - The strategies for our Distribution segment include:

·	minimizing the gap between actual and allowed returns through sustainable cost reductions and innovative rate strategies that provide faster cost recovery for shareholders while simultaneously stabilizing rates for consumers;

·	growing rate base through investment in our system while emphasizing safety and efficiency; and

·	providing customer programs designed to reduce volumetric sensitivity and create value for our customers.

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Our regulatory strategy incorporates rate features that reduce earnings lag, protect margin and mitigate risks. These strategies include performance-based rate mechanisms in Oklahoma and capital-recovery mechanisms in Kansas and portions of Texas. In addition, we also have cost-of-service adjustments in certain Texas markets that address investments in rate base and changes in expense. Margin protection strategies include increased fixed-customer charges in all three states, as well as weather normalization mechanisms. Risk mitigation strategies include fuel-related bad-debt recovery mechanisms in Oklahoma, Kansas and portions of Texas.

Description of Business - Our Distribution segment provides natural gas distribution services to more than 2 million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service. We serve residential, commercial, industrial and transportation customers in all three states. In addition, our distribution companies serve wholesale and public authority customers.

Our operating results are affected primarily by the number of customers, usage and the ability to collect delivery rates that provide a reasonable rate of return on our investment and recovery of our cost of service. Natural gas costs are passed through to our customers based on the actual cost of natural gas purchased by the respective distribution companies and related expenses. Substantial fluctuations in natural gas sales can occur from year to year without materially or adversely impacting our net margin, since the fluctuations in natural gas costs affect natural gas sales and cost of gas by an equivalent amount. Higher natural gas costs may cause customers to conserve or use alternative energy sources. Higher natural gas costs may also impact adversely our accounts receivable collections, resulting in higher bad-debt expense. Recovery of the fuel-related portion of bad debts is allowed in all three states.

Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service distribute natural gas as public utilities to approximately 82 percent, 67 percent and 13 percent of the distribution markets for Oklahoma, Kansas and Texas, respectively. Natural gas sold to residential and commercial customers accounts for approximately 80 and 19 percent of our natural gas sales, respectively, in Oklahoma; 75 and 19 percent of our natural gas sales, respectively, in Kansas; and 70 and 22 percent of our natural gas sales, respectively, in Texas.

In the first quarter of 2010, responsibility for our retail marketing business was transferred to our Distribution segment from our Energy Services segment. As a result, we have revised our reportable segments to reflect this change in responsibility. Our retail marketing business provides physical marketing and supply services. We manage the commodity price and volumetric risk in our retail operations through a variety of risk management and hedging activities. Our retail marketing business serves municipal, small commercial, industrial and agricultural customers in the Mid-Continent region, residential and agricultural customers in Nebraska and residential customers in Wyoming.

Market Conditions and Seasonality - Supply - Our LDCs purchased 186 Bcf and 169 Bcf of natural gas supply in 2010 and 2009, respectively. Our natural gas supply portfolio consists of long-term, seasonal and short-term contracts from a diverse group of suppliers. These contracts are awarded through competitive-bidding processes to ensure reliable and competitively priced natural gas supply. Our Distribution segment’s natural gas supply is purchased from a combination of natural gas processing plants, natural gas marketers and natural gas producers.

We are responsible for acquiring sufficient natural gas supplies, interstate and intrastate pipeline capacity and storage capacity to meet customer requirements. As such, we must contract for both reliable and adequate supplies and delivery capacity to our distribution system, while considering: (i) the dynamics of the interstate and intrastate pipeline and storage capacity market; (ii) our peaking facilities and storage and contractual commitments; and (iii) the demand characteristics of our customer base.

An objective of our supply-sourcing strategy is to diversify our supply among multiple production areas and suppliers. This strategy is designed to protect receipt of supply from being curtailed by physical interruption, possible financial difficulties of a single supplier, natural disasters and other unforeseen force majeure events.

We do not anticipate problems with securing natural gas supply to satisfy customer demand; however, if supply shortages were to occur, each of our LDCs has curtailment tariff provisions in place that provide for: (i) reducing or discontinuing natural gas service to large industrial users; and (ii) requesting that residential and commercial customers reduce their natural gas requirements to an amount essential for public health and safety. In addition, during times of critical supply problems, curtailments of deliveries to customers with firm contracts may be made in accordance with guidelines established by appropriate federal, state and local regulatory agencies.

Natural gas supply requirements are affected by changes in the natural gas consumption pattern of our customers that are driven by factors other than weather. Economic conditions impact usage of commercial and industrial customers. Natural

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gas usage per residential customer may decline as customers change their consumption patterns in response to: (i) more volatile and higher natural gas prices, as discussed above; (ii) customers’ improving the energy efficiency of existing homes by replacing doors and windows and adding insulation, along with retrofitting natural gas appliances with more efficient appliances; (iii) more energy-efficient construction; and (iv) fuel switching. In each jurisdiction in which we operate, changes in customer usage profiles have been reflected in recent rate case proceedings, where rates have been adjusted to reflect current customer usage.

In managing our natural gas supply portfolios, we partially mitigate price volatility using a combination of financial derivatives and fixed price contracts. Our regulatory authorities in each of the three states have approved natural gas hedging programs that have been in place over the last few years. We do not utilize financial derivatives for speculative purposes nor do we have trading operations associated with our Distribution segment. In addition, we utilized 39.3 Bcf of contracted storage capacity in 2010, which allows gas to be purchased during the off-peak season and stored for use in the winter periods.

Demand - Our retail business’ demand for natural gas is driven primarily by industrial and small commercial process requirements, heating requirements for municipalities and residential users, and agricultural requirements for irrigation. Demand for the retail business is impacted significantly by temperature and precipitation variations.

See discussion below under “Seasonality” and “Competition” for factors affecting LDC demand.

Seasonality - Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas is used 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 LDCs resulting from weather that is above or below normal is offset substantially through weather-normalization adjustments (WNA). These adjustments are now approved by the regulatory authorities for our Oklahoma, Kansas and Texas service territories. WNA allows 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.

Competition - We encounter competition based on customers’ preference for natural gas, compared with other energy products, and the comparative prices of those other energy products. The most significant product competition occurs between natural gas and electricity in the residential and small commercial markets. We compete for space and water heating, cooking, clothes drying and other general energy needs. Customers and builders typically make the decision on the type of equipment to install at initial installation and use the chosen energy source for the life of the equipment. The markets in our service territories have become increasingly competitive. Changes in the competitive position of natural gas relative to electricity and other energy products have the potential to cause a decline in consumption or in the number of future natural gas customers.

However, recent studies have demonstrated that assessing energy efficiency in terms of full fuel cycle analysis highlights the high overall efficiency of natural gas as a preferred fuel in residential and commercial uses, compared with electricity. These studies may have a positive impact on the promotion of natural gas for these primary uses, as national energy and environmental policies and standards are reshaped.

We believe that we must maintain a competitive advantage in order to retain our customers, and, accordingly, we focus on providing safe, reliable and efficient service and controlling costs. Our Distribution segment is subject to competition from other pipelines for our existing industrial load. Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service compete for service to large industrial and commercial customers, and competition has and may continue to impact margins.

Under our transportation tariffs, qualifying industrial and commercial customers are able to purchase their natural gas commodity from the supplier of their choice and have us transport it for a fee. A portion of transportation services provided is at negotiated rates that are generally below the maximum approved transportation tariff rates. Reduced rate transportation service may be negotiated when a competitive pipeline is in proximity or another viable energy option is available. Increased competition could potentially lower these rates.

Government Regulation - Rates charged by LDCs in our Distribution segment for natural gas services 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 purchase costs for our LDCs are included in the Purchased Gas Adjustment (PGA) clause rate that is billed to customers. Our LDCs do not make a profit on the cost of natural gas. Other changes in costs must be recovered through periodic rate adjustments

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approved by the OCC, KCC, RRC and various municipalities in Texas. See pages 49-50 for a detailed description of our various regulatory initiatives.

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

Energy Services

Business Strategy - Our Energy Services segment utilizes our network of contracted natural gas supply and contracted transportation and storage assets to provide premium services to our customers. The asset positions afford us the flexibility to develop innovative, customer-specific demand delivery services for those we serve, at a competitive cost. We also continue to align our strategic supply portfolio to complement our contracted asset position. With these services and a focus on customer relationships, we expect to retain existing customers and attract new customers that generate recurring margins.

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

It is our intention to minimize the mark-to-market earnings impact that our forward hedges have on current period earnings. When possible, we implement effective hedging strategies using derivative instruments that qualify as hedges for accounting purposes.

Our Energy Services segment requires working capital to purchase natural gas inventory, to reserve transportation and storage capacity and to meet cash collateral requirements associated with our risk management activities. Our inventory purchases and hedging strategies are implemented with consideration given to ONEOK’s overall working capital requirements and liquidity. Restrictions on our access to working capital may impact our inventory purchases and risk management activities, which could impact our results. Our working capital costs would be impacted by a change in ONEOK’s current investment-grade credit rating. See discussion under “Credit Risk” of Note C of the Notes to Consolidated Financial Statements in this Annual Report for additional information.

Description of Business - Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk-management services through our network of contracted natural gas transportation and storage capacity and natural gas supply. This contracted storage and transportation capacity connects the major supply and demand centers throughout the United States and into Canada. Our customers are primarily LDCs, electric utilities, and commercial and industrial end-users. Our customers’ natural gas needs vary with seasonal changes in weather and are therefore somewhat unpredictable.

To ensure natural gas is available when our customers need it, we offer premium services and products that satisfy our customers’ swing and peaking natural gas commodity requirements on a year-round basis. We also provide no-notice service, weather-related protection and other custom solutions based on our customers’ specific needs. Our storage and transportation assets enable us to provide these services and provide us with opportunities to optimize our contracted assets through our application of market knowledge and risk-management skills.

We actively manage the commodity price and volatility risks associated with providing energy risk management services to our customers by executing derivative instruments in accordance with the parameters established in our commodity risk management policy. The derivative instruments consist of over-the-counter transactions such as forward, swap and option contracts, and NYMEX futures and option contracts.

We utilize our experience to optimize the value of our contracted assets and use our risk management and marketing capabilities to both manage risk and generate additional margins. We apply a combination of cash flow and fair value hedge accounting when implementing hedging strategies that take advantage of favorable market conditions. See Note C of the Notes to Consolidated Financial Statements in this Annual Report for additional information. Additionally, certain non-trading transactions, which are economic hedges of our accrual transactions, such as our storage and transportation contracts, will not qualify for hedge accounting treatment. These economic hedges receive mark-to-market accounting treatment, as they are derivative contracts and are not designated as part of a hedge relationship. As a result, the underlying risk being hedged receives accrual accounting treatment, while we use mark-to-market accounting treatment for the economic hedges. We cannot predict the earnings fluctuations from mark-to-market accounting, and the impact on earnings could be material.

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Our working capital requirements related to our inventory in storage were as high as $284.3 million during 2010 and had decreased to $256.9 million by December 31, 2010. In addition, margin requirements can result in increased working capital requirements. During 2010, the amount we were required to post with counterparties to meet our margin requirements ranged from $0.7 million to $35.5 million, and the amount posted for our benefit by our counterparties ranged from $32.1 million to $115.2 million.

Our Energy Services segment conducts business with our ONEOK Partners and Distribution segments. These services are provided under agreements with market-based terms. Additionally, business with our LDCs is awarded through a competitive-bidding process. Through our wholesale marketing and risk management capabilities, we are a full-service supply provider to our Distribution segment’s retail marketing operations. We manage the commodity price and volumetric risk in these operations through a variety of risk management and hedging activities.

Market Conditions and Seasonality - Supply - Our Energy Services segment maintains a natural gas supply portfolio consisting of various term-length contracted supply in all of the major producing regions, including the Rocky Mountain, Mid-Continent and Gulf Coast. During periods of high natural gas demand, we utilize storage capacity that allows us to supplement natural gas supply volumes to meet our peak day demand obligations or market needs.

Demand - Demand under our swing and peaking natural gas requirements contracts in our wholesale operation is usually driven by the extent to which temperatures vary from normal levels. A significant portion of this business is contracted during the winter period of November through March.

Seasonality - Due to the seasonality of natural gas consumption, storage withdrawals and demand for our products and services, earnings are higher normally during the winter months than the summer months. Natural gas sales volumes are higher typically in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices. During periods of high natural gas demand, we utilize storage and transportation capacity that allows us to supplement natural gas supply volumes to meet our premium-services obligations or market needs.

Competition - Market conditions and uncertainties associated with the implementation of financial reform continue to affect liquidity in the financial derivatives market, particularly for basis swaps, which make it difficult to implement forward hedges around our transportation and storage positions. In response to a competitive marketing environment, our strategy is to concentrate our efforts on providing reliable service during peak demand periods and capturing opportunities created by short-term pricing volatility. We can compete effectively in the market by utilizing our contracted storage and transportation assets. We continue to focus on building and strengthening supplier and customer relationships to execute our strategy and increase our market presence.

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.

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

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was enacted, representing a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act and are currently seeking comments on the proposals. We expect additional proposed regulations as the remaining provisions of the Dodd-Frank Act are implemented. Until the final regulations are established, we are unable to ascertain how we may be affected. Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur

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additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations.

ENVIRONMENTAL AND SAFETY MATTERS

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

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. Currently, Congress is reauthorizing existing Pipeline Safety legislation, and there are also a number of new bills addressing pipeline safety being considered. We are monitoring activity concerning the reauthorization and proposed new legislation, as well as potential changes in the Pipeline and Hazardous Materials Safety Administration’s regulations, to assess the potential impact on our operations. At this time, no revised or new legislation has been enacted, and potential cost, fees or expenses associated with changes or new legislation are unknown. We cannot provide assurance that existing pipeline safety regulations will not be revised or interpreted in a different manner or that new regulations will not be adopted that could result in increased compliance costs or additional operating restrictions.

Air and Water Emissions - The Clean Air Act, the Clean Water Act and analogous state laws 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 regulate greenhouse gas emissions are under way. We are monitoring federal and state legislation to assess the potential impact on our operations. We estimate our direct greenhouse gas emissions annually as we collect certain greenhouse gas emission data for the previous year. Our most recent estimate for ONEOK and ONEOK Partners indicates that our direct emissions were less than 4.5 million metric tons of carbon dioxide equivalents during 2009. This does not include the carbon-dioxide equivalents of product delivered to certain customers as required by the EPA’s Mandatory Greenhouse Gas Reporting rule. The EPA’s Mandatory Greenhouse Gas Reporting rule, released in September 2009, requires greenhouse gas emissions reporting for affected facilities on an annual basis, beginning with our 2010 emissions report that will be due in March 2011, and requires us to track the emission equivalents for the natural gas delivered by us to our distribution customers and emission equivalents for all NGLs delivered to customers of ONEOK Partners. Also, the EPA has recently released a subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities. The new requirements began in January 2011, with the first reporting of fugitive emissions due March 31, 2012. We do not expect the cost to gather this emission data to have a material impact on our results of operations, financial position or cash flows. In addition, the United States Congress has considered, and may consider in the future, legislation to reduce greenhouse gas emissions, including carbon dioxide and methane. At this time, no rules or legislation have been enacted that assess any costs, fees or expenses on any of these emissions.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and, at current emission threshold levels, will have 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.

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, scheduled to be adopted in 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

Finally, while the Texas Commission on Environmental Quality (TCEQ) has been delegated primary responsibility for implementing federal environmental programs under the Clean Air Act and Clean Water Act in Texas, the EPA retains program oversight. Recently, an apparent division has arisen between TCEQ and the EPA over key aspects of these Texas regulatory programs (including among others, air and new source review permitting). This division has led to

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increased EPA scrutiny of TCEQ’s environmental permitting decisions and uncertainty with respect to how these programs will be administered in the future.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of a facility where the release occurred and 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 current responsibilities under CERCLA, if any, to 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 were subsequently 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, along with the United States Department of Transportation have completed a review and inspection of our “critical facilities” and identified no material security issues.

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

ONEOK Partners participates in the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. In 2010, ONEOK Partners received a Continuing Excellence award for five years of active participation in the STAR Program, including consistent reporting of emission-reduction activities, by its natural gas pipelines business. 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. Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput. We expect to complete our annual estimate for 2010 during the second quarter of 2011 and will post the information on our website when available.

EMPLOYEES

We employed 4,839 people at January 31, 2011, including 728 people employed by Kansas Gas Service who are subject to collective bargaining contracts. The following table sets forth our contracts with collective bargaining units at January 31, 2011:

Union	Employees		Contract Expires
The United Steelworkers		412	October 27, 2011
International Union of Operating Engineers		12	October 27, 2011
International Brotherhood of Electrical Workers (IBEW)		304	June 30, 2014

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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 or, in the case of Mr. Norton, will be 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	58	2010 to present	President and Chief Executive Officer
President, Chief Executive Officer		2007 to 2009	Chief Executive Officer
and Vice Chairman of the Board of Directors (1)		2011 to present	Vice Chairman of the Board of Directors
		2006 to present	Member of the Board of Directors
		2010	Chairman, President and Chief Executive Officer, ONEOK Partners, L.P.
		2007 to 2009	Chairman and Chief Executive Officer, ONEOK Partners, L.P.
		2006	President and Chief Operating Officer, ONEOK Partners, L.P.
		2005 to 2006	President, ONEOK Energy Companies

Curtis L. Dinan	43	2007 to present	Senior Vice President, Chief Financial Officer and Treasurer
Senior Vice President, Chief Financial Officer		2004 to 2006	Senior Vice President and Chief Accounting Officer
and Treasurer (2)

Robert F. Martinovich	53	2009 to present	Chief Operating Officer
Chief Operating Officer (3)		2007 to 2009	President, Gathering and Processing
		2006 to 2007	Group Vice President, EHS, Operations & Technical Services, DCP Midstream LLC
		2002 to 2006	Senior Vice President, Northern Division (Mid-Continent and Rockies), DCP
			Midstream LLC

Pierce H. Norton	51	2009 to present	President, ONEOK Distribution Companies
President, ONEOK Distribution Companies (4)		2007 to 2009	Executive Vice President, Natural Gas
		2006 to 2007	President, Gathering and Processing

Terry K. Spencer	51	2009 to present	Chief Operating Officer, ONEOK Partners, L.P.
Chief Operating Officer, ONEOK Partners, L.P.		2007 to 2009	Executive Vice President, Natural Gas Liquids
		2006	President, Natural Gas Liquids

John R. Barker	63	2004 to present	Senior Vice President, General Counsel and Assistant Secretary
Senior Vice President, General Counsel and
Assistant Secretary

Derek S. Reiners	39	2009 to present	Senior Vice President and Chief Accounting Officer
Senior Vice President and Chief Accounting Officer		2004 to 2009	Partner, Grant Thornton LLP

(1) - Mr. Gibson was elected Vice Chairman of the Board of Directors on February 17, 2011, and will become Chairman of the Board of Directors following our Annual Meeting of Shareholders on May 25, 2011.
(2) - Mr. Dinan will become President, Natural Gas of ONEOK Partners, L.P. effective March 1, 2011.
(3) - Mr. Martinovich will become Senior Vice President, Chief Financial Officer and Treasurer effective March 1, 2011.
(4) - Mr. Norton will become Chief Operating Officer, ONEOK, Inc. effective March 1, 2011.

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 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, Corporate Governance Guidelines and Director Independence Guidelines are also available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T. In accordance with Rule 402 of Regulation S-T, the Interactive Data Files shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be

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incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

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 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 adversely affect our business.

The capital and credit markets have experienced volatility and disruption. In many cases, 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 credit markets. Similar or more severe levels of 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 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 one of our largest cash-generating assets. 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 would 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 “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 includes ONEOK Partners’ natural gas gathering and processing business, most of its natural gas liquids business, our energy services business and the retail marketing portion of our distribution business have a higher level of risk than our regulated operations, which include the LDCs in our distribution business, 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.

Our LDCs have recorded certain assets that may not be recoverable from our customers.

Accounting principles that govern our LDCs permit certain assets that result from the regulatory process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as rate orders from regulators, previous rate orders for substantially similar costs, written approval from the regulators and analysis of

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recoverability from internal and external legal counsel to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.

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

Since the September 11, 2001, terrorist attacks, 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 may target 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. Currency forward contracts are used to mitigate unexpected changes that may occur in anticipated revenue streams of our Canadian natural gas sales and purchases driven by currency rate fluctuations. However, financial derivative instrument contracts do not eliminate the risks. Specifically, such risks include commodity price changes, 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. 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 adversely impact 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 materially and adversely impact the results of operations for our Energy Services segment.

Increased competition could have a significant adverse financial impact on us.

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. Our ability to compete also depends on a number of other factors, including competition from other pipelines for our existing load, the efficiency, quality and reliability of the services we provide, and competition for throughput for our gathering systems, pipelines, processing plants, fractionators and storage facilities.

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

We may not be able to successfully make additional strategic acquisitions or integrate businesses we acquire into our operations.

Our ability to successfully make strategic acquisitions and investments will depend on: (i) the extent to which acquisitions and investment opportunities become available; (ii) our success in bidding for the opportunities that do become available; (iii) regulatory approval, if required, of the acquisitions on favorable terms; and (iv) 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. If we are unable to successfully integrate new businesses into our operations, we could experience increased costs and losses on our investments.

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 successfully integrate the businesses we acquire;

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·	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, for which our indemnity is inadequate or for which 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.

Any reduction in our credit ratings could materially and adversely affect our business, financial condition, liquidity and results of operations.

Our long-term senior unsecured debt has been assigned an investment-grade rating by S&P of “BBB” (Stable) and Moody’s of “Baa2” (Stable); however, we cannot provide assurance that any of our 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 S&P or Moody’s were to downgrade our long-term rating, particularly below investment grade, our borrowing costs would increase, which would affect adversely our financial results, and our potential pool of investors and funding sources could decrease. Further, if our short-term ratings were to fall below A-2 or Prime-2, the current ratings assigned by S&P and Moody’s, respectively, it could limit significantly our access to the commercial paper market. Any such downgrade of our long- or short-term ratings could increase significantly our cost of capital and reduce the availability of capital and, thus, have a material adverse effect on our business, financial condition, liquidity and results of operations. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.

A downgrade in our credit ratings below investment grade would affect negatively the operations of our Energy Services segment. If our credit ratings fall below investment grade, ratings triggers and/or adequate assurance clauses in many of our financial and wholesale physical contracts would be in effect. A ratings trigger or adequate assurance clause gives a counterparty the right to suspend or terminate the agreement unless margin thresholds are met. Margin requirements related to the trading activities of our Energy Services segment may also increase as a result of market volatility without regard to our credit rating. The additional increase in capital required to support our Energy Services segment would impact materially and adversely our ability to compete, as well as our ability to manage actively the risk associated with existing storage and transportation contracts.

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

We have developed and implemented a comprehensive 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 trading activities of our Energy Services segment. 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.

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

As of December 31, 2010, we had total indebtedness for borrowed money of approximately $1.6 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 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 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 comprehensive energy regulation by governmental agencies, and the recovery of our costs is dependent on regulatory action.

We are subject to comprehensive regulation by several federal, state and municipal utility regulatory agencies, which significantly influences our operating environment and our ability to recover our costs from utility customers. The utility regulatory authorities in Oklahoma, Kansas and Texas regulate many aspects of our utility operations, including customer service and the rates that we can charge customers. Federal, state and local agencies also have jurisdiction over many of our other activities, including regulation by the FERC of our storage and interstate pipeline assets. The profitability of our regulated operations is dependent on our ability to pass through costs related to providing energy and other commodities to our customers by filing synchronized rate cases. The regulatory environment applicable to our regulated businesses could impair our ability to recover costs historically absorbed by our customers.

We are unable to predict the impact that the future regulatory activities of these agencies will have on our operating results. Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition and results of operations. Further, the results of our LDCs’ operations could be negatively impacted if the cost recovery mechanisms authorized by our rate cases do not function as anticipated.

Additionally, the regulatory authorities of each state in which we operate allow LDCs to obtain weather protection. If the weather protection clause is disallowed, it would affect our business.

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

In July 2010, the Dodd-Frank Act was enacted, which provides for new statutory and regulatory requirements for financial derivative transactions. Certain derivative 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

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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. It also requires the CFTC to establish new position trading limits.

We expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations. These requirements could adversely affect the liquidity and pricing of derivative contracts, and the anticipated increased costs of compliance by dealers and counterparties will likely be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.

The volatility of natural gas prices may impact negatively LDC customers’ perception of natural gas.

Natural gas costs are passed through to the customers of our LDCs based on the actual cost of the natural gas purchased by the particular LDC. Substantial fluctuations in natural gas prices can occur from year to year. Sustained periods of high natural gas prices or of pronounced natural gas price volatility may impact negatively our LDC customers’ perception of natural gas, which could lead to customers selecting other energy alternatives, such as electricity, and to difficulties in the rate-making process. Additionally, high natural gas prices may cause customers to conserve more and may also impact adversely our accounts receivable collections, resulting in higher bad-debt expense.

Our business is subject to increased regulatory oversight and potential penalties.

The natural gas industry historically has been heavily regulated; therefore, there is no assurance that a more stringent regulatory approach will not be pursued by the FERC, CFTC and/or the United States Congress in the future. In response to previous market power abuse by certain companies engaged in interstate commerce, the United States Congress, in the Energy Policy Act of 2005 (EPACT), developed requirements intended to ensure that the energy market is not impacted by the exercise of market power or manipulative conduct. The FERC then adopted the Market Manipulation Rules to implement the authority granted under EPACT. These rules are intended to prohibit fraud and manipulation and are subject to broad interpretation. EPACT also gave the FERC increased penalty authority for violations of these rules, as well as other FERC rules. In addition to the authority granted to the FERC under EPACT, the CFTC also has the authority to regulate market manipulation under the Commodities Exchange Act and the Dodd-Frank Act.

Demand for services of our Distribution and Energy Services segments and for certain of ONEOK Partners’ products is highly weather sensitive and seasonal.

The demand for natural gas and for certain of ONEOK Partners’ products, such as propane, is weather sensitive and seasonal, with a significant portion of revenues derived from sales to retail markets 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 our segments’ business can create large variations in earnings and short-term cash requirements.

We are subject to environmental regulations that could be difficult and costly to comply with.

We are 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 generally require us 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 us to fines, penalties and/or interruptions in our operations that could be material to the results of operations. If a leak or spill of hazardous substance occurs from our lines or facilities in the process of transporting natural gas or NGLs or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could materially affect our 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 our 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, scheduled to be adopted in early 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become

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applicable to us. 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 our business, financial condition and results of operations. For further discussion on this topic, see Note P of the Notes to Consolidated Financial Statements in this Annual Report.

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 not able 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 adversely affected. 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.

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

The national trend toward increased 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 conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could affect adversely our operations.

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 L 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.

Our business could be affected adversely by strikes or work stoppages by our unionized employees.

As of January 31, 2011, 728 of our 4,839 employees were represented by collective bargaining units under collective bargaining agreements. We are involved periodically in discussions with collective bargaining units representing some of our employees to negotiate or renegotiate labor agreements. We cannot predict the results of these negotiations, including whether any failure to reach new agreements will have a negative effect on our business, financial condition and results of operations or whether we will be able to reach any agreement with the collective bargaining units. Any failure to reach agreement on new labor contracts might result in a work stoppage. Any future work stoppage could, depending on the operations and the length of the work stoppage, have a material adverse effect on our business, financial condition and results of certain operations.

We 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.

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We believe it is possible that future governmental legislation and/or regulation may require us either to limit greenhouse gas emissions from our operations or to purchase allowances for such emissions that are actually attributable to our distribution customers or attributable to NGL customers of ONEOK Partners. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations, or when they will become effective. Several 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 us 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.

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 our activities uneconomic to maintain or operate. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with greenhouse gas regulatory requirements. Our 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 our customers.

We continue to monitor legislative and regulatory developments in this area. Although the regulation of greenhouse gas emissions may have a material impact on our operations and rates, we are unable to quantify the potential costs of the impacts at this time.

We do 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 our results of operations.

Certain of our 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. Our Energy Services segment’s primary exposures arise from seasonal and locational price differentials and our ability to execute hedges. Our ONEOK Partners segment’s primary exposures arise from the value of the NGL and natural gas it receives in exchange for the natural gas gathering and processing services it provides; the differentials between commodity prices with respect to its keep-whole contracts and the differentials between NGL and natural gas prices and their impact on our natural gas and NGL transportation, fractionation and exchange throughputs; the differentials between the individual NGL products; differentials between NGL prices at different locations; the seasonal differentials impacting the volume of natural gas and NGLs stored; and the fuel costs and the value of the retained fuel in-kind in ONEOK Partners’ natural gas pipelines and storage operations. Our ONEOK Partners and Energy Services segments are also 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, we use physical forward transactions and commodity 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. We adhere to policies and procedures that monitor our exposure to market risk from open positions. However, we do not fully hedge against commodity price changes, and therefore, we retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and/or increased costs.

Our Distribution segment uses storage to minimize the volatility of natural gas costs for our customers by storing natural gas in periods of low demand for consumption in peak demand periods. In addition, various natural gas supply contracts allow us the option to convert index-based purchases to fixed prices. Also, we use derivative instruments to hedge the cost of anticipated natural gas purchases during the winter heating months to protect customers from upward volatility in the market price of natural gas.

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.

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Although we control ONEOK Partners, we may have conflicts of interest with ONEOK Partners which 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 42.8 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.

We are 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. Our 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 us to invest in more pipeline and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our 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 our operating territory could also have an impact on our revenues. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornadoes and snow or ice storms. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our 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 our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for lawsuits against greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change.

RISK FACTORS RELATED TO ONEOK PARTNERS’ BUSINESS

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

A significant portion of ONEOK Partners’ revenues are derived from the sale of commodities that are received as payment for gathering and processing services, for the transportation and storage of natural gas, and for the sale of purity 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;

·	geopolitical conditions impacting supply and demand for natural gas 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;

·	the effect of worldwide energy conservation measures; and

·	the impact of new supplies, new pipelines, processing and fractionation facilities on basis differentials.

These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services. As commodity prices decline, ONEOK Partners is paid less for its commodities, thereby reducing its cash flow. In addition, production could also decline.

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

ONEOK Partners utilizes financial instruments to mitigate its exposure to interest-rate and commodity price fluctuations. Hedging instruments that are used to reduce its 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 may limit the benefit ONEOK Partners would otherwise receive if market prices for natural gas, crude oil and NGLs exceed the stated price in the hedge instrument for these commodities.

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 quarterly cash 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 adversely impact 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 risks and risks that adequate natural gas or NGL supplies will not be available 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 involves 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 supplies 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 ONEOK Partners’ 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 materially adversely affect ONEOK Partners’ results of operations and financial condition.

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 is, 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. ONEOK Partners’ 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 our financial condition, results of operations and cash flows.

Additionally, certain natural gas processing, natural gas liquids fractionators or other facilities (or parts thereof) used by ONEOK Partners are leased from third parties for specific periods. ONEOK Partners’ inability to renew equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material adverse effect on our results of operations and cash flows.

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ONEOK Partners’ operations are subject to operational hazards and unforeseen interruptions, which could materially adversely affect its business and for which ONEOK Partners may not be adequately insured.

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 and transportation 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, 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 explosions, fires, 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 operation of ONEOK Partners’ pipeline caused by such an event could reduce revenues generated by ONEOK Partners and increase expenses, thereby impairing ONEOK Partners’ ability to meet its obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost, and ONEOK Partners is not fully insured against all risks inherent to ONEOK Partners’ business.

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, ONEOK Partners may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all. If ONEOK Partners was to incur a significant liability for which ONEOK Partners was not fully insured, it could have a material adverse effect on 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.

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

ONEOK Partners’ 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 ONEOK Partners to conduct certain operations without full staff, thus hiring outside resources, which decreases its productivity and increases its costs. This shortage of trained workers is the result of experienced workers reaching retirement age, 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 ONEOK Partners’ labor productivity and costs and ONEOK Partners’ ability to expand production in the event there is an increase in the demand for ONEOK Partners’ products and services, which could adversely affect its operations and cash flows available for distribution to unitholders.

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 pipelines from the producing areas and ONEOK Partners’ facilities.

In addition, drilling and production may be impacted by environmental regulations governing water discharge or regulation of drilling and production technologies including, but not limited to, hydraulic fracturing. If the level of drilling and production in any of these regions substantially declines, ONEOK Partners’ volumes and revenue could be materially reduced.

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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 significantly decrease.

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

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

Pursuant to a United States Department of Transportation rule, pipeline operators were required to develop integrity management programs for intrastate and interstate natural gas and natural gas liquids pipelines located near high-consequence areas, where a leak or rupture could do the most harm. The rule also requires operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high-consequence area; improve data collection, integration and analysis; repair and remediate the pipeline as necessary; and implement preventive and mitigating actions. The results of these testing programs could cause 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’ regulated pipelines’ transportation rates are subject to review and possible adjustment by federal and state regulators.

ONEOK Partners’ regulated pipelines are subject to extensive regulation by the FERC and state regulatory agencies, which regulate most aspects of ONEOK Partners’ pipeline business, including ONEOK Partners’ transportation rates. 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, interstate transportation rates must be just and reasonable and not unduly discriminatory.

Action by the FERC or a state regulatory agency could adversely affect ONEOK Partners’ pipeline business’ ability to establish or charge rates that would cover future increases in its costs, or even to continue to collect rates that cover current costs, including a reasonable return. ONEOK Partners cannot assure unitholders that its pipeline systems will be able to recover all of its 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.

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

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·	the EPA has issued a rule on air quality standards, known as RICE NESHAP, that is scheduled to be adopted in early 2013.

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, historical 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 non-compliance 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 P 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 materially adversely affected by increased costs due to stricter pollution-control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might also materially 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.

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.

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 adequately assess 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.

Any reduction in ONEOK Partners’ credit ratings could materially and adversely affect 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); 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’ 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 indenture governing ONEOK Partners’ senior notes due 2011 include an event of default upon acceleration of other indebtedness of $25 million or more, and the indentures governing ONEOK Partners’ other 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 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 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 the capital 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2. PROPERTIES

DESCRIPTION OF PROPERTIES

ONEOK Partners

Property - Our ONEOK Partners segment owns the following assets:

·	approximately 10,300 miles and 4,900 miles of natural gas gathering pipelines in the Mid-Continent and Rocky Mountain regions, respectively;

·	nine active natural gas processing plants, with approximately 645 MMcf/d of processing capacity, in the Mid-Continent region, and four active natural gas processing plants, with approximately 124 MMcf/d of processing capacity, in the Rocky Mountain region;

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·	approximately 24 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Mid-Continent and Rocky Mountain regions;

·	approximately 1,500 miles of FERC-regulated interstate natural gas pipelines with approximately 3.1 Bcf/d of peak transportation capacity;

·	approximately 5,600 miles of intrastate natural gas gathering and state-regulated intrastate transmission pipelines with approximately 3.4 Bcf/d of peak transportation capacity;

·	approximately 51.7 Bcf of total active working natural gas storage capacity;

·	approximately 2,500 miles of natural gas liquids gathering pipelines with approximately 500 MBbl/d of peak capacity;

·	approximately 160 miles of natural gas liquids distribution pipelines with approximately 66 MBbl/d of peak transportation capacity;

·	two natural gas liquids fractionators with approximately 260 MBbl/d of combined operating capacity, which are located in Oklahoma and Kansas;

·	150 MBbl/d of leased fractionation capacity;

·	80-percent 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 9 MBbl/d of operating capacity;

·	six natural gas liquids storage facilities and other leased facilities in Oklahoma, Kansas and Texas, with approximately 26.1 MMBbl of total operating underground NGL storage capacity;

·	approximately 780 miles of FERC-regulated natural gas liquids gathering pipelines with approximately 200 MBbl/d of peak capacity;

·	approximately 3,500 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with approximately 691 MBbl/d of peak transportation capacity;

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

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

ONEOK Partners owns or leases five underground natural gas storage facilities in Oklahoma, three underground natural gas storage facilities in Kansas and three underground natural gas storage facilities in Texas. One of its natural gas storage facilities in Kansas has been idle since 2001. In compliance with a KDHE order, ONEOK Partners began injecting brine into that facility in the first quarter of 2007 in order to ensure the long-term integrity of the idled facility. ONEOK Partners expects to complete the injection process by the end of 2012. Monitoring of the facility and review of the data for the geo-engineering studies are ongoing, in compliance with a KDHE order while ONEOK Partners evaluates the alternatives for the facility. Following the testing of the gathered data, ONEOK Partners expects that the facility will be returned to storage service, although most likely for a product other than natural gas. The return to service will require KDHE approval. It is possible, however, that testing could reveal that it is not safe to return the facility to service or that the KDHE will not grant the required permits to resume service.

Utilization - The utilization rates for ONEOK Partners’ various assets for 2010 and 2009 were as follows:

·	natural gas processing plants were approximately 69 percent and 68 percent utilized, respectively;

·	natural gas pipelines were approximately 87 percent and 86 percent subscribed, respectively, and storage facilities were fully subscribed both years;

·	non-FERC-regulated natural gas liquids pipelines were approximately 56 percent and 51 percent subscribed, respectively;

·	average contracted natural gas storage volumes were approximately 64 percent and 58 percent of storage capacity, respectively;

·	natural gas liquids fractionators were approximately 93 percent and 88 percent utilized, respectively;

·	FERC-regulated natural gas liquids gathering pipelines were approximately 70 percent and 58 percent utilized, respectively; and

·	FERC-regulated natural gas liquids distribution pipelines were approximately 63 percent and 62 percent utilized, respectively.

ONEOK Partners calculates utilization on its assets using a weighted-average approach, adjusting for the dates that assets were placed in service during 2010 and 2009. The utilization rate of ONEOK Partners’ FERC-regulated natural gas liquids gathering pipelines reflect Overland Pass Pipeline and its related lateral pipelines until Overland Pass Pipeline Company was deconsolidated in September 2010. The utilization rate of ONEOK Partners’ fractionation facilities reflects leased capacity

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and the approximate proportional capacity associated with ownership interests noted in the above discussion under “Property.”

Distribution

Property - We own approximately 18,500 miles of pipeline and other distribution facilities in Oklahoma; approximately 12,800 miles of pipeline and other distribution facilities in Kansas; and approximately 9,700 miles of pipeline and other distribution facilities in Texas.

Energy Services

Property - Our total natural gas storage capacity under lease is 73.6 Bcf, with maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.3 Bcf/d. At December 31, 2010, our natural gas transportation capacity was 1.4 Bcf/d, of which 1.1 Bcf/d was contracted under long-term natural gas transportation contracts. Our contracted storage and transportation capacity connects major supply and demand centers throughout the United States and into Canada. Our storage leases are spread across 22 different contracts within the United States.

Other

Property - We own the 17-story ONEOK Plaza office building, with approximately 517,000 square feet of net rentable space, and an associated parking garage.

ITEM 3. LEGAL PROCEEDINGS

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price, et al. v. Gas Pipelines, et al., f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Boles I”). Plaintiffs brought suit on May 28, 1999, against us and our division, Oklahoma Natural Gas, four subsidiaries of ONEOK Partners, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants. Plaintiffs sought class certification for their claims for monetary damages, alleging that the defendants had underpaid gas producers and royalty owners throughout the United States by intentionally understating both the volume and the heating content of purchased gas. After extensive briefing and a hearing, the Court refused to certify the class sought by plaintiffs. Plaintiffs then filed an amended petition limiting the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming and limiting the claim to undermeasurement of volumes. On September 18, 2009, the Court denied the plaintiffs' motions for class certification, which, in effect, limits the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas. The plaintiffs’ motion for reconsideration of the Court’s denial of class certification was denied on March 31, 2010.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Boles II”). This action was filed by the plaintiffs on May 12, 2003, after the Court denied class status in Boles I. Plaintiffs are seeking monetary damages based upon a claim that 21 groups of defendants, including us and our division, Oklahoma Natural Gas, four subsidiaries of ONEOK Partners, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. Boles II has been consolidated with Boles I for the determination of whether either or both cases may be certified properly as class actions. On September 18, 2009, the Court denied the plaintiffs' motions for class certification, which, in effect, limits the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas. The plaintiffs’ motion for reconsideration of the Court’s denial of class certification was denied on March 31, 2010.

Gas Index Pricing Litigation: We, ONEOK Energy Services Company, L.P. (“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

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United States District Court for the District of Nevada); Breckenridge Brewery of Colorado, LLC, et al. v. ONEOK, Inc., et al. (filed in the District Court of Denver County, Colorado, in May 2006, 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 the 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. Other than as noted below, pretrial discovery has been suspended in each of the cases, waiting on rulings by the Court on pending motions.

On January 8, 2009, summary judgment was granted in favor of all of the defendants except one in the Breckenridge case, and judgment was entered against the plaintiffs in favor of those defendants, including us, OESC and our other affiliate. The judgment against the plaintiffs in the Breckenridge case is not final for purposes of appeal until the plaintiffs’ remaining claim against the one defendant has been resolved. We continue to analyze all claims and are vigorously defending against them.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matter was submitted to a vote of our security holders, through the solicitation of proxies or otherwise, during the fourth quarter 2010.

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				Year Ended
	December 31, 2010				December 31, 2009
	High		Low		High		Low
First Quarter	$	47.15	$	40.62	$	31.08	$	18.19
Second Quarter	$	50.72	$	42.00	$	30.34	$	23.07
Third Quarter	$	47.91	$	42.29	$	36.76	$	27.91
Fourth Quarter	$	55.69	$	45.64	$	44.57	$	35.18

At February 14, 2011, there were 15,979 holders of record of our 107,021,170 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,
	2010		2009		2008
First Quarter	$	0.44	$	0.40	$	0.38
Second Quarter	$	0.44	$	0.40	$	0.38
Third Quarter	$	0.46	$	0.42	$	0.40
Fourth Quarter	$	0.48	$	0.42	$	0.40
Total	$	1.82	$	1.64	$	1.56

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In January 2011, we declared a dividend of $0.52 per share ($2.08 per share on an annualized basis) for the fourth quarter of 2010, which was paid on February 14, 2011, to shareholders of record as of January 31, 2011.

ISSUER PURCHASES OF EQUITY SECURITIES

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

Period		Total Number of Shares Purchased			Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Be Purchased Under the Plans or Programs

October 1-31, 2010			23,954	(a)	$25.50		-		-
November 1-30, 2010			112,477	(a), (b)	$33.19		-		-
December 1-31, 2010			28,301	(a), (b)	$26.06		-		-
Total			164,732		$30.84		-		-

(a) - Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise
	of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows:
23,954 shares for the period of October 1-31, 2010
112,467 shares for the period of November 1-30, 2010
23,478 shares for the period of December 1-31, 2010
(b) - Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows:
10 shares for the period November 1-30, 2010
4,823 shares for the period December 1-31, 2010

EMPLOYEE STOCK AWARD PROGRAM

Under our Employee Stock Award Program, we issued, for no consideration, to all eligible employees (all full-time employees and employees on short-term disability) 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 $26 per share. We have issued and will continue to issue, for no consideration, one additional share of our common stock to all eligible employees when the closing price on the NYSE is for the first time at or above each one dollar increment above $26 per share. The total number of shares of our common stock available for issuance under this program is 300,000.

On December 21, 2010, our common stock closed above $55 per share. Accordingly, 4,823 shares were issued to all eligible employees as of that date. Through December 31, 2010, a total of 149,175 shares has been issued to employees under this program. Since December 31, 2010, our common stock has closed above $64 per share, and an additional 43,394 shares have been issued to employees resulting from each one-dollar increment since the award in December 2010. 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.

PERFORMANCE GRAPH

The following performance graph compares the performance of our common stock with the S&P 500 Index and the S&P Utilities Index during the period beginning on December 31, 2005, and ending on December 31, 2010. 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.

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Value of $100 Investment Assuming Reinvestment of Dividends

At December 31, 2005, and at the End of Every Year Through December 31, 2010,

Among ONEOK, Inc., The S&P 500 Index and The S&P Utilities Index

	Cumulative Total Return
	Years Ended December 31,
	2005		2006		2007		2008		2009		2010

ONEOK, Inc.	$	100.00	$	167.71	$	179.28	$	121.02	$	195.29	$	252.65
S&P 500 Index	$	100.00	$	115.78	$	122.14	$	76.96	$	97.33	$	112.01
S&P Utilities Index (a)	$	100.00	$	120.95	$	144.37	$	102.51	$	114.75	$	121.05
(a) - The Standard & Poors Utilities Index is comprised of the following companies: AES Corp.; Allegheny Energy, Inc.;
Ameren Corp.; American Electric Power Co., Inc.; Centerpoint Energy, Inc.; CMS Energy Corp.; Consolidated Edison, Inc.;
Constellation Energy Group, Inc.; Dominion Resources, Inc.; DTE Energy Co.; Duke Energy Corp.; Edison International;
Entergy Corp.; EQT Corporation; Exelon Corp.; FirstEnergy Corp.; FPL Group, Inc.; Integrys Energy Group, Inc.; NextEra
Energy, Inc.; Nicor, Inc.; NiSource, Inc.; Northeast Utilities; NRG Energy, Inc.; Pepco Holdings, Inc.; PG&E Corp.; Pinnacle West
Capital Corp.; PPL Corp.; Progress Energy, Inc.; Public Service Enterprise Group, Inc.; SCANA Corp.; Sempra Energy; Southern
Co.; TECO Energy, Inc.; Wisconsin Energy Corp.; and Xcel Energy, Inc.

ITEM 6. SELECTED FINANCIAL DATA

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

	Years Ended December 31,
	2010		2009		2008		2007		2006
	(Millions of dollars except per share amounts)
Revenues	$	13,030.0	$	11,111.7	$	16,157.4	$	13,477.4	$	11,920.3
Net income	$	541.3	$	491.2	$	600.5	$	498.1	$	528.3
Net income attributable to ONEOK	$	334.6	$	305.5	$	311.9	$	304.9	$	306.3
Total assets	$	12,499.2	$	12,827.7	$	13,126.1	$	11,062.0	$	10,391.1
Long-term debt, including current maturities	$	4,329.8	$	4,602.4	$	4,230.8	$	4,635.5	$	4,049.0
Basic earnings per share	$	3.15	$	2.90	$	2.99	$	2.84	$	2.74
Diluted earnings per share	$	3.10	$	2.87	$	2.95	$	2.79	$	2.68
Dividends declared per common share	$	1.82	$	1.64	$	1.56	$	1.40	$	1.22

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ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATION

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.

ONEOK Partners’ Growth Projects - ONEOK Partners has announced in 2010 and early 2011 approximately $1.8 billion to $2.1 billion in growth projects, primarily in the Williston Basin in North Dakota and the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas, that will enable ONEOK Partners to meet the rapidly growing needs of crude oil and natural gas producers as they increase their drilling activities.

Williston Basin Projects - Drilling rig counts in Dunn, McKenzie and Williams counties in North Dakota have increased dramatically since the beginning of 2010. The development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin are being driven primarily by crude oil economics, with the associated natural gas production having a high NGL content. Current natural gas processing and natural gas liquids infrastructure in the Williston Basin is being expanded to accommodate the additional production from the increased development activities.

ONEOK Partners is the largest independent gatherer and processor of natural gas in the Williston Basin. With its natural gas gathering and processing business’ existing infrastructure and acreage dedications, ONEOK Partners is well positioned to provide critical midstream services to crude oil and natural gas producers as they develop Bakken Shale and Three Forks reserves. Additional natural gas liquids infrastructure is also needed due to the continued NGL production growth that has saturated the area’s current truck and railcar transportation capacity and market. The following provides additional details about the individual projects:

Williston Basin Processing Plants and related projects - ONEOK Partners announced plans to construct three new 100 MMcf/d natural gas processing facilities, the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I and II plants in western Williams County, North Dakota. In addition, ONEOK Partners plans to make investments in related natural gas liquids infrastructure, expansions and upgrades to its existing gathering and compression infrastructure and new well connections associated with these plants. The Garden Creek plant and related projects are expected to be in service by the end of 2011 and cost approximately $350 million to $415 million, excluding AFUDC. The Stateline I plant, which is expected to be in service during the third quarter of 2012, and related projects are expected to cost approximately $300 million to $355 million, excluding AFUDC. The Stateline II plant, which is expected to be in service during the first half of 2013, and related projects are expected to cost approximately $260 million to $305 million, excluding AFUDC. These projects are in ONEOK Partners’ natural gas gathering and processing business.

Bakken Pipeline and related projects - ONEOK Partners announced plans to build a 525- to 615-mile natural gas liquids pipeline, the Bakken Pipeline, that will transport unfractionated NGLs from the Williston Basin in North Dakota to the Overland Pass Pipeline. The Bakken Pipeline will have capacity to transport initially up to 60 MBbl/d of unfractionated NGL production from ONEOK Partners’ natural gas gathering and processing assets in the Williston Basin originating in eastern Montana and connecting to the Overland Pass Pipeline in northeastern Colorado. The unfractionated NGLs will then be delivered to ONEOK Partners’ existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent. Additional pump facilities could increase the Bakken Pipeline’s capacity to 110 MBbl/d. Supply commitments for the Bakken Pipeline will be anchored by NGL production from ONEOK Partners’ natural gas processing plants. ONEOK Partners is also discussing NGL supply commitments with third-party processors. Following receipt of all necessary permits, construction of the 12-inch diameter pipeline is expected to begin in the second quarter of 2012 and be in service during the first half of 2013. Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.

The unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies will require additional pump stations and the expansion of existing pump stations on the Overland Pass Pipeline. These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d. ONEOK Partners’ anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC. The Bakken Pipeline and related projects are in ONEOK Partners’ natural gas liquids business.

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Bushton Fractionator Expansion - To accommodate the additional volume from the Bakken Pipeline, ONEOK Partners will invest $110 million to $140 million, excluding AFUDC, to expand and upgrade its existing fractionation capacity at Bushton, Kansas, increasing its capacity to 210 MBbl/d from 150 MBbl/d. This project is expected to be in service during the first half of 2013 and is in ONEOK Partners’ natural gas liquids business.

Cana-Woodford Shale and Granite Wash projects - In addition to the growth projects in the Williston Basin, ONEOK Partners has also announced plans to invest approximately $270 million to $330 million, excluding AFUDC, in its existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. The expansions and upgrades will increase ONEOK Partners’ ability to accommodate the growing natural gas and NGL supply from producers and natural gas processors as drilling activities increase in these areas. These investments will expand its ability to transport unfractionated NGLs from these supply areas to fractionation facilities in Oklahoma and Texas and distribute purity NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers. A portion of these investments will also allow ONEOK Partners to increase utilization in its natural gas processing capacity in Oklahoma.

ONEOK Partners also announced plans to construct more than 230 miles of natural gas liquids pipeline that will expand its existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas. The pipeline will connect to three new third-party natural gas processing facilities that are under construction and to three existing third-party natural gas processing facilities that are being expanded. Additionally, ONEOK Partners will install additional pump stations on the Arbuckle Pipeline to increase its capacity to 240 MBbl/d. When completed, these projects are expected to add approximately 75 to 80 MBbl/d of raw, unfractionated NGLs to ONEOK Partners’ existing natural gas liquids gathering systems. These projects are expected to be in service during the first half of 2012 and cost approximately $180 million to $240 million, excluding AFUDC. These projects are in ONEOK Partners’ natural gas liquids business.

ONEOK Partners will invest an additional $55 million in the Cana-Woodford Shale development in Oklahoma. The investments include approximately $20 million for new well connections in 2010 and 2011 to gather additional Cana-Woodford Shale natural gas volumes. In addition, ONEOK Partners completed in the fourth quarter of 2010 the connection of its Western Oklahoma natural gas gathering system to its existing Maysville natural gas processing facility in central Oklahoma and the connection of a new natural gas processing plant to its natural gas liquids gathering system. These projects are in ONEOK Partners’ natural gas gathering and processing and natural gas liquids businesses, respectively.

Sterling I Pipeline Expansion - ONEOK Partners will install seven additional pump stations for approximately $36 million, excluding AFUDC, along its existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which will be supplied by ONEOK Partners’ Mid-Continent natural gas liquids infrastructure. The Sterling I pipeline transports NGL purity products from ONEOK Partners’ fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center and is currently operating at capacity. The pump stations are expected to be in service in the second half of 2011. This project is in ONEOK Partners’ natural gas liquids business.

For a discussion of capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources” beginning on page 55.

Stock Repurchase Program - In October 2010, our Board of Directors authorized a three-year stock repurchase program to buy up to $750 million of our outstanding common stock, subject to the limitation that purchases will not exceed $300 million in any one calendar year. If shares are repurchased, they will be acquired from time to time in open-market transactions or through privately negotiated transactions at our discretion, subject to market conditions and other factors. Any purchases will be funded by our available cash, free cash flow and short-term borrowings. The program will terminate upon completion of the repurchase of $750 million of common stock or on December 31, 2013, whichever occurs first. As of February 21, 2011, no shares have been repurchased under the program.

Overland Pass Pipeline Company - In September 2010, ONEOK Partners completed a transaction to sell a 49-percent ownership interest in Overland Pass Pipeline Company to a subsidiary of Williams Partners resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. In accordance with the joint-venture agreement, ONEOK Partners received approximately $423.7 million in cash at closing. ONEOK Partners used the proceeds from the transaction to repay short-term debt and to fund a portion of its recently announced capital projects. A subsidiary of Williams Partners has elected to become the operator of Overland Pass Pipeline Company and is expected to assume the role of operator in the second quarter of 2011. As a result of the transaction, ONEOK Partners no longer controls Overland Pass Pipeline Company and began accounting for the investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, ONEOK Partners recognized a gain of approximately $16.3 million.

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ONEOK Partners’ Commercial Paper Program - In June 2010, ONEOK Partners established a commercial paper program providing for the issuance of up to $1.0 billion of unsecured commercial paper notes. Amounts outstanding under the commercial paper program reduce the borrowings available under the ONEOK Partners Credit Agreement. In July 2010, ONEOK Partners repaid all borrowings outstanding under the ONEOK Partners Credit Agreement with proceeds from the issuance of commercial paper.

ONEOK Partners’ Debt Maturity - In June 2010, ONEOK Partners repaid $250 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, ONEOK Partners no longer has any obligation to offer to repurchase the $225 million senior notes due March 2011 in the event that ONEOK Partners’ long-term debt credit ratings fall below investment grade.

ONEOK Partners’ Debt Issuance - In January 2011, ONEOK Partners completed an underwritten public offering of $1.3 billion senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041. The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under ONEOK Partners’ commercial paper program and for general partnership purposes, including capital expenditures, and will be used to repay the $225 million principal amount of senior notes due March 2011.

ONEOK Partners’ Equity Issuance - In February 2010, ONEOK Partners completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million. In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2-percent general partner interest. ONEOK Partners used the proceeds from the sale of common units and the general partner contribution to repay borrowings under the ONEOK Partners Credit Agreement and for general partnership purposes.

Dividends/Distributions - During 2010, we paid dividends totaling $1.82 per share, an increase of approximately 11.0 percent over the $1.64 per share paid during 2009. We declared a quarterly dividend of $0.52 per share ($2.08 per share on an annualized basis) in January 2011, an increase of approximately 18.2 percent over the $0.44 declared in January 2010. During 2010, ONEOK Partners paid cash distributions totaling $4.46 per unit, an increase of approximately 3.0 percent over the $4.33 per unit paid during 2009. A cash distribution from ONEOK Partners of $1.14 per unit ($4.56 per unit on an annualized basis) was declared in January 2011, an increase of approximately 3.6 percent over the $1.10 declared in January 2010.

REGULATORY

Environmental Liabilities - We are subject to multiple historical and wildlife preservation laws and environmental regulations affecting many aspects of our present and future operations. Regulated activities include those involving air emissions, stormwater and wastewater discharges, handling and disposal of solid and hazardous wastes, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. 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 clean-up costs, which could affect materially our results of operations and cash flows. In addition, emission controls required 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 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.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and, at current emission threshold levels, will have 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.

In addition, the EPA issued a proposed rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, scheduled to be adopted in 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control

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equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

Financial Markets Legislation - In July 2010, the Dodd-Frank Act was enacted, representing a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act and are currently seeking comments on the proposals. We expect additional proposed regulations as the remaining provisions of the Dodd-Frank Act are implemented. Until the final regulations are established, we are unable to ascertain how we may be affected. Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations.

Health Care Legislation - In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, the Health Care Acts) were signed into law. Based on our preliminary analysis of the Health Care Acts, we do not expect a significant impact to our benefit plans or their related costs. We do not participate in the federal retiree prescription drug subsidy program, for which the tax treatment was changed as a result of the Health Care Acts, and accordingly, are not impacted by the change in tax treatment of the subsidy. With the exception of increasing our dependent care age requirement to age 26 from age 24, our health plans provide coverage levels that meet the near-term minimum requirements outlined in the Health Care Acts. We continue to evaluate the implications of the provisions of the Health Care Acts and expect to continue to provide benefit plan options that meet the provisions outlined by the Health Care Acts.

Other - Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment. See discussion of our Distribution segment’s regulatory initiatives beginning on page 49.

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. ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” is a disclosure only standard, which did not have a material impact. See Note B of the Notes to Consolidated Financial Statements for discussion of our fair value measurements.

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 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. 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 - Determining Fair Value - We define fair value as the price that would be received to sell an asset or transfer 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. 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

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from our derivative assets and liabilities to present value. The interest-rate yields used to calculate the present-value discount factors are derived from LIBOR, Eurodollar futures and Treasury swaps. The projected cash flows are then multiplied by the appropriate discount factors to determine the present value or fair value of our derivative instruments. We also take into consideration the potential impact on market prices of liquidating positions in an orderly manner and over a reasonable period of time using current market conditions. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk by using specific and sector bond yields and also monitor the credit default swap markets, net of collateral. 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.

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 B of the Notes to Consolidated Financial Statements in this Annual Report.

Derivatives, Accounting for Financially Settled Transactions and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading 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 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 property 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 in 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

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material. We assess the effectiveness of hedging relationships quarterly by performing an effectiveness test on our hedging relationships to determine whether they are highly effective on a retrospective and prospective basis. Upon election, many of our purchase and sale agreements that otherwise would be required to follow the accounting for derivative instruments qualify as normal purchases and normal sales that result in physical delivery 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 C of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion.

As part of our impairment test, an initial assessment is made by comparing the fair value of a reporting unit with its book value, including goodwill. 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.

Our estimates of fair value significantly exceeded the book value of our reporting units and our indefinite-lived intangible assets in our July 1, 2010, impairment test. Even if the estimated fair values used in our July 1, 2010, impairment tests were reduced by 10 percent, no impairment charges would have resulted. The following table sets forth our goodwill, by segment, at both December 31, 2010 and 2009:


	(Thousands of dollars)
ONEOK Partners	$	433,537
Distribution		157,953
Energy Services		10,255
Other		1,099
Total goodwill	$	602,844

As part of our indefinite-lived intangible asset impairment test, we compare the estimated fair value of our indefinite-lived intangible assets with their book values. The fair value of our indefinite-lived intangible assets 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 assets. The multiples used are consistent with historical asset transactions. We determined that there were no impairments to our indefinite-lived intangible assets in 2010, 2009 or 2008.

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 2010, 2009 or 2008.

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 re-evaluate 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 2010, 2009 or 2008.

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.

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See Notes A, D, and E of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of goodwill and long-lived assets.

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 L of the Notes to Consolidated Financial Statements in this Annual Report for additional information.

Assumed health care cost-trend rates have a significant effect 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		One Percentage
	Point Increase		Point Decrease
	(Thousands of dollars)
Effect on total of service and interest cost	$	1,835	$	(1,571	)
Effect on postretirement benefit obligation	$	22,556	$	(19,445	)

During 2010, we recorded net periodic benefit costs of $32.6 million related to our defined benefit pension plans and $20.9 million related to postretirement benefits. We estimate that in 2011, we will record net periodic benefit costs of $40.0 million related to our defined benefit pension plans and $19.9 million related to postretirement benefits. In determining our estimated expenses for 2011, we assumed an 8.25-percent expected return on plan assets and a discount rate of 5.5 percent. A decrease in our expected return on plan assets to 8.0 percent would increase our 2011 estimated net periodic benefit costs by approximately $2.3 million for our defined benefit pension plans and would not have a significant impact on our postretirement benefit plans. A decrease in our assumed discount rate to 5.25 percent would increase our 2011 estimated net periodic benefit costs by approximately $3.0 million for our defined benefit pension plans and would not have a significant impact on our postretirement benefit plans. During 2010, we made contributions of $96.8 million and $12.5 million to our defined benefit pension plans and postretirement benefit plans, respectively. These contributions to our defined benefit pension plans included $57.0 million attributable to the 2011 plan year. We anticipate our total 2011 contributions will include an additional $4.3 million for our defined benefit pension plans and $13.9 million for our postretirement benefit plans.

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 base our 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 2010, 2009 and 2008. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note P of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.

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FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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

										Variances					Variances
	Years Ended December 31,									2010 vs. 2009					2009 vs. 2008
Financial Results	2010			2009			2008			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	13,030.0		$	11,111.6		$	16,157.4		$	1,918.4		17	%	$	(5,045.8	)	(31	%)
Cost of sales and fuel		10,957.5			9,095.7			14,221.9			1,861.8		20	%		(5,126.2	)	(36	%)
Net margin		2,072.5			2,015.9			1,935.5			56.6		3	%		80.4		4	%
Operating costs		839.8			837.1			776.9			2.7		0	%		60.2		8	%
Depreciation and amortization		307.3			289.0			243.9			18.3		6	%		45.1		18	%
Gain (loss) on sale of assets		18.6			4.8			2.3			13.8		*			2.5		*
Operating income	$	944.0		$	894.6		$	917.0		$	49.4		6	%	$	(22.4	)	(2	%)

Equity earnings from investments	$	101.9		$	72.7		$	101.4		$	29.2		40	%	$	(28.7	)	(28	%)
Allowance for equity funds used during construction	$	1.0		$	26.9		$	50.9		$	(25.9	)	(96	%)	$	(24.0	)	(47	%)
Interest expense	$	(292.2	)	$	(300.8	)	$	(264.2	)	$	(8.6	)	(3	%)	$	36.6		14	%
Net income attributable to noncontrolling interests	$	(206.7	)	$	(185.8	)	$	(288.6	)	$	20.9		11	%	$	(102.8	)	(36	%)
Capital expenditures	$	582.7		$	791.2		$	1,473.1		$	(208.5	)	(26	%)	$	(681.9	)	(46	%)
* Percentage change is greater than 100 percent.

2010 vs. 2009 - Commodity prices were generally higher during 2010, compared with 2009, which had a direct impact on our revenues and cost of sales and fuel. Our operating results include the benefits from a full year of ONEOK Partners’ more than $2.0 billion of completed growth projects that were placed in service in 2009.

Operating income increased 6 percent in 2010, when compared with 2009, reflecting higher NGL volumes, higher contracted natural gas transportation capacity, an increase in natural gas processing volumes, higher natural gas and NGL storage margins and a gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company in our ONEOK Partners segment. These increases were offset partially by ONEOK Partners’ lower NGL optimization margins. Our Distribution segment benefited from new rates in Oklahoma that increased fixed fees and lowered our volumetric sensitivity, providing more consistent revenues each month. Our Energy Services segment’s results were consistent with the prior year, with higher realized seasonal storage price differentials and marketing margins offset by lower realized Mid-Continent-to-Gulf Coast transportation margins and lower premium-services margins.

Operating costs increased due primarily to the recognition of previously deferred integrity-management costs in our Distribution segment that are now being recovered through rates, offset partially by lower than estimated ad valorem taxes in our ONEOK Partners segment and lower legal-related costs in our Energy Services segment.

Our results were also favorably impacted by increased equity earnings from investments in our ONEOK Partners segment. The overall increase is due primarily to increased contracted capacity on Northern Border Pipeline, which benefited from wider natural gas price differentials between the markets it serves, and as a result of accounting for ONEOK Partners’ 50-percent investment in Overland Pass Pipeline Company as an equity investment beginning September 2010.

2009 vs. 2008 - Commodity prices were generally lower during 2009, compared with 2008, which had a direct impact on our revenues and cost of sales and fuel. Operations associated with ONEOK Partners’ growth projects were increasing since these projects were placed in service in late 2008 and in 2009.

Operating income in 2009 decreased 2 percent, compared with 2008, due primarily to lower realized commodity prices and less favorable NGL price differentials. These decreases were offset partially by substantially higher NGL volumes; higher natural gas transportation contracted capacity attributable to ONEOK Partners’ completed growth projects; increased transportation and premium-services margins in our Energy Services segment; and additional revenues from capital-recovery mechanisms in our Distribution segment.

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Operating costs increased due primarily to incremental costs associated with the operation of ONEOK Partners’ completed capital projects; and increased employee-related costs in our Distribution segment. These increases were offset partially by lower bad-debt expense in our Distribution segment.

Equity earnings from investments decreased due primarily to lower subscription volumes and rates on Northern Border Pipeline in ONEOK Partners’ natural gas liquids business and from the $8.3 million gain on the sale of Bison Pipeline LLC by Northern Border Pipeline in 2008. Equity earnings also decreased due to lower natural gas gathering volumes, primarily in the Powder River Basin in Wyoming, in ONEOK Partners’ various natural gas gathering and processing equity investments.

Interest expense increased due primarily to ONEOK Partners’ March 2009 debt issuance and a decrease in capitalized interest due to the completion of ONEOK Partners’ capital projects, offset partially by decreased borrowings by ONEOK.

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

ONEOK Partners

Selected Financial Results and Operating Information - ONEOK Partners’ 2010 operating results include the benefits from a full year of operation of more than $2.0 billion in growth projects that it completed in 2009, reflecting increases in NGL volumes gathered, fractionated and sold in its natural gas liquids business, pipeline capacity contracted in its natural gas pipelines business and natural gas volumes processed in the Williston Basin in its natural gas gathering and processing business. ONEOK Partners expects continued development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas, as drilling activities increase in these areas.

ONEOK Partners placed the following projects in service during 2009:

·	February - Guardian Pipeline’s expansion and extension project in its natural gas pipeline business;

·	March - Grasslands natural gas processing plant expansion in its natural gas gathering and processing business;

·	March - D-J Basin lateral pipeline in its natural gas liquids business;

·	July - Arbuckle Pipeline in its natural gas liquids business; and

·	October - Piceance lateral pipeline in its natural gas liquids business.

The in-service dates of these completed capital projects have impacted the period-to-period comparisons of net margin and operating expenses, primarily in ONEOK Partners’ natural gas liquids and natural gas pipelines businesses, as operations associated with these projects have been increasing since being placed in service.

Additionally, 2010 results for ONEOK Partners’ natural gas liquids business include the gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company. As a result of the sale, ONEOK Partners accounts for its 50-percent investment in Overland Pass Pipeline Company, which operates Overland Pass Pipeline and the D-J Basin and Piceance lateral pipelines, as an equity investment beginning in September 2010.

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The following table sets forth certain selected financial results for our ONEOK Partners segment for the periods indicated:

										Variances					Variances
	Years Ended December 31,									2010 vs. 2009					2009 vs. 2008
Financial Results	2010			2009			2008			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	8,675.9		$	6,474.5		$	7,720.2		$	2,201.4		34	%	$	(1,245.7	)	(16	%)
Cost of sales and fuel		7,531.0			5,355.2			6,579.5			2,175.8		41	%		(1,224.3	)	(19	%)
Net margin		1,144.9			1,119.3			1,140.7			25.6		2	%		(21.4	)	(2	%)
Operating costs		403.5			411.3			371.8			(7.8	)	(2	%)		39.5		11	%
Depreciation and amortization		173.7			164.1			124.8			9.6		6	%		39.3		31	%
Gain (loss) on sale of assets		18.6			2.7			0.7			15.9		*			2.0		*
Operating income	$	586.3		$	546.6		$	644.8		$	39.7		7	%	$	(98.2	)	(15	%)

Equity earnings from investments	$	101.9		$	72.7		$	101.4		$	29.2		40	%	$	(28.7	)	(28	%)
Allowance for equity funds used during construction	$	1.0		$	26.9		$	50.9		$	(25.9	)	(96	%)	$	(24.0	)	(47	%)
Interest expense	$	(204.3	)	$	(206.0	)	$	(151.1	)	$	(1.7	)	(1	%)	$	54.9		36	%
Capital expenditures	$	352.7		$	615.7		$	1,253.9		$	(263.0	)	(43	%)	$	(638.2	)	(51	%)
* Percentage change is greater than 100 percent.

2010 vs. 2009 - Net margin increased due primarily to the following:

an increase of $51.4 million due to higher NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline, Piceance lateral pipeline and D-J Basin lateral pipeline, as well as new NGL supply connections in ONEOK Partners’ natural gas liquids business;

·	an increase of $14.4 million due to higher storage margins, primarily as a result of contract renegotiations in ONEOK Partners’ natural gas pipelines and natural gas liquids businesses;

·	an increase of $9.1 million due to increased Williston Basin volumes in ONEOK Partners’ natural gas gathering and processing business; and

an increase of $8.7 million from higher natural gas transportation margins from an increase in contracted capacity on Midwestern Gas Transmission, Viking Gas Transmission’s Fargo lateral pipeline and the incremental margin from the Guardian Pipeline expansion and extension project in ONEOK Partners’ natural gas pipelines business; offset partially by

a decrease of $34.7 million related to lower optimization margins due to limited NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf Coast NGL market centers until September 2010 and less favorable NGL price differentials in ONEOK Partners’ natural gas liquids business;

·	a decrease of $7.8 million due to decreased volumes processed and sold in western Oklahoma and Kansas as a result of natural production declines, operational outages and a period of ethane rejection in ONEOK Partners’ natural gas gathering and processing business;

·	a decrease of $6.5 million from selling ONEOK Partners’ Lehman Brothers bankruptcy claims in 2009; and

·	a decrease of $6.3 million due to lower natural gas volumes gathered as a result of natural production declines and reduced drilling activity by its customers in the Powder River Basin in ONEOK Partners’ natural gas gathering and processing business.

Operating costs decreased due primarily to a decrease of $8.2 million due to lower than estimated ad valorem taxes associated with ONEOK Partners’ capital projects completed in 2009 in its natural gas liquids business.

Depreciation and amortization expense increased primarily as a result of ONEOK Partners’ capital projects completed in 2009 in its natural gas liquids and natural gas pipelines businesses, offset partially by the deconsolidation of Overland Pass Pipeline Company in the third quarter of 2010 in ONEOK Partners’ natural gas liquids business.

Gain (loss) on sale of assets increased due primarily to the gain on sale of a 49-percent ownership interest in Overland Pass Pipeline Company in ONEOK Partners’ natural gas liquids business.

Equity earnings from investments increased due primarily to increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials in ONEOK Partners’ natural gas pipelines business and equity earnings from ONEOK Partners’ investment in Overland Pass Pipeline Company, which was deconsolidated in September 2010.

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Allowance for equity funds used during construction and capital expenditures decreased due primarily to ONEOK Partners’ completed capital projects in 2009 in its natural gas liquids and natural gas pipelines businesses.

2009 vs. 2008 - The Guardian Pipeline expansion and extension was placed into service in February 2009 and impacts the period-to-period comparisons of ONEOK Partners and specifically its natural gas pipelines business. The Overland Pass Pipeline and related expansion projects were placed in service during the fourth quarter of 2008, and operations of those assets have been increasing since that time. The Arbuckle Pipeline was placed in service during the third quarter of 2009, and operations have been increasing since that time. The in-service dates of those projects have impacted the period-to-period comparisons of net margin and expense for ONEOK Partners’ natural gas liquids business.

Net margin decreased due primarily to the following:

·	a decrease of $106.0 million due to lower realized commodity prices in ONEOK Partners’ natural gas gathering and processing business; and

·	a decrease of $41.7 million due to less favorable NGL price differentials in ONEOK Partners’ natural gas liquids business; offset partially by

an increase of $68.7 million due to increased NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Overland Pass Pipeline and related expansion projects, and the Arbuckle Pipeline, as well as new NGL supply connections in ONEOK Partners’ natural gas liquids business;

·	an increase of $38.8 million due to higher natural gas transportation margins from the Guardian Pipeline expansion and extension that was completed in February 2009 and an increase in volumes contracted on Midwestern Gas Transmission in ONEOK Partners’ natural gas pipelines business; and

·	an increase of $23.5 million due to higher volumes processed and sold in ONEOK Partners’ natural gas gathering and processing business.

Operating costs increased due primarily to higher employee-related costs in all of ONEOK Partners’ businesses, the incremental costs associated with the operation of the Overland Pass Pipeline and related expansion projects and Arbuckle Pipeline, and costs associated with the expanded Bushton Plant fractionator in its natural gas liquids business.

Depreciation and amortization expense increased primarily as a result of ONEOK Partners’ completed capital projects, primarily in its natural gas liquids business and also in its natural gas pipelines business.

Equity earnings from investments decreased due primarily to lower subscription volumes and rates on Northern Border Pipeline, in ONEOK Partners’ natural gas pipeline business. Additionally, there was a gain on the sale of Bison Pipeline LLC by Northern Border Pipeline in the third quarter of 2008. Equity earnings from investments also decreased due to lower natural gas volumes gathered in ONEOK Partners’ various natural gas gathering and processing equity investments whose assets are located primarily in the Powder River Basin of Wyoming.

Allowance for equity funds used during construction decreased due primarily to the completion of the Arbuckle Pipeline in July 2009 and the Overland Pass Pipeline and related expansion projects in ONEOK Partners’ natural gas liquids business, and the Guardian Pipeline expansion and extension that was placed in service in February 2009 in its natural gas pipelines business.

Capital expenditures decreased due primarily to the completion of ONEOK Partners’ capital projects, primarily related to its natural gas liquids business.

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

	Years Ended December 31,
Operating Information	2010			2009			2008
Natural gas gathered (BBtu/d) (a)		1,067			1,123			1,164
Natural gas processed (BBtu/d) (a)		674			658			641
Natural gas transportation capacity contracted (MDth/d) (b)		5,616			5,507			4,835
Transportation capacity subscribed		87	%		86	%		83	%
Residue gas sales (BBtu/d) (a)		286			291			279
NGL sales (MBbl/d) (c)		457			408			283
NGLs fractionated (MBbl/d)		512			481			389
NGLs transported-gathering lines (MBbl/d)		440			372			260
NGLs transported-distribution lines (MBbl/d)		468			459			331
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.10		$	0.11		$	0.15
Realized composite NGL net sales price ($/gallon) (a) (d)	$	0.94		$	0.90		$	1.26
Realized condensate net sales price ($/Bbl) (a) (d)	$	63.81		$	78.35		$	88.35
Realized residue gas net sales price ($/MMBtu) (a) (d)	$	5.58		$	3.55		$	7.53
Realized gross processing spread ($/MMBtu) (a)	$	6.41		$	6.63		$	7.47
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business.
(b) - Unit of measure converted from MMcf/d in 2010. Prior periods have been recast to reflect this change.
(c) - Statistic relates to ONEOK Partners' natural gas liquids business.
(d) - Presented net of the impact of hedging activities and includes equity volumes only.

Distribution

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

							Variances					Variances
	Years Ended December 31,						2010 vs. 2009					2009 vs. 2008
Financial Results	2010		2009		2008		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Gas sales	$	2,038.3	$	2,014.7	$	2,690.2	$	23.6		1	%	$	(675.5	)	(25	%)
Transportation revenues		91.5		87.6		87.3		3.9		4	%		0.3		0	%
Cost of gas		1,403.4		1,410.8		2,123.1		(7.4	)	(1	%)		(712.3	)	(34	%)
Net margin, excluding other revenues		726.4		691.5		654.4		34.9		5	%		37.1		6	%
Other revenues		38.9		42.5		41.4		(3.6	)	(8	%)		1.1		3	%
Net margin		765.3		734.0		695.8		31.3		4	%		38.2		5	%
Operating costs		407.8		390.2		381.4		17.6		5	%		8.8		2	%
Depreciation and amortization		131.1		122.7		116.9		8.4		7	%		5.8		5	%
Gain (loss) on sale of assets		-		0.5		-		(0.5	)	(100	%)		0.5		100	%
Operating income	$	226.4	$	221.6	$	197.5	$	4.8		2	%	$	24.1		12	%
Capital expenditures	$	215.6	$	157.5	$	169.0	$	58.1		37	%	$	(11.5	)	(7	%)

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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,						2010 vs. 2009					2009 vs. 2008
Net margin, excluding other revenues	2010		2009		2008		Increase (Decrease)					Increase (Decrease)
Gas sales	(Millions of dollars)
Regulated
Residential	$	509.1	$	473.8	$	444.0	$	35.3		7	%	$	29.8		7	%
Commercial		108.9		105.1		101.3		3.8		4	%		3.8		4	%
Industrial		2.2		2.5		2.6		(0.3	)	(12	%)		(0.1	)	(4	%)
Wholesale		0.5		0.4		0.6		0.1		25	%		(0.2	)	(33	%)
Public Authority		4.2		4.1		3.8		0.1		2	%		0.3		8	%
Retail marketing		10.0		18.0		14.8		(8.0	)	(44	%)		3.2		22	%
Net margin on gas sales		634.9		603.9		567.1		31.0		5	%		36.8		6	%
Transportation margin		91.5		87.6		87.3		3.9		4	%		0.3		0	%
Net margin, excluding other revenues	$	726.4	$	691.5	$	654.4	$	34.9		5	%	$	37.1		6	%

2010 vs. 2009 - Net margin increased due primarily to the following:

·	an increase of $40.1 million from new rates in Oklahoma that increased fixed fees, which lowered our volumetric sensitivity and provides more consistent revenues each month;

·	an increase of $6.5 million from increased rider recoveries in Oklahoma and ad valorem tax surcharge recoveries in Kansas;

·	an increase of $3.7 million from higher natural gas sales volumes, primarily in the first quarter of 2010, due to colder weather;

·	an increase of $3.4 million from capital-recovery mechanisms in Kansas; and

·	an increase of $2.7 million from higher transportation volumes; offset partially by

·	a decrease of $17.4 million from the expiration of the 2009 capital-recovery mechanism in Oklahoma, which as a result of our 2009 rate case in Oklahoma, the revenues related to capital recovery are now included in base rates; and

·	a decrease of $7.6 million in retail marketing margins.

Operating costs increased due primarily to an increase of $15.5 million related to the recognition of previously deferred Integrity Management Program costs in Oklahoma that have been approved for recovery in our revenues.

Depreciation and amortization expense increased due primarily to an increase of $6.7 million in regulatory amortization associated with revenue rider recoveries.

2009 vs. 2008 - Net margin increased due primarily to the following:

·	an increase of $26.3 million resulting from capital-recovery mechanisms, which includes a $22.3 million increase in Oklahoma, a $3.0 million increase in Kansas and a $1.0 million increase in Texas;

·	an increase of $6.3 million in rider recoveries;

·	an increase of $3.2 million in retail marketing margins; and

·	an increase of $1.9 million resulting from the implementation of new rate mechanisms in Texas; offset partially by

·	a decrease of $1.7 million due to lower sales volumes.

Operating costs increased due primarily to the following:

·	an increase of $20.8 million in employee-related costs due primarily to increased incentive and benefit costs; and

·	an increase of $3.4 million in property tax expense; offset partially by

·	a decrease of $10.3 million in bad-debt expense as a result of the authorized recovery of the fuel-related portion of bad debts in Oklahoma, effective January 2009; and

·	a decrease of $5.3 million in vehicle-related costs.

Depreciation and amortization expense increased due primarily to the following:

·	an increase of $4.8 million in regulatory amortization associated with previously deferred costs that have been approved for recovery in our revenues; and

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·	an increase of $1.0 million in depreciation expense related to our investment in property, plant and equipment.

Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifications to customer-service lines, increasing system capabilities, general replacements and improvements, including an automated meter reading investment in Oklahoma. It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations.

Capital expenditures increased for 2010, compared with 2009, primarily as a result of expenditures related to an investment in automated meter reading in Oklahoma. Capital expenditures decreased for 2009, compared with 2008, primarily as a result of lower spending on growth projects due to the economic slowdowns experienced in our service territories during 2009.

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


	Years Ended December 31,
Number of Customers	2010		2009		2008
Residential		1,912,205		1,901,782		1,886,118
Commercial		153,650		156,337		159,748
Industrial		1,271		1,343		1,420
Wholesale		35		27		28
Public Authority		2,666		2,740		2,963
Transportation		11,308		10,410		10,376
Total customers		2,081,135		2,072,639		2,060,653

	Years Ended December 31,
Volumes (MMcf)	2010		2009		2008
Gas sales
Residential		121,240		120,370		125,834
Commercial		35,223		35,414		37,758
Industrial		1,211		1,208		1,395
Wholesale		9,212		10,032		7,186
Public Authority		2,848		2,673		2,592
Total volumes sold		169,734		169,697		174,765
Transportation		205,692		201,952		219,398
Total volumes delivered		375,426		371,649		394,163

Residential volumes increased during 2010, compared with 2009, due to colder temperatures across our entire service territory in the first quarter of 2010; however, the impact on margin was moderated by weather-normalization mechanisms.

Residential volumes decreased during 2009, compared with 2008, due to warmer temperatures across our entire service territory; however, the impact on margin was moderated by weather-normalization mechanisms.

Wholesale sales represent contracted natural gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Public authority natural gas volumes reflect volumes used by state agencies and school districts served by Texas Gas Service.

Regulatory Initiatives - Oklahoma - In September 2010, Oklahoma Natural Gas filed an application and supporting testimony with the OCC seeking approval of a demand portfolio of conservation and energy-efficiency programs and authorizing recovery of costs and performance incentives. The proposed programs include: Energy-Efficiency Education Program, Heating System Check-Up Program, Low-Income Energy-Efficiency Assistance Program, Water Heater Replacement Program, Space Heating Replacement Program, Clothes Dryer Replacement Program, New Homes Program and Commercial Customer Program. A settlement agreement was reached between all the parties to the filing and filed at the

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OCC on February 10, 2011. This agreement allows Oklahoma Natural Gas to pursue the key energy-efficiency programs requested in its filing. The settlement agreement was presented to an administrative law judge in a hearing on February 18, 2011.

In June 2010, the OCC approved recovery of our Integrity Management Program deferral for 2009 and annual adjustments associated with the prior recovery period in the amount of $16.7 million. Billing of the new rates began July 1, 2010.

In December 2009, the OCC approved a rate increase of $54.5 million, which included moving existing riders into base rates that effectively reduced the rate increase to a net amount of $25.7 million. The new rates went into effect on December 18, 2009, and reduce our volumetric exposure. Under a previous order, Oklahoma Natural Gas migrated from traditional rates to performance-based rates that provide for a streamlined annual review of the company’s performance, resulting in smaller, potentially more frequent rate adjustments.

Kansas - In December 2010, the KCC approved Kansas Gas Service’s application to increase the Gas System Reliability Surcharge, resulting in a $1.7 million increase in operating income for 2011, effective with customer billings in January 2011.

In May 2010, Kansas Gas Service was granted a motion to withdraw its application with the KCC to become an Efficiency Kansas Loan Program utility partner and provide a portfolio of energy-efficiency programs designed to encourage the purchase of energy-efficient natural gas appliances. The application was withdrawn as a result of the wide discrepancy between the positions of the parties involved in the case. Kansas Gas Service will continue to explore opportunities to promote energy-efficiency initiatives in a manner that does not penalize Kansas Gas Service and meets regulators’ requirements.

In December 2009, the KCC approved Kansas Gas Service’s application to increase the Gas System Reliability Surcharge. In April 2010, the surcharge recovery was slightly reduced as a result of a revised application. The impact of the Gas System Reliability Surcharge on 2010 operating income was an increase of $3.4 million.

Texas - In December 2009, Texas Gas Service filed a statement of intent to increase rates in its El Paso service area by $7.3 million. On April 13, 2010, the City of El Paso rejected the proposed increase. Texas Gas Service filed an appeal on May 12, 2010, with the RRC. The filing updated rate base and cost of service for pension expense and included a statement of intent to increase rates by $5.3 million. Subsequently, rate-case expenses were placed into a separate docket, effectively reducing the requested increase to $4.4 million. On December 14, 2010, the RRC approved a base rate increase of $0.8 million annually and a $0.8 million decrease in depreciation and amortization expense, plus recovery of annual pipeline integrity expenditures via a separate rider.

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. There were no write-offs of regulatory assets resulting from the failure to meet the criteria for capitalization during 2010, 2009 or 2008.

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,						2010 vs. 2009					2009 vs. 2008
Financial Results	2010		2009		2008		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	3,301.2	$	3,553.6	$	7,537.5	$	(252.4	)	(7	%)	$	(3,983.9	)	(53	%)
Cost of sales and fuel		3,141.5		3,394.0		7,441.6		(252.5	)	(7	%)		(4,047.6	)	(54	%)
Net margin		159.7		159.6		95.9		0.1		0	%		63.7		66	%
Operating costs		28.4		35.5		29.5		(7.1	)	(20	%)		6.0		20	%
Depreciation and amortization		0.6		0.5		0.8		0.1		20	%		(0.3	)	(38	%)
Gain on sale of assets		-		-		1.5		-		0	%		(1.5	)	(100	%)
Operating income	$	130.7	$	123.6	$	67.1	$	7.1		6	%	$	56.5		84	%
Capital expenditures	$	0.5	$	0.1	$	0.1	$	0.4		*		$	-		0	%
* Percentage change is greater than 100 percent.

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

							Variances					Variances
	Years Ended December 31,						2010 vs. 2009					2009 vs. 2008
	2010		2009		2008		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Marketing, storage and transportation revenues, gross	$	342.9	$	367.7	$	313.4	$	(24.8	)	(7	%)	$	54.3		17	%
Storage and transportation costs		189.4		211.2		219.8		(21.8	)	(10	%)		(8.6	)	(4	%)
Marketing, storage and transportation, net		153.5		156.5		93.6		(3.0	)	(2	%)		62.9		67	%
Financial trading, net		6.2		3.1		2.3		3.1		100	%		0.8		35	%
Net margin	$	159.7	$	159.6	$	95.9	$	0.1		0	%	$	63.7		66	%

Marketing, storage and transportation revenues, gross, primarily includes marketing, purchases and sales, premium services and the impact of cash flow and fair value hedges and other derivative instruments used to manage our risk associated with these activities. Storage and transportation costs primarily include the cost of leasing capacity, storage injection and withdrawal fees, fuel charges and gathering fees. Risk management and operational decisions have an impact on the net result of our marketing, premium services and storage activities. We evaluate our strategies on an ongoing basis to optimize the value of our contracted assets and to minimize the financial impact of market conditions on the services we provide.

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

2010 vs. 2009 - Net margin was relatively unchanged but reflects the following:

·	an increase of $39.7 million in storage and marketing margins, net of hedging activities, due primarily to the following:

-	higher realized seasonal storage price differentials and a decrease in storage expense due to the reduction in storage capacity; offset partially by

-	a reduction in storage withdrawals due to decreased natural gas storage capacity under lease; and

-	unfavorable unrealized fair-value changes on non-qualifying economic hedge activity and marketing margins; and

·	an increase of $3.1 million in financial trading margins; offset by

·	a decrease of $21.4 million in transportation margins, net of hedging, due primarily to narrower realized Mid-Continent-to-Gulf Coast price differentials; and

a decrease of $21.3 million in premium-services margins, associated primarily with lower demand fees as a result of lower volatility of natural gas prices, offset partially by the favorable management of customer-peaking requirements resulting from warmer weather in the fourth quarter of 2010, compared with the same period last year.

Operating costs decreased due primarily to a decrease in legal-related costs and property taxes.

2009 vs. 2008 - Net margin increased due primarily to the following:

·	an increase of $41.3 million in transportation margins, net of hedging activities, due primarily to higher realized Rocky Mountain-to-Mid-Continent transportation margins, resulting from the following:

-	realization of more favorable hedges related to transportation spreads; and

-	favorable unrealized fair-value changes on non-qualifying economic hedge activity and ineffectiveness on qualified hedges;

·	an increase of $13.9 million in premium services, associated primarily with managing our demand load, due to warmer weather in the first quarter of 2009, offset partially by increased peaking demand load due to colder than normal weather in the fourth quarter of 2009; and

·	an increase of $7.8 million in storage and marketing margins, net of hedging activities, due primarily to the following:

-	favorable unrealized fair-value changes on non-qualifying economic hedge activity and marketing margins; and

-	the impact of a lower of cost or market inventory write-down of $9.7 million in the third quarter 2008; offset partially by

-	lower realized seasonal storage differentials.

Operating costs increased due to higher legal and employee-related costs.

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

	Years Ended December 31,
Operating Information		2010		2009		2008
Natural gas marketed (Bcf)		919		1,105		1,173
Natural gas gross margin ($/Mcf)	$	0.18	$	0.15	$	0.09
Physically settled volumes (Bcf)		1,874		2,217		2,374

Our Energy Services segment has focused its efforts on aligning its contracted natural gas transportation and storage capacity with meeting the needs of our premium-services customers. The effect of this strategy has been a reduction in our contracted natural gas transportation and storage capacity, which also will reduce our working-capital requirements primarily through a reduction in natural gas inventory levels.

Our natural gas in storage at December 31, 2010, was 63.0 Bcf, compared with 60.5 Bcf at December 31, 2009. At December 31, 2010, our total natural gas storage capacity under lease was 73.6 Bcf, compared with 82.8 Bcf at December 31, 2009. At December 31, 2010, our natural gas storage capacity under lease had a maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.3 Bcf/d. At December 31, 2010, our natural gas transportation capacity was 1.4 Bcf/d, of which 1.1 Bcf/d was contracted under long-term natural gas transportation contracts, compared with 1.7 Bcf/d of total capacity and 1.4 Bcf/d of long-term capacity at the end of 2009.

Natural gas volumes marketed and physically settled volumes decreased during 2010, compared with 2009, due primarily to reduced transportation capacity and lower transported volumes. Transportation capacity in certain markets was not utilized due to the economics of the location differentials.

Natural gas volumes marketed decreased during 2009, compared with 2008, due primarily to significantly warmer weather in November 2009, compared with the same period in 2008. In addition, during the first quarter of 2009, compared with the first quarter 2008, we experienced fewer incremental sales from inventory beyond our normal baseload due to warmer than normal temperatures.

CONTINGENCIES

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal in the course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the 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 - Part of our strategy is to grow through internally generated growth projects and acquisitions that strengthen and complement our existing assets. ONEOK and ONEOK Partners have relied primarily on operating cash flow, commercial paper, bank credit facilities, debt issuances and/or the sale of equity for their liquidity and capital resource requirements. ONEOK and ONEOK Partners fund their operating expenses, debt service, dividends to shareholders and distributions to unitholders primarily with operating cash flow. We expect to continue to use these sources and ONEOK Partners’ commercial paper program, discussed below, for liquidity and capital resource needs on both a short- and long-term basis. Neither ONEOK nor ONEOK Partners guarantees the debt or other similar commitments to unaffiliated parties, and ONEOK does not guarantee the debt or other similar commitments of ONEOK Partners.

In 2010, ONEOK accessed the commercial paper markets to meet its short-term liquidity needs, and ONEOK Partners utilized the ONEOK Partners Credit Agreement and accessed the commercial paper markets beginning in June 2010 to fund its short-term liquidity needs. Additionally, ONEOK Partners accessed the public debt markets in January 2011 and the public equity markets in February 2010 for its long-term financing needs. See discussion below under “ONEOK Partners’ Debt Issuance” and “ONEOK Partners’ Equity Issuance” for more information.

In June 2010, ONEOK Partners established a commercial paper program providing for the issuance of up to $1.0 billion of unsecured commercial paper notes to fund its short-term borrowing needs. The maturities of ONEOK Partners’ commercial paper notes vary but may not exceed 270 days from the date of issue. ONEOK Partners’ commercial paper notes are

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generally sold at a negotiated discount from par. The ONEOK Partners Credit Agreement, which expires in March 2012, is available to repay its commercial paper notes, if necessary. Amounts outstanding under the commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement.

ONEOK’s and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on market conditions and ONEOK’s and ONEOK Partners’ respective financial condition and credit ratings. ONEOK and ONEOK Partners anticipate that cash flow generated from operations, existing capital resources and ability to obtain financing will enable both entities to maintain current levels of operations and planned operations, collateral requirements and fund capital expenditures.

Capitalization Structure - The following table sets forth our consolidated capitalization structure for the periods indicated:

	December 31,		December 31,
	2010		2009
Long-term debt		52%		57%
Total equity		48%		43%

Debt (including notes payable)		55%		61%
Total equity		45%		39%

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 ONEOK’s capital structure, excluding the debt of ONEOK Partners, for the periods indicated:

	December 31,		December 31,
	2010		2009
Long-term debt		38%		41%
ONEOK shareholders' equity		62%		59%

Debt (including notes payable)		40%		46%
ONEOK shareholders' equity		60%		54%

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.

Short-term Liquidity - ONEOK’s principal sources of short-term liquidity consist of cash generated from operating activities, quarterly distributions from ONEOK Partners and the issuance of commercial paper. To the extent commercial paper is unavailable, the ONEOK Credit Agreement may be utilized. The ONEOK Credit Agreement expires in July 2011 and we anticipate entering into a new agreement prior to the maturity date. ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities, the ONEOK Partners Credit Agreement and ONEOK Partners’ commercial paper program.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion. At December 31, 2010, ONEOK had $127.0 million in commercial paper outstanding, $27.0 million in letters of credit issued under the ONEOK Credit Agreement and approximately $30.1 million of available cash and cash equivalents. ONEOK had

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approximately $1.0 billion of credit available at December 31, 2010, under the ONEOK Credit Agreement. As of December 31, 2010, ONEOK could have issued $3.7 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements.

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, 2010, ONEOK Partners had $429.9 million in commercial paper outstanding, no borrowings outstanding under the ONEOK Partners Credit Agreement, leaving approximately $570.1 million of credit available under the ONEOK Partners Credit Agreement, and approximately $0.9 million of available cash and cash equivalents. As of December 31, 2010, ONEOK Partners could have issued $1.0 billion of additional short- and long-term debt under the most restrictive provisions contained in its various borrowing agreements. At December 31, 2010, ONEOK Partners had $24.2 million in letters of credit issued outside the ONEOK Partners Credit Agreement.

The ONEOK Credit Agreement contains certain financial, operational and legal covenants. These requirements include, among others:

·	a $400 million sublimit for the issuance of standby letters of credit;

·	a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter;

·	a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners,

·	a limit on new investments in master limited partnerships; and

other customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in ONEOK’s businesses, changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that prevents ONEOK from restricting its subsidiaries’ ability to pay dividends.

The debt covenant calculations in the ONEOK Credit Agreement exclude the debt of ONEOK Partners. Upon breach of any covenant by ONEOK, amounts outstanding under the ONEOK Credit Agreement may become immediately due and payable. At December 31, 2010, ONEOK’s stand-alone debt-to-capital ratio, as defined by the ONEOK Credit Agreement, was 39.4 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement.

Under the ONEOK Partners Credit Agreement, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in ONEOK Partners’ Credit Agreement, as adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 to 1. If ONEOK Partners consummates one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will be increased to 5.5 to 1 for the three calendar quarters following the acquisition. Upon any breach of any covenant by ONEOK Partners in its ONEOK Partners Credit Agreement, amounts outstanding under the ONEOK Partners Credit Agreement may become immediately due and payable. At December 31, 2010, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.79 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement. As a result of ONEOK Partners’ January 2011 debt issuance, available borrowings are limited by the ratio of indebtedness to adjusted EBITDA covenant under the ONEOK Partners Credit Agreement; however, ONEOK Partners had approximately $956 million in cash at January 31, 2011, and $266 million of available borrowings that provide ample liquidity to meet its funding needs. ONEOK Partners expects the limitation of its available borrowings to be eliminated during 2011.

At December 31, 2010, the weighted-average interest rate on each of ONEOK’s and ONEOK Partners’ short-term debt outstanding was 0.38 percent. The weighted-average interest rates for the year ended December 31, 2010, on ONEOK’s and ONEOK Partners’ short-term borrowings were 0.30 percent and 0.58 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 2011, compared with interest rates on amounts outstanding at December 31, 2010.

Long-term Financing - In addition to the principal sources of short-term liquidity discussed above, options available to ONEOK to meet its longer-term cash requirements include the issuance of equity, issuance of long-term notes, issuance of convertible debt securities, asset securitization and the sale and leaseback of facilities. Options available to ONEOK Partners to meet its longer-term cash requirements include the issuance of common units, issuance of long-term notes, issuance of convertible debt securities, and asset securitization and sale and leaseback 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

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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’s and ONEOK Partners’ investment-grade credit ratings, general financial condition and market expectations regarding their future earnings and projected cash flows, ONEOK and ONEOK Partners believe that they will be able to meet their respective cash requirements and maintain their investment-grade credit ratings.

ONEOK Partners’ Debt Maturity - In June 2010, ONEOK Partners repaid $250.0 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, ONEOK Partners no longer has any obligation to offer to repurchase the $225 million senior notes due March 2011 in the event that ONEOK Partners’ long-term debt credit ratings fall below investment grade.

Debt Covenants - The indentures governing ONEOK’s senior notes due 2011, 2019 and 2028 include an event of default upon acceleration of other indebtedness of $15 million or more, and the indentures governing the senior notes due 2015 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 2011, 2015, 2019, 2028 and 2035 to declare those notes immediately due and payable in full.

ONEOK may redeem the notes due 2011, 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 notes due 2019 and 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. 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. The notes due 2011, 2015, 2019, 2028 and 2035 are senior unsecured obligations, ranking equally in right of payment with all of ONEOK’s existing and future unsecured senior indebtedness.

The indentures governing ONEOK Partners’ senior notes due March 2011 include an event of default upon acceleration of other indebtedness of $25 million or more, and the indentures governing its other 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 notes immediately due and payable in full.

ONEOK Partners may redeem the notes due 2011, 2012, 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 3.25-percent notes due 2016 and 6.125-percent notes due 2041 at par starting one and six months, respectively, before their maturity dates. Prior to these times, ONEOK Partners may redeem these notes on the same terms as its other senior notes. ONEOK Partners’ senior notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and structurally subordinate to all of the existing and future debt and other liabilities of any non-guarantor subsidiaries. ONEOK Partners’ senior notes are nonrecourse to ONEOK.

Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are financed through operating cash flows, short- and long-term debt and the issuance of equity. Capital expenditures were $582.7 million, $791.2 million and $1,473.1 million for 2010, 2009 and 2008, respectively, exclusive of acquisitions. Of these amounts, ONEOK Partners’ capital expenditures were $352.7 million, $615.7 million and $1,253.9 million for 2010, 2009 and 2008, respectively, exclusive of acquisitions. Capital expenditures in 2010 were significantly less than 2009, due primarily to the completion of the Arbuckle

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Pipeline, the D-J Basin lateral pipeline, Piceance lateral pipeline, the Grasslands natural gas processing plant expansion and the Guardian Pipeline expansion and extension. This decrease is offset partially by an increase in capital expenditures in ONEOK Partners’ natural gas gathering and processing business related primarily to its projects in the Williston Basin.

The following table sets forth our 2011 projected capital expenditures, excluding AFUDC:

2011 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners	$	1,116
Distribution		224
Other		22
Total projected capital expenditures	$	1,362

In 2011, ONEOK Partners expects to make contributions of approximately $35 million to $40 million for additional pump stations and the expansion of existing pump stations to increase the capacity of Overland Pass Pipeline to accommodate increased volumes of unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies.

Other - We lease portions of equipment at a natural gas processing plant under non-cancelable operating leases. We acquired the leases in a business combination in prior years. ONEOK Partners has certain contractual rights to the Bushton Plant through a Processing and Services Agreement with us, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012. ONEOK Partners has contracted for all of the capacity of the Bushton Plant from us. In exchange, ONEOK Partners pays us for all costs and expenses necessary for the operation and maintenance of the Bushton Plant and reimburses us for our obligations under equipment leases covering portions of the Bushton Plant. The Bushton equipment leases will expire in 2012 unless, in the second quarter of 2011, we provide irrevocable notice of our intent to either renew the equipment leases at fair market rental value or purchase the original leased equipment (or any replacement parts) pursuant to the terms of the equipment leases. The Processing and Services Agreement provides that ONEOK Partners will reimburse us for any amounts incurred in connection with the foregoing option, if any.

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. The Northern Border Pipeline Management Committee has adopted a cash distribution policy related to financial ratio targets and capital contributions. The cash distribution policy defines minimum equity-to- total-capitalization ratios to be used by the Northern Border Pipeline Management Committee to establish the timing and amount of required capital contributions. In addition, any shortfall due to the inability to refinance maturing debt will be funded by capital contributions. See Note N of the Notes to Consolidated Financial Statements in this Annual Report for a discussion of ONEOK Partners’ investment in Northern Border Pipeline.

Northern Border Pipeline anticipates requiring an additional equity contribution of approximately $100 million to $120 million from its partners in 2011, of which ONEOK Partners’ share will be approximately $50 million to $60 million based on its 50-percent equity interest.

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Credit Ratings - Our credit ratings as of December 31, 2010, are shown in the table below:

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

ONEOK’s and ONEOK Partners’ commercial paper are rated Prime-2 by Moody’s and A2 by S&P. ONEOK’s and ONEOK Partners’ credit ratings, which are currently investment grade, may be affected by a material change in financial ratios or a material event affecting the business. The most common criteria for assessment of credit ratings are the debt-to-capital ratio, business risk profile, pretax and after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners do not currently anticipate their respective credit ratings to be downgraded. However, if ONEOK’s or ONEOK Partners’ credit ratings were downgraded, the cost to borrow funds under their respective commercial paper programs and credit agreements would increase, and ONEOK or ONEOK Partners potentially could lose access to the commercial paper market. In the event that ONEOK is unable to borrow funds under its commercial paper program and there has not been a material adverse change in its business, ONEOK would continue to have access to the ONEOK Credit Agreement, which expires in July 2011. 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 March 2012. An adverse rating change alone is not a default under the ONEOK Credit Agreement or the ONEOK Partners Credit Agreement. See additional discussion about our credit ratings under “Long-term Financing.”

Our Energy Services segment relies upon the investment-grade rating of ONEOK’s senior unsecured long-term debt to reduce its collateral requirements. If ONEOK’s credit ratings were to decline below investment grade, our ability to participate in energy marketing and trading activities could be significantly limited. Without an investment-grade rating, we may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments. At December 31, 2010, ONEOK could have been required to fund approximately $7.4 million in margin requirements related to financial contracts upon such a downgrade. A decline in ONEOK’s credit rating below investment grade may also significantly impact other business segments.

In the normal course of business, ONEOK’s and ONEOK Partners’ counterparties provide secured and unsecured credit. In the event of a downgrade in ONEOK’s or ONEOK Partners’ credit ratings or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK Partners could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 62 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, in included under Note L of the Notes to Consolidated Financial Statements in this Annual Report.

During 2010, we made contributions of $96.8 million and $12.5 million to our defined benefit pension plans and postretirement benefit plans, respectively. These contributions to our defined benefit pension plans included $57.0 million of contributions attributable to the 2011 plan year. We anticipate our total 2011 contributions will include an additional $4.3 million for our defined benefit pension plans and $13.9 million for our postretirement benefit plans. The expected 2011 benefit payments for our postretirement benefit plans are estimated to be $15.2 million.

ENVIRONMENTAL MATTERS

Information about our environmental matters is included in “Environmental and Safety Matters” of Item 1, Business and Note P of the Notes to Consolidated Financial Statements in this Annual Report. We cannot assure that existing environmental 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

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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 2010, 2009 and 2008.

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. 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:

										Variances					Variances
	Years Ended December 31,									2010 vs. 2009					2009 vs. 2008
	2010			2009			2008			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	834.0		$	1,452.7		$	475.7		$	(618.7	)	(43	%)	$	977.0		*
Investing activities		(134.3	)		(787.8	)		(1,454.3	)		653.5		83	%		666.5		46	%
Financing activities		(698.1	)		(1,145.6	)		1,469.6			447.5		39	%		(2,615.2	)	*
Change in cash and cash equivalents		1.6			(480.7	)		491.0			482.3		(100	%)		(971.7	)	*
Cash and cash equivalents at beginning of period		29.4			510.1			19.1			(480.7	)	(94	%)		491.0		*
Cash and cash equivalents at end of period	$	31.0		$	29.4		$	510.1		$	1.6		5	%	$	(480.7	)	(94	%)
* Percentage change is greater than 100 percent.

Operating Cash Flows - Operating cash flows are affected by earnings from our business activities. We provide services to producers and consumers of natural gas, condensate and NGLs. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, 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.

2010 vs. 2009 - Cash flows from operating activities, before changes in operating assets and liabilities, were $994.9 million for 2010, compared with $974.3 million for 2009. The increase was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information on page 43.

The changes in operating assets and liabilities decreased operating cash flows $160.9 million for 2010, compared with an increase of $478.4 million for 2009, primarily as a result of the impact of commodity prices on our operating assets and liabilities and an increase in volumes of commodities in storage primarily in our Distribution segment and ONEOK Partners’ natural gas liquids business.

2009 vs. 2008 - Cash flows from operating activities, before changes in operating assets and liabilities, were $974.3 million for 2009, compared with $991.0 million for 2008. The decrease was due primarily to changes in net margin and operating expenses discussed in Financial Results and Operating Information beginning on page 43.

The changes in operating assets and liabilities increased operating cash flows $478.4 million for 2009, compared with a decrease of $515.3 million for 2008, primarily as a result of the following:

· a decrease in cash collateral and margin requirements in our Energy Services segment; and

· the impact of commodity prices on our operating assets and liabilities.

Investing Cash Flows - Cash used in investing activities decreased for 2010, compared with 2009, due primarily to the $423.7 million in proceeds ONEOK Partners received from the sale of a 49-percent ownership interest in Overland Pass Pipeline Company in 2010 and reduced capital expenditures as a result of the completion of the capital projects in our ONEOK Partners segment in 2009. Cash used in investing activities decreased for 2009, compared with 2008, due primarily to reduced capital expenditures as a result of the completion of the capital projects in our ONEOK Partners segment in 2009.

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Financing Cash Flows - Cash used in financing activities decreased for 2010, compared with the 2009, due primarily to decreased borrowings resulting from the completion of ONEOK Partners’ capital projects in 2009, ONEOK Partners’ repayment of $250 million of maturing senior notes in 2010, an increase of approximately 12.0 percent in dividends paid during 2010, an increase of approximately 3.0 percent in cash distributions per unit paid to noncontrolling interests and additional ONEOK Partners common units, offset partially by increased net proceeds generated from ONEOK Partners’ common unit offering in 2010.

Cash used in financing activities increased for 2009, compared with cash provided by financing activities in 2008, due primarily to the repayment of amounts borrowed in 2008 related to ONEOK Partners’ capital projects, an increase of approximately 6.1 percent in dividends paid during 2009, an increase of approximately 3.0 percent in cash distributions per unit paid to noncontrolling interests and additional ONEOK Partners common units, offset partially by increased net proceeds generated from ONEOK Partners’ common unit offering in 2009.

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, 2010. For additional discussion of the debt and operating lease agreements, see Notes G and P, respectively, of the Notes to the Consolidated Financial Statements in this Annual Report:

	Payments Due by Period
Contractual Obligations	Total		2011		2012		2013		2014		2015		Thereafter
ONEOK	(Thousands of dollars)
Commercial paper	$	127,000	$	127,000	$	-	$	-	$	-	$	-	$	-
Long-term debt		1,480,225		406,306		6,329		6,205		6,006		406,006		649,373
Interest payments on debt		924,100		71,400		62,700		62,300		61,900		50,200		615,600
Operating leases		34,043		32,130		901		591		324		90		7
Firm transportation and storage
contracts		521,711		133,772		126,088		91,581		73,137		47,827		49,306
Financial and physical derivatives		877,413		817,783		58,541		998		91		-		-
Employee benefit plans		18,171		18,171		-		-		-		-		-
	$	3,982,663	$	1,606,562	$	254,559	$	161,675	$	141,458	$	504,123	$	1,314,286

ONEOK Partners
Commercial paper	$	429,855	$	429,855	$	-	$	-	$	-	$	-	$	-
Long-term debt		2,822,850		236,931		361,062		7,650		7,650		7,650		2,201,907
Interest payments on debt		2,697,300		183,100		163,400		157,500		156,000		154,300		1,883,000
Operating leases		21,139		3,503		3,037		2,932		2,513		996		8,158
Firm transportation and storage
contracts		42,688		6,487		6,784		6,658		6,268		6,081		10,410
Financial and physical derivatives		154,524		154,524		-		-		-		-		-
Purchase commitments,
rights of way and other		449,941		174,784		66,577		25,911		25,905		25,629		131,135
	$	6,618,297	$	1,189,184	$	600,860	$	200,651	$	198,336	$	194,656	$	4,234,610
Total	$	10,600,960	$	2,795,746	$	855,419	$	362,326	$	339,794	$	698,779	$	5,548,896

Long-term debt - Long-term debt as reported in our Consolidated Balance Sheets includes unamortized debt discount and the mark-to-market effect of interest-rate swaps.

Interest payments on debt - Interest expense is calculated by multiplying long-term debt by the respective coupon rates, adjusted for active swaps.

Operating leases - Our operating leases include a natural gas processing plant, office space, pipeline equipment, rights of way and vehicles. Operating lease obligations for ONEOK Partners exclude intercompany payments related to the lease of a natural gas processing plant.

Firm transportation and storage contracts - We are party to fixed-price contracts for firm transportation and storage capacity. However, the costs associated with our Distribution segment’s contracts that are recovered through rates as allowed by the applicable regulatory agency are excluded from the table above.

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Financial and physical derivatives - These are obligations arising from our fixed- and variable-price purchase commitments for financial and physical commodity derivatives. However, the commitments associated with our Distribution segment’s contracts are recovered through rates as allowed by the applicable regulatory agency and are excluded from the table above. Estimated future variable-price purchase commitments are based on market information at December 31, 2010. 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 contribution to maintain the minimum required funding level to our pension and postretirement benefit plans for 2011. See Note L of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our employee benefit plans.

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

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Annual Report are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. The forward-looking statements relate to our anticipated financial performance, management’s plans and objectives for our future operations, our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this 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 status of deregulation of retail natural gas distribution;

·	the capital intensive nature of our businesses;

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

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

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

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

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

·	the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, 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;

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·	changes in demand for the use of natural gas 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 Pipeline and Hazardous Materials Safety Administration and the EPA;

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

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

·	the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;

·	the impact and outcome of pending and future litigation;

·	the ability to market pipeline capacity on favorable terms, including the effects of:

-	future demand for and prices of natural gas and NGLs;

-	competitive conditions in the overall energy market;

-	availability of supplies of Canadian and United States natural gas; and

-	availability of additional storage capacity;

·	performance of contractual obligations by our customers, service providers, contractors and shippers;

·	the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;

our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;

·	the mechanical integrity of facilities operated;

·	demand for our services in the proximity of our facilities;

·	our ability to control operating costs;

·	adverse labor relations;

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

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

·	the risk of a prolonged slowdown in growth or decline in the United States economy or the risk of delay in growth recovery in the United States economy, including liquidity risks in United States credit markets;

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

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

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

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

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

·	the impact of unsold pipeline capacity being greater or less than expected;

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

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

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

·	the impact of potential impairment charges;

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

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

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·	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, and marketing and trading activities. The committee also monitors risk metrics including value-at-risk (VAR) 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 would occur assuming hypothetical future movements in interest rates or commodity prices. 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. 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 in storage and basis risk.

ONEOK Partners

ONEOK Partners is exposed to commodity price risk as a result of receiving commodities in exchange for its gathering and processing services. To a lesser extent, ONEOK Partners is exposed to 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 the risk of locational price differentials and the cost of third-party transportation to various market locations. As part of ONEOK Partners’ hedging strategy, ONEOK Partners uses commodity fixed-price physical forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize earnings volatility in its natural gas gathering and processing business related to natural gas, NGL and condensate price fluctuations.

ONEOK Partners reduces its gross processing spread exposure through a combination of physical and financial hedges. ONEOK Partners utilizes a portion of its percent-of-proceeds equity natural gas as an offset, or natural hedge, to an equivalent portion of its keep-whole shrink requirements. This has the effect of converting ONEOK Partners’ gross processing spread risk to NGL commodity price risk, and ONEOK Partners then uses financial instruments to hedge the sale of NGLs.

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As of December 31, 2010, ONEOK Partners had $17.6 million of derivative assets and $6.5 million of derivative liabilities, excluding the impact of netting, all of which related to commodity contracts. The following tables set forth ONEOK Partners’ hedging information for the periods indicated, as of February 21, 2011:

	Year Ending December 31, 2011
	Volumes Hedged		Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		5,469	$	1.17	/ gallon		67%
Condensate (Bbl/d) (a)		1,713	$	2.13	/ gallon		75%
Total (Bbl/d)		7,182	$	1.40	/ gallon		69%
Natural gas (MMBtu/d)		24,596	$	5.61	/ MMBtu		74%
(a) - Hedged with fixed-price swaps.

	Year Ending December 31, 2012
	Volumes Hedged		Average Price			Percentage Hedged
NGLs (Bbl/d) (a)		513	$	2.34	/ gallon		4%
Condensate (Bbl/d) (a)		1,245	$	2.34	/ gallon		50%
Total (Bbl/d)		1,758	$	2.34	/ gallon		12%
(a) - Hedged with fixed-price swaps.

ONEOK Partners’ commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas, excluding the effects of hedging, and assuming normal operating conditions. ONEOK Partners’ condensate sales are based on the price of crude oil. ONEOK Partners estimates the following:

·	a $0.01 per gallon decrease in the composite price of NGLs would decrease annual net margin by approximately $1.2 million;

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

·	a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $1.1 million.

ONEOK Partners is also exposed to commodity price 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, known as basis risk. ONEOK Partners utilizes fixed-price 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 NGL 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. At December 31, 2010, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas pipeline business.

Distribution

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

Energy Services

Our Energy Services segment is exposed to commodity price risk, basis risk and price volatility arising from natural gas in storage, requirement contracts, asset management contracts and index-based purchases and sales of natural gas at various market locations. We minimize the volatility of 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 are also exposed to

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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 $101.1 million and $161.5 million of net assets at December 31, 2010 and 2009, 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, 2009	$	3,656
Derivatives reclassified or otherwise settled during the period		(15,112	)
Fair value of new derivatives entered into during the period		3,481
Other changes in fair value		10,700
Net fair value of derivatives outstanding at December 31, 2009		2,725
Derivatives reclassified or otherwise settled during the period		(7,494	)
Fair value of new derivatives entered into during the period		31,817
Other changes in fair value		(18,607	)
Net fair value of derivatives outstanding at December 31, 2010 (a)	$	8,441
(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: $2.5 million matures through March 2011 and $5.9 million matures through March 2015.

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

For further discussion of fair value measurements and 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 B and C 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 $2.9 million and $5.4 million at December 31, 2010 and 2009, respectively. The following table sets forth the average, high and low VAR calculations for the periods indicated:

	Years Ended December 31,
Value-at-Risk	2010		2009
	(Millions of dollars)
Average	$	5.5	$	8.0
High	$	9.6	$	14.1
Low	$	2.3	$	4.6

Our VAR calculation includes derivatives, executory storage and transportation agreements and their related hedges. The variations in the VAR data are reflective of market volatility and changes in our portfolio during the year. The decrease in average VAR for 2010, compared with 2009, was due primarily to higher correlations between regional locations and a decrease in natural gas prices and volatility.

Our VAR calculation uses historical prices, placing more emphasis on the most recent price movements. We calculate the VAR on our mark-to-market derivative positions, which reflects the risk associated with derivatives whose change in fair value will impact current period earnings. VAR associated with these derivative positions was not material during 2010 or 2009. 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 the business, operating results or financial position.

INTEREST-RATE RISK

General - We are subject to the risk of interest-rate fluctuation in the normal course of business. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and, at times, interest-rate swaps. Fixed-rate swaps may be used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps may be used to convert the fixed rates of long-term borrowings into short-term variable rates. At December 31, 2010, the interest rate on all of ONEOK’s and ONEOK Partners’ long-term debt was fixed, and neither ONEOK nor ONEOK Partners had any 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

ONEOK, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, shareholders' equity, comprehensive income and cash flows present fairly, in all material respects, the financial position of ONEOK, Inc. and its subsidiaries (the Company) at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, 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, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 in the Company's Form 10-K for the year ended December 31, 2010. 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 22, 2011

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2010			2009			2008
	(Thousands of dollars, except per share amounts)

Revenues	$	13,030,051		$	11,111,651		$	16,157,433
Cost of sales and fuel		10,957,509			9,095,705			14,221,906
Net margin		2,072,542			2,015,946			1,935,527
Operating expenses
Operations and maintenance		748,612			736,125			694,597
Depreciation and amortization		307,317			288,991			243,927
General taxes		91,215			100,996			82,315
Total operating expenses		1,147,144			1,126,112			1,020,839
Gain on sale of assets		18,619			4,806			2,316
Operating income		944,017			894,640			917,004
Equity earnings from investments (Note N)		101,880			72,722			101,432
Allowance for equity funds used during construction		1,018			26,868			50,906
Other income		11,590			22,609			16,838
Other expense		(11,102	)		(17,492	)		(27,475	)
Interest expense		(292,239	)		(300,822	)		(264,167	)
Income before income taxes		755,164			698,525			794,538
Income taxes (Note M)		(213,834	)		(207,321	)		(194,071	)
Net income		541,330			491,204			600,467
Less: Net income attributable to noncontrolling interests		206,698			185,753			288,558
Net income attributable to ONEOK	$	334,632		$	305,451		$	311,909

Earnings per share of common stock (Note J)
Net earnings per share, basic	$	3.15		$	2.90		$	2.99
Net earnings per share, diluted	$	3.10		$	2.87		$	2.95

Average shares of common stock (thousands)
Basic		106,368			105,362			104,369
Diluted		107,785			106,320			105,760

Dividends declared per share of common stock	$	1.82		$	1.64		$	1.56
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	December 31,		December 31,
	2010		2009
Assets	(Thousands of dollars)
Current assets
Cash and cash equivalents	$	31,034	$	29,399
Accounts receivable, net		1,332,726		1,437,994
Gas and natural gas liquids in storage		708,933		583,127
Commodity imbalances		94,854		186,015
Energy marketing and risk management assets (Notes B and C)		61,940		113,039
Other current assets		149,558		238,890
Total current assets		2,379,045		2,588,464

Property, plant and equipment
Property, plant and equipment		9,854,485		10,145,800
Accumulated depreciation and amortization		2,541,302		2,352,142
Net property, plant and equipment (Note D)		7,313,183		7,793,658

Investments and other assets
Goodwill and intangible assets (Note E)		1,022,894		1,030,560
Energy marketing and risk management assets (Notes B and C)		1,921		23,125
Investments in unconsolidated affiliates (Note N)		1,188,124		765,163
Other assets		594,008		626,713
Total investments and other assets		2,806,947		2,445,561
Total assets	$	12,499,175	$	12,827,683
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	December 31,			December 31,
	2010			2009
Liabilities and equity	(Thousands of dollars)
Current liabilities
Current maturities of long-term debt (Note G)	$	643,236		$	268,215
Notes payable (Note F)		556,855			881,870
Accounts payable		1,215,468			1,240,207
Commodity imbalances		288,494			394,971
Energy marketing and risk management liabilities (Notes B and C)		22,800			65,162
Other current liabilities		424,259			488,487
Total current liabilities		3,151,112			3,338,912

Long-term debt, excluding current maturities		3,686,542			4,334,204

Deferred credits and other liabilities
Deferred income taxes		1,171,997			1,037,665
Energy marketing and risk management liabilities (Notes B and C)		2,221			8,926
Other deferred credits		566,462			662,514
Total deferred credits and other liabilities		1,740,680			1,709,105

Commitments and contingencies (Note P)

Equity (Note H)
ONEOK shareholders' equity:
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 122,815,636 shares and outstanding
106,815,582 shares at December 31, 2010; issued 122,394,015 shares and
outstanding 105,906,776 shares at December 31, 2009		1,228			1,224
Paid-in capital		1,392,671			1,322,340
Accumulated other comprehensive loss (Note I)		(108,802	)		(118,613	)
Retained earnings		1,826,800			1,685,710
Treasury stock, at cost: 16,000,054 shares at December 31, 2010 and
16,487,239 shares at December 31, 2009		(663,274	)		(683,467	)
Total ONEOK shareholders' equity		2,448,623			2,207,194

Noncontrolling interests in consolidated subsidiaries		1,472,218			1,238,268

Total equity		3,920,841			3,445,462
Total liabilities and equity	$	12,499,175		$	12,827,683
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Years Ended December 31,
	2010			2009			2008
	(Thousands of dollars)
Operating Activities
Net income	$	541,330		$	491,204		$	600,467
Depreciation and amortization		307,317			288,991			243,927
Allowance for equity funds used during construction		(1,018	)		(26,868	)		(50,906	)
Gain on sale of assets		(18,619	)		(4,806	)		(2,316	)
Equity earnings from investments		(101,880	)		(72,722	)		(101,432	)
Distributions received from unconsolidated affiliates		96,958			75,377			93,261
Deferred income taxes		142,303			198,713			165,191
Share-based compensation expense		24,372			23,148			30,791
Other		4,153			1,216			11,992
Changes in assets and liabilities, net of acquisitions:
Accounts receivable		92,469			(181,426	)		433,859
Gas and natural gas liquids in storage		(164,722	)		266,674			(370,662	)
Accounts payable		(43,883	)		154,039			(340,584	)
Commodity imbalances, net		(15,316	)		77,174			(37,375	)
Energy marketing and risk management assets and liabilities		112,827			113,540			60,846
Fair value of firm commitments		(105,084	)		176,799			505
Pension and postretirement benefits		(68,719	)		(42,040	)		(83,254	)
Other assets and liabilities		31,554			(86,319	)		(178,633	)
Cash provided by operating activities		834,042			1,452,694			475,677
Investing Activities
Contributions to unconsolidated affiliates		(1,331	)		(46,461	)		(20,786	)
Distributions received from unconsolidated affiliates		17,847			34,430			24,749
Capital expenditures (less allowance for equity funds used during construction)		(582,748	)		(791,245	)		(1,473,136	)
Proceeds from sale of assets		428,908			10,982			2,630
Other		2,968			4,500			12,242
Cash used in investing activities		(134,356	)		(787,794	)		(1,454,301	)
Financing Activities
Borrowing (repayment) of notes payable, net		(325,015	)		(518,130	)		1,197,400
Borrowing (repayment) of notes payable with maturities over 90 days		-			(870,000	)		870,000
Issuance of debt, net of discounts		-			498,325			-
Long-term debt financing costs		-			(4,000	)		-
Payment of debt		(262,715	)		(114,975	)		(416,040	)
Repurchase of common stock		(7	)		(254	)		(29	)
Issuance of common stock		20,912			17,317			16,495
Issuance of common units, net of discounts		322,701			241,642			146,969
Dividends paid		(193,542	)		(172,774	)		(162,785	)
Distributions to noncontrolling interests		(260,385	)		(222,710	)		(201,658	)
Other financing activities		-			-			19,225
Cash provided by (used in) financing activities		(698,051	)		(1,145,559	)		1,469,577
Change in cash and cash equivalents		1,635			(480,659	)		490,953
Cash and cash equivalents at beginning of period		29,399			510,058			19,105
Cash and cash equivalents at end of period	$	31,034		$	29,399		$	510,058
Supplemental cash flow information:
Cash paid for interest, net of amounts capitalized	$	298,354		$	314,509		$	237,577
Cash paid for income taxes	$	16,841		$	30,560		$	82,965
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY


	ONEOK Shareholders' Equity
							Accumulated
	Common						Other
	Stock		Common		Paid-in		Comprehensive
	Issued		Stock		Capital		Income (Loss)
	(Shares)		(Thousands of dollars)

January 1, 2008		121,115,217	$	1,211	$	1,273,800	$	(7,069	)
Net income		-		-		-		-
Other comprehensive income (loss)		-		-		-		(63,547	)
Repurchase of common stock		-		-		-		-
Common stock issued		531,790		5		27,353		-
Common stock dividends -
$1.56 per share		-		-		-		-
Issuance of common units of ONEOK Partners		-		-		-		-
Distributions to noncontrolling interests		-		-		-		-
Change in measurement date for
employee benefit plans		-		-		-		-
December 31, 2008		121,647,007		1,216		1,301,153		(70,616	)
Net income		-		-		-		-
Other comprehensive loss		-		-		-		(47,997	)
Repurchase of common stock		-		-		-		-
Common stock issued		747,008		8		21,187		-
Common stock dividends -
$1.64 per share		-		-		-		-
Issuance of common units of ONEOK Partners		-		-		-		-
Distributions to noncontrolling interests		-		-		-		-
December 31, 2009		122,394,015		1,224		1,322,340		(118,613	)
Net income		-		-		-		-
Other comprehensive income		-		-		-		9,811
Repurchase of common stock		-		-		-		-
Common stock issued		421,621		4		19,600		-
Common stock dividends -
$1.82 per share		-		-		-		-
Issuance of common units of ONEOK Partners		-		-		50,731		-
Distributions to noncontrolling interests		-		-		-		-
Other		-		-		-		-
December 31, 2010		122,815,636	$	1,228	$	1,392,671	$	(108,802	)
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(Continued)

	ONEOK Shareholders' Equity
							Noncontrolling
							Interests in
	Retained			Treasury			Consolidated			Total
	Earnings			Stock			Subsidiaries			Equity
	(Thousands of dollars)

January 1, 2008	$	1,411,492		$	(710,126	)	$	801,964		$	2,771,272
Net income		311,909			-			288,558			600,467
Other comprehensive income (loss)		-			-			43,536			(20,011	)
Repurchase of common stock		-			(29	)		-			(29	)
Common stock issued		-			13,539			-			40,897
Common stock dividends -
$1.56 per share		(162,785	)		-			-			(162,785	)
Issuance of common units of ONEOK Partners		-			-			146,969			146,969
Distributions to noncontrolling interests		-			-			(201,658	)		(201,658	)
Change in measurement date for
employee benefit plans		(7,583	)		-			-			(7,583	)
December 31, 2008		1,553,033			(696,616	)		1,079,369			3,167,539
Net income		305,451			-			185,753			491,204
Other comprehensive loss		-			-			(45,786	)		(93,783	)
Repurchase of common stock		-			(254	)		-			(254	)
Common stock issued		-			13,403			-			34,598
Common stock dividends -
$1.64 per share		(172,774	)		-			-			(172,774	)
Issuance of common units of ONEOK Partners		-			-			241,642			241,642
Distributions to noncontrolling interests		-			-			(222,710	)		(222,710	)
December 31, 2009		1,685,710			(683,467	)		1,238,268			3,445,462
Net income		334,632			-			206,698			541,330
Other comprehensive income		-			-			15,695			25,506
Repurchase of common stock		-			(7	)		-			(7	)
Common stock issued		-			20,200			-			39,804
Common stock dividends -
$1.82 per share		(193,542	)		-			-			(193,542	)
Issuance of common units of ONEOK Partners		-			-			271,970			322,701
Distributions to noncontrolling interests		-			-			(260,385	)		(260,385	)
Other		-			-			(28	)		(28	)
December 31, 2010	$	1,826,800		$	(663,274	)	$	1,472,218		$	3,920,841

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2010			2009			2008
	(Thousands of dollars)

Net income	$	541,330		$	491,204		$	600,467
Other comprehensive income (loss), net of tax
Unrealized gains on energy marketing and risk management
assets/liabilities, net of tax of $(43,039), $(26,488) and
$(106,616), respectively		85,623			24,455			213,320
Realized gains in net income, net of tax of $29,278,
$48,059 and $110,214, respectively		(48,117	)		(104,549	)		(167,199	)
Unrealized holding gains (losses) on available-for-sale securities,
net of tax of $44, $(396) and $3,805, respectively		(70	)		627			(6,032	)
Gains in investment securities recognized in net income, net of tax
of $0, $0 and $4,310, respectively		-			-			(6,832	)
Change in pension and postretirement benefit plan liability, net of tax
of $7,570, $9,186 and $33,601, respectively		(12,001	)		(14,560	)		(53,268	)
Other, net of tax of $(45), $(84) and $0, respectively		71			244			-
Total other comprehensive income (loss), net of tax		25,506			(93,783	)		(20,011	)
Comprehensive income		566,836			397,421			580,456
Less: Comprehensive income attributable to noncontrolling interests		222,393			139,967			332,096
Comprehensive income attributable to ONEOK	$	344,443		$	257,454		$	248,360
See accompanying Notes to Consolidated Financial Statements.

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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. Our common stock is listed on the NYSE under the trading symbol “OKE.” We are the sole general partner and own 42.8 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest publicly traded master limited partnerships.

We have divided our operations into three reportable business segments as follows:

·	ONEOK Partners;

·	Distribution; and

·	Energy Services.

Our ONEOK Partners segment conducts midstream activities which include gathering, processing, fractionating, transporting and storing natural gas and NGLs. Our ONEOK Partners segment’s natural gas gathering and processing business is engaged in the gathering and processing of natural gas produced from crude oil and natural gas wells, primarily in the Mid-Continent and Rocky Mountain regions, which include the Anadarko Basin of Oklahoma that contains the NGL-rich Cana-Woodford Shale formation, Hugoton and Central Kansas Uplift Basins of Kansas, and the Williston Basin 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. Through gathering systems, natural gas is aggregated and treated or processed for removal of water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream. In the Powder River Basin, the natural gas that ONEOK Partners gathers is coal-bed methane, or dry natural gas, that does not require processing or NGL extraction in order to be marketable; dry natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

ONEOK Partners’ natural gas pipeline business operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners also provides natural gas transportation and storage services in accordance with Section 311(a) of the Natural Gas Policy Act. ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines that access supply from Canada and from the Mid-Continent, Rocky Mountain and Gulf Coast regions. ONEOK Partners’ intrastate natural gas pipeline assets are located in Oklahoma, Texas and Kansas, and have access to major natural gas producing areas in those states. ONEOK Partners owns underground natural gas storage facilities in Oklahoma, Kansas and Texas.

ONEOK Partners’ natural gas liquids business gathers, treats, fractionates, transports and stores NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver unfractionated NGLs gathered from natural gas processing plants located in Oklahoma, Kansas, Texas and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas, as well as third-party fractionators and third-party pipelines. The NGLs are then separated through the fractionation process into the individual NGL products to realize the greater economic value of the NGL components. The individual NGL products are then stored or distributed to petrochemical manufacturers, heating-fuel users, refineries and propane distributors through ONEOK Partners’ FERC-regulated distribution pipelines that move NGL products from Oklahoma and Kansas to the market centers in Conway, Kansas, and Mont Belvieu, Texas, as well as the Midwest markets near Chicago, Illinois.

Our Distribution segment provides natural gas distribution services to more than two million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service, respectively, each a division of ONEOK. We serve residential, commercial, industrial and transportation customers in all three states. Our distribution companies in Oklahoma and Kansas serve wholesale customers, and in Texas we serve public authority customers, such as cities, governmental agencies and schools. In addition, our Distribution segment’s retail marketing business serves residential customers in Wyoming, residential and agricultural customers in Nebraska and commercial and industrial customers in the Mid-Continent region.

Our Energy Services segment’s primary focus is to create value for our customers by delivering physical natural gas products and risk-management services through our network of contracted natural gas transportation and storage capacity and natural gas supply. This contracted storage and transportation capacity connects the major supply and demand centers throughout

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the United States and into Canada. Our customers are primarily LDCs, electric utilities, and commercial 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. We have recorded noncontrolling interests in consolidated subsidiaries on our Consolidated Balance Sheets to recognize the percent 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.

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; conversely, if we do not have the ability to exercise significant influence, then we use the cost method. Impairment of equity and cost method investments is recorded when the impairments are other than temporary. 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.

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 - Determining Fair Value - We define fair value as the price that would be received from the sale of an asset or the transfer of a liability in an orderly transaction between market participants at the measurement date. We use the market and income approaches to determine the fair value of our assets and liabilities and consider the markets in which the transactions are executed. 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 United States Treasury 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 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.

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·	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.

·	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. 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 B 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 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, all retail customers and some distribution commercial customers are invoiced on a cyclical basis throughout the month, and we accrue unbilled revenues at the end of each month.

Our Energy Services segment’s wholesale customers are invoiced at the end of each month based on physical sales. 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 non-affiliated 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 non-payment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. At December 31, 2010 and 2009, 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 - Natural gas and NGL imbalances are valued at market or their contractually stipulated rate. Natural gas imbalances and NGL exchanges are settled in cash or made up in-kind, subject to the terms of the pipelines’ tariffs or by agreement.

Derivatives and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading 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. Commodity price volatility may have a significant impact on the fair value of our derivative instruments as of a given date.

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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 non-trading 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 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 non-derivative 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 Consolidated Statements of Cash Flows category as the cash flows from the related hedged items.

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

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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 non-regulated 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. Interest costs capitalized in 2010, 2009 and 2008 were $4.9 million, $17.0 million and $39.9 million, respectively. 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, and the changes in economic lives, if applicable, are implemented prospectively when the new rates are billed. For our non-regulated 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 progress 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 progress when they are substantially complete and ready for their intended use.

See Note D 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. As part of our impairment test, 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. There were no impairment charges resulting from our 2010, 2009 or 2008 impairment tests.

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.

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 2010, 2009 or 2008.

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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 2010, 2009 or 2008.

See Notes D and E for our goodwill and long-lived assets disclosures.

Regulation - Our 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. Certain examples of types of regulatory guidance include costs for fuel and losses, acquisition costs, contributions in aid of construction, charges for depreciation and gains or losses on disposition of assets. 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.

At December 31, 2010 and 2009, we recorded regulatory assets of approximately $463.9 million and $488.6 million, respectively, which are being recovered through various rate cases or are expected to be recovered. Of these amounts, approximately $375.1 million and $372.7 million relate to our pension and postretirement benefit plans at December 31, 2010 and 2009, respectively, which are discussed on page 100. Regulatory assets are being recovered as a result of approved rate proceedings over varying time periods up to 40 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 L 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 carry-forward 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 2010, 2009 and 2008, 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 M 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. 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 reasonably estimate the fair value of the asset retirement obligations for portions of our assets because the settlement dates are indeterminable. For our assets that 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 amortization 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 are non-legal obligations; however, these non-legal asset-removal obligations are accounted for as a regulatory liability. Historically, the regulatory authorities that have jurisdiction over our regulated operations have not required us to quantify 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 removal cost liability using current rates since the last general rate order in each of our jurisdictions; however, significant uncertainty exists regarding the ultimate determination of this liability, pending, among other issues, clarification of regulatory intent. We continue to monitor the regulatory authorities and the liability may be adjusted as more information is obtained. We record the estimated non-legal asset removal obligation in non-current 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.

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 January 2010, the FASB issued ASU 2010-06, “Improving Disclosures about Fair Value Measurements,” which established new disclosure requirements and clarified existing requirements for disclosures of fair value measurements. ASU 2010-06 requires us to add two new disclosures, when applicable: (i) transfers in and out of Level 1 and 2 fair value measurements including the reasons for the transfers, and (ii) a gross presentation of activity within the reconciliation of Level 3 fair value measurements. Except for separate disclosure of purchases, sales, issuances and settlements in the reconciliation of our Level 3 fair value measurements, we applied this guidance in 2010.

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The separate disclosure of purchases, sales, issuances and settlements in the reconciliation of our Level 3 fair value measurements will be required beginning with our March 31, 2011, Quarterly Report. We do not expect the impact to be material. ASU 2010-06 requires prospective application in the period of adoption, and we have not recast our prior-year disclosures. See Note B for more discussion of our fair value measurements.

Our policy for calculating transfers between levels of the fair value hierarchy recognizes the transfer as of the end of each reporting period. Prior to January 1, 2010, our policy of calculating transfers recognized transfers in at the end of the reporting period and transfers out at the beginning of the reporting period. Therefore, transfers into and out of Level 3 and included in earnings may not be comparable with prior periods.

B. FAIR VALUE MEASUREMENTS

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

	December 31, 2010
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)
Commodity contracts
Financial contracts	$	127,789		$	1,755		$	152,639		$	-		$	282,183
Physical contracts		-			13,185			20,391			-			33,576
Netting		-			-			-			(251,898	)		(251,898	)
Total derivatives		127,789			14,940			173,030			(251,898	)		63,861
Trading securities (b)		7,591			-			-			-			7,591
Available-for-sale investment securities (c)		2,574			-			-			-			2,574
Total assets	$	137,954		$	14,940		$	173,030		$	(251,898	)	$	74,026

Liabilities
Derivatives (a)
Commodity contracts
Financial contracts	$	(64,768	)	$	(3,241	)	$	(119,430	)	$	-		$	(187,439	)
Physical contracts		-			(3,763	)		(4,334	)		-			(8,097	)
Netting		-			-			-			170,515			170,515
Total derivatives		(64,768	)		(7,004	)		(123,764	)		170,515			(25,021	)
Fair value of firm commitments (d)		-			-			(29,536	)		-			(29,536	)
Total liabilities	$	(64,768	)	$	(7,004	)	$	(153,300	)	$	170,515		$	(54,557	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities 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, 2010, we held $82.5 million of cash collateral and had posted $1.1 million of cash collateral with various counterparties.
(b) - Our trading securities are presented in our Consolidated Balance Sheets as other current assets.
(c) - Our available-for-sale investment securities are presented in our Consolidated Balance Sheets as other assets.
(d) - Our fair value of firm commitments are presented in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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	December 31, 2009
	Level 1			Level 2			Level 3			Netting			Total
	(Thousands of dollars)
Assets
Derivatives (a)	$	149,034		$	4,898		$	672,631		$	(690,399	)	$	136,164
Trading securities (b)		7,927			-			-			-			7,927
Available-for-sale investment securities (c)		2,688			-			-			-			2,688
Total assets	$	159,649		$	4,898		$	672,631		$	(690,399	)	$	146,779

Liabilities
Derivatives (a)	$	(109,713	)	$	(8,481	)	$	(535,937	)	$	580,043		$	(74,088	)
Fair value of firm commitments (d)		-			-			(134,620	)		-			(134,620	)
Total liabilities	$	(109,713	)	$	(8,481	)	$	(670,557	)	$	580,043		$	(208,708	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets as energy marketing and risk management assets and liabilities 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, 2009, we held $136.5 million of cash collateral and had posted $26.1 million of cash collateral with various counterparties.
(b) - Our trading securities are presented in our Consolidated Balance Sheets as other current assets.
(c) - Our available-for-sale investment securities are presented in our Consolidated Balance Sheets as other assets.
(d) - Our fair value of firm commitments are presented in our Consolidated Balance Sheets as other current liabilities and other deferred credits.

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

Our Level 2 fair value inputs are based on NYMEX-settled prices for natural gas and crude oil that are utilized to determine the fair value of certain non-exchange-traded financial instruments, including natural gas and crude oil swaps, as well as physical forwards. Also included in Level 2 are foreign currency forwards.

Our Level 3 inputs include internally developed basis curves incorporating observable and unobservable market data, NGL price curves from a pricing service, historical correlations of NGL product prices to published NYMEX crude oil prices, 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 or a pricing service. The derivatives categorized as Level 3 include natural gas basis swaps, swing swaps, options, other commodity swaps, physical forward contracts and interest-rate swaps. 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.

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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, 2010	$	136,694			$	(134,620	)		$	2,074
Total realized/unrealized gains (losses):
Included in earnings		(91,662	)	(a)		105,084		(a)		13,422
Included in other comprehensive income (loss)		11,122				-				11,122
Transfers into Level 3		765				-				765
Transfers out of Level 3		(7,653	)			-				(7,653	)
December 31, 2010	$	49,266			$	(29,536	)		$	19,730

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, 2010 (a)	$	22,101		(a)	$	(4,551	)	(a)	$	17,550
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.

	Derivative Assets (Liabilities)				Fair Value of Firm Commitments				Long-Term Debt				Total
	(Thousands of dollars)
January 1, 2009	$	42,355			$	42,179			$	(171,455	)		$	(86,921	)
Total realized/unrealized gains (losses):
Included in earnings		147,703		(a)		(176,799	)	(a)		1,455		(b)		(27,641	)
Included in other comprehensive income (loss)		(60,565	)			-				-				(60,565	)
Maturities		-				-				100,000				100,000
Terminations prior to maturity		-				-				70,000				70,000
Transfers in and/or out of Level 3		7,201				-				-				7,201
December 31, 2009	$	136,694			$	(134,620	)		$	-			$	2,074

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, 2009 (a)	$	161,599		(a)	$	(153,576	)	(a)	$	-			$	8,023
(a) - Reported in revenues and cost of sales and fuel in our Consolidated Statements of Income.
(b) - Reported in interest expense 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 and fixed-rate debt swapped to a floating rate. Maturities represent the long-term debt associated with an interest-rate swap that matured during the period. Terminations prior to maturity represent the long-term debt associated with an interest-rate swap that was terminated during the period. 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 previously classified as Level 3 for which the observable inputs became a more significant portion of the fair value estimates.

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.

The estimated fair value of long-term debt, including current maturities, was $4.7 billion and $4.8 billion at December 31, 2010 and 2009, respectively. The book value of long-term debt, including current maturities, was $4.3 billion and $4.6

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billion at December 31, 2010 and 2009, respectively. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues with similar terms and maturities.

C. RISK MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

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

Commodity price risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and crude oil. We use commodity derivative instruments such as futures, physical forward contracts, swaps and options to reduce 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;

Basis risk - We are exposed to the risk of loss in cash flows and future earnings arising from adverse changes in the price differentials between pipeline receipt and delivery locations. Our firm transportation capacity allows us to purchase natural gas at a pipeline receipt point and sell natural gas at a pipeline delivery point. 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

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

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

·	Futures contracts - Standardized exchange-traded contracts to purchase or sell natural gas and crude oil at a specified price, requiring delivery on or settlement through the sale or purchase of an offsetting contract by a specified future date under the provisions of exchange regulations;

Forward contracts - Commitments to purchase or sell natural gas, crude oil or NGLs for physical delivery at some specified time in the future. We also use currency forward contracts to manage our currency exchange rate risk. Forward contracts are different from futures in that forwards are customized and non-exchange traded;

Swaps - Financial trades involving the exchange of payments based on two different pricing structures for a commodity. In a typical commodity swap, parties exchange payments based on changes in the price of a commodity or a market index, while fixing the price they effectively pay or receive for the physical commodity. As a result, one party assumes the risks and benefits of movements in market prices, while the other party assumes the risks and benefits of a fixed price for the commodity; 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 non-exchange traded.

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

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

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

·	reducing our exposure to fluctuations in foreign currency exchange rates.

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

With respect to the net open positions that exist within our marketing and financial trading operations, fluctuating commodity prices can impact our financial position and results of operations. The net open positions are actively managed, 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.

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

We are also subject to fluctuation in interest rates. 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 an interest payment at some future point based on the differential between two interest rates. At December 31, 2010 and 2009, we did not have any interest-rate swap agreements.

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


	December 31, 2010						December 31, 2009
	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	$	136,040	(b)	$	(23,843	)	$	311,009	(c)	$	(130,831	)
Physical contracts		-			(883	)		1,702			(937	)
Total derivatives designated as hedging instruments		136,040			(24,726	)		312,711			(131,768	)
Derivatives not designated as hedging instruments
Commodity contracts
Non-trading instruments
Financial contracts		125,503			(144,940	)		407,475			(447,714	)
Physical contracts		33,576			(7,214	)		46,598			(16,234	)
Trading instruments
Financial contracts		20,640			(18,656	)		59,751			(58,334	)
Total commodity contracts		179,719			(170,810	)		513,824			(522,282	)
Foreign exchange contracts		-			-			28			(81	)
Total derivatives not designated as hedging instruments		179,719			(170,810	)		513,852			(522,363	)
Total derivatives	$	315,759		$	(195,536	)	$	826,563		$	(654,131	)
(a) - Included on a net basis in energy marketing and risk management assets and liabilities on our Consolidated Balance Sheets.
(b) - Includes $44.9 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 loss.
(c) - Includes $37.7 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 loss.

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

					December 31, 2010		December 31, 2009
				Contract Type	Purchased/ Payor	Sold/ Receiver	Purchased/ Payor	Sold/ Receiver
Derivatives designated as hedging instruments:
	Cash flow hedges
		Fixed price
			- Natural gas (Bcf)	Exchange futures	0.4	(7.6)	6.4	(20.7)
				Swaps	3.0	(69.9)	18.1	(80.7)
			- Crude oil and NGLs (MMBbl)	Swaps	-	(1.5)	-	(2.4)
		Basis
			- Natural gas (Bcf)	Forwards and swaps	2.8	(64.9)	23.7	(99.6)
	Fair value hedges
		Basis
			- Natural gas (Bcf)	Forwards and swaps	141.1	(141.1)	210.4	(210.4)

Derivatives not designated as hedging instruments:
		Fixed price
			- Natural gas (Bcf)	Exchange futures	34.6	(20.6)	38.8	(22.7)
				Forwards and swaps	73.6	(100.3)	100.6	(117.4)
				Options	81.0	(74.3)	102.6	(80.6)
			- Crude and NGLs (MMBbl)	Forwards and swaps	0.6	(0.6)	-	-
			- Foreign currency (Millions of dollars)	Swaps	$ -	$ -	$ 4.6	$ -
		Basis
			- Natural gas (Bcf)	Forwards and swaps	411.5	(419.7)	940.7	(947.1)
		Index
			- Natural gas (Bcf)	Forwards and swaps	33.6	(6.1)	66.4	(33.1)

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, 2010, includes gains of approximately $17.8 million, net of tax, related to these hedges that will be recognized within the next 15 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $18.5 million in net gains over the next 12 months, and we will recognize net losses of $0.7 million thereafter.

In 2010 and 2009, cost of sales and fuel in our Consolidated Statements of Income includes $58.7 million and $11.3 million in each period, respectively, reflecting an adjustment to natural gas inventory at the lower of cost or market value. In each period, we reclassified $58.7 million and $11.3 million, respectively, of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.

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

	Years Ended
Derivatives in Cash Flow Hedging Relationships	December 31,
Derivatives in Cash Flow Hedging Relationships	2010		2009
	(Thousands of dollars)
Commodity contracts	$	128,662	$	49,344
Interest rate contracts		-		1,599
Total gain (loss) recognized in other comprehensive income (loss) on derivatives (effective portion)	$	128,662	$	50,943

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

	Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Net Income (Effective Portion)		Years Ended
Derivatives in Cash Flow			December 31,
Hedging Relationships			2010		2009
			(Thousands of dollars)
Commodity contracts	Revenues	$	68,209	$	188,144
Commodity contracts	Cost of sales and fuel		9,158		(36,776	)
Interest rate contracts	Interest expense		28		1,240
Total gain (loss) reclassified from accumulated other comprehensive income (loss) into net income on derivatives (effective portion)		$	77,395	$	152,608

	Location of Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Years Ended
Derivatives in Cash Flow			December 31,
Hedging Relationships			2010		2009
			(Thousands of dollars)
Commodity contracts	Revenues	$	1,856	$	2,366
Commodity contracts	Cost of sales and fuel		(698)		(725)
Total gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)		$	1,158	$	1,641

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 years ended December 31, 2010 and 2009, there were no gains or losses due to the discontinuance of cash flow hedge treatment since the underlying transactions were 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 the period indicated:

		Years Ended
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	December 31,
Derivatives Not Designated as Hedging Instruments	Location of Gain (Loss)	2010		2009
		(Thousands of dollars)
Commodity contracts - trading	Revenues	$	5,710	$	3,210
Commodity contracts - non-trading (a)	Cost of sales and fuel		5,371		10,085
Foreign exchange contracts	Revenues		18		886
Total gain recognized in income on derivatives		$	11,099	$	14,181
(a) - Amounts are presented net of deferred losses associated with derivatives entered into by our Distribution segment.

Our Distribution segment held natural gas call options with premiums totaling $16.7 million and $18.2 million, at December 31, 2010, and 2009, 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 associated with the decline in value

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and expiration of option contracts totaling approximately $25.5 million and $22.6 million for the years ended December 31, 2010 and 2009, respectively, which were deferred as part of our unrecovered purchased-gas costs.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements. 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 2010, 2009 and 2008, were $10.2 million, $10.3 million and $10.5 million, respectively. The remaining amortization of terminated swaps will be recognized over the following periods:

			ONEOK
	ONEOK		Partners		Total
	(Millions of dollars)
2011	$	3.4	$	0.9	$	4.3
2012	$	1.7	$	-	$	1.7
2013	$	1.7	$	-	$	1.7
2014	$	1.7	$	-	$	1.7
Thereafter	$	23.6	$	-	$	23.6

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 include gains of $2.4 million and $253.2 million for 2010 and 2009, respectively, related to the change in fair value of derivatives designated as fair value hedges. Revenues include losses of $2.7 million and $250.5 million for 2010 and 2009, respectively, to recognize the change in fair value of the related hedged firm commitments. Cost of sales and fuel also included a loss of $0.3 million for 2010, a gain of $2.7 million for 2009 and a loss of $3.3 million for 2008 related to the ineffectiveness related to these hedges.

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, we would be in violation of these provisions, and 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, 2010, was $8.5 million for which we have posted collateral of $1.1 million in the normal course of business. If the contingent features underlying these agreements were triggered on December 31, 2010, we would have been required to post an additional $7.4 million of collateral to our counterparties.

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.

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The following tables set forth the net credit exposure from our derivative assets for the period indicated:

	December 31, 2010
	Investment		Non-investment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	33,847	$	1,240	$	678	$	35,765
Oil and gas		8,995		35		2,091		11,121
Industrial		18		-		7,682		7,700
Financial		9,254		-		-		9,254
Other		-		-		21		21
Total	$	52,114	$	1,275	$	10,472	$	63,861

	December 31, 2009
	Investment		Non-investment		Not
	Grade		Grade		Rated		Total
Counterparty sector	(Thousands of dollars)
Gas and electric utilities	$	26,964	$	2,668	$	7,972	$	37,604
Oil and gas		54,578		224		10,084		64,886
Industrial		689		-		3		692
Financial		32,880		-		7		32,887
Other		-		55		40		95
Total	$	115,111	$	2,947	$	18,106	$	136,164

D. PROPERTY, PLANT AND EQUIPMENT

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

	Estimated Useful		December 31,			December 31,
	Lives (Years)		2010			2009
			(Thousands of dollars)
Non-Regulated
Gathering pipelines and related equipment	5 to 46	$	1,144,753		$	982,849
Processing and fractionation and related equipment	5 to 42		993,100			959,339
Storage and related equipment	5 to 54		263,125			219,898
Transmission pipelines and related equipment	15 to 54		198,373			190,734
General plant and other	2 to 42		298,065			303,983
Construction work in process	-		228,868			181,920
Regulated
Natural gas distribution pipelines and related equipment	15 to 80		3,160,197			2,997,250
Storage and related equipment	5 to 54		133,314			134,934
Natural gas transmission pipelines and related equipment	5 to 80		1,717,276			1,702,839
Natural gas liquids transmission pipelines and related equipment	5 to 80		1,351,245			2,138,017
General plant and other	2 to 85		261,783			226,670
Construction work in process	-		104,386			107,367
Property, plant and equipment			9,854,485			10,145,800
Accumulated depreciation and amortization - non-regulated			(707,964	)		(611,944	)
Accumulated depreciation and amortization - regulated			(1,833,338	)		(1,740,198	)
Net property, plant and equipment		$	7,313,183		$	7,793,658

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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	2010			2009			2008
ONEOK Partners		1.9% - 2.2	%		1.8% - 2.2	%		2.0% - 2.4	%
Distribution		2.1% - 2.8	%		2.6% - 2.7	%		2.7% - 3.0	%

E. GOODWILL AND INTANGIBLE ASSETS

Goodwill - The following table sets forth our goodwill, by segment, at both December 31, 2010 and 2009:


	(Thousands of dollars)
ONEOK Partners	$	433,537
Distribution		157,953
Energy Services		10,255
Other		1,099
Total Goodwill	$	602,844

Intangible Assets - Our ONEOK Partners segment has $264.5 million of intangible assets related primarily to contracts acquired through acquisition, which are being amortized over an aggregate weighted-average period of 40 years. The remaining intangible asset balance has an indefinite life. Amortization expense for intangible assets for 2010, 2009 and 2008 was $7.7 million each year, and the aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. The following table sets forth the gross carrying amount and accumulated amortization of intangible assets for the periods indicated:

	December 31,			December 31,
	2010			2009
	(Thousands of dollars)
Gross Intangible Assets	$	462,214		$	462,214
Accumulated Amortization		(42,164	)		(34,498	)
Net Intangible Assets	$	420,050		$	427,716

F. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK Credit Agreement - Under the ONEOK Credit Agreement, which expires July 2011, ONEOK is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include:

·	a $400 million sublimit for the issuance of standby letters of credit;

·	a limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not exceed 67.5 percent at the end of any calendar quarter;

·	a requirement that ONEOK maintains the power to control the management and policies of ONEOK Partners; and

·	a limit on new investments in master limited partnerships.

The ONEOK Credit Agreement also contains customary affirmative and negative covenants, including covenants relating to liens, investments, fundamental changes in the nature of ONEOK’s businesses, transactions with affiliates, the use of proceeds and a covenant that prevents ONEOK from restricting its subsidiaries’ ability to pay dividends.

The ONEOK Credit Agreement expires in July 2011 and we anticipate entering into a new agreement prior to the maturity date.

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At December 31, 2010, ONEOK had $127.0 million in commercial paper outstanding and $27.0 million in letters of credit issued under the ONEOK Credit Agreement, leaving approximately $1.0 billion of credit available under the ONEOK Credit Agreement. At December 31, 2009, ONEOK had $358.9 million in commercial paper outstanding and $37.0 million in letters of credit issued under the ONEOK Credit Agreement.

The weighted-average interest rate on ONEOK’s short-term debt outstanding was 0.38 percent and 0.30 percent at December 31, 2010 and 2009, respectively.

ONEOK Partners Credit Agreement - Under the ONEOK Partners Credit Agreement, which expires March 2012, ONEOK Partners is required to comply with certain financial, operational and legal covenants. Among other things, these requirements include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in the ONEOK Partners Credit Agreement, as adjusted for all non-cash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5 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 three calendar quarters following the acquisition. Upon breach of any covenant, discussed above, amounts outstanding under the ONEOK Partners Credit Agreement may become due and payable immediately. At December 31, 2010, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 3.79 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement. As a result of ONEOK Partners’ January 2011 debt issuance, its available borrowings are limited by the ratio of indebtedness to adjusted EBITDA covenant under the ONEOK Partners Credit Agreement; however, ONEOK Partners had approximately $956 million in cash at January 31, 2011, and $266 million of available borrowings that provide ample liquidity to meet its funding needs. ONEOK Partners expects the limitation of its available borrowings to be eliminated during 2011.

In June 2010, ONEOK Partners initiated a commercial paper program under which ONEOK Partners may issue unsecured commercial paper notes up to a maximum amount outstanding of $1.0 billion to fund ONEOK Partners’ short-term borrowing needs. The maturities of the commercial paper notes vary but may not exceed 270 days from the date of issue. The commercial paper notes are generally sold at a negotiated discount from par.

The ONEOK Partners Credit Agreement is available to repay the commercial paper notes, if necessary. Amounts outstanding under ONEOK Partners’ commercial paper program reduce the borrowing capacity under the ONEOK Partners Credit Agreement. In July 2010, ONEOK Partners repaid all borrowings outstanding under the ONEOK Partners Credit Agreement with proceeds from the issuance of commercial paper.

At December 31, 2010, ONEOK Partners had $429.9 million in commercial paper outstanding and no borrowings outstanding under the ONEOK Partners Credit Agreement, leaving approximately $570.1 million of credit available under the most restrictive provisions of the ONEOK Partners Credit Agreement. At December 31, 2009, ONEOK Partners had $523.0 million in borrowings outstanding under the ONEOK Partners Credit Agreement. At December 31, 2010 and 2009, ONEOK Partners had a total of $24.2 million issued in letters of credit outside of the ONEOK Partners Credit Agreement. Borrowings under the ONEOK Partners Credit Agreement are nonrecourse to ONEOK.

The weighted-average interest rate on ONEOK Partners’ short-term debt outstanding was 0.38 percent and 0.54 percent at December 31, 2010 and 2009, respectively.

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

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G. 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,
	2010			2009
	(Thousands of dollars)
ONEOK
$400,000 at 7.125% due 2011	$	400,000		$	400,000
$400,000 at 5.2% due 2015		400,000			400,000
$100,000 at 6.4% due 2019		90,091			90,314
$100,000 at 6.5% due 2028		87,971			88,247
$100,000 at 6.875% due 2028		100,000			100,000
$400,000 at 6.0% due 2035		400,000			400,000
Other		2,163			2,448
Total ONEOK long-term notes payable		1,480,225			1,481,009
ONEOK Partners
$250,000 at 8.875% due 2010		-			250,000
$225,000 at 7.10% due 2011		225,000			225,000
$350,000 at 5.90% due 2012		350,000			350,000
$450,000 at 6.15% due 2016		450,000			450,000
$500,000 at 8.625% due 2019		500,000			500,000
$600,000 at 6.65% due 2036		600,000			600,000
$600,000 at 6.85% due 2037		600,000			600,000
Guardian Pipeline
Average 7.85%, due 2022		97,850			109,780
Total ONEOK Partners long-term notes payable		2,822,850			3,084,780
Total long-term notes payable		4,303,075			4,565,789
Unamortized portion of terminated swaps		33,113			43,298
Unamortized debt discount		(6,410	)		(6,668	)
Current maturities		(643,236	)		(268,215	)
Long-term debt	$	3,686,542		$	4,334,204

The aggregate maturities of long-term debt outstanding for the years 2011 through 2015 are shown below:

				ONEOK	Guardian
	ONEOK			Partners	Pipeline			Total
	(Millions of dollars)
2011	$	406.3	$	225.0	$	11.9	$	643.2
2012	$	6.3	$	350.0	$	11.1	$	367.4
2013	$	6.2	$	-	$	7.7	$	13.9
2014	$	6.0	$	-	$	7.7	$	13.7
2015	$	406.0	$	-	$	7.7	$	413.7

Additionally, $178.1 million of our debt is callable at par at our option from now until maturity, which is 2019 for $90.1 million and 2028 for $88.0 million.

In June 2010, ONEOK Partners repaid $250.0 million of maturing senior notes with available cash and short-term borrowings. With the repayment of these notes, ONEOK Partners no longer has any obligation to offer to repurchase the $225 million senior notes due 2011 in the event that ONEOK Partners’ long-term debt credit ratings fall below investment grade.

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ONEOK Partners’ Debt Issuances - In January 2011, ONEOK Partners completed an underwritten public offering of $1.3 billion senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041. The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under ONEOK Partners’ commercial paper program and for general partnership purposes, including capital expenditures, and will be used to repay the $225 million principal amount of senior notes due March 2011. ONEOK Partners will pay interest on the senior notes due 2016 and 2041 on February 1 and August 1 of each year beginning August 1, 2011.

In March 2009, ONEOK Partners completed an underwritten public offering of $500 million aggregate principal amount of 8.625-percent Senior Notes due 2019. The net proceeds from this offering of approximately $494.3 million were used to repay indebtedness outstanding under the ONEOK Partners Credit Agreement. ONEOK Partners will pay interest on these notes on March 1 and September 1 of each year.

Debt Covenants - The indentures governing ONEOK’s senior notes due 2011, 2019 and 2028 include an event of default upon acceleration of other indebtedness of $15 million or more. The indentures governing the senior notes due 2015 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 2011, 2015, 2019, 2028 and 2035 to declare those notes immediately due and payable in full.

The indentures governing ONEOK Partners’ senior notes due 2011 include an event of default upon acceleration of other indebtedness of $25 million or more, and the indentures governing its other 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 any ONEOK Partners’ outstanding senior notes to declare those notes immediately due and payable in full.

Debt Guarantee - ONEOK Partners’ senior notes are fully and unconditionally guaranteed on a senior unsecured basis by ONEOK Partners’ wholly owned subsidiary, ONEOK Partners Intermediate Limited Partnership (Intermediate Partnership). ONEOK Partners’ long-term debt is nonrecourse to ONEOK. The guarantee ranks equally in right of payment to all of the Intermediate Partnership’s existing and future unsecured senior indebtedness. ONEOK Partners has no significant assets or operations other than its investment in the Intermediate Partnership, which is also consolidated. At December 31, 2010, the Intermediate Partnership held partnership interests in the equity of ONEOK Partners’ subsidiaries, as well as a 50-percent interest in both Northern Border Pipeline and in Overland Pass Pipeline Company.

Guardian Pipeline Senior Notes - These notes were issued under a master shelf agreement with certain financial institutions. Principal payments are due quarterly through 2022. Interest rates on the $97.9 million in senior notes outstanding at December 31, 2010, range from 7.61 percent to 8.27 percent, with an average rate of 7.85 percent. Guardian Pipeline’s senior notes contain financial covenants that require the maintenance of a ratio of (i) EBITDAR, as defined in the master shelf agreement dated as of November 8, 2001, to fixed charges (interest expense plus operating lease expense) of not less than 1.5 to 1; and (ii) total indebtedness to EBITDAR of not greater than 4.75 to 1. Upon any breach of these covenants,

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all amounts outstanding under the master shelf agreement may become due and payable immediately. At December 31, 2010, Guardian Pipeline’s EBITDAR-to-fixed-charges ratio was 6.1 to 1, the ratio of total indebtedness to EBITDAR was 2.0 to 1, and Guardian Pipeline was in compliance with its financial covenants.

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.

H. CAPITAL STOCK

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 - Series C Preferred Stock (Series C) is designed to protect our shareholders from coercive or unfair takeover tactics. If issued, holders of shares of Series C are entitled to receive, in preference to the holders of ONEOK Common Stock, quarterly dividends in an amount per share equal to the greater of $0.50 or, subject to adjustment, 100 times the aggregate per share amount of all cash dividends, and 100 times the aggregate per share amount (payable in kind) of all non-cash dividends. No shares of Series C have been issued.

Common Stock - At December 31, 2010, we had approximately 176.2 million shares of authorized and unreserved common stock available for issuance.

Dividends - Dividends paid totaled $193.5 million, $172.8 million and $162.8 million for 2010, 2009 and 2008, 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,
	2010		2009		2008
First Quarter	$	0.44	$	0.40	$	0.38
Second Quarter	$	0.44	$	0.40	$	0.38
Third Quarter	$	0.46	$	0.42	$	0.40
Fourth Quarter	$	0.48	$	0.42	$	0.40
Total	$	1.82	$	1.64	$	1.56

Additionally, a quarterly dividend of $0.52 per share was declared in January 2011, payable in the first quarter of 2011.

I. 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		Unrealized Holding Gains (Losses) on Investment Securities		Pension and Postretirement Benefit Plan Obligations		Accumulated Other Comprehensive Income (Loss)
		(Thousands of dollars)
December 31, 2008	$	27,913	$	814	$	(99,343)	$	(70,616)
Other comprehensive income (loss) attributable to ONEOK		(34,064)		627		(14,560)		(47,997)
December 31, 2009		(6,151)		1,441		(113,903)		(118,613)
Other comprehensive income (loss) attributable to ONEOK		21,882		(70)		(12,001)		9,811
December 31, 2010	$	15,731	$	1,371	$	(125,904)	$	(108,802)

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J. EARNINGS PER SHARE

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

	Year Ended December 31, 2010
					Per Share
	Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock	$	334,632		106,368	$	3.15
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		1,417
Net income attributable to ONEOK available for common stock
and common stock equivalents	$	334,632		107,785	$	3.10

	Year Ended December 31, 2009
					Per Share
	Income		Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock	$	305,451		105,362	$	2.90
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		958
Net income attributable to ONEOK available for common stock
and common stock equivalents	$	305,451		106,320	$	2.87

	Year Ended December 31, 2008
					Per Share
		Income	Shares		Amount
	(Thousands, except per share amounts)
Basic EPS from continuing operations
Net income attributable to ONEOK available for common stock	$	311,909		104,369	$	2.99
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-		1,391
Net income attributable to ONEOK available for common stock
and common stock equivalents	$	311,909		105,760	$	2.95

There were no option shares excluded from the calculation of diluted EPS for 2010. There were 192,952 and 64,989 option shares excluded from the calculation of diluted EPS for 2009 and 2008, respectively, since their inclusion would be anti-dilutive.

K. SHARE-BASED PAYMENTS

Equity Compensation Plan

The ONEOK, Inc. Equity Compensation Plan provides for the granting of stock-based compensation, including incentive stock options, non-statutory 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 non-employee directors. We have reserved a total of 5.0 million shares of common stock for issuance under the plan, and at December 31, 2010, we had 1.9 million shares available for issuance under the plan. The Equity Compensation Plan allows for the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code section 409A requirements.

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Restricted Stock Units - Restricted stock units may be granted to key employees with ownership of the common stock underlying the unit vesting over a period determined by the Executive Compensation Committee. Awards outstanding 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 are paid on the restricted stock units. Compensation expense is recognized on a straight-line basis over the vesting period of the award.

Performance Unit Awards - Performance unit awards may be granted to key employees. The shares of our common stock underlying the performance units vest at the expiration of a period determined by the Committee if certain performance criteria are met by us. 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. The compensation expense on these awards will only be adjusted for changes in forfeitures.

Long-Term Incentive Plan

The ONEOK, Inc. Long-Term Incentive Plan (the LTIP) provides for the granting of stock awards similar to those described above with respect to the Equity Compensation Plan. We have reserved a total of approximately 7.8 million shares of common stock for issuance under the plan. The maximum number of shares for which options or other awards may be granted to any employee during any year is 300,000.

Options - Stock options may be granted that are not exercisable until a fixed future date or in installments. All outstanding options issued to date have vested and must be exercised no later than 10 years after grant date. Options issued to date become void upon involuntary termination of employment for just cause or voluntary termination of employment other than retirement. In the event of retirement or involuntary termination other than for just cause, the optionee may exercise the option within a period determined by the Executive Compensation Committee and stated in the option. In the event of death, the option may be exercised by the personal representative of the optionee within a period to be determined by the Committee and stated in the option. No stock options have been granted since 2003.

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 Committee at any time, until grants have been made for all shares authorized under the DSCP. We have reserved a total of 700,000 shares of common stock for issuance under the DSCP. The maximum number of shares of common stock which can be issued to a participant under the DSCP during any year is 20,000. No performance unit awards or restricted stock awards have been made to non-employee directors under the DSCP.

General

For all awards outstanding, we used a forfeiture rate ranging from zero percent to 12 percent based on historical forfeitures under our share-based payment plans. We use a combination of issuances from treasury stock and repurchases in the open market to satisfy our share-based payment obligations.

Compensation cost expensed for our share-based payment plans described below was $15.9 million, $15.1 million and $13.1 million during 2010, 2009 and 2008, respectively, which is net of $10.0 million, $9.5 million and $8.3 million of tax benefits, respectively. No share-based compensation cost was capitalized for 2010, 2009 and 2008.

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Cash received from the exercise of awards under all share-based payment arrangements was $6.0 million, $3.3 million and $3.8 million for 2010, 2009 and 2008, respectively. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled $3.4 million, $0.9 million and $1.4 million for 2010, 2009 and 2008, respectively.

Stock Option Activity

The following table sets forth the stock option activity for employees and non-employee directors for the periods indicated:

	Number of			Weighted
	Shares			Average Price
Outstanding December 31, 2009		551,373		$	25.29
Exercised		(412,683	)	$	26.60
Expired		(3,500	)	$	16.90
Outstanding December 31, 2010		135,190		$	21.52

Exercisable December 31, 2010		135,190		$	21.52

The aggregate intrinsic value in the table below represents the total pre-tax intrinsic value, based on our year-end closing stock price of $55.47, that would have been received by the option holders had all option holders exercised their options as of December 31, 2010:

		Stock Options Outstanding and Exercisable
				Weighted				Aggregate
				Average		Weighted		Intrinsic
Range of		Number		Remaining		Average		Value
Exercise Prices		of Awards		Life (yrs)		Exercise Price		(in 000's)
$	16.88 to $25.32		105,999		1.41	$	17.16	$	4,061
$	25.33 to $38.00		16,481		1.04	$	34.38	$	348
$	38.01 to $43.67		12,710		1.04	$	41.25	$	181

The weighted-average period of outstanding options is 1.3 years. As of December 31, 2010, all stock options were fully vested and expensed. The following table sets forth statistics relating to our stock option activity:

	December 31, 2010		December 31, 2009		December 31, 2008
	(Thousands of dollars)
Intrinsic value of options exercised	$	8,953	$	2,453	$	3,652

Restricted Stock Unit Activity

The total fair value of shares vested during 2010 was $2.2 million. As of December 31, 2010, there was $7.1 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 1.5 years. The following tables set forth activity and various statistics for our restricted stock unit awards:

	Number of			Weighted
	Shares			Average Price
Nonvested December 31, 2009		322,100		$	33.87
Granted		219,825		$	37.33
Released to participants		(47,857	)	$	37.37
Forfeited		(5,282	)	$	34.98
Nonvested December 31, 2010		488,786		$	35.07

	2010		2009		2008
Weighted-average grant date fair value (per share)	$	37.33	$	23.47	$	43.22
Fair value of shares granted (thousands of dollars)	$	8,206	$	2,251	$	2,314

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Performance Unit Activity

The total fair value of shares vested during 2010 was $12.9 million. As of December 31, 2010, there was $18.9 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 1.2 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 2010, 2009 and 2008 grants at the grant date:

	Number of		Weighted
	Units		Average Price
Nonvested December 31, 2009	1,188,896		$	36.79
Granted	431,225		$	48.09
Released to participants	(286,821	)	$	37.58
Forfeited	(18,713	)	$	38.69
Nonvested December 31, 2010	1,314,587		$	40.30

	2010		2009		2008
Volatility (a)		40.60%		43.58%		22.50%
Dividend Yield		4.12%		5.70%		3.20%
Risk-free Interest Rate		1.47%		1.01%		2.46%
(a) - Volatility was based on historical volatility over three years using daily stock price observations.

	2010		2009		2008
Weighted-average grant date fair value (per share)	$	48.09	$	29.34	$	43.88
Fair value of shares granted (thousands of dollars)	$	20,738	$	17,232	$	16,987

Employee Stock Purchase Plan

We have reserved a total of 4.8 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 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 53 percent, 53 percent and 52 percent of employees participated in the plan in 2010, 2009 and 2008, respectively. Compensation expense for the ESPP was $3.9 million, $6.5 million and $1.3 million in 2010, 2009 and 2008, respectively. Under the plan, we sold 216,897 shares at $37.95 in 2010, 321,888 shares at $24.41 per share in 2009, and 297,864 shares at $24.41 per share in 2008.

Deferred Compensation Plan for Non-Employee Directors

The ONEOK, Inc. Nonqualified Deferred Compensation Plan for Non-Employee Directors provides our directors, who are not our employees, 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 non-employee directors at the fair market value of our common stock at the date of distribution.

L. EMPLOYEE BENEFIT PLANS

Retirement and Postretirement Benefit Plans

Retirement Plans - We have defined benefit retirement plans covering certain full-time employees. Nonbargaining unit employees hired after December 31, 2004, and employees covered by the IBEW collective bargaining agreement hired after June 30, 2010, are not eligible for our defined benefit pension plan; however, they are covered by a defined contribution

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profit-sharing plan. Certain officers and key employees are also eligible to participate in supplemental retirement plans. We generally 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 and the Pension Protection Act of 2006.

Postretirement Benefit Plans - We sponsor 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.

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,
	2010				2009			2010			2009
Change in Benefit Obligation	(Thousands of dollars)
Benefit obligation, beginning of period	$	997,003			$	887,563		$	267,666		$	278,765
Service cost		19,277				20,762			4,926			5,173
Interest cost		58,143				58,052			15,643			16,918
Plan participants' contributions		-				-			3,048			2,865
Actuarial (gain) loss		75,704				83,715			20,761			(22,765	)
Benefits paid		(51,895	)			(53,089	)		(16,561	)		(13,290	)
Benefit obligation, end of period		1,098,232				997,003			295,483			267,666

Change in Plan Assets
Fair value of plan assets, beginning of period		748,686				601,891			92,360			77,687
Actual return on plan assets		110,473				122,757			12,677			5,736
Employer contributions		96,825		(a)		77,127			12,548			8,937
Benefits paid		(51,895	)			(53,089	)		-			-
Fair value of assets, end of period		904,089				748,686			117,585			92,360
Balance at December 31	$	(194,143	)		$	(248,317	)	$	(177,898	)	$	(175,306	)

Current liabilities	$	(4,203	)		$	(3,396	)	$	-		$	-
Non-current liabilities		(189,940	)			(244,921	)		(177,898	)		(175,306	)
Balance at December 31	$	(194,143	)		$	(248,317	)	$	(177,898	)	$	(175,306	)
(a) - Includes $57.0 million contributed for the 2011 plan year.

The accumulated benefit obligation for our pension plans was $1,041.5 million and $939.9 million at December 31, 2010 and 2009, respectively.

There are no plan assets expected to be withdrawn and returned to us in 2011.

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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,
		2010			2009			2008
		(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	19,277		$	20,762		$	20,165
Interest cost		58,143			58,052			49,801
Expected return on assets		(73,651	)		(66,034	)		(61,268)
Amortization of unrecognized prior service cost		1,278			1,565			1,551
Amortization of net loss		27,555			17,322			9,548
Net periodic benefit cost	$	32,602		$	31,667		$	19,797

	Postretirement Benefits
	Years Ended December 31,
	2010			2009			2008
	(Thousands of dollars)
Components of net periodic benefit cost
Service cost	$	4,926		$	5,173		$	5,675
Interest cost		15,643			16,918			17,899
Expected return on assets		(7,896	)		(6,809	)		(7,421	)
Amortization of unrecognized net asset at adoption		3,189			3,189			3,189
Amortization of unrecognized prior service cost		(2,003	)		(2,003	)		(2,003	)
Amortization of net loss		7,009			9,660			10,972
Net periodic benefit cost	$	20,868		$	26,128		$	28,311

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,
		2010			2009			2008
		(Thousands of dollars)
Regulatory asset gain (loss)	$	19,146		$	(4,674	)	$	252,747
Net loss arising during the period		(43,055	)		(30,340	)		(343,274)
Amortization of regulatory asset		(18,359	)		(11,465)			(11,465)
Amortization of prior service credit		1,278			1,565			1,941
Amortization of loss		27,555			17,322			11,935
Deferred income taxes		5,197			10,674			34,417
Total recognized in other comprehensive income (loss)	$	(8,238	)	$	(16,918	)	$	(53,699)

	Postretirement Benefits
	Years Ended December 31,
	2010			2009			2008
	(Thousands of dollars)
Regulatory asset gain (loss)	$	8,408		$	(19,292	)	$	492
Net gain (loss) arising during the period		(15,980	)		21,692			(1,531	)
Amortization of regulatory asset		(6,759	)		(9,400	)		(12,911	)
Amortization of transition obligation		3,189			3,189			3,986
Amortization of prior service cost		(2,003	)		(2,003	)		(2,504	)
Amortization of loss		7,009			9,660			13,715
Deferred income taxes		2,373			(1,488	)		(816	)
Total recognized in other comprehensive income (loss)	$	(3,763	)	$	2,358		$	431

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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,
	2010			2009			2010			2009
	(Thousands of dollars)
Transition obligation	$	-		$	-		$	(6,346	)	$	(9,535	)
Prior service credit (cost)		(4,009	)		(5,287	)		4,377			6,381
Accumulated gain (loss)		(483,607	)		(468,107	)		(90,846	)		(81,876	)
Accumulated other comprehensive income (loss) before regulatory assets		(487,616	)		(473,394	)		(92,815	)		(85,030	)
Regulatory asset for regulated entities		316,527			315,743			58,577			56,927
Accumulated other comprehensive income (loss) after regulatory assets		(171,089	)		(157,651	)		(34,238	)		(28,103	)
Deferred income taxes		66,180			60,981			13,243			10,870
Accumulated other comprehensive income (loss), net of tax	$	(104,909	)	$	(96,670	)	$	(20,995	)	$	(17,233	)

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:

	Pension		Postretirement
	Benefits		Benefits
Amounts to be recognized in 2011	(Thousands of dollars)
Transition obligation	$	-	$	3,189
Prior service credit (cost)	$	1,018	$	(2,003	)
Net loss	$	35,708	$	8,123

Actuarial Assumptions - The following table sets forth the weighted-average assumptions used to determine benefit obligations for the periods indicated:

	Pension Benefits				Postretirement Benefits
	December 31,				December 31,
	2010		2009		2010		2009
Discount rate		5.50%		6.00%		5.50%		6.00%
Compensation increase rate		3.3% - 3.9%		3.1% - 4.0%		3.3% - 3.9%		3.1% - 4.0%

The following table sets forth the weighted-average assumptions used to determine net periodic benefit costs for the periods indicated:

	Pension Benefits				Postretirement Benefits
	December 31,				December 31,
	2010		2009		2010		2009
Discount rate		6.00%		6.25%		6.00%		6.25%
Expected long-term return on plan assets		8.50%		8.50%		8.50%		8.50%
Compensation increase rate		3.1% - 4.0%		4.3% - 4.8%		3.1% - 4.0%		4.3% - 4.8%

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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Health Care Cost Trend Rates - The following table sets forth the assumed health care cost trend rates for the periods indicated:

	2010		2009
Health care cost-trend rate assumed for next year		6.0% - 9.0%		5.0% - 9.0%
Rate to which the cost-trend rate is assumed
to decline (the ultimate trend rate)		5.0%		5.0%
Year that the rate reaches the ultimate trend rate		2020		2019

	One Percentage		One Percentage
	Point Increase		Point Decrease
	(Thousands of dollars)
Effect on total of service and interest cost	$	1,835	$	(1,571	)
Effect on postretirement benefit obligation	$	22,556	$	(19,445	)

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 category as of the measurement date:

	Pension Benefits
	December 31, 2010
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Equity securities (a):
Large-cap value	$	163,701	$	-	$	-	$	163,701
Large-cap growth		160,112		-		-		160,112
Mid-cap		58,364		-		-		58,364
Small-cap		65,891		-		-		65,891
International		140,156		-		-		140,156
Fixed income securities (b):
Corporate bonds		-		106,734		-		106,734
Insurance contracts		-		-		72,198		72,198
High yield corporate bonds		-		22,698		-		22,698
International bonds		26,439		-		-		26,439
Other types of investments (c)		86,734		-		1,062		87,796
Total assets	$	701,397	$	129,432	$	73,260	$	904,089
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds or insurance contracts from diverse industries.
(c) - This category is primarily money market funds, cash and other investments.

	Pension Benefits
	December 31, 2009
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Equity securities (a):
Large-cap value	$	86,295	$	-	$	-	$	86,295
Large-cap growth		103,375		-		-		103,375
Mid-cap		70,232		-		-		70,232
Small-cap		53,692		-		-		53,692
International		92,529		-		-		92,529
Fixed income securities (b):
Corporate bonds		-		130,182		-		130,182
Insurance contracts		-		-		76,079		76,079
High yield corporate bonds		-		83,373		-		83,373
Other types of investments (c)		51,831		-		1,098		52,929
Total assets	$	457,954	$	213,555	$	77,177	$	748,686
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents bonds or insurance contracts from diverse industries.
(c) - This category is primarily money market funds.

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	Postretirement Benefits
	December 31, 2010
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Equity securities (a):
Large-cap value	$	6,964	$	-	$	-	$	6,964
Large-cap growth		2,816		-		-		2,816
Mid-cap		2,260		-		-		2,260
Small-cap		3,269		-		-		3,269
International		1,952		-		-		1,952
Fixed income securities (b):
Corporate bonds		12,149		-		-		12,149
Insurance contract (c)		-		75,561		-		75,561
Other types of investments (d)		12,614		-		-		12,614
Total assets	$	42,024	$	75,561	$	-	$	117,585
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents mutual funds that invest in bonds from diverse industries.
(c) - This category represents an insurance contract with underlying investments that are primarily directed by us which include equity securities and bonds from diverse industries.
(d) - This category is primarily money market funds, cash and other investments.

	Postretirement Benefits
	December 31, 2009
Asset Category	Level 1		Level 2		Level 3		Total
	(Thousands of dollars)
Equity securities (a):
Large-cap value	$	3,636	$	-	$	-	$	3,636
Large-cap growth		2,952		-		-		2,952
Mid-cap		1,806		-		-		1,806
Small-cap		1,705		-		-		1,705
International		1,699		-		-		1,699
Fixed income securities (b):
Corporate bonds		9,835		-		-		9,835
Insurance contract (c)		-		60,014		-		60,014
Other types of investments (d)		10,713		-		-		10,713
Total assets	$	32,346	$	60,014	$	-	$	92,360
(a) - This category represents securities of the respective market sector from diverse industries.
(b) - This category represents mutual funds that invest in bonds from diverse industries.
(c) - This category represents an insurance contract with underlying investments that are primarily directed by us which include equity securities and bonds from diverse industries.
(d) - This category is primarily money market funds.

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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, 2010
	Insurance Contracts			Other Investments			Total
	(Thousands of dollars)
December 31, 2009	$	76,079		$	1,098		$	77,177
Actual return on plan assets
held at the reporting date		(3,881	)		(36	)		(3,917	)
December 31, 2010	$	72,198		$	1,062		$	73,260

	Pension Benefits
	December 31, 2009
	Insurance Contracts			Other Investments			Total
	(Thousands of dollars)
December 31, 2008	$	80,702		$	1,881		$	82,583
Actual return on plan assets
held at the reporting date		(4,623	)		(783	)		(5,406	)
December 31, 2009	$	76,079		$	1,098		$	77,177

Contributions - During 2010, we made contributions of $96.8 million and $12.5 million to our defined benefit pension plans and postretirement benefit plans, respectively. These contributions to our defined benefit pension plans included $57.0 million of contributions attributable to the 2011 plan year. We anticipate our total 2011 contributions will include an additional $4.3 million for our defined benefit pension plans and $13.9 million for our postretirement benefit plans.

Pension and Postretirement Benefit Payments - Benefit payments for our pension and postretirement benefit plans for the period ending December 31, 2010, were $51.9 million and $16.6 million, respectively. The following table sets forth the pension benefits and postretirement benefit payments expected to be paid in 2011-2020:

		Pension Benefits	Postretirement Benefits
Benefits to be paid in:		(Thousands of dollars)
2011	$	59,876	$	15,220
2012	$	61,508	$	16,012
2013	$	63,197	$	16,965
2014	$	65,060	$	17,912
2015	$	67,478	$	19,012
2016 through 2020	$	373,472	$	109,689

The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2010, and include estimated future employee service.

Regulatory Recovery - Our Distribution segment recovers certain pension benefit plan and postretirement benefit plan costs through rates charged to utility customers. In September 2009, the KCC authorized us to defer the difference between current GAAP pension and post-retirement expenses and the level of these expenses incorporated in base rates as either a regulatory asset or liability. Amortization and recovery of the accumulated deferrals will begin with the effective date of our next rate change and will continue for a period not to exceed five years. The impact from the KCC order was not material for the years ended December 31, 2010 or 2009.

Health Care Legislation - In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, the Health Care Acts) were signed into law. Based on our preliminary analysis of the Health Care Acts, we do not expect a significant impact to our benefit plans or their related costs. We do not participate in the federal retiree prescription drug subsidy program, for which the tax treatment was changed as a result of the Health Care Acts and, accordingly, are not impacted by the change in tax treatment of the subsidy. With the exception of increasing our dependent care age requirement to age 26 from age 24, our health plans provide coverage levels that meet the

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near-term minimum requirements outlined in the Health Care Acts. We continue to evaluate the implications of the provisions of the Health Care Acts and expect to continue to provide benefit plan options that meet the provisions outlined by the Health Care Acts.

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 $15.4 million, $14.7 million and $14.7 million in 2010, 2009 and 2008, respectively.

Profit-Sharing Plan - We have a 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. 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 $4.7 million, $4.7 million and $3.2 million in 2010, 2009 and 2008, 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 2010, 2009 and 2008.

M. INCOME TAXES

The following table sets forth our provisions for income taxes for the periods indicated:

	Years Ended December 31,
	2010		2009		2008
Current income taxes	(Thousands of dollars)
Federal	$	58,895	$	6,381	$	18,833
State		12,636		2,227		10,047
Total current income taxes		71,531		8,608		28,880
Deferred income taxes
Federal		124,175		170,077		143,807
State		18,128		28,636		21,384
Total deferred income taxes		142,303		198,713		165,191
Total provision for income taxes	$	213,834	$	207,321	$	194,071

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The following table is a reconciliation of our income tax provision for the periods indicated:

	Years Ended December 31,
	2010			2009			2008
	(Thousands of dollars)
Income before income taxes	$	755,164		$	698,525		$	794,538
Less: Net income attributable to noncontrolling interest		206,698			185,753			288,558
Income attributable to ONEOK before income taxes		548,466			512,772			505,980
Federal statutory income tax rate		35	%		35	%		35	%
Provision for federal income taxes		191,963			179,470			177,093
State income taxes, net of federal tax benefit		19,997			20,061			20,431
Other, net		1,874			7,790			(3,453	)
Income tax provision	$	213,834		$	207,321		$	194,071

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,		December 31,
	2010		2009
Deferred tax assets	(Thousands of dollars)
Employee benefits and other accrued liabilities	$	89,489	$	118,027
Net operating loss carryforward		-		2,559
Other comprehensive income		73,515		78,838
Other		25,710		31,813
Total deferred tax assets		188,714		231,237

Deferred tax liabilities
Excess of tax over book depreciation and depletion		519,679		464,788
Purchased gas adjustment		-		13,726
Investment in partnerships		729,682		664,377
Regulatory assets		157,756		159,540
Total deferred tax liabilities		1,407,117		1,302,431
Net deferred tax liabilities	$	1,218,403	$	1,071,194

We had income taxes receivable of approximately $45.7 million and $94.6 million at December 31, 2010 and 2009, respectively.

N. UNCONSOLIDATED AFFILIATES

Overland Pass Pipeline Company - In September 2010, ONEOK Partners completed a transaction to sell a 49-percent ownership interest in Overland Pass Pipeline Company to Williams Partners, resulting in each joint-venture member now owning 50 percent of Overland Pass Pipeline Company. In accordance with the joint-venture agreement, ONEOK Partners received approximately $423.7 million in cash at closing. As a result of the transaction, ONEOK Partners no longer controls Overland Pass Pipeline Company and began accounting for the investment under the equity method of accounting in September 2010. In connection with the deconsolidation of Overland Pass Pipeline Company, ONEOK Partners recognized approximately $16.3 million in gain on sale of assets, primarily attributable to the remeasurement of its retained investment in Overland Pass Pipeline Company to its fair value, and has recorded its retained investment of approximately $438 million in investments in unconsolidated affiliates. The estimate of the fair value of ONEOK Partners’ retained interest in Overland Pass Pipeline Company was based upon the income and market valuation approaches.

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In 2011, ONEOK Partners expects to make contributions of approximately $35 million to $40 million to Overland Pass Pipeline Company for additional pump stations and expansions of existing pump stations.

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. The Northern Border Pipeline Management Committee has adopted a cash distribution policy related to financial ratio targets and capital contributions. The cash distribution policy defines minimum equity-to- total-capitalization ratios to be used by the Northern Border Pipeline Management Committee to establish the timing and amount of required capital contributions. In addition, any shortfall due to the inability to refinance maturing debt will be funded by capital contributions.

Investments in Unconsolidated Affiliates - The following table sets forth our investments in unconsolidated affiliates for the periods indicated:

	Net Ownership Interest
			December 31,		December 31,
			2010		2009
			(Thousands of dollars)
Overland Pass Pipeline Company	50%	$	443,392	$	-
Northern Border Pipeline	50%		384,011		401,773
Fort Union Gas Gathering, L.L.C.	37%		115,148		111,675
Bighorn Gas Gathering, L.L.C.	49%		92,659		96,492
Lost Creek Gathering Company, L.L.C. (a)	35%		80,765		80,041
Other	Various		72,149		75,182
Investments in unconsolidated affiliates (b)		$	1,188,124	$	765,163
(a) - ONEOK Partners is entitled to receive an incentive allocation of earnings from third-party gathering services revenue recognized by Lost Creek Gathering Company, L.L.C. As a result of the incentive, ONEOK Partners' share of Lost Creek Gathering Company, L.L.C.'s income exceeds its 35 percent ownership interest.
(b) - Equity method goodwill (Note A) was $185.6 million at December 31, 2010 and 2009.

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,
	2010		2009		2008
	(Thousands of dollars)
Overland Pass Pipeline Company	$	5,421	$	-	$	-
Northern Border Pipeline		68,124		41,300		65,912
Fort Union Gas Gathering, L.L.C.		14,367		14,533		14,172
Bighorn Gas Gathering, L.L.C.		5,495		7,807		8,195
Lost Creek Gathering Company, L.L.C.		4,391		4,872		5,365
Other		4,082		4,210		7,788
Equity earnings from investments	$	101,880	$	72,722	$	101,432

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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,			December 31,
	2010			2009
	(Thousands of dollars)
Balance Sheet
Current assets	$	93,698		$	84,910
Property, plant and equipment, net	$	2,500,708		$	1,717,825
Other noncurrent assets	$	28,222		$	28,675
Current liabilities	$	74,969		$	70,500
Long-term debt	$	616,210		$	653,937
Other noncurrent liabilities	$	13,773		$	12,144
Accumulated other comprehensive income (loss)	$	(2,883	)	$	(3,054	)
Owners' equity	$	1,920,559		$	1,097,883

	Years Ended December 31,
	2010		2009		2008
	(Thousands of dollars)
Income Statement (a)
Operating revenues	$	440,826	$	383,625	$	415,552
Operating expenses	$	189,437	$	178,194	$	179,380
Net income	$	223,715	$	164,002	$	209,915

Distributions paid to us	$	114,805	$	109,807	$	118,010
(a) - Overland Pass Pipeline Company was deconsolidated in September 2010; related summarized financial information is included for the last four months of 2010.

O. ONEOK PARTNERS

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the table below for the periods presented:

	December 31,	December 31,
	2010	2009
General partner interest	2.0%	2.0%
Limited partner interest (a)	40.8%	43.1%
Total ownership interest	42.8%	45.1%
(a) - Represents 5.9 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units.

In February 2010, ONEOK Partners completed an underwritten public offering of 5,500,900 common units, including the partial exercise by the underwriters of their over-allotment option, at a public offering price of $60.75 per common unit, generating net proceeds of approximately $322.7 million. In conjunction with the offering, ONEOK Partners GP contributed $6.8 million in order to maintain its 2-percent general partner interest. ONEOK Partners used the proceeds from the sale of common units and the general partner contribution to repay borrowings under the ONEOK Partners Credit Agreement and for general partnership purposes.

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 at a premium to our carrying value per unit, we recognized an increase to paid-in capital of $50.7 million for the year ended December 31, 2010.

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Cash Distributions - Under the ONEOK Partners’ partnership agreement, distributions are made to the partners with respect to each calendar quarter in an amount equal to 100 percent of available cash. Available cash generally consists of all cash receipts adjusted for cash disbursements and net changes to cash reserves. Available cash will generally 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. Under the incentive distribution provisions, the general partner receives:

·	15 percent of amounts distributed in excess of $0.605 per unit;

·	25 percent of amounts distributed in excess of $0.715 per unit; and

·	50 percent of amounts distributed in excess of $0.935 per unit.

ONEOK Partners’ Class B limited partner units are entitled to receive increased quarterly distributions equal to 110 percent of the distributions paid with respect to its common units. As the sole holder of the Class B limited partner units, we have waived our right to receive the increased quarterly distributions on the Class B units. We retain the option to withdraw our waiver of increased distributions on Class B units at any time by giving ONEOK Partners no less than 90 days advance notice. Any such withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after the 90 days following delivery of the notice.

If ONEOK Partners’ common unitholders vote at any time to remove us as general partner, quarterly distributions payable on the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units.

ONEOK Partners’ income is allocated to the general and limited partners in accordance with their respective partnership ownership percentages. The effect of any incremental income allocations for incentive distributions that are allocated to the general partner is calculated after the income allocation for the general partner’s partnership interest and before the income allocation to the limited partners.

The following table shows ONEOK Partners’ general partner and incentive distributions declared for the periods indicated:

	Years Ended December 31,
	2010		2009		2008
	(Thousands of dollars)
General partner distributions	$	11,577	$	10,228	$	9,456
Incentive distributions		108,711		87,734		76,042
Total distributions to general partner	$	120,288	$	97,962	$	85,498

In 2010, ONEOK Partners paid total quarterly distributions to its limited partners of $4.46 per unit. In January 2011, ONEOK Partners declared a cash distribution of $1.14 per unit payable in the first quarter. On February 14, 2011, we received the related incentive distribution of $28.6 million for the fourth quarter of 2010, which is included in the table above.

For the years ended December 31, 2010, 2009 and 2008, cash distributions paid by ONEOK Partners to us totaled $303.8 million, $278.2 million and $251.7 million, respectively.

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 our distributions. Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of the ONEOK Partners partnership agreement. See Note Q for more information on ONEOK Partners’ results.

Affiliate Transactions - We have certain transactions with ONEOK Partners and its subsidiaries, which 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 Distribution segments, which contract with ONEOK Partners for natural gas transportation and storage services. ONEOK

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Partners also purchases natural gas from our Energy Services segment for its natural gas liquids and its natural gas gathering and processing operations.

ONEOK Partners has certain contractual rights to the Bushton Plant through a Processing and Services Agreement with us, which sets out the terms for processing and related services we provide at the Bushton Plant through 2012. ONEOK Partners has contracted for all of the capacity of the Bushton Plant from us. In exchange, ONEOK Partners pays us for all costs and expenses necessary for the operation and maintenance of the Bushton Plant and reimburses us for our obligations under equipment leases covering portions of the Bushton Plant. The Bushton equipment leases will expire in 2012 unless, in the second quarter of 2011, we provide irrevocable notice of our intent to either renew the equipment leases at fair market rental value or purchase the original leased equipment (or any replacement parts) pursuant to the terms of the equipment leases. The Processing and Services Agreement provides that ONEOK Partners will reimburse us for amounts incurred in connection with the foregoing option, if any.

We provide a variety of services to our affiliates, including cash management and financial services, legal and administrative services provided by our employees and management, insurance and office space leased in our headquarters building and other field locations. Where costs are specifically incurred 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 shown:

	Years Ended December 31,
	2010		2009		2008
	(Thousands of dollars)
Revenues	$	457,740	$	475,765	$	744,886

Expenses
Cost of sales and fuel	$	53,107	$	46,824	$	107,983
Administrative and general expenses		207,282		200,002		191,798
Total expenses	$	260,389	$	246,826	$	299,781

P. COMMITMENTS AND CONTINGENCIES

Commitments - Operating leases represent future minimum lease payments under non-cancelable equipment leases covering a portion of the Bushton Plant, 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. The following table sets forth our operating lease and firm transportation and storage contract payments for the periods presented:

ONEOK		Operating Leases	Firm Transportation and Storage Contracts			Total
		(Millions of dollars)
2011	$	32.1	$	133.8	$	165.9
2012	$	0.9	$	126.1	$	127.0
2013	$	0.6	$	91.6	$	92.2
2014	$	0.3	$	73.1	$	73.4
2015	$	-	$	47.8	$	47.8

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ONEOK Partners		Operating Leases	Firm Transportation and Storage Contracts			Total
		(Millions of dollars)
2011	$	3.5	$	6.5	$	10.0
2012	$	3.0	$	6.8	$	9.8
2013	$	2.9	$	6.7	$	9.6
2014	$	2.5	$	6.3	$	8.8
2015	$	1.0	$	6.1	$	7.1

The amounts in the ONEOK table above include minimum lease payments relating to the equipment leases covering portions of the Bushton Plant totaling $30.6 million in 2011. We acquired the lease in a business combination and recorded a liability for uneconomic lease terms. The liability is accreted to rent expense in the amount of $13.0 million per year over the term of the lease; however, the cash outflow under the lease remains the same. The amounts in the ONEOK Partners table above exclude intercompany payments relating to the lease of a gas processing plant.

Environmental Liabilities - We are subject to multiple historical and wildlife preservation laws and environmental regulations affecting many aspects of our present and future operations. Regulated activities include those involving air emissions, stormwater and wastewater discharges, handling and disposal of solid and hazardous wastes, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If a leak or spill of hazardous substances or petroleum products occurs from lines 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 clean-up costs, which could materially affect our 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 our facilities. We cannot assure that existing environmental 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.

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

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

Our expenditures for environmental 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 effects on earnings or cash flows during 2010, 2009 or 2008.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria. Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. The rule was phased in beginning January 2011 and, at current emission threshold levels, will have 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.

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, scheduled to be adopted in early 2013. The rule will require capital expenditures over the next three years for the purchase and installation of new emissions-control

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equipment. We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

Financial Markets Legislation - In July 2010, the Dodd-Frank Act was enacted, representing a far-reaching overhaul of the framework for regulation of United States financial markets. Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act and are currently seeking comments on the proposals. We expect additional proposed regulations as the remaining provisions of the Dodd-Frank Act are implemented. Until the final regulations are established, we are unable to ascertain how we may be affected. Based on our assessment of the proposed regulations issued to date, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation. We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record-keeping, reporting and disclosure obligations.

Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or liquidity.

Q. SEGMENTS

Segment Descriptions - Our operations are divided into three reportable business segments as follows: (i) our ONEOK Partners segment gathers, processes, transports, stores and sells natural gas and gathers, treats, fractionates, stores, distributes and markets NGLs; (ii) our Distribution segment, which includes our retail marketing operations, delivers natural gas to residential, commercial and industrial customers, and transports natural gas; and (iii) our Energy Services segment markets natural gas to wholesale customers. Our Distribution segment is comprised primarily of regulated public utilities, and portions of our ONEOK Partners segment are also regulated. Other and eliminations consists 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 - 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 O. 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 2010, 2009 and 2008, 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, 2010	ONEOK Partners (a)		Distribution (b)				Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	8,218,160		$	2,161,762		$	2,647,460	$	2,669		$	13,030,051
Intersegment revenues		457,740			6,900			653,717		(1,118,357	)		-
Total revenues	$	8,675,900		$	2,168,662		$	3,301,177	$	(1,115,688	)	$	13,030,051

Net margin	$	1,144,853		$	765,288		$	159,739	$	2,662		$	2,072,542
Operating costs		403,476			407,774			28,384		193			839,827
Depreciation and amortization		173,708			131,061			694		1,854			307,317
Gain (loss) on sale of assets		18,632			(13	)		-		-			18,619
Operating income	$	586,301		$	226,440		$	130,661	$	615		$	944,017

Equity earnings from investments	$	101,880		$	-		$	-	$	-		$	101,880
Investments in unconsolidated affiliates	$	1,188,124		$	-		$	-	$	-		$	1,188,124
Total assets	$	7,920,100		$	3,237,196		$	651,960	$	689,919		$	12,499,175
Noncontrolling interests in consolidated subsidiaries	$	5,176		$	-		$	-	$	1,467,042		$	1,472,218
Capital expenditures	$	352,714		$	215,608		$	488	$	13,938		$	582,748
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $612.2 million, net margin of $479.1 million and operating income of $250.9 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $1,817.4 million, net margin of $754.9 million and operating income of $225.1 million.

Year Ended December 31, 2009	ONEOK Partners (a)		Distribution (b)		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	5,998,726	$	2,138,044	$	2,971,902	$	2,979		$	11,111,651
Intersegment revenues		475,765		6,745		581,740		(1,064,250	)		-
Total revenues	$	6,474,491	$	2,144,789	$	3,553,642	$	(1,061,271	)	$	11,111,651

Net margin	$	1,119,297	$	734,023	$	159,647	$	2,979		$	2,015,946
Operating costs		411,227		390,287		35,542		65			837,121
Depreciation and amortization		164,136		122,662		540		1,653			288,991
Gain (loss) on sale of assets		2,668		486		-		1,652			4,806
Operating income	$	546,602	$	221,560	$	123,565	$	2,913		$	894,640

Equity earnings from investments	$	72,722	$	-	$	-	$	-		$	72,722
Investments in unconsolidated affiliates	$	765,163	$	-	$	-	$	-		$	765,163
Total assets	$	7,953,259	$	3,122,222	$	930,086	$	822,116		$	12,827,683
Noncontrolling interests in consolidated subsidiaries	$	5,603	$	-	$	-	$	1,232,665		$	1,238,268
Capital expenditures	$	615,691	$	157,508	$	105	$	17,941		$	791,245
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $555.9 million, net margin of $451.0 million and operating income of $200.3 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $1,838.9 million, net margin of $716.0 million and operating income of $209.8 million.

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Year Ended December 31, 2008	ONEOK Partners (a)		Distribution (b)				Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	6,975,320		$	2,223,993		$	6,954,917	$	3,203		$	16,157,433
Intersegment revenues		744,886			594,841			582,539		(1,922,266	)		-
Total revenues	$	7,720,206		$	2,818,834		$	7,537,456	$	(1,919,063	)	$	16,157,433

Net margin	$	1,140,659		$	695,761		$	95,927	$	3,180		$	1,935,527
Operating costs		371,797			381,378			29,543		(5,806	)		776,912
Depreciation and amortization		124,765			116,869			834		1,459			243,927
Gain (loss) on sale of assets		713			(21	)		1,500		124			2,316
Operating income	$	644,810		$	197,493		$	67,050	$	7,651		$	917,004

Equity earnings from investments	$	101,432		$	-		$	-	$	-		$	101,432
Investments in unconsolidated affiliates	$	755,492		$	-		$	-	$	-		$	755,492
Total assets	$	7,254,272		$	3,145,529		$	1,715,382	$	1,010,879		$	13,126,062
Noncontrolling interests in consolidated subsidiaries	$	5,941		$	-		$	-	$	1,073,428		$	1,079,369
Capital expenditures	$	1,253,853		$	169,049		$	62	$	50,172		$	1,473,136
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $434.5 million, net margin of $332.0 million and operating income of $156.8 million.
(b) - Our Distribution segment has regulated and non-regulated operations. Our Distribution segment's regulated operations had revenues of $2,175.7 million, net margin of $681.0 million and operating income of $188.8 million.

R. QUARTERLY FINANCIAL DATA (UNAUDITED)

	First		Second		Third		Fourth
Year Ended December 31, 2010	Quarter		Quarter		Quarter		Quarter
	(Thousands of dollars except per share amounts)
Total revenues	$	3,923,967	$	2,807,131	$	2,942,703	$	3,356,250
Net margin	$	619,319	$	458,077	$	451,370	$	543,776
Operating income	$	337,332	$	178,713	$	186,904	$	241,068
Net income	$	186,720	$	86,374	$	120,301	$	147,935
Net income attributable to ONEOK	$	154,539	$	41,724	$	55,295	$	83,074
Earnings per share from continuing operations
Basic	$	1.46	$	0.39	$	0.52	$	0.78
Diluted	$	1.44	$	0.39	$	0.51	$	0.76

	First		Second		Third		Fourth
Year Ended December 31, 2009	Quarter		Quarter		Quarter		Quarter
	(Thousands of dollars except per share amounts)
Total revenues	$	2,789,827	$	2,227,627	$	2,364,736	$	3,729,461
Net margin	$	551,411	$	432,426	$	451,854	$	580,255
Operating income	$	293,003	$	154,804	$	173,778	$	273,055
Net income	$	163,549	$	81,350	$	102,308	$	143,997
Net income attributable to ONEOK	$	122,285	$	41,679	$	48,042	$	93,445
Earnings per share from continuing operations
Basic	$	1.16	$	0.40	$	0.46	$	0.88
Diluted	$	1.16	$	0.39	$	0.45	$	0.87

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ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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 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, 2010.

Our internal control over financial reporting as of December 31, 2010, 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 Controls Over Financial Reporting

There have been no changes in our internal controls over financial reporting during the quarter ended December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.

OTHER INFROMATION

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 2011 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 2011 definitive Proxy Statement and is incorporated herein by this reference.

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Code of Ethics

Information concerning the code of ethics, or code of business conduct, is set forth in our 2011 definitive Proxy Statement and is incorporated herein by this reference.

Nominating Committee Procedures

Information concerning the Nominating Committee procedures is set forth in our 2011 definitive Proxy Statement and is incorporated herein by this reference.

Audit Committee

Information concerning the Audit Committee is set forth in our 2011 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 2011 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 11.

EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2011 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 2011 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 2011 definitive Proxy Statement and is incorporated herein by this reference.

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Equity Compensation Plan Information

The following table sets forth certain information concerning our equity compensation plans as of December 31, 2010:

							Number of Securities
							Remaining Available For
		Number of Securities		Weighted-Average			Future Issuance Under
		to be Issued Upon		Exercise Price of			Equity Compensation
		Exercise of Outstanding		Outstanding Options,			Plans (Excluding
		Options, Warrants and Rights		Warrants and Rights			Securities in Column (a))
Plan Category		(a)		(b)			(c)
Equity compensation plans
approved by security holders (1)			1,989,621	$	36.59			4,508,062
Equity compensation plans
not approved by security holders (2)			209,314	$	53.20	(3)		503,602
Total			2,198,935	$	38.17			5,011,664
(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 K of the Notes to Consolidated Financial Statements in this Annual Report. Column (c) includes 571,794, 150,825, 1,837,470 and 1,947,973 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 K 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 used for these plans to calculate the weighted-average exercise price in the table is $55.47, 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 2011 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 2011 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	66

	(b)	Consolidated Statements of Income for the years ended	67
		December 31, 2010, 2009 and 2008

	(c)	Consolidated Balance Sheets as of December 31, 2010 and 2009	68-69

	(d)	Consolidated Statements of Cash Flows for the years ended	71
		December 31, 2010, 2009 and 2008

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(e)	Consolidated Statements of Shareholders’ Equity for the years	72-73
	ended December 31, 2010, 2009 and 2008

(f)	Consolidated Statements of Comprehensive Income for the years	74
	ended December 31, 2010, 2009 and 2008

(g)	Notes to Consolidated Financial Statements	75-116

(2) Financial Statement Schedules

All schedules have been omitted because of the absence of conditions under which they are required.

(3) Exhibits

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 99.1 to Form 8-K filed January 20, 2009).

3.5

Amended and Restated Certificate of Incorporation of ONEOK, Inc. dated May 15, 2008 (incorporated by reference from Exhibit 3.1 to Form 8-K filed May 19, 2008).

3.6

Certificate of Correction form dated November 5, 2008 (incorporated by reference from Exhibit 4.2 to Registration Statement on Form S-3 filed November 21, 2008).

Certificate of Designation for Convertible Preferred Stock of WAI, Inc. (now ONEOK, Inc.) filed November 21, 2008 (incorporated by reference from Exhibit 4.2 to Registration Statement on Form S-3 filed November 21, 2008, Commission File No. 333-155593).

4.1

Certificate of Designation for Series C Participating Preferred Stock of ONEOK, Inc. filed November 21, 2008 (incorporated by reference from Exhibit No. 4.2 to Registration Statement on Form S-3 filed November 21, 2008).

4.2

Form of Common Stock Certificate (incorporated by reference from Exhibit 1 to Registration Statement on Form 8-A filed November 21, 1997).

4.3

Indenture, dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.1 to Registration Statement on Form S-3 filed August 26, 1998, Commission File No. 333-62279).

4.4

Indenture dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.1 to Amendment No. 1 to Registration Statement on Form S-3 filed December 28, 2001, Commission File No. 333-65392).

4.5

First Supplemental Indenture dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(a) to Form 8-K/A filed October 2, 1998).

4.6

Second Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorpated by reference from Exhibit 5(b) to Form 8-K/A filed October 2, 1998).

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4.7

Not used.

4.8

Fourth Supplemental Indenture dated February 17, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4.5 to Registration Statement on Form S-3 filed April 15, 1999, Commission File No. 333-76375).

4.9

Not used.

4.10

Not used.

4.11

Not used.

4.12

Eighth Supplemental Indenture dated April 6, 2001, between ONEOK, Inc. and The Chase Manhattan Bank (incorporated by reference from Exhibit 4.9 to Registration Statement on Form S-3 filed July 19, 2001, Commission File No. 333-65392).

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 Form 8-K filed June 17, 2005).

4.15

Third Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.3 to Form 8-K filed June 17, 2005).

4.16

Not used.

4.17

Not used.

4.18

Indenture, dated as of March 21, 2001, between Northern Border Partners, L.P. and Northern Border Intermediate Limited Partnership and Bank One Trust Company, N.A., Trustee (incorporated by reference to Exhibit 4.3 to Northern Border Partners, L.P.’s Form 10-K for the year ended December 31, 2001, filed on March 29, 2002 (File No. 1-12202)).

4.19

Indenture, dated as of 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 Form 8-K filed on September 26, 2006 (File No. 1-12202)).

4.20

First Supplemental Indenture, dated as of 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 5.90 percent Senior Notes due 2012 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.’s Form 8-K filed on September 26, 2006 (File No. 1-12202)).

4.21

Second Supplemental Indenture, dated as of 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 Form 8-K filed on September 26, 2006 (File No. 1-12202)).

4.22

Third Supplemental Indenture, dated as of 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 Form 8-K filed on September 26, 2006 (File No. 1-12202)).

4.23

Fourth Supplemental Indenture, dated as of 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

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percent Senior Notes due 2037 (incorporated by reference to Exhibit 4.2 to ONEOK Partners, L.P.'s Form 8-K filed on September 28, 2007 (File No. 1-12202)).

4.24

Fifth Supplemental Indenture, dated as of 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 the Current Report on Form 8-K, filed by ONEOK Partners, L.P. on March 3, 2009 (File No. 1-12202)).

4.25

Amended and Restated Rights Agreement dated as of February 5, 2003, between ONEOK, Inc. and UMB Bank, N.A., as Rights Agent (incorporated by reference from Exhibit 1 to Registration Statement on Form 8-A/A (Amendment No. 1) filed February 6, 2003).

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 Form 8-K filed on 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% Senior Notes due 2016 (the “2016 Notes”) (incorporated by reference from Exhibit 4.2 to Form 8-K for the 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% Senior Notes due 2041(together with the 2016 Notes, the “Notes”) (incorporated by reference from Exhibit 4.3 to Form 8-K for the filed January 26, 2011 (File No. 1-12202)).

ONEOK, Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit 10(a) to Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002).

10.1

ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by reference from Exhibit 99 to Form S-8 filed January 25, 2001).

10.2

ONEOK, Inc. Supplemental Executive Retirement Plan terminated and frozen December 31, 2004 (incorporated by reference from Exhibit 10.1 to Form 8-K filed on December 20, 2004).

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 Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009).

10.4

Form of Termination Agreement between ONEOK, Inc. and ONEOK, Inc. executives, as amended, dated January 1, 2003 (incorporated by reference from Exhibit 10.3 to Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003).

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 Form 10-K for the fiscal year ended December 31, 2002, filed March 10, 2003).

10.6

Amended and Restated ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10.1 to Form 8-K filed May 27, 2009).

10.7

ONEOK, Inc. Employee Nonqualified Deferred Compensation Plan, as amended and restated December 16, 2004 (incorporated by reference from Exhibit 10.3 to Form 8-K filed December 20, 2004).

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 Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009).

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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 Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009).

10.10

Letter agreement between ONEOK, Inc. and Sam Combs III, dated June 16, 2009 (incorporated by reference from Exhibit 10.1 to our Form 10-Q filed August 6, 2009).

10.11

Underwriting Agreement dated June 16, 2009, among ONEOK Partners, L.P. and the underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s report on Form 8-K filed on June 22, 2009).

10.12

Not used.

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 Form 10-Q for the period ended June 30, 2006, filed on August 4, 2006 (File No. 1-12202)).

10.14

Not used.

10.15

First Amended and Restated General Partnership Agreement of Northern Border Pipeline Company dated April 6, 2006 by and between Northern Border Intermediate Limited Partnership and TC PipeLines Intermediate Limited Partnership (incorporated by reference to Exhibit 3.1 to Northern Border Pipeline Company’s Form 8-K filed April 12, 2006 (File No. 333-87753)).

10.16

Processing and Gathering Services Agreement between ONEOK Field Services Company, L.L.C, ONEOK, Inc. and ONEOK Bushton Processing, Inc. dated April 6, 2006 (incorporated by reference to Exhibit 10.7 to ONEOK Partners, L.P.’s Form 10-Q for the period ended June 30, 2006, filed on August 4, 2006 (File No. 1-12202)).

10.17

$1,200,000,000 Amended and Restated Credit Agreement dated as of July 14, 2006 among ONEOK, Inc., as the Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, Citibank, N.A., as L/C Issuer, and the Lenders party hereto (incorporated by reference from Exhibit 10.1 to the Form 10-Q for the quarter ended June 30, 2006, filed August 4, 2006).

10.18

Underwriting Agreement dated February 2, 2010, among ONEOK Partners, L.P. and the underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.'s report on Form 8-K filed on February 5, 2010.

10.19

Not used.

10.20

Not used.

10.21

First Amendment, dated as of September 26, 2008, to the Amended and Restated Credit Agreement, dated as of July 14, 2006, among ONEOK, Inc., as the Borrower, Bank of America, N.A., as the Administrative Agent, Swing Line Lender and L/C Issuer, Citibank N.A., as L/C Issuer and the financial institutions named therein as lenders (incorporated by reference from Exhibit 10.1 to our Form 10-Q filed November 6, 2008).

10.22

Commercial Paper Dealer Agreement between ONEOK Partners, L.P. and Citigroup Global Markets Inc. dated as of June 16, 2010 (incorporated by reference to Exhibit 10.1 to ONEOK Inc.’s Current Report on Form 8-K filed on June 22, 2010).

10.23

Commercial Paper Dealer Agreement between ONEOK Partners, L.P. and Banc of America Securities LLC dated as of June 16, 2010 (incorporated by reference to Exhibit 10.2 to ONEOK Inc.’s Current Report on Form 8-K filed on June 22, 2010).

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10.24

Commercial Paper Dealer Agreement between ONEOK Partners, L.P. and SunTrust Robinson Humphrey, Inc. dated as of June 16, 2010 (incorporated by reference to Exhibit 10.3 to ONEOK Inc.’s Current Report on Form 8-K filed on June 22, 2010).

10.25

Not used.

10.26

Not used.

10.27

Not used.

10.28

Not used.

10.29

Not used.

10.30

Not used.

10.31

Not used.

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 our Form 8-K filed April 12, 2006).

10.33

Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P. dated as of September 15, 2006 (incorporated by reference to Exhibit 3.1 to ONEOK Partners, L.P.’s Form 8-K filed on September 19, 2006 (File No. 1-12202)).

10.34

Not used.

10.35

Not used.

10.36

Not used.

10.37

ONEOK, Inc. Profit Sharing Plan dated January 1, 2005 (incorporated by reference from Exhibit 99 to Registration Statement on Form S-8 filed December 30, 2004).

10.38

ONEOK, Inc. Employee Stock Purchase Plan as amended and restated effective as of December 20, 2007 (incorporated by reference from Exhibit 4.2 to Registration Statement on Form S-8 filed August 4, 2008).

10.39

Form of Non-Statutory Stock Option Agreement (incorporated by reference from Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2004, filed November 3, 2004).

10.40

Not used.

10.41

Not used.

10.42

Not used.

10.43

Not used.

10.44

ONEOK, Inc. Equity Compensation Plan, as amended and restated, dated December 18, 2008 (incorporated by reference from Exhibit 10.44 to Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009).

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10.45

Form of Restricted Unit Award Agreement (incorporated by reference from Exhibit 10.45 to Form 10-K filed February 28, 2007).

10.46

Form of Performance Unit Award Agreement (incorporated by reference from Exhibit 10.46 to Form 10-K filed February 28, 2007).

10.47

Not used.

10.48

Amended and Restated Revolving Credit Agreement dated March 30, 2007, among ONEOK Partners, L.P., as Borrower, the lenders from time to time party thereto, SunTrust Bank, as Administrative Agent, Wachovia Bank, National Association, as Syndication Agent, and BMO Capital Markets, Barclays Bank PLC, and Citibank, N.A., as Co-Documentation Agents (incorporated by reference from Exhibit 10.1 to our Form 10-Q filed May 2, 2007).

10.49

Supplement and Joinder Agreement dated July 31, 2007, among ONEOK Partners, L.P., as Borrower, each of the existing Lenders, SunTrust Bank, as Administrative Agent, and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to ONEOK Partners, L.P.’s report on Form 10-Q filed on August 3, 2007 (File No. 1-12202)).

10.50

Thrift Plan for Employees of ONEOK, Inc. and Subsidiaries as amended and restated effective as of January 1, 2008 (incorporated by reference from Exhibit 4.3 to Registration Statement on Form S-8 filed August 4, 2008).

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 Form 10-Q filed on August 3, 2007 (File No. 1-12202)).

10.52

Not used.

10.53

Not used.

10.54

Form of Performance Unit Award Agreement dated January 15, 2009 (incorporated by reference from Exhibit 10.54 to Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009).

10.55

Form of Restricted Unit Stock Bonus Award Agreement dated January 15, 2009 (incorporated by reference from Exhibit 10.55 to Form 10-K for the fiscal year ended December 31, 2008, filed February 25, 2009).

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 report on Form 8-K filed on July 17, 2009).

10.57

Form of Restricted Unit Stock Bonus Award Agreement dated February 18, 2010 (incorporated by reference from Exhibit 10.57 to Form 10-K/A for the fiscal year ended December 31, 2009, filed October 12, 2010).

10.58

Form of Performance Unit Award Agreement dated February 18, 2010 (incorporated by reference from Exhibit 10.58 to Form 10-K/A for the fiscal year ended December 31, 2009, filed October 12, 2010).

10.59

Form of Restricted Unit Stock Bonus Award Agreement dated February 17, 2011.

10.60

Form of Performance Unit Award Agreement dated February 17, 2011.

Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2010, 2009, 2008, 2007 and 2006.

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Not used.

Required information concerning the registrant’s subsidiaries.

Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.

23.1

Not used.

31.1

Certification of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of John W. Gibson pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant to Rule 13a-14(b)).

32.2

Certification of Curtis L. Dinan 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 documents formatted in XBRL: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008; (iii) Consolidated Balance Sheets at December 31, 2010 and 2009; (iv) Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008; (v) Consolidated Statements of Shareholders’ Equity for the years ended December 31, 2010, 2009 and 2008; (vi) Consolidated Statements of Comprehensive Income for the years ended December 31, 2010, 2009 and 2008; and (vii) Notes to Consolidated Financial Statements.

Users of this data are advised pursuant to Rule 401 of Regulation S-T that the information contained in the XBRL documents is unaudited, and these XBRL documents are not the official publicly filed consolidated financial statements of ONEOK, Inc. The purpose of submitting these XBRL formatted documents is to test the related format and technology, and as a result, investors should continue to rely on the official filed version of the furnished documents and not rely on this information in making investment decisions.

In accordance with Rule 402 of Regulation S-T, the XBRL related information in Exhibit 101 to this Annual Report shall not be deemed to be “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing. We also make available on our Web site the Interactive Data Files submitted as Exhibit 101 to this Annual Report.

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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.

ONEOK, Inc.

Registrant

Date: February 22, 2011 By: /s/ Curtis L. Dinan

Curtis L. Dinan

Senior Vice President,

Chief Financial Officer and Treasurer

(Principal Financial Officer)

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 22nd day of February 2011.

	/s/ John W. Gibson			/s/ David L. Kyle
	John W. Gibson			David L. Kyle
	President and			Chairman of the
	Chief Executive Officer			Board of Directors

	/s/ Curtis L. Dinan			/s/ Derek S. Reiners
	Curtis L. Dinan			Derek S. Reiners
	Senior Vice President,			Senior Vice President and
	Chief Financial Officer and Treasurer			Chief Accounting Officer

	/s/ Julie H. Edwards			/s/ William L. Ford
	Julie H. Edwards			William L. Ford
	Director			Director

	/s/ Bert H. Mackie			/s/ Jim W. Mogg
	Bert H. Mackie			Jim W. Mogg
	Director			Director

				/s/ Gary D. Parker
	Pattye L. Moore			Gary D. Parker
	Director			Director

	/s/ Eduardo A. Rodriguez			/s/ David J. Tippeconnic
	Eduardo A. Rodriguez			David J. Tippeconnic
	Director			Director

	/s/ Gerald B. Smith			/s/ James C. Day
	Gerald B. Smith			James C. Day
	Director			Director

127