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, 2008.

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

Indicate by checkmark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer X Accelerated filer __ Non-accelerated filer __

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, 2008, was $5.1 billion.

On February 18, 2009, the Company had 105,239,496 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 21, 2009, are incorporated by reference in Part III.

ONEOK, Inc.

2008 ANNUAL REPORT ON FORM 10-K

Part I.		Page No.
Item 1. Item 1A. Item 1B.	Business Risk Factors Unresolved Staff Comments	5-17 17-29 29
Item 2.	Properties	29-30
Item 3.	Legal Proceedings	31-32
Item 4.	Submission of Matters to a Vote of Security Holders	32
Part II.
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32-34
Item 6.	Selected Financial Data	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	35-62
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	63-66
Item 8.	Financial Statements and Supplementary Data	67-117
Item 9. Item 9A. Item 9B.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information	117 117-118 118
Part III.
Item 10.	Directors, Executive Officers and Corporate Governance	118-119
Item 11.	Executive Compensation	119
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	119
Item 13.	Certain Relationships and Related Transactions, and Director Independence	120
Item 14.	Principal Accounting Fees and Services	120
Part IV.
Item 15.	Exhibits, Financial Statement Schedules	120-125
Signatures		126

As used in this Annual Report on Form 10-K, references to “we,” “our” or “us” refers 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 on Form 10-K are defined as follows:

AFUDC

Allowance for funds used during construction

APB Opinion

Accounting Principles Board Opinion

ARB

Accounting Research Bulletin

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

Black Mesa Pipeline

Black Mesa Pipeline, Inc.

Btu

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

EBITDA

Earnings before interest, taxes, depreciation and amortization

EITF

Emerging Issues Task Force

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

FIN

FASB Interpretation

Fort Union Gas Gathering

Fort Union Gas Gathering, L.L.C.

GAAP

Generally Accepted Accounting Principles in the United States

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

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.

NGL(s)

Natural gas liquid(s)

Northern Border Pipeline

Northern Border Pipeline Company

NYMEX

New York Mercantile Exchange

NYSE

New York Stock Exchange

OBPI

ONEOK Bushton Processing Inc.

OCC

Oklahoma Corporation Commission

ONEOK

ONEOK, Inc.

ONEOK Leasing Company

ONEOK Leasing Company, L.L.C.

ONEOK Partners

ONEOK Partners, L.P.

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

RRC

Texas Railroad Commission

S&P

Standard & Poor’s Rating Group

SEC

Securities and Exchange Commission

Statement

Statement of Financial Accounting Standards

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TC PipeLines

TC PipeLines Intermediate Limited Partnership, a subsidiary of TC

PipeLines, LP

TransCanada

TransCanada Corporation

The statements in this Annual Report on Form 10-K 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,” “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 on Form 10-K for the year ended December 31, 2008.

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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 47.7 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 operation is engaged in providing premium natural gas marketing services to wholesale and retail customers across the United States and Canada.

DESCRIPTION OF BUSINESS SEGMENTS

We report operations in the following reportable business segments:

·	ONEOK Partners

·	Distribution

·	Energy Services

Other

For financial and statistical information regarding our business segments, see below in the “Segment Financial Information” section, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation and Note M of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Business Strategy

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

·	developing and executing internally generated growth projects within our ONEOK Partners segment;

·	increasing the level of sustainable earnings in our Distribution segment;

·	continuing our focus on physical activities in our Energy Services segment;

·	executing strategic acquisitions that utilize our core competencies; and

·	managing our balance sheet over the long term to maintain our credit ratings at or above their current investment-grade levels.

ONEOK Partners - ONEOK Partners’ primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to its unitholders and to increase its quarterly cash distributions over time. ONEOK Partners’ ability to maintain and grow its distributions to unitholders depends on, among other things, the growth of its existing businesses and strategic acquisitions. We plan to continue pursuing internal growth opportunities and strategic acquisitions related to gathering, processing, fractionating, transporting, storing and marketing natural gas and NGLs that will utilize our core competencies, minimize commodity price risk and provide long-term, sustainable and stable cash flows. Our strategy focuses on maintaining stable cash flows through predominantly fee-based income, equity earnings derived primarily from fee-based earnings, and by managing commodity and spread risk.

Distribution - Our integrated strategy for our LDCs incorporates a rates and regulatory plan that includes positive relationships with regulators, consistent strategies and synchronized rate case filings. We focus on growth of our customer count and rate base through efficient investment in our system while emphasizing safety and cost control. We provide customer choice programs designed to reduce volumetric sensitivity and create value for our customers.

Energy Services - Our Energy Services segment creates value by providing premium services to our customers by delivering physical and risk management products and services to our customers through our network of contracted gas supply and leased transportation and storage assets. We optimize our storage and transportation capacity through the daily application of market knowledge and effective risk management.

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Outlook for 2009

We expect continued deteriorating economic conditions in 2009, with downward pressures, relative to 2008, on commodity prices for natural gas, NGLs and crude oil. We anticipate that lower commodity prices will result in reduced drilling activity and economic conditions will result in reduced petrochemical demand. We also expect continued volatility and disruption in the financial markets which could result in an increased cost of capital. We expect depressed commodity prices and tighter capital markets to also result in the sale or consolidation of underperforming assets in the industry, which may present opportunities for us.

ONEOK Partners - ONEOK Partners intends to pursue continued growth in its natural gas businesses through well-connects, contract renegotiations and expansions and extensions of its existing systems and plants. For its natural gas liquids businesses, ONEOK Partners will continue to focus on adding new supply connections and optimizing existing assets, as well as completing the growth projects currently under construction. Capital expenditures in 2009 are expected to be significantly lower than in 2008 when ONEOK Partners spent approximately $1.3 billion. ONEOK Partners plans to spend approximately $425 million on capital expenditures in 2009, of which approximately $355 million is for growth projects. ONEOK Partners also plans to pursue strategic acquisitions related to gathering, processing, fractionating, storing, transporting and marketing natural gas and NGLs.

Distribution - In our Distribution segment, we plan to grow our asset base through efficient capital investment in infrastructure and technology and increase the level of sustainable earnings.

Energy Services - In our Energy Services segment, we expect higher natural gas basis differentials. We plan to manage our current portfolio of supply and leased assets, reduce storage capacity utilization as compared with 2008, continue to offer premium products and services, and draw on the competitive position of our assets to extract incremental value through daily optimization of storage and transportation assets. Additionally, we plan to grow our asset management agreements with LDCs, use hedging to establish base margins and capture incremental margins related to location and seasonal differences, and continue to achieve high customer satisfaction.

SIGNIFICANT DEVELOPMENTS IN 2008

Capital Projects - ONEOK Partners placed the following projects in-service during 2008:

·	January - Midwestern Gas Transmission’s eastern extension pipeline;

·	July - final phase of Fort Union Gas Gathering expansion project;

·	September - Woodford Shale natural gas liquids pipeline extension;

·	October - Bushton Fractionation expansion;

·	November - Overland Pass Pipeline from Opal, Wyoming to Conway, Kansas; and

·	December - partial operations of the Guardian Pipeline extension with interruptible service from Ixonia, Wisconsin, to Green Bay, Wisconsin.

Equity Issuance - In March 2008, we purchased from ONEOK Partners, in a private placement, an additional 5.4 million of ONEOK Partners’ common units for a total purchase price of approximately $303.2 million. In addition, ONEOK Partners completed a public offering of 2.5 million common units at $58.10 per common unit and received net proceeds of $140.4 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ private placement and public offering of common units, ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent general partner interest.

In April 2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per common unit to the underwriters of the public offering upon the partial exercise of their option to purchase additional common units to cover over-allotments. ONEOK Partners received net proceeds of approximately $7.2 million from the sale of these common units after deducting underwriting discounts but before offering expenses. In conjunction with the partial exercise by the underwriters, ONEOK Partners GP contributed $0.2 million to ONEOK Partners in order to maintain its 2 percent general partner interest. Following these transactions, our ownership interest in ONEOK Partners is 47.7 percent.

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SEGMENT FINANCIAL INFORMATION

Operating Income - The following table sets forth operating income by segment, as a percentage of our consolidated total, excluding any gain or (loss) on sale of assets, for the periods indicated.

	Years Ended December 31,
Operating Income	2008	2007	2006
ONEOK Partners	70%	54%	53%
Distribution	21%	21%	16%
Energy Services	8%	25%	31%
Other and Eliminations	1%	*	*
Total	100%	100%	100%

* Represents a value of less than 1 percent.

Customers and Total Assets - See Note M of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of revenues from external customers under “Customers” and disclosure of total assets by segment within the “Operating Segment Information” table.

Intersegment Revenues - The following table sets forth the percentage of intersegment revenues to total revenue, by segment, for the periods indicated.

	Years Ended December 31,
Intersegment Revenues	2008	2007	2006
ONEOK Partners	10%	11%	13%
Distribution	*	*	*
Energy Services	8%	7%	8%

* Represents a value of less than 1 percent.

See Note M of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information about intersegment revenues.

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 47.7 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. See Note Q of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of our incentive distribution rights.

Business Strategy - ONEOK Partners’ primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to its unitholders and to increase its quarterly cash distributions over time. ONEOK Partners plans to accomplish these objectives while focusing on safe, environmentally sound and legally compliant operations for its customers, employees, contractors and the public through the following:

·	developing and executing internally generated growth projects;

·	executing strategic acquisitions related to gathering, processing, fractionating, storing, transporting and marketing natural gas and NGLs that utilize its core competencies; and

·	managing its balance sheet over the long-term to maintain its investment-grade credit ratings at or above their current levels.

Description of Business - Our ONEOK Partners segment is engaged in the gathering and processing of unprocessed natural gas and fractionation of NGLs, primarily in the Mid-Continent, and Rocky Mountain regions covering Oklahoma, Kansas, Montana, North Dakota and Wyoming. These operations include the gathering of unprocessed natural gas produced from crude oil and natural gas wells. Through gathering systems, unprocessed 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. This stream is then separated by a distillation process, referred to as fractionation, into marketable product components such as ethane, ethane/propane (EP),

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propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products can then be stored, transported and marketed to a diverse customer base of end-users.

Revenue from the gathering and processing business is primarily derived 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, compressing and processing the producer’s unprocessed natural gas. For 2008, this type of contract represented approximately 34 percent of contracted volumes.

·	Fee - ONEOK Partners is paid a fee for the services provided based on Btus gathered, compressed and/or processed. For 2008, this type of contract represented approximately 58 percent of contracted volumes.

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. For 2008, this type of contract represented approximately 8 percent of contracted volumes, with approximately 89 percent of that contracted volume containing language that effectively converts these contracts into fee contracts when the gross processing spread is negative.

ONEOK Partners also 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, the Texas panhandle and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas, and Texas. 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’ 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.

Revenue for the natural gas liquids businesses is primarily derived from the following types of services:

·	Exchange services - ONEOK Partners gathers and transports unfractionated NGLs to its fractionators, separating them into marketable products and redelivering the NGL products to its customers 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 of its NGL products between the major market centers in Conway, Kansas, and Mont Belvieu, Texas, 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.

ONEOK Partners 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’ pipelines include Midwestern Gas Transmission, Guardian Pipeline, Viking Gas Transmission Company, OkTex Pipeline Company L.L.C. and a 50 percent ownership interest in Northern Border Pipeline.

ONEOK Partners’ intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. ONEOK Partners also has access to the major natural gas producing area in south central Kansas. In Texas, its intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin, and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market. ONEOK Partners owns or leases storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas. ONEOK Partners’ natural gas pipeline assets primarily serve LDCs, large industrial companies, municipalities, irrigation customers, power generation facilities and marketing companies.

ONEOK Partners’ revenues from its natural gas pipelines are typically derived from fee services under the following types of 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

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

The main factors that affect ONEOK Partners’ margins are:

·	NGL transportation and fractionation volumes and associated fees;

·	natural gas transportation and storage volumes;

·	weather impacts on demand and operations;

·	fees charged for processing services and storage services;

·	the Mid-Continent, Gulf Coast and Rocky Mountain natural gas price, crude oil price and the daily average OPIS price for its products sold, as well as the relative value on a Btu basis of each of the components to each other;

·	the relative value of ethane to natural gas; and

·	regional 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’ customers relating to the output of the gas processing plants, 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 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 value of the composite price of NGLs to the price of natural gas, primarily ethane to natural gas. In addition, volume delivered through the system may increase or decrease as a result of the relative NGL price between the Mid-Continent and Gulf Coast regions. Natural gas transportation throughput fluctuates due to rainfall that impacts irrigation demand, hot temperatures that affect power generation demand and cold temperatures that affect heating demand.

Natural gas and NGL supply is affected by rig availability, operating capability and producer drilling activity, which is sensitive to commodity prices, exploration success, available capital and regulatory control. Relatively high natural gas and crude oil prices, resulted in increased drilling for most of 2008 in the Mid-Continent and Rocky Mountain regions, which are our primary supply regions. Significant price declines and reduced drilling activity starting in the fourth quarter of 2008 are now creating less favorable near-term supply projections.

Demand - Demand for gathering and processing services is typically aligned with the supply of natural gas, which generally flows from a producing area at a relatively steady but gradually declining pace over time unless new reserves are added. ONEOK Partners’ plant operations can be adjusted to respond to market conditions, such as demand for ethane. By changing operating parameters at certain plants, ONEOK Partners can produce more of the specific commodity that has the most favorable price or price spread.

Demand for natural gas pipeline transportation service and natural gas storage is directly related 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. The effect of weather on ONEOK Partners’ natural gas pipelines operations is discussed below under “Seasonality.” The strength of the economy directly impacts manufacturing and industrial companies that rely on 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 successfully and economically sustain their operations impacts the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for natural gas liquids gathering, fractionation and distribution services. Natural gas and propane are subject to weather-related seasonal demand.

Other 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. Ethane and EP are used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fiber.

Commodity Prices - During 2008, both crude oil and natural gas prices were volatile, with NYMEX crude oil settlement prices ranging from $49.62 to $134.62 per Bbl and NYMEX natural gas settlement prices ranging from $6.47 to $13.11 per MMBtu.

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Seasonality - Some of ONEOK Partners’ products, such as natural gas and propane used for heating, are subject to seasonality, resulting in more demand during the months of November through March. As a result, prices of these products are typically higher during that time period. Demand has also increased for natural gas in the summer periods as more electric generation is now dependent upon natural gas for fuel. Other products, such as ethane and EP, are tied to the petrochemical industry, while normal butane, iso-butane and natural gasoline are used by the refining industry as blending stocks. As a result, the prices of these products are affected by the economic conditions and demand associated with these various industries.

Competition - ONEOK Partners’ natural gas and natural gas liquids pipelines compete directly with other intrastate and interstate pipeline companies and other storage facilities for natural gas and NGLs. Competition for natural gas transportation services continues to increase as the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Competition among pipelines and storage facilities is based primarily on fees for services, quality of services provided, current and forward natural gas prices and proximity to supply areas and markets. ONEOK Partners believes that its pipelines and storage assets enable it to effectively compete.

ONEOK Partners’ natural gas gathering and processing business competes for natural gas supplies with major integrated exploration and production companies, 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’ gathering and fractionation business competes with other fractionators, storage providers and gatherers 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:

·	producer drilling activity;

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

·	fees charged under our contracts;

·	pressures maintained on our gathering systems;

·	location of our gathering systems relative to our competitors;

·	location of our gathering systems relative to drilling activity;

·	efficiency and reliability of our operations; and

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

ONEOK Partners is responding to these industry conditions by making capital investments to access new supplies, increase gathering and fractionation capacity, increase storage capabilities, improve plant processing flexibility and reduce operating costs, evaluating consolidation opportunities to maximize earnings, selling assets in non-core operating areas and renegotiating unprofitable contracts. The principal goal of the contract renegotiation effort is to eliminate unprofitable contracts and improve margins, primarily during periods when the gross processing spread is negative.

Government Regulation - The FERC has traditionally maintained that a 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. 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 believes its gathering facilities and operations meet the criteria used by the FERC for non-jurisdictional gathering facility status. ONEOK Partners can transport residue gas from its plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act.

Oklahoma and Kansas 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 in both Oklahoma and Kansas are not regulated by the FERC or the states’ respective corporation commissions. ONEOK Partners’ remaining natural gas liquids gathering and

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distribution pipelines are interstate pipelines regulated by the FERC. ONEOK Partners transports unfractionated NGLs and NGL products pursuant to filed tariffs.

Additionally, the operations of our assets are regulated by various state and federal government agencies. See further discussion in the “Environmental and Safety Matters” section.

Unconsolidated Affiliates - Our ONEOK Partners segment has the following unconsolidated affiliates:

·	50 percent interest in Northern Border Pipeline, which transports natural gas from the Montana-Saskatchewan border near Port Morgan, Montana, to a terminus near North Hayden, Indiana;

·	49 percent ownership interest in Bighorn Gas Gathering, L.L.C., which operates a major coalbed methane gathering system serving a broad production area in northeast Wyoming;

·	37 percent ownership interest in Fort Union Gas Gathering, which gathers coalbed methane gas produced in the Powder River Basin and delivers natural gas into the interstate pipeline grid;

·	35 percent ownership interest in Lost Creek Gathering Company, L.L.C., which gathers natural gas produced from conventional wells in the Wind River Basin of central Wyoming and delivers natural gas into the interstate pipeline grid;

·	10 percent ownership interest in Venice Energy Services Co., LLC, a gas processing complex near Venice, Louisiana;

·	50 percent ownership interest in Chisholm Pipeline Company which operates an interstate natural gas liquids pipeline system extending approximately 184 miles from origin points in Oklahoma and Kansas;

·	48 percent ownership interest in Sycamore Gas System, which is a gathering system with compression located in south central Oklahoma; and

·	50 percent ownership interest in the Heartland joint venture, which operates a terminal and pipeline systems that transport refined petroleum products in Kansas, Nebraska and Iowa.

See Note O of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of unconsolidated affiliates.

Distribution

Business Strategy - Our Distribution segment focuses on increasing the level of sustainable earnings through safe, reliable, environmentally sound and legally compliant distribution operations.

The integrated strategy for our LDCs incorporates:

·	a rates and regulatory strategy that includes fostering positive relationships with regulators, consistent strategies and synchronized rate case filings;

·	a focus on the growth of our customer count and rate base through efficient investment in our system while emphasizing safety and cost control; and

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

Our regulatory strategy incorporates rate features that provide strategies for earnings lag, margin protection and risk mitigation. These strategies include capital recovery mechanisms in Oklahoma, Kansas and portions of Texas. In Texas, we also have cost of service adjustments that address investments in rate base and changes in expense. Margin protection strategies include increased customer fixed charges in all three states. 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 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. In addition, 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.

Our operating results are primarily affected 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 gas purchased by the respective distribution companies. 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, in the case of industrial customers, to use alternative energy sources. Higher natural gas costs may also adversely impact our accounts receivable collections, resulting in higher bad-debt expense.

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The rate structure for Oklahoma Natural Gas includes two service rate options for residential gas sales customers. Certain high usage customers pay a higher monthly service charge and a lower per dekatherm delivery charge, while lower usage customers pay a lower monthly service charge coupled with a higher per dekatherm delivery charge. Customers can elect to change service rate options to ensure that they are billed under the alternative that best fits their individual usage, but they must remain on the selected option for a full year after the change is made.

Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service distribute natural gas as public utilities to approximately 87 percent, 70 percent and 14 percent of the distribution markets for Oklahoma, Kansas and Texas, respectively. Natural gas sold to residential and commercial customers accounts for approximately 79 and 20 percent of natural gas sales, respectively, in Oklahoma; 74 and 19 percent of natural gas sales, respectively, in Kansas; and 66 and 26 percent of natural gas sales, respectively, in Texas.

A franchise, although nonexclusive, is a utility’s right to use the municipal streets, alleys and other public ways for a defined period of time in exchange for a fee. In management’s opinion, our franchises contain no unduly burdensome restrictions and are sufficient for the transaction of business in the manner in which it is now conducted.

Market Conditions and Seasonality - Supply - In 2008, our Distribution segment purchased 182 Bcf of natural gas supply. Our gas supply portfolio consists of long-term, seasonal and short-term contracts from a diverse group of suppliers. These contracts are awarded through competitive bid processes to ensure reliable and competitively priced gas supply. Our Distribution segment’s natural gas supply is purchased from a combination of direct wellhead production, natural gas processing plants, natural gas marketers and production companies.

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.

There is an adequate supply of natural gas available to our utility systems, and we do not anticipate problems with securing additional natural gas supply as needed for our customers. However, if supply shortages occur, each of our LDCs has curtailment tariff provisions in place that provide for: (i) reducing or discontinuing gas service to large industrial users; and (ii) requesting that residential and commercial customers reduce their 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. Natural gas usage per 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’ replacement of older, less efficient 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 December 2007, Oklahoma Natural Gas was authorized by the OCC to implement a natural gas hedging program as a three-year pilot program, with up to $10 million per year in hedge costs to be recovered from customers. Kansas Gas Service has a natural gas hedging program in place, subject to annual KCC approval, which is designed to reduce volatility in the natural gas price paid by consumers. The costs of this program are borne by the Kansas Gas Service customers. Texas Gas Service also has a natural gas hedging program for certain of its jurisdictions.

In managing our gas supply portfolios, we partially mitigate gas price volatility using a combination of financial derivatives, the triggering of forward prices on certain gas supply contracts, and injecting gas into leased storage capacity. Our Distribution segment does not utilize financial derivatives for speculative purposes, nor does it have trading operations. To further mitigate gas price volatility, we utilize 38.3 Bcf of leased storage capacity, which allows gas to be purchased during the off-peak season and stored for use in the winter periods.

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

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Seasonality - Natural gas sales to residential and commercial customers are seasonal, as a substantial portion of their natural gas is used for space heating. Accordingly, the volume of natural gas sales is normally higher during the heating season (November through March) than in other months of the year. The sales effect resulting from weather that is above or below normal is substantially offset through weather normalization adjustments (WNA), which are now approved by the regulatory authorities for all of our Oklahoma and Kansas 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.

Approximately 94 percent of Texas Gas Service’s revenues, including Austin and Galveston, are protected from abnormal weather due to a higher customer charge or WNA clauses. A higher customer charge is included in the authorized rate design for the jurisdictions of El Paso, north Texas, Rio Grande Valley and Port Arthur to protect customers from abnormal rate fluctuation due to weather.

Competition - We can face competition based on customers’ preference for natural gas compared with other energy products, and the comparative prices of those products. The most significant product competition occurs between natural gas and electricity in the residential and small commercial markets. We compete for space heating, water heating, cooking and other general energy needs. Customers and builders typically make the decision for 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 of causing a decline in the number of future natural gas customers.

We believe that we must maintain a competitive advantage in order to retain our customers, and, accordingly, we focus on providing safe, reliable, 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. Texas Gas Service files all negotiated transportation service contracts under a separate, confidential tariff at the RRC.

Government Regulation - Rates charged by 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 and all appellate matters are subject to regulatory oversight by the RRC. Natural gas purchase costs are included in the Purchased Gas Adjustment (PGA) clause rate that is billed to customers. Our distribution companies do not make a profit on the cost of gas. Other changes in costs must be recovered through periodic rate adjustments approved by the OCC, KCC, RRC and various municipalities in Texas. See page 49 for a detailed description of our various regulatory initiatives.

Oklahoma Natural Gas has settled all known claims arising out of long-term gas supply contracts containing “take-or-pay” provisions that purport to require us to pay for volumes of natural gas contracted for but not taken. The OCC has previously authorized recovery of the accumulated settlement costs over a 20-year period expiring in 2014, or approximately $7.0 million annually, through a combination of a surcharge from customers, revenue from transportation under Section 311(a) of the Natural Gas Policy Act and other intrastate transportation revenues.

Additionally, the operations of our assets are regulated by various state and federal government agencies. See further discussion in the “Environmental and Safety Matters” section.

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Energy Services

Business Strategy - Our Energy Services segment utilizes our network of contracted gas supply and leased 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. With these services and a focus on customer relationships, we expect to attract new customers and retain existing 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 time and locational spread risks that are inherent to storage and transportation contracts and will pursue hedging strategies that effectively mitigate these risks. At the same time, we capitalize on opportunities created by market volatility, weather-related events, supply-demand imbalances and market liquidity inefficiency, which allows us to capture additional margin. Using market information, we manage these asset-based positions and seek to provide incremental margin in our trading portfolio.

Through our wholesale marketing and risk management capabilities, we are able to be a full-service provider in our retail operations. We are able to offer a broad range of products and are expanding our markets. We plan to grow our retail business through internal growth initiatives, as well as expansion into areas that allow retail unbundling. We manage the commodity price and volumetric risk in these operations through a variety of risk management and hedging activities.

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 under Statement 133, “Accounting for Derivative Instruments and Hedging Activities,” (Statement 133).

Our Energy Services segment requires working capital to purchase natural gas inventory 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.

We are assessing the ongoing capital requirements of the wholesale energy business, which includes evaluating our contracted storage and transportation. This review is focused on ensuring our contracted assets continue to be aligned with our key strategy of providing customer-specific premium delivery services that generate recurring demand revenues and margins.

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 transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. Our contracted storage and transportation capacity connects major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized premium products and services valued by our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Our storage and transportation capacity allows us opportunities to optimize value 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.

Numerous risk management opportunities and operational strategies exist that can be implemented through the use of storage facilities and transportation capacity. We utilize our industry knowledge and expertise in order to capitalize on opportunities that are provided through market volatility. We utilize our experience to optimize the value of our contracted assets, and we use our risk management and marketing capabilities to both manage risk and to 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 D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K 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

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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.

Our working capital requirements related to our inventory in storage peaked in August 2008, with 61.0 Bcf valued at $614.6 million; this balance had decreased to $451.7 million by December 31, 2008. During September 2008, we impaired our inventory value; were it not for this impairment, our highest inventory balance would have been in November 2008 with 84.3 Bcf in storage. In addition, margin requirements can result in increased working capital requirements. During 2008, our margin requirements with counterparties ranged from zero to $378 million.

Market Conditions and Seasonality - Supply - During periods of high natural gas demand, we utilize storage capacity to supplement natural gas supply volumes to meet our peak day demand obligations or market needs.

Demand - Demand met by our swing and peaking natural gas requirements contracts in our wholesale operation is 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. Our retail business’ demand for natural gas is primarily driven by the use of space heating and is significantly impacted by temperature variations.

Seasonality - Due to seasonality of natural gas consumption, storage withdrawals and demand for our products and services, earnings are normally higher during the winter months than the summer months. Our Energy Services segment’s margins are subject to fluctuations during the year, primarily due to the impact certain seasonal factors have on sales volumes and the price of natural gas. Natural gas sales volumes are typically higher in the winter heating months than in the summer months, reflecting increased demand due to greater heating requirements and, typically, higher natural gas prices.

Competition - The recent market conditions affecting credit and liquidity have impacted competition by causing some of our competitors, including financial institutions, to either exit the business or scale back their operations. 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 effectively compete in the market by utilizing our leased 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.

Other

Description of Business - The primary companies in our Other segment include ONEOK Leasing Company and ONEOK Parking Company, L.L.C.

Through ONEOK Leasing Company 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 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.

In July 2007, ONEOK Leasing Company gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the lease term that was set to expire on September 30, 2009. In March 2008, ONEOK Leasing Company, purchased ONEOK Plaza for a total purchase price of approximately $48 million, which included $17.1 million for the present value of the remaining lease payments and $30.9 million for the base purchase price.

ENVIRONMENTAL AND SAFETY MATTERS

Information about our environmental matters is included in Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Pipeline Safety - We are subject to United States Department of Transportation regulations, including integrity management regulations. The Pipeline Safety Improvement Act requires pipeline companies to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high consequence areas. To our knowledge, we are in compliance with all material requirements associated with the various pipeline safety regulations.

Air and Water Emissions - The federal Clean Air Act, the federal 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

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pollutants discharged to waters of the United States and remediation of waters affected by such discharge. To our knowledge, we are in compliance with all material requirements associated with the various regulations.

The United States Congress is actively considering legislation to reduce emissions of greenhouse gases, including carbon dioxide and methane. In addition, state and regional initiatives to regulate greenhouse gas emissions are underway. We are monitoring federal and state legislation to assess the potential impact on our operations. Our most recent calculation of direct greenhouse gas emissions for ONEOK and ONEOK Partners is estimated to be less than 6 million metric tons of carbon dioxide equivalents on an annual basis. We will continue efforts to quantify our direct greenhouse gas emissions and will report such emissions as required by any mandatory reporting rule, including the rules anticipated to be issued by the EPA in mid-2009.

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.

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 to 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. A majority of our facilities were not tiered. We are waiting for Homeland Security’s analysis to determine if any of the tiered facilities will require Site Security Plans and possible physical security enhancements.

Climate Change - 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 rules anticipated to be issued by the EPA in mid-2009; (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; (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere; and (v) analyzing options for future energy investment.

Currently, certain subsidiaries of ONEOK Partners participate in the Processing and Transmission sectors and LDCs in our Distribution segment participate in the Distribution sector of the EPA’s Natural Gas STAR Program to voluntarily reduce methane emissions. A subsidiary in our ONEOK Partners’ segment was honored in 2008 as the “Natural Gas STAR Gathering and Processing Partner of the Year” for its efforts to positively address environmental issues through voluntary implementation of emission-reduction opportunities. In addition, we continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of methane 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.

EMPLOYEES

We employed 4,742 people at January 31, 2009, including 739 people employed by Kansas Gas Service, who were subject to collective bargaining contracts. The following table sets forth our contracts with collective bargaining units at January 31, 2009.

Union	Employees	Contract Expires
United Steelworkers of America	414	June 30, 2009
International Union of Operating Engineers	13	June 30, 2009
International Brotherhood of Electrical Workers	312	June 30, 2010

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EXECUTIVE OFFICERS

All executive officers are elected at the annual meeting of our Board of Directors and serve for a period of one year or until successors are duly elected. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.

Name and Position	Age	Business Experience in Past Five Years
John W. Gibson	56	2007 to present	Chief Executive Officer
Chief Executive Officer		2006 to present	Member of the Board of Directors
and Member of the Board of Directors		2006	President and Chief Operating Officer of ONEOK Partners, L.P.
		2005 to 2006	President, ONEOK Energy Companies
		2000 to 2005	President, Energy
Jim Kneale	57	2007 to present	President and Chief Operating Officer
President and Chief Operating Officer		2004 to 2006	Executive Vice President - Finance and Administration and Chief Financial Officer
		2001 to 2004	Senior Vice President, Treasurer and Chief Financial Officer
Curtis L. Dinan	41	2007 to present	Senior Vice President, Chief Financial Officer and Treasurer
Senior Vice President,		2004 to 2006	Senior Vice President and Chief Accounting Officer
Chief Financial Officer and Treasurer		2004	Vice President and Chief Accounting Officer
		2002 to 2004	Assurance and Business Advisory Partner, Grant Thornton, LLP
John R. Barker	61	2004 to present	Senior Vice President and General Counsel
Senior Vice President and		1994 to 2004	Stockholder, President and Director, Gable & Gotwals
General Counsel
Caron A. Lawhorn	47	2007 to present	Senior Vice President and Chief Accounting Officer
Senior Vice President and		2005 to 2006	Senior Vice President, Financial Services and Treasurer
Chief Accounting Officer		2004 to 2005	Vice President and Controller
		2003 to 2004	Vice President of Audit and Risk Control

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.

AVAILABLE INFORMATION

We make available on our Web site copies of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct, Corporate Governance Guidelines and Director Independence Guidelines are also available on our Web site, and we will make available, free of charge, copies of these documents upon request. However, our Web site and any contents thereof are not incorporated by reference into this document.

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 on Form 10-K, including “Forward-Looking Statements,” which are included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.

RISK FACTORS INHERENT IN OUR BUSINESS

Current levels of market volatility are unprecedented.

The capital and credit markets have been experiencing volatility and disruption. During the fourth quarter of 2008, the volatility and disruption reached unprecedented levels. In many cases, the capital markets have exerted downward pressure on equity prices 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. If current levels of market disruption and volatility continue or worsen, our access to capital and credit markets could be disrupted, making growth through acquisitions and development projects difficult or impractical to pursue until such time as markets stabilize.

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Our operating results may be adversely affected 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 might 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 and results of operations.

The recent downturn in the credit markets has increased the cost of borrowing and has made financing difficult to obtain, each of which may have a material adverse effect on our results of operations and business.

Recent events in the financial markets have had an adverse impact on the credit markets. As a result, credit has become more expensive and difficult to obtain. Some lenders are imposing more stringent restrictions on the terms of credit and there may be a general reduction in the amount of credit available in the markets in which we conduct business. The negative impact of the tightening of the credit markets may have a material adverse effect on us resulting from, but not limited to, an inability to obtain credit necessary to expand facilities or finance the acquisition of assets on favorable terms, if at all, increased financing costs or financing with increasingly restrictive covenants.

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 the ONEOK Partners 2008 Annual Report on Form 10-K.

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

Some of our nonregulated operations, which include ONEOK Partners’ gathering and processing, natural gas liquids gathering and fractionation, and our energy services businesses, have a higher level of risk than our regulated operations, which include our distribution and ONEOK Partners’ natural gas and natural gas liquids pipelines businesses. 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 policies for 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 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

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swaps 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 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. Although we attempt to obtain adequate security for these risks, if we fail to adequately assess 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 filed for bankruptcy protection, we may not be able to recover amounts owed, which would negatively 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, resulting from deregulation and other initiatives being pursued by the industry and regulatory agencies that allow customers increased options for energy supplies and service. 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 and plants.

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. Although we believe our businesses are positioned to compete effectively in the energy market, there are no assurances that this will be true 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:

·	mistaken assumptions about volumes, revenues and costs, including synergies;

·	an inability to successfully integrate the businesses we acquire;

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

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

·	the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

·	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;

·	mistaken 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.

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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 these funds and other resources.

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 adversely affect our financial results, and our potential pool of investors and funding sources could decrease. If S&P or Moody’s were to downgrade the long-term ratings of ONEOK Partners below investment grade, ONEOK Partners would, under certain circumstances, be required to offer to repurchase certain of its senior notes. Further, if our short-term ratings were to fall below A-2 (capacity to meet its financial commitment on the obligation is satisfactory) or P-2 (strong ability to repay short-term debt obligations), the current ratings assigned by S&P and Moody’s, respectively, it could significantly limit our access to the commercial paper market. Any such downgrade of our long- or short-term ratings could increase 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 negatively affect 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. The additional increase in capital required to support our Energy Services segment would negatively impact our ability to compete, as well as our ability to actively manage the risk associated with existing storage and transportation contracts.

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

As of December 31, 2008, we had total indebtedness for borrowed money of approximately $3.0 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 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 adversely affect 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 of these agreements also require us to maintain certain financial ratios, which limits the amount of additional indebtedness we can incur. 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.

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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 costs related to providing energy and other commodities through to our customers. 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.

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 and United States Congress, especially in light of previous market power abuse by certain companies engaged in interstate commerce. In response to this issue, 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.

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 marketers for heating during the winter months. Weather conditions directly influence 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. 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, 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 K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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

We have grown rapidly in the last several years as a result of acquisitions. Further acquisitions may require additional external 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

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number of factors could adversely affect 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 significantly constrained, our interest costs will likely increase and our financial condition and future results of operations could be significantly harmed.

Energy efficiency and technological advances may affect the demand for natural gas and adversely affect 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 retail customers. More strict conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could adversely affect 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.

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, cash contributions to our pension plans may be required.

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

As of January 31, 2009, 739 of our 4,742 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.

Global warming is a significant concern for the energy industry. 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.

We believe it is likely 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. 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 compel 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 type of 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 legislation that is adopted.

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Future legislation and/or regulation designed to reduce greenhouse gas emissions could make some of our activities uneconomic to maintain or operate and could affect future results of operations, cash flows or financial condition if such costs are not recovered through regulated rates.

We continue to monitor legislative and regulatory developments in this area. Although we expect the regulation of greenhouse gas emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.

We do not fully hedge against price changes in commodities. 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 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 energy prices. Our Energy Services segment’s primary exposures arise from fixed-price physical purchase or sale agreements that extend for periods of up to five years and natural gas in storage. Our ONEOK Partners segment’s primary exposures arise from commodity prices with respect to processing agreements and the differentials between NGL and natural gas prices with respect to natural gas and NGL transportation, fractionation and exchange agreements, as well as the differential between the individual NGL products and the differentials in natural gas and NGLs in storage utilized in our 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 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 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.

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 47.7 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 are 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 service territory could also have an impact on our revenues. Severe weather impacts our service 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

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mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings.

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change create financial risk. Increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate the emission of greenhouse gases. Numerous states have announced or adopted programs to stabilize and reduce greenhouse gases and federal legislation has been introduced in both houses of the United States Congress. Our pipelines, natural gas processing facilities and natural gas liquids fractionation facilities will potentially be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. We may not be able to pass on the higher costs to our customers or recover all costs related to complying with climate change regulatory requirements, which could have a material adverse effect on our results of operations, cash flows or financial condition.

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 received as payment for its natural gas gathering and processing services, for transportation and storage of natural gas and NGLs, and for the fractionation of NGLs. As a result, ONEOK Partners is sensitive to commodity price fluctuations. Commodity prices have been volatile and are likely to continue to be so in the future. Recent significant and steep declines in commodity prices and compressions in commodity price differentials could have material negative impacts on ONEOK Partners’ financial results. 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 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 transportation 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; and

·	the effect of worldwide energy conservation measures.

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 and related volumes could also decline.

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 has 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 and NGLs exceed the stated price in the hedge instrument for these commodities.

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ONEOK Partners’ inability to execute growth and development projects and acquire new assets could reduce 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 requires the expenditure of significant amounts of capital, which may exceed ONEOK Partners’ estimates, and involves numerous regulatory, environmental, political and legal 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 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, 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, or increased costs to renew such rights, could have a material adverse effect on our financial condition, results of operations and cash flows.

ONEOK Partners’ operations are subject to operational hazards and unforeseen interruptions, which could 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’ infrastructure 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. Additionally, in accordance with typical industry practice, ONEOK Partners does not have any property insurance on any of our underground pipeline systems that would cover damage to such systems.

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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. For example, change in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 and 2008 have made it more difficult for ONEOK Partners to obtain certain types of coverage. Consequently, ONEOK Partners may not be able to renew existing insurance policies or procure 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.

If the level of drilling and production in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions substantially declines 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 in the Mid-Continent, Texas, Rocky Mountain and Gulf Coast regions. Drilling and production are impacted by factors beyond ONEOK Partners’ control, including:

·	demand for natural gas and refinery-grade crude oil;

·	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. If the level of drilling and production in any of these regions substantially declines, ONEOK Partners’ volumes and revenue could be reduced.

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 because ONEOK Partners’ interstate pipelines primarily transport Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern U.S. market area. If demand for natural gas increases in Canada or other markets not served by ONEOK Partners’ interstate pipelines and 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.

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 take remediation, 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 their 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.

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

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

the federal Comprehensive Environmental Response, Compensation and Liability Act 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; and

·	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.

Various 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 Comprehensive Environmental Response, Compensation and Liability Act, 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 and processes, 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 significantly increase 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 K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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 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 adversely affect ONEOK Partners’ products and activities, and federal and state agencies could impose additional safety requirements, all of which could materially affect ONEOK Partners’ profitability.

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

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

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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 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 security 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 adversely affect 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.

A downgrade of ONEOK Partners’ credit rating may require ONEOK Partners to offer to repurchase certain of its senior notes or may impair its ability to access capital.

ONEOK Partners could be required to offer to repurchase certain of its senior notes due 2010 and 2011 at par value, plus any accrued and unpaid interest, if Moody’s or S&P rates those senior notes below investment grade (Baa3 for Moody’s and BBB- for S&P) and the investment-grade rating is not reinstated within a period of 40 days. Further, the indenture governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governing ONEOK Partners’ senior notes due 2012, 2016, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2036 and 2037 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 adversely affect 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

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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 the United States Treasury regulations. An IRS challenge to these conventions could adversely affect 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 10,100 miles and 4,500 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 80 MMcf/d of processing capacity in the Rocky Mountain region;

·	approximately 18 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Mid-Continent and Rocky Mountain regions;

·	approximately 1,320 miles of FERC-regulated interstate natural gas pipelines with approximately 2.5 Bcf/d of peak transportation capacity;

·	approximately 5,560 miles of intrastate natural gas gathering and state-regulated intrastate transmission pipelines with peak transportation capacity of approximately 3.3 Bcf/d;

·	approximately 51.6 Bcf of total active working natural gas storage capacity;

·	approximately 2,011 miles of natural gas liquids gathering pipelines with peak capacity of approximately 247 MBbl/d;

·	approximately 163 miles of natural gas liquids distribution pipelines with peak transportation capacity of approximately 66 MBbl/d;

·	two natural gas liquids fractionators with operating capacity of approximately 260 MBbl/d;

·	150 MBbl/d of fractionation capacity, including leased capacity;

·	80 percent ownership interest in one natural gas liquids fractionator with operating capacity of approximately 160 MBbl/d;

·	interest in one natural gas liquids fractionator with proportional operating capacity of approximately 11 MBbl/d;

·	one 9 MBbl/d isomerization unit;

·	six NGL storage facilities and four other leased facilities in Okalahoma, Kansas and Texas, with approximately 26.4 MMBbl of total operating underground NGL storage capacity;

·	approximately 1,480 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 203 MBbl/d;

·	approximately 3,480 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with peak transportation capacity of 691 MBbl/d;

·	eight NGL product terminals in Missouri, Nebraska, Iowa and Illinois; and

·	above- and below-ground storage facilities in Iowa, Illinois, Nebraska and Kansas with 978 MBbl operating capacity.

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ONEOK Partners’ natural gas pipelines business owns 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 has been idle since 2001 following natural gas explosions and eruptions of natural gas geysers in Hutchinson, Kansas. ONEOK Partners began injecting brine into the idled facility in the first quarter of 2007 in order to ensure its long-term integrity. ONEOK Partners expects to complete the injection process by the end of 2011. Monitoring of the facility and review of the data for the geoengineering study 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 to return the facility 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 businesses for 2008 were as follows:

·	natural gas processing plants were approximately 71 percent;

·	natural gas pipelines were approximately 86 percent subscribed, and storage facilities were fully subscribed;

·	natural gas liquids gathering pipelines were approximately 73 percent;

·	ONEOK Partners’ average contracted storage volume were approximately 74 percent of storage capacity;

·	natural gas liquids fractionators were approximately 87 percent;

·	FERC-regulated natural gas liquids gathering pipelines were approximately 55 percent; and

·	natural gas liquids distribution pipelines were approximately 49 percent.

ONEOK Partners calculated utilization on its assets using a weighted-average approach, adjusting for the in-service dates of assets placed in service during 2008. The utilization rate of ONEOK Partners’ fractionation facilities reflects approximate proportional capacity associated with ownership interests noted above and partial service for the Bushton facilities, which were placed in service during the second half of 2008.

On January 1, 2007, the Bushton Plant was temporarily idled as a result of a decline in natural gas volumes available for natural gas processing at this straddle plant. Volumes declined due to natural field declines and as a result of contract terminations, as advances in technology made it more cost efficient to process natural gas at other facilities. ONEOK Partners has contracted for all of the capacity of the plant from ONEOK.

During 2007 and 2008, ONEOK Partners added new natural gas liquids fractionation facilities at the Bushton location, in conjunction with other changes that were made to the NGL fractionation capabilities of the existing plant. Although the Bushton Plant remains idled, ONEOK Partners currently has 150 MBbl/d of active NGL fractionation capacity as a result of combining the previously existing fractionation equipment with the new fractionation facilities. ONEOK Partners resumed fractionating NGLs at the facilities in the second half of 2008.

Distribution

Property - We own approximately 18,100 miles of pipeline and other distribution facilities in Oklahoma, approximately 12,800 miles of pipeline and other distribution facilities in Kansas, and approximately 9,600 miles of pipeline and other distribution facilities in Texas.

Energy Services

Property - Our total natural gas storage capacity under lease is 91 Bcf, with maximum withdrawal capability of 2.3 Bcf/d and maximum injection capability of 1.5 Bcf/d. Our current natural gas transportation capacity is 1.8 Bcf/d. 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 25 different contracts and two facilities in Canada.

Other

Property - We own the 17-story ONEOK Plaza office building, with approximately 517,000 square feet of net rentable space, and the associated parking garage. In March 2008, ONEOK Leasing Company purchased ONEOK Plaza for the total purchase price of approximately $48 million, which included $17.1 million for the present value of the remaining lease payments and $30.9 million for the base purchase price.

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ITEM 3. LEGAL PROCEEDINGS

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 (“Price I”). Plaintiffs brought suit on May 28, 1999, against us, five of our subsidiaries and one of our divisions, as well as approximately 225 other defendants. Additionally, in connection with the completion of our acquisition of the natural gas liquids businesses owned by several Koch companies, on July 1, 2005, we acquired Koch Hydrocarbon, LP (renamed ONEOK Hydrocarbon, L.P.), which is also one of the defendants in this case. Plaintiffs sought class certification for its claims for monetary damages 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. Oral argument on the plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. The Court has not yet ruled on the class certification issue.

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 (“Price II”). This action was filed by the plaintiffs on May 12, 2003, after the Court had denied class status in Price I. Plaintiffs are seeking monetary damages based upon a claim that 21 groups of defendants, including us and four of our subsidiaries, intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming. Additionally, in connection with the completion of our acquisition of the natural gas liquids businesses owned by several Koch companies, on July 1, 2005, we acquired Koch Hydrocarbon, LP (renamed ONEOK Hydrocarbon, L.P.), which is also one of the defendants in this case. Price II has been consolidated with Price I for the determination of whether either or both cases may properly be certified as class actions. Oral argument on the plaintiffs’ motion to certify this suit as a class action was conducted on April 1, 2005. The Court has not yet ruled on the class certification issue.

Mont Belvieu Emissions, Texas Commission on Environmental Quality - Personnel of ONEOK Hydrocarbon Southwest, L.L.C. (OHSL), a subsidiary of ONEOK Partners, are in discussions with the Texas Commission on Environmental Quality (TCEQ) staff regarding air emissions from a heat exchanger at ONEOK Partners’ Mont Belvieu fractionator, which may have exceeded the emissions allowed under its air permit. OHSL discovered the possibility of excessive air emissions in May 2008. The TCEQ has not issued a notice of enforcement relating to the emissions under this permit. Although no assurances can be given, ONEOK Partners does not believe that any penalties associated with any alleged violations will have a material adverse effect on its financial position, results of operations, or net cash flows.

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: Samuel P. Leggett, et al. v. Duke Energy Corporation, et al. (filed in the Chancery Court for the Twenty-Fifth Judicial District at Somerville, Tennessee, in January 2005); 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); J.P. Morgan Trust Company v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte County, Kansas, in October 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); Learjet, Inc., et al. v. ONEOK, Inc., et al. (filed in the District Court of Wyandotte, Kansas, in November 2005, transferred to MDL-1566 in the United States District Court for the District of Nevada); 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); Missouri Public Service Commission v. ONEOK, Inc., et al. (filed in the Sixth Judicial Circuit Court of Jackson County, Missouri, in October 2006); 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, transferred to MDL-1566 in the United States District Court for the District of Nevada). 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 during the years from 2000 to 2002. All of the complaints arise out of the U.S. Commodity Futures Trading Commission investigation into and reports concerning false gas price index-reporting or manipulation in the energy marketing industry. Other than as noted below, each of the cases are in pretrial discovery.

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Motions to dismiss were granted in the Leggett, Sinclair, and Missouri Public Service Commission cases. The dismissal of the Sinclair case was appealed to the United States Court of Appeals for the Ninth Circuit, but is in the process of being remanded back to the multi-district litigation matter MDL-1566 in the United States District Court for the District of Nevada for further proceedings. The dismissal of the Leggett case was reversed by the Tennessee Court of Appeals on October 29, 2008, but the defendants, including us and OESC, have filed an application with the Tennessee Supreme Court to appeal the decision. 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. We continue to analyze all of these 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 2008.

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, 2008				December 31, 2007
	High		Low		High		Low
First Quarter	$	49.21	$	43.93	$	46.13	$	40.12
Second Quarter	$	50.63	$	45.62	$	54.58	$	44.57
Third Quarter	$	49.59	$	33.41	$	54.86	$	43.65
Fourth Quarter	$	34.35	$	23.17	$	52.05	$	44.29

At February 18, 2009, there were 13,804 holders of record of our 105,239,496 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,
			2008		2007
First Quarter		$	0.38	$	0.34
Second Quarter		$	0.38	$	0.34
Third Quarter		$	0.40	$	0.36
Fourth Quarter		$	0.40	$	0.36	(a)
(a) - Declared in the previous quarter.

In January 2009, we declared a dividend of $0.40 per share ($1.60 per share on an annualized basis) for the fourth quarter of 2008, which was paid on February 13, 2009, to shareholders of record as of January 30, 2009.

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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, 2008		-			-		-		-
November 1-30, 2008		-			-		-		-
December 1-31, 2008		10	(1)		$27.38		-		-
Total		10			$27.38		-		-

(1) - Represents shares repurchased directly from employees, pursuant to our Employee Stock Award Program.

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, and 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.

Through December 31, 2008, a total of 144,352 shares have been issued to employees under this program. The shares issued under this program have not been registered under the Securities Act of 1933, as amended (1933 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 1933 Act. See Note N of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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PERFORMANCE GRAPH

The following performance graph compares the performance of our common stock with the S&P 500 Index and the S&P Utilities Index during the period beginning on December 31, 2003, and ending on December 31, 2008. The graph assumes a $100 investment in our common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.

Value of $100 Investment Assuming Reinvestment of Dividends

At December 31, 2003, and at the End of Every Year Through December 31, 2008

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

	Cumulative Total Return
	Years Ending December 31,
	2003		2004		2005		2006		2007		2008

ONEOK, Inc.	$	100.00	$	133.74	$	130.01	$	218.10	$	233.19	$	157.65
S&P 500 Index	$	100.00	$	110.88	$	116.32	$	134.69	$	142.09	$	89.52
S&P Utilities Index (a)	$	100.00	$	124.28	$	145.21	$	175.69	$	209.73	$	148.95
(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.; Dynegy, Inc.; Edison
International; Entergy Corp.; Equitable Resources, Inc.; Exelon Corp.; FirstEnergy Corp.; FPL Group, Inc.; Integrys Energy
Group, Inc.; Nicor, Inc.; NiSource, Inc.; Pepco Holdings, Inc.; PG&E Corp.; Pinnacle West Capital Corp.; PPL Corp.; Progress
Energy, Inc.; Public Service Enterprise Group, Inc.; Questar Corp.; SCANA Corp.; Sempra Energy; Southern Co.; TECO
Energy, Inc.; Wisconsin Energy Corp.; and Xcel Energy, Inc.

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ITEM 6. SELECTED FINANCIAL DATA

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

	Years Ended December 31,
	2008		2007		2006		2005		2004
	(Millions of dollars, except per share amounts)
Revenues	$	16,157.4	$	13,477.4	$	11,920.3	$	12,676.2	$	5,785.5
Income from continuing operations	$	311.9	$	304.9	$	306.7	$	403.1	$	224.7
Net income	$	311.9	$	304.9	$	306.3	$	546.5	$	242.2
Total assets	$	13,126.1	$	11,062.0	$	10,391.1	$	9,284.2	$	7,199.2
Long-term debt, including current maturities	$	4,230.8	$	4,635.5	$	4,049.0	$	2,030.6	$	1,884.7
Basic earnings per share - continuing operations	$	2.99	$	2.84	$	2.74	$	4.01	$	2.21
Basic earnings per share - total	$	2.99	$	2.84	$	2.74	$	5.44	$	2.38
Diluted earnings per share - continuing operations	$	2.95	$	2.79	$	2.68	$	3.73	$	2.13
Diluted earnings per share - total	$	2.95	$	2.79	$	2.68	$	5.06	$	2.30
Dividends declared per common share	$	1.56	$	1.40	$	1.22	$	1.09	$	0.88

Financial data for 2008, 2007 and 2006 is not directly comparable with 2005 and 2004 due to the significance of the sale of certain assets to ONEOK Partners in April 2006. See discussion of acquisitions and dispositions beginning on page 36 under “Significant Acquisitions and Divestitures” in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.

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 on Form 10-K.

EXECUTIVE SUMMARY

The following discussion highlights some of our achievements this past year. Please refer to the “Financial Results and Operating Information,” “Liquidity and Capital Resources,” and “Capital Projects” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operation and our consolidated financial statements for additional information.

Operating Results - Diluted earnings per share of common stock from continuing operations (EPS) increased to $2.95 in 2008, compared with $2.79 in 2007. Operating income for 2008 increased to $917.0 million from $822.5 million for 2007. This increase is primarily due to wider NGL product price differentials, higher realized commodity prices, increased NGL gathering and fractionation volumes, and incremental operating income associated with the assets acquired from Kinder Morgan Energy Partners, L.P. (Kinder Morgan), all in our ONEOK Partners segment. This increase in operating income was partially offset by decreases in storage and marketing margins and transportation margins, net of hedging activities, in our Energy Services segment.

ONEOK Partners’ Equity Issuance - In March 2008, we purchased from ONEOK Partners, in a private placement, an additional 5.4 million of ONEOK Partners’ common units for a total purchase price of approximately $303.2 million. In addition, ONEOK Partners completed a public offering of 2.5 million common units at $58.10 per common unit and received net proceeds of $140.4 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ private placement and public offering of common units, ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent general partner interest.

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ONEOK Partners used a portion of the proceeds from the sale of common units and the general partner contributions to repay borrowings under its $1.0 billion revolving credit agreement dated March 30, 2007, as amended July 31, 2007 (the ONEOK Partners Credit Agreement).

Dividends/Distributions - During 2008, we paid dividends totaling $1.56 per share, an increase of approximately 11 percent over the $1.40 per share paid during 2007. We declared a quarterly dividend of $0.40 per share ($1.60 per share on an annualized basis) in January 2009, an increase of approximately 5 percent over the $0.38 declared in January 2008. During 2008, ONEOK Partners paid cash distributions totaling $4.205 per unit, an increase of approximately 6 percent over the $3.98 per unit paid during 2007. ONEOK Partners declared a cash distribution of $1.08 per unit ($4.32 per unit on an annualized basis) in January 2009, an increase of approximately 5 percent over the $1.025 declared in January 2008.

Capital Projects - ONEOK Partners placed the following projects in-service during 2008:

·	January - Midwestern Gas Transmission’s eastern extension pipeline;

·	July - final phase of Fort Union Gas Gathering expansion project;

·	September - Woodford Shale natural gas liquids pipeline extension;

·	October - Bushton Fractionation expansion;

·	November - Overland Pass Pipeline from Opal, Wyoming to Conway, Kansas; and

·	December - partial operations of the Guardian pipeline extension with interruptible service from Ixonia, Wisconsin, to Green Bay, Wisconsin.

Key Performance Indicators - Key performance indicators reviewed by management include:

·	earnings per share;

·	return on invested capital; and

·	shareholder appreciation.

For 2008, our basic and diluted earnings per share from continuing operations were $2.99 and $2.95, respectively, representing a 5 percent increase in basic earnings per share and a 6 percent increase in diluted earnings per share from continuing operations compared with 2007. For 2007, our basic and diluted earnings per share from continuing operations were $2.84 and $2.79, respectively, representing a 4 percent increase in basic earnings per share and a 4 percent increase in diluted earnings per share from continuing operations compared with 2006. Return on invested capital was 13 percent in 2008 and 14 percent in 2007 and 2006, respectively.

To evaluate shareholder appreciation, we compare the total return over a three-year period of an investment in our stock with the total return of an investment in the stock of a group of peer companies. For the three-year period ended December 31, 2008, we ranked fifth in this shareholder appreciation calculation when compared with 18 of our peers.

Outlook for 2009 - We expect continued deteriorating economic conditions in 2009, with significant downward pressures, relative to 2008, on commodity prices for natural gas, NGLs and crude oil. We anticipate that lower commodity prices will result in reduced drilling activity, and economic conditions will reduce petrochemical demand. We also expect continued volatility and disruption in the financial markets which could result in an increased cost of capital. We expect depressed commodity prices and tighter capital markets to also result in the sale or consolidation of underperforming assets in the industry, which may present opportunities for us.

SIGNIFICANT ACQUISITIONS AND DIVESTITURES

Acquisition of NGL Pipeline - In October 2007, ONEOK Partners completed the acquisition of an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments. The system extends from Bushton and Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full range of NGL products and refined petroleum products. The FERC-regulated system spans 1,624 miles and has a capacity to transport up to 134 MBbl/d. The transaction also included approximately 978 MBbl of owned storage capacity, eight NGL terminals and a 50 percent ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of a refined petroleum products terminal and pipelines with access to two other refined petroleum products terminals. ONEOK Partners’ investment in Heartland is accounted for under the equity method of accounting. Financing for this transaction came from a portion of the proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note I of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for a discussion of the 2037 Notes. The working capital settlement was finalized in April 2008, with no material adjustments.

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Overland Pass Pipeline Company - See “Capital Projects” for discussion of Overland Pass Pipeline Company.

ONEOK Partners - In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our ownership of the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we owned a total of approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control of the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, was 45.7 percent at the date of acquisition.

The sale of certain assets comprising our former gathering and processing, pipelines and storage, and natural gas liquids segments did not affect our consolidated operating income on our Consolidated Statements of Income or total assets on our Consolidated Balance Sheets, as we were already required under EITF 04-5 to consolidate our investment in ONEOK Partners effective January 1, 2006. However, minority interest expense and net income were affected. See Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K beginning on page 76 for additional discussion of our consolidation of ONEOK Partners.

Disposition of 20 percent interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted for as an investment under the equity method applied on a retroactive basis to January 1, 2006.

Acquisition of Guardian Pipeline Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million, increasing its ownership interest to 100 percent. ONEOK Partners used borrowings from its credit facility to fund the acquisition of the additional interest in Guardian Pipeline. Following the completion of the transaction, we consolidated Guardian Pipeline in our consolidated financial statements. This change was accounted for on a retroactive basis to January 1, 2006.

CAPITAL PROJECTS

All of the capital projects discussed below are in our ONEOK Partners segment.

Woodford Shale Natural Gas Liquids Pipeline Extension - The 78-mile natural gas liquids gathering pipeline connecting two natural gas processing plants, operated by Devon Energy Corporation and Antero Resources Corporation, was placed into service in September 2008. The cost of the project was approximately $36 million, excluding AFUDC. These two plants have the capacity to produce approximately 25 MBbl/d of unfractionated NGLs. The natural gas liquids production is gathered by ONEOK Partners’ existing Mid-Continent natural gas liquids gathering pipelines. Upon completion of the Arbuckle Pipeline project, the Woodford Shale natural gas liquids production is expected to be transported through the Arbuckle Pipeline to ONEOK Partners’ Mont Belvieu, Texas, fractionation facility.

Overland Pass Pipeline Company - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company. In November 2008, Overland Pass Pipeline Company completed construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The Overland Pass Pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs and can be increased to approximately 255 MBbl/d with additional pump facilities. During 2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, managed the construction project, advanced all costs associated with construction and is currently operating the pipeline. On or before November 17, 2010, Williams will have the option to increase its ownership up to 50 percent, with the purchase price determined in accordance with the joint venture’s operating agreement. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. The pipeline project cost was approximately $575 million, excluding AFUDC.

As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming, estimated to be approximately 60 MBbl/d, to the Overland Pass Pipeline. Subsidiaries of ONEOK Partners will

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provide downstream fractionation, storage and transportation services to Williams. ONEOK Partners has also reached agreements with certain producers for supply commitments of up to an additional 80 MBbl/d and is negotiating agreements with other producers for supply commitments that could add an additional 60 MBbl/d of supply to this pipeline within the next three to five years.

ONEOK Partners also invested approximately $239 million, excluding AFUDC, to expand its existing fractionation and storage capabilities and to increase the capacity of its natural gas liquids distribution pipelines. Part of this expansion included adding new fractionation facilities at ONEOK Partners’ Bushton location, increasing total fractionation capacity at Bushton to 150 MBbl/d. The addition of the new facilities and the upgrade to the existing fractionator was completed in October 2008. Additionally, portions of the natural gas liquids distribution pipeline upgrades were completed in the second and third quarters of 2008.

Piceance Lateral Pipeline - In March 2007, ONEOK Partners announced that Overland Pass Pipeline Company also plans to construct a 150-mile lateral pipeline with capacity to transport as much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to the Overland Pass Pipeline. Williams announced that it intends to construct a new natural gas processing plant in the Piceance Basin and will dedicate its NGL production from that plant and an existing plant, with estimated volumes totaling approximately 30 MBbl/d, to be transported by the lateral pipeline. ONEOK Partners continues to negotiate with other producers for supply commitments. In October 2008, this project received approval of various state and federal regulatory authorities allowing construction to commence. Construction began during the fourth quarter of 2008 and is expected be completed during the third quarter of 2009. The project is currently estimated to cost in the range of $110 million to $140 million, excluding AFUDC.

D-J Basin Lateral Pipeline - In September 2008, ONEOK Partners announced plans to construct a 125-mile natural gas liquids lateral pipeline from the Denver-Julesburg Basin in northeastern Colorado to the Overland Pass Pipeline, with capacity to transport as much as 55 MBbl/d of unfractionated NGLs. The project is currently estimated to cost in the range of $70 million to $80 million, excluding AFUDC. ONEOK Partners has supply commitments for up to 33 MBbl/d of unfractionated NGLs with potential for an additional 10 MBbl/d of supply from new drilling and plant upgrades in the next two years. The pipeline is currently under construction and is expected to be fully completed during the first quarter of 2009.

Arbuckle Pipeline Natural Gas Liquids Pipeline - In March 2007, ONEOK Partners announced plans to build the 440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern Oklahoma through northern Texas and continuing on to the Texas Gulf Coast. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated NGLs, expandable to 210 MBbl/d with additional pump facilities, and will connect with ONEOK Partners’ existing Mid-Continent infrastructure with its fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. ONEOK Partners has supply commitments from producers that it expects will be sufficient to fill the 210 MBbl/d capacity level over the next three to five years. Construction on the pipeline has been underway since the third quarter of 2008. Much of the Oklahoma and north Texas portions are either complete or nearing completion. However, right-of-way acquisition has been challenging, time consuming and expensive, which could affect the completion schedule and final cost of the project. Many of Arbuckle Pipeline’s remaining right-of-way tracts are being acquired through a condemnation process, which adds to the cost and time to construct the pipeline. The demand for surface easements has increased dramatically in Texas and Oklahoma in the last 12 to 18 months because of increased oil and natural gas exploration and production activities, as well as pipeline construction. Because of the delays associated with right-of-way acquisition, we anticipate construction on the south end of the project will be more difficult and expensive due to wet low-lying areas and potential for spring rains. Accordingly, we expect the project to be operational in the second quarter of 2009. Based on the increased costs and delays associated with right-of-way acquisition and potential weather impacts, our project costs could increase 10 percent to 15 percent above the range of $340 million to $360 million, excluding AFUDC, as previously reported.

Williston Basin Gas Processing Plant Expansion - In March 2007, ONEOK Partners announced the expansion of its Grasslands natural gas processing facility in North Dakota, currently estimated to cost in the range of $40 million to $45 million, excluding AFUDC. ONEOK Partners’ estimated project costs increased from $30 million primarily as a result of higher contract labor and equipment costs. The Grasslands facility is ONEOK Partners’ largest natural gas processing plant in the Williston Basin. The expansion increases processing capacity to approximately 100 MMcf/d from its current capacity of 63 MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8 MBbl/d. The construction of the expansion project is expected to be complete in the first quarter of 2009.

Fort Union Gas Gathering Expansion - In January 2007, Fort Union Gas Gathering announced plans to double its existing gathering pipeline capacity by adding 148 miles of new gathering lines, resulting in approximately 649 MMcf/d of additional capacity in the Powder River basin of Wyoming. The expansion occurred in two phases and cost approximately $121 million, excluding AFUDC, which was financed within the Fort Union Gas Gathering partnership. Any cost overruns are covered through escalation clauses to preserve the original economics of the project. Phase I, with more than 200 MMcf/d

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capacity, was placed in service during the fourth quarter of 2007. Phase II, with approximately 450 MMcf/d capacity, was completed in July 2008. The additional capacity has been fully subscribed for 10 years. ONEOK Partners owns approximately 37 percent of Fort Union Gas Gathering, and accounts for its ownership under the equity method of accounting.

Guardian Pipeline Expansion and Extension - In December 2007, Guardian Pipeline received and accepted the certificate of public convenience and necessity issued by the FERC for its expansion and extension project. The certificate authorizes ONEOK Partners to construct, install and operate approximately 119 miles of a 20-inch and 30-inch natural gas transportation pipeline with a capacity to transport 537 MMcf/d of natural gas north from Ixonia, Wisconsin to the Green Bay, Wisconsin, area. The project is supported by 15-year shipper commitments with We Energies and Wisconsin Public Service Corporation and the capacity has been fully subscribed. The project is currently estimated to cost in the range of $277 million and $305 million, excluding AFUDC. ONEOK Partners’ estimated project costs increased from the initial estimate of $241 million in 2006, which excluded AFUDC, primarily due to weather delays, equipment delivery delays, construction in environmentally sensitive areas, rocky terrain, and escalating costs associated with crop damage and condemnation costs. ONEOK Partners received the notice to proceed from the FERC in May 2008. On December 22, 2008, the FERC issued a letter order granting Guardian Pipeline’s request for an extension of time for a phased in-service. On December 29, 2008, the FERC issued a letter order granting Guardian Pipeline’s request to commence service. On December 31, 2008, the pipeline and seven meter stations were placed into service with the ability to transport natural gas on a limited basis. Construction on one compressor station is complete, and construction on a second compressor station is near completion. The project is expected to be fully in service in the first quarter of 2009.

REGULATORY

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

IMPACT OF NEW ACCOUNTING STANDARDS

Information about the impact of the following new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K:

·	Statement 123R, “Share-Based Payment;”

·	Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans;”

·	FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109;”

·	Statement 157, “Fair Value Measurements,” and related FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement no. 157,” and FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active;”

·	Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities;”

·	FSP FIN 39-1, “Amendment of FASB Interpretation No. 39;”

·	Statement 141R, “Business Combinations;”

·	Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51;”

·	Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133;”

·	EITF 08-6, “Equity Method Investment Accounting Considerations;” and

·	Statement 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets.”

CRITICAL ACCOUNTING 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. 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 estimates, which are defined as those estimates 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 critical accounting policies and estimates with the Audit Committee of our Board of Directors.

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Fair Value Measurements - General - In September 2006, the FASB issued Statement 157 that establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Beginning January 1, 2008, we partially applied Statement 157 as allowed by FSP 157-2 that delayed the effective date of Statement 157 for nonrecurring fair value measurements associated with our nonfinancial assets and liabilities. As of January 1, 2008, we applied the provisions of Statement 157 to our recurring fair value measurements, and the impact was not material upon adoption. As of January 1, 2009, we have applied the provisions of Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities, and the impact was not material. FSP 157-3, which clarified the application of Statement 157 in inactive markets, was issued in October 2008 and was effective for our September 30, 2008, consolidated financial statements. FSP 157-3 did not have a material impact on our consolidated financial statements.

In February 2007, the FASB issued Statement 159 that allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. At January 1, 2008, we did not elect the fair value option under Statement 159, and therefore there was no impact on our consolidated financial statements.

Determining Fair Value - Statement 157 defines 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 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 over a reasonable period of time under current market conditions. Finally, we consider credit risk of our counterparties on the fair value of our derivative assets, as well as our own credit risk for derivative liabilities, using default probabilities and recovery rates, net of collateral. We also take into consideration current market data in our evaluation when available, such as bond prices and yields and credit default swaps. 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 - Statement 157 establishes the fair value hierarchy that prioritizes inputs to valuation techniques based on observable and unobservable data and categorizes the inputs into three levels, with the highest priority given to Level 1 and the lowest priority given to Level 3. The levels 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 - Generally unobservable inputs, which 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 judgment of the significance of the price change of that particular input to the total fair value of the derivative.

See Note C of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more discussion of fair value measurements.

Derivatives, Accounting for Financially Settled Transactions and Risk Management Activities - We engage in wholesale energy marketing, retail marketing, trading and risk management activities. We account for derivative instruments utilized in connection with these activities and services in accordance with Statement 133, as amended.

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Under Statement 133, entities are required to record derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. See previous discussion in “Fair Value Measurements” for additional information. 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 we will determine if the hedging instrument is effective. 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. For more information on fair value sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

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 of 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. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.

Upon election, many of our purchase and sale agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and normal sales under Statement 133 and are therefore exempt from fair value accounting treatment.

The presentation of settled derivative instruments on either a gross or net basis in our Consolidated Statements of Income is dependent on a number of factors, including whether the derivative instrument (i) is held for trading purposes; (ii) is financially settled; (iii) results in physical delivery or services rendered; and (iv) qualifies for the normal purchase or sale exception as defined in Statement 133. In accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,” EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and Statement 133, we report settled derivative instruments as follows:

·	all financially settled derivative contracts are reported on a net basis;

·	derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis;

·	derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis; and

·	derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.

We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery.

See Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of derivatives and risk management activities.

Impairment of Long-Lived Assets, Goodwill and Intangible Assets - We assess our long-lived assets for impairment based on Statement 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” A long-lived asset is tested for impairment whenever events or changes in circumstances indicate that its carrying amount may exceed its fair value. Fair values are based on the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the assets.

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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.

We use two generally accepted valuation approaches, an income approach and a market approach, to estimate the fair value of a reporting unit. Under the income approach, we use anticipated cash flows over a three-year period plus a terminal value and discount these amounts to their present value using appropriate rates of return. Under the market approach, we apply multiples to forecasted EBITDA amounts. The multiples used are consistent with historical asset transactions, and the EBITDA amounts are based on average EBITDA for a reporting unit over a three-year forecasted period. At December 31, 2008 we had $602.8 million of goodwill recorded on our Consolidated Balance Sheet as shown below.


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

Intangible assets with a finite useful life are amortized over their estimated useful life, while intangible assets with an indefinite useful life are not amortized. All intangible assets are subject to impairment testing. We had $435.4 million of intangible assets recorded on our Consolidated Balance Sheet as of December 31, 2008, of which $279.8 million in our ONEOK Partners segment is being amortized over an aggregate weighted-average period of 40 years, while the remaining balance has an indefinite life.

Our impairment tests require the use of assumptions and estimates. 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 an impairment charge.

During 2006, we recorded a goodwill and asset impairment related to ONEOK Partners’ Black Mesa Pipeline of $8.4 million and $3.6 million, respectively, which was recorded as depreciation and amortization. The reduction to our net income, net of minority interests and income taxes, was $3.0 million.

For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill and under Statement 142, is not subject to amortization but rather to impairment testing pursuant to APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The impairment test under APB Opinion No. 18 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 the excess of cost over fair value of net assets accounted for under the equity method to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with APB Opinion No. 18.

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 result in material changes in the costs and liabilities we recognize. See Note J of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K 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	$	1,989	$	(1,706	)
Effect on postretirement benefit obligation	$	19,585	$	(17,171	)

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During 2008, we recorded net periodic benefit costs of $19.8 million related to our defined benefit pension plans and $28.3 million related to postretirement benefits. We estimate that in 2009, we will record net periodic benefit costs of $26.6 million related to our defined benefit pension plans and $26.1 million related to postretirement benefits. In determining our estimated expenses for 2009, our actuarial consultant assumed an 8.50 percent expected return on plan assets and a discount rate of 6.25 percent. A decrease in our expected return on plan assets to 8.25 percent would increase our 2009 estimated net periodic benefit costs by approximately $1.9 million for our defined benefit pension plans and would not have a significant impact on our postretirement benefit plan. A decrease in our assumed discount rate to 6.00 percent would increase our 2009 estimated net periodic benefit costs by approximately $2.4 million for our defined benefit pension plans and $0.6 million for our postretirement benefit plan. For 2009, we anticipate our total contributions to our defined benefit pension plans and postretirement benefit plan to be $31.2 million and $11.4 million, respectively, and the expected benefit payments for our postretirement benefit plan are estimated to be $16.2 million.

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 in accordance with Statement 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion of contingencies.

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,									2008 vs. 2007					2007 vs. 2006
Financial Results	2008			2007			2006			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	16,157.4		$	13,477.4		$	11,920.3		$	2,680.0		20	%	$	1,557.1		13	%
Cost of sales and fuel		14,221.9			11,667.3			10,198.3			2,554.6		22	%		1,469.0		14	%
Net margin		1,935.5			1,810.1			1,722.0			125.4		7	%		88.1		5	%
Operating costs		776.9			761.5			740.8			15.4		2	%		20.7		3	%
Depreciation and amortization		243.9			228.0			235.5			15.9		7	%		(7.5	)	(3	%)
Gain (loss) on sale of assets		2.3			1.9			116.5			0.4		21	%		(114.6	)	(98	%)
Operating income	$	917.0		$	822.5		$	862.2		$	94.5		11	%	$	(39.7	)	(5	%)
Equity earnings from investments	$	101.4		$	89.9		$	95.9		$	11.5		13	%	$	(6.0	)	(6	%)
Allowance for equity funds used during construction	$	50.9		$	12.5		$	2.2		$	38.4		*		$	10.3		*
Other income (expense)	$	(10.6	)	$	14.1		$	1.9		$	(24.7	)	*		$	12.2		*
Interest expense	$	(264.2	)	$	(256.3	)	$	(239.7	)	$	7.9		3	%	$	16.6		7	%
Minority interests in income of consolidated subsidiaries	$	(288.6	)	$	(193.2	)	$	(222.0	)	$	95.4		49	%	$	(28.8	)	(13	%)
Capital expenditures	$	1,473.1		$	883.7		$	376.3		$	589.4		67	%	$	507.4		*

* Percentage change is greater than 100 percent.

2008 vs. 2007 - Net margin increased primarily due to wider NGL product price differentials, higher realized commodity prices, incremental net margin associated with the assets acquired from Kinder Morgan, and increased NGL gathering and fractionation volumes, all in our ONEOK Partners segment. Additionally, net margin increased due to implementation of new rate mechanisms in our Distribution segment. These increases were partially offset by decreases in storage and marketing margins and transportation margins, net of hedging activities, in our Energy Services segment.

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Operating costs increased primarily due to incremental operating expenses associated with the assets acquired from Kinder Morgan, outside services primarily associated with scheduled maintenance expenses at ONEOK Partners’ Medford and Mont Belvieu fractionators, and chemical costs. Operating costs also increased due to costs associated with the startup of the newly expanded Bushton fractionator and Overland Pass Pipeline, both in our ONEOK Partners segment.

Depreciation and amortization increased primarily due to the assets acquired from Kinder Morgan and depreciation expense associated with ONEOK Partners’ completed capital projects. Additionally, our Distribution segment had an increase in depreciation and amortization, primarily due to additional investment in property, plant and equipment.

Equity earnings from investments increased primarily due to ONEOK Partners’ share of the gain on the sale of Bison Pipeline LLC by Northern Border Pipeline and ONEOK Partners’ earnings related to higher gathering revenues in its natural gas gathering and processing business’ various investments, partially offset by reduced throughput on Northern Border Pipeline. ONEOK Partners owns a 50 percent equity interest in Northern Border Pipeline.

Allowance for equity funds used during construction and capital expenditures increased due to ONEOK Partners’ capital projects.

Other income (expense) fluctuated primarily due to investment gains (losses) and fluctuations in interest income. In addition, other income (expense) was impacted by realized and unrealized gains on available-for-sale securities sold and transferred to trading. Our available-for-sale securities were reclassified to trading securities due to a reconsideration event in August 2008 when our NYMEX Holding, Inc. Class A shares held were converted to CME Group, Inc. (CME) Class A shares, due to the NYMEX Holding, Inc. and CME merger. A modification was made to the number of shares required to be maintained by NYMEX Holding, Inc. Class A Members, which resulted in our sale of certain shares and the reclassification of the remaining shares to trading.

Interest expense increased primarily due to increased borrowings to fund ONEOK Partners’ capital projects.

Minority interest in income of consolidated subsidiaries for 2008 and 2007 reflects the remaining 52.3 percent and 54.3 percent, respectively, of ONEOK Partners that we did not own. The increase in minority interest is due to the increase in income for our ONEOK Partners segment, partially offset by our increased equity ownership interest in ONEOK Partners.

2007 vs. 2006 - Net margin increased primarily due to the implementation of new rate schedules in Kansas and Texas in our Distribution segment. Net margin was also positively impacted by our ONEOK Partners segment due to its natural gas liquids businesses, which benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold. Net margin also increased due to ONEOK Partners’ natural gas liquids gathering and fractionation business benefiting from higher product price differentials and higher isomerization price differentials, as well as the incremental net margin related to the assets acquired from Kinder Morgan in October 2007. These increases were offset by decreased transportation margins in our Energy Services segment and decreased net margin in ONEOK Partners’ natural gas gathering and processing business, primarily due to lower natural gas volumes processed as a result of contract terminations in late 2006.

Gain on sale of assets decreased primarily due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our ONEOK Partners segment.

Equity earnings from investments decreased primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006.

Allowance for equity funds used during construction and capital expenditures increased due to ONEOK Partners’ capital projects.

Other income (expense) fluctuated primarily due to increased civic donations and expenses incurred by ONEOK Partners in 2006 related to costs associated with transitioning operations from Omaha, Nebraska.

Interest expense increased primarily due to the additional borrowings by ONEOK Partners to complete the April 2006 transactions with us. The additional borrowings resulted in $21.3 million in higher interest expense in the first quarter of 2007. Increased interest expense was partially offset by lower interest expense on ONEOK’s short-term debt of $11.8 million during 2007, as a result of the proceeds from the sale of assets to ONEOK Partners, which reduced ONEOK’s short-term debt.

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Minority interest in income of consolidated subsidiaries for 2007 and 2006 reflects the remaining 54.3 percent of ONEOK Partners that we did not own. For 2007, minority interest was lower due to the $113.9 million gain on sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006 in our ONEOK Partners segment. Additionally, minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline after March 31, 2006.

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 - The following tables set forth certain selected financial results and operating information for our ONEOK Partners segment for the periods indicated.

											Variances					Variances
	Years Ended December 31,										2008 vs. 2007					2007 vs. 2006
Financial Results		2008			2007			2006			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues		$	7,720.2		$	5,831.6		$	4,738.2		$	1,888.6		32	%	$	1,093.4		23	%
Cost of sales and fuel			6,579.5			4,935.7			3,894.7			1,643.8		33	%		1,041.0		27	%
Net margin			1,140.7			895.9			843.5			244.8		27	%		52.4		6	%
Operating costs			371.8			337.4			325.8			34.4		10	%		11.6		4	%
Depreciation and amortization			124.8			113.7			122.0			11.1		10	%		(8.3	)	(7	%)
Gain on sale of assets			0.7			2.0			115.5			(1.3	)	(65	%)		(113.5	)	(98	%)
Operating income		$	644.8		$	446.8		$	511.2		$	198.0		44	%	$	(64.4	)	(13	%)
Equity earnings from investments		$	101.4		$	89.9		$	95.9		$	11.5		13	%	$	(6.0	)	(6	%)
Allowance for equity funds used during construction		$	50.9		$	12.5		$	2.2		$	38.4		*		$	10.3		*
Minority interests in income of consolidated subsidiaries		$	(0.4	)	$	(0.4	)	$	(2.4	)	$	-		0	%	$	2.0		83	%
Capital expenditures		$	1,253.9		$	709.9		$	201.7		$	544.0		77	%	$	508.2		*

* Percentage change is greater than 100 percent.

	Years Ended December 31,
Operating Information	2008		2007		2006
Natural gas gathered (BBtu/d) (a)		1,164		1,171		1,168
Natural gas processed (BBtu/d) (a)		641		621		988
Natural gas transported (MMcf/d)		3,665		3,579		3,634
Residue gas sales (BBtu/d) (a)		279		281		302
NGLs gathered (MBbl/d)		276		248		226
NGL sales (MBbl/d)		283		231		207
NGLs fractionated (MBbl/d)		373		356		313
NGLs transported (MBbl/d)		333		299		200
Conway-to-Mont Belvieu OPIS average price differential
Ethane ($/gallon)	$	0.15	$	0.06	$	0.05
Realized composite NGL sales prices ($/gallon) (a)	$	1.27	$	1.06	$	0.93
Realized condensate sales price ($/Bbl) (a)	$	89.30	$	67.35	$	57.84
Realized residue gas sales price ($/MMBtu) (a)	$	7.34	$	6.21	$	6.31
Realized gross processing spread ($/MMBtu) (a)	$	7.47	$	5.21	$	5.05
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business.

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2008 vs. 2007 - Net margin increased primarily due to the following:

·	an increase in ONEOK Partners’ natural gas liquids gathering and fractionation business due to the following:

o	an increase of $70.8 million in wider NGL product price differentials;

o	an increase of $32.1 million due to increased NGL gathering and fractionation volumes; and

o	an increase of $8.4 million in certain operational measurement gains, primarily at NGL storage caverns;

·	an increase in ONEOK Partners’ natural gas gathering and processing business due to the following:

o	an increase of $58.4 million due to higher realized commodity prices;

o	an increase of $11.9 million due to improved contractual terms;

o	an increase of $7.0 million due to higher volumes sold and processed; partially offset by

o	a decrease of $8.6 million due to a one-time favorable contract settlement that occurred in the fourth quarter of 2007;

an increase of $44.3 million in incremental margin in ONEOK Partners’ natural gas liquids pipelines business, due to the assets acquired from Kinder Morgan in October 2007, including $10.3 million due to increased throughput during the fourth quarter of 2008, compared with the fourth quarter of 2007;

·	an increase of $11.7 million due to increased transportation and storage margins primarily as a result of the impact of higher natural gas prices on retained fuel, and new and renegotiated storage contracts in ONEOK Partners’ natural gas pipelines business; and

·	an increase of $6.9 million primarily due to increased throughput from new NGL supply connections, including $2.6 million from Overland Pass Pipeline, which began operations during the fourth quarter 2008.

Operating costs increased primarily due to incremental operating expenses associated with the assets acquired from Kinder Morgan, outside service costs primarily associated with scheduled maintenance expenses at ONEOK Partners’ Medford and Mont Belvieu fractionators, and chemical costs. Operating costs also increased due to costs associated with the startup of ONEOK Partners’ newly expanded Bushton fractionator and Overland Pass Pipeline.

Depreciation and amortization increased primarily due to depreciation expense associated with ONEOK Partners’ completed capital projects and the assets acquired from Kinder Morgan.

Equity earnings from investments increased primarily due to higher gathering revenues in ONEOK Partners’ various investments, as well as a $8.3 million gain on the sale of Bison Pipeline LLC by Northern Border Pipeline, partially offset by reduced throughput on Northern Border Pipeline. ONEOK Partners owns a 50 percent equity interest in Northern Border Pipeline.

Allowance for equity funds used during construction and capital expenditures increased due to ONEOK Partners’ capital projects.

2007 vs. 2006 - Net margin increased primarily due to the following:

·	an increase of $27.3 million from increased performance of ONEOK Partners’ natural gas liquids businesses, which benefited primarily from new supply connections that increased volumes gathered, transported, fractionated and sold;

·	an increase of $20.6 million from new and renegotiated contractual terms and increased volumes in ONEOK Partners’ natural gas and natural gas liquids businesses;

·	an increase of $13.5 million in higher NGL product price differentials and higher isomerization price differentials in ONEOK Partners’ natural gas liquids gathering and fractionation business;

·	an increase of $11.5 million in incremental net margin in ONEOK Partners’ natural gas liquids pipeline business, due to the assets acquired from Kinder Morgan in October 2007; and

·	an increase of $5.4 million in storage margins in ONEOK Partners’ natural gas pipelines business; partially offset by

·	a decrease of $32.9 million in natural gas processing and transportation margins in ONEOK Partners’ natural gas businesses resulting primarily from lower throughput, higher fuel costs and lower volumes processed as a result of various contract terminations.

Operating costs increased primarily due to higher employee-related costs and the incremental operating expenses associated with the assets acquired from Kinder Morgan, partially offset by lower litigation costs.

Depreciation and amortization decreased primarily due to a goodwill and asset impairment charge of $12.0 million recorded in the second quarter of 2006 related to Black Mesa Pipeline.

Gain on sale of assets decreased primarily due to the $113.9 million gain on the sale of a 20 percent partnership interest in Northern Border Pipeline recorded in the second quarter of 2006.

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Equity earnings from investments primarily include earnings from ONEOK Partners’ interest in Northern Border Pipeline. The decrease for 2007 was primarily due to the decrease in ONEOK Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent beginning in the second quarter of 2006. See page 85 for discussion of the disposition of the 20 percent partnership interest in Northern Border Pipeline.

Allowance for equity funds used during construction and capital expenditures increased due to ONEOK Partners’ capital projects.

Minority interest in income of consolidated subsidiaries decreased primarily due to our acquisition of the remaining interest in Guardian Pipeline. Minority interest in net income of consolidated subsidiaries for our ONEOK Partners’ segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that ONEOK Partners did not own until April 2006. ONEOK Partners owned 100 percent of Guardian Pipeline beginning in April 2006, resulting in no minority interest in income of consolidated subsidiaries related to Guardian Pipeline after March 31, 2006.

Commodity Price Risk - ONEOK Partners is exposed to commodity price risk, primarily from NGLs, as a result of its contractual obligations for services provided. A small percentage of its services, based on volume, is provided through keep-whole arrangements. See discussion regarding ONEOK Partners’ commodity price risk beginning on page 63 under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

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,							2008 vs. 2007					2007 vs. 2006
Financial Results	2008		2007			2006		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Gas sales	$	2,049.0	$	1,976.3		$	1,836.9	$	72.7		4	%	$	139.4		8	%
Transportation revenues		87.3		87.3			88.3		-		0	%		(1.0	)	(1	%)
Cost of gas		1,496.7		1,435.4			1,358.4		61.3		4	%		77.0		6	%
Net margin, excluding other		639.6		628.2			566.8		11.4		2	%		61.4		11	%
Other revenues		41.3		35.4			33.0		5.9		17	%		2.4		7	%
Net margin		680.9		663.6			599.8		17.3		3	%		63.8		11	%
Operating costs		375.3		377.8			371.5		(2.5	)	(1	%)		6.3		2	%
Depreciation and amortization		116.8		111.6			110.9		5.2		5	%		0.7		1	%
Gain (loss) on sale of assets		-		(0.1	)		-		0.1		100	%		(0.1	)	(100	%)
Operating income	$	188.8	$	174.1		$	117.4	$	14.7		8	%	$	56.7		48	%
Capital expenditures	$	169.0	$	162.0		$	159.0	$	7.0		4	%	$	3.0		2	%

2008 vs. 2007 - Net margin increased primarily due to:

·	an increase of $15.7 million resulting from the implementation of new rate mechanisms, which includes a $12.4 million increase in Oklahoma and a $3.3 million increase in Texas; and

·	an increase of $2.2 million related to recovery of carrying costs for natural gas in storage.

Operating costs decreased primarily due to:

·	a decrease of $4.3 million in employee-related costs; and

·	a decrease of $1.0 million in bad debt expense; partially offset by

·	an increase of $2.4 million in fuel-related vehicle costs.

Depreciation and amortization increased primarily due to:

·	an increase of $4.0 million in depreciation expense related to our investment in property, plant and equipment; and

·	an increase of $1.2 million of regulatory amortization associated with revenue rider recoveries.

2007 vs. 2006 - Net margin increased primarily due to:

·	an increase of $55.2 million resulting from the implementation of new rate schedules, which includes $51.1 million in Kansas and $4.1 million in Texas; and

·	an increase of $8.0 million from higher customer sales volumes as a result of a return to more normal weather in our entire service territory.

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Operating costs increased primarily due to:

·	an increase of $4.8 million in bad debt expense, primarily in Oklahoma; and

·	an increase of $5.3 million due to higher property taxes in Kansas; partially offset by

·	a decrease of $4.0 million in labor and employee benefit costs.

Capital Expenditures - Our capital expenditure program includes expenditures for extending service to new areas, modifying customer service lines, increasing system capabilities, general replacements and improvements. It is our practice to maintain and upgrade facilities to ensure safe, reliable and efficient operations. Our capital expenditure program included $51.8 million, $50.6 million and $54.9 million for new business development in 2008, 2007 and 2006, respectively.

Selected Operating Information - The following tables set forth certain selected operating information for our Distribution segment for the periods indicated.

	Years Ended December 31,
Operating Information	2008		2007		2006
Customers per employee		719		732		713
Inventory storage balance (Bcf)		25.1		22.7		26.3

	Years Ended December 31,
Volumes (MMcf)	2008		2007		2006
Gas sales
Residential		125,834		121,587		110,123
Commercial		37,758		37,295		34,865
Industrial		1,395		1,758		1,624
Wholesale		7,186		13,231		29,263
Public Authority		2,592		2,679		2,520
Total volumes sold		174,765		176,550		178,395
Transportation		219,398		204,049		200,828
Total volumes delivered		394,163		380,599		379,223

	Years Ended December 31,
Margin	2008		2007		2006
Gas Sales	(Millions of dollars)
Residential	$	444.0	$	440.9	$	390.2
Commercial		101.3		99.5		88.8
Industrial		2.6		2.3		2.9
Wholesale		0.6		1.2		4.8
Public Authority		3.8		3.7		3.2
Net margin on gas sales		552.3		547.6		489.9
Transportation revenues		87.3		80.6		76.9
Net margin, excluding other	$	639.6	$	628.2	$	566.8

	Years Ended December 31,
Number of Customers	2008		2007		2006
Residential		1,886,118		1,876,054		1,859,480
Commercial		159,748		160,517		159,214
Industrial		1,420		1,455		1,528
Wholesale		28		27		18
Public Authority		2,963		2,952		2,645
Transportation		10,376		9,762		8,666
Total customers		2,060,653		2,050,767		2,031,551

Residential volumes increased during 2008, compared with 2007, due to colder temperatures in our Oklahoma and Kansas service territories; however, margins were moderated by weather normalization mechanisms.

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Residential and commercial volumes increased during 2007, compared with 2006, primarily due to a return to more normal weather from the unseasonably warm weather in 2006.

Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available for sale to other parties. Wholesale volumes decreased during 2008, compared with 2007 and 2006, due to reduced volumes available for sale.

Public authority natural gas volumes reflect volumes used by state agencies and school districts served by Texas Gas Service.

Transportation margins increased during 2008, compared with 2007, primarily due to increased transportation volumes in Oklahoma and Kansas.

Regulatory Initiatives

Oklahoma - In August 2007, Oklahoma Natural Gas filed an application for authorization of a capital investment recovery mechanism. In February 2008, the OCC approved a joint stipulation, which allows Oklahoma Natural Gas to collect a rate of return, depreciation and 50 percent of the property tax expense associated with non-revenue producing incremental capital investments since its 2005 rate case. The rates, which were effective in March 2008, generated margins of approximately $7.7 million in 2008. In July 2008, Oklahoma Natural Gas filed to increase the capital investment recovery mechanism from $7.6 million to $12.6 million annually. In October 2008, the parties signed a joint stipulation approving the request, and an administrative law judge of the OCC subsequently recommended approval of the joint stipulation. The final order was approved by the OCC in December 2008, and the increased recovery level was effective in January 2009.

The OCC has authorized Oklahoma Natural Gas to defer transmission pipeline Integrity Management Program (IMP) costs incurred (inclusive of operations and maintenance expense, depreciation, property taxes and a rate of return) in compliance with the Federal Pipeline Safety Improvement Act of 2002. On January 31, 2007, Oklahoma Natural Gas filed the first application with the OCC seeking recovery of these costs. On August 31, 2007, the OCC issued an order approving a stipulation of the parties, which provided for recovery of $7.2 million in IMP deferrals incurred as of July 31, 2007, and these deferrals were recovered during the months of October 2007 through June 2008.

The second IMP application was made at the OCC on January 31, 2008, and covered the IMP deferrals for the months of August through December 2007 and the true-ups associated with the prior recovery period. This filing also requested $7.2 million to be recovered with a new IMP billing rate to be put in place in July 2008. The OCC approved this request, and billings under the 2008 IMP application began in July 2008. The third IMP application was made at the OCC on January 30, 2009, and covered the IMP deferrals for 2008, and the true-ups associated with the prior recovery period. This filing requests a total of $10.8 million with a new IMP billing rate to be put in place in July 2009. Oklahoma Natural Gas will continue to defer IMP costs as they are incurred and will make future filings to recover those costs.

In August 2008, Oklahoma Natural Gas filed with the OCC for approval to include the fuel-related portion of bad debts in the Purchased Gas Adjustment mechanism for cost recovery. In October 2008, all parties signed the joint stipulation approving the request, and an administrative law judge of the OCC subsequently recommended approval of the joint stipulation. The joint stipulation allows Oklahoma Natural Gas to begin deferring its fuel-related bad debts beginning in January 2009 and to collect those amounts above the levels in base rates through the Purchased Gas Adjustment beginning in January 2010. The final order was issued by the OCC in December 2008. The associated deferrals began in January 2009.

In October 2008, a joint application for incentive-based rates was filed by the OCC staff and Oklahoma Natural Gas. This application proposes that the OCC adopt an incentive-based rate design and more streamlined regulatory process. If approved, this will provide for more timely rate changes.

Kansas - In October 2006, Kansas Gas Service reached a settlement with the KCC staff and all other parties to increase annual revenues by approximately $52 million. The terms of the settlement were approved by the KCC in November 2006. The rate increase is effective for services rendered on or after January 1, 2007.

In August 2008, Kansas Gas Service filed an application with the KCC to impose a surcharge designed to annually collect approximately $2.9 million in costs associated with its Gas System Reliability Surcharge (GSRS) mechanism. The GSRS mechanism allows natural gas utilities to earn a return and recover carrying costs associated with investments made to comply with state and federal pipeline safety requirements or costs to relocate existing facilities pursuant to requests made by a government entity. The KCC approved the request in December 2008, with authorized GSRS collections effective with customer billings on January 1, 2009.

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Texas - Texas Gas Service has received several regulatory approvals to implement rate increases in various municipalities in Texas. A total of $1.7 million in annual rate increases were approved and implemented in 2007. A total of $5.5 million in annual rate increases were approved and implemented in 2006.

In August 2007, Texas Gas Service filed for a rate adjustment with the city of El Paso, Texas, and the municipalities of Anthony, Clint, Horizon City, Socorro and Vinton. Texas Gas Service requested a total annual increase of $5.5 million. In February 2008, the El Paso City Council approved an annual rate increase of approximately $3.1 million. The increase was effective in February 2008.

In April 2008, the RRC approved a rate increase in our South Texas jurisdiction. The rate increase was effective May 2008 and will increase revenues by $1.1 million annually.

In May 2008, Texas Gas Service filed for interim rate relief under the Gas Reliability Infrastructure Program with the city of El Paso, Texas, and surrounding communities for approximately $1.1 million. This program is a capital recovery mechanism that allows for an interim rate adjustment providing recovery and a return on incremental capital investments made between rate cases. In August 2008, an annual rate increase of approximately $1.0 million was approved; the new rates were effective in September 2008.

In February 2009, Texas Gas Service filed a statement of intent to increase rates in its central Texas service area for approximately $3.6 million. If approved, new rates are expected to become effective in June 2009.

General - Certain costs to be recovered through the ratemaking process have been recorded as regulatory assets in accordance with Statement 71, “Accounting for the Effects of Certain Types of Regulation.” Should recovery cease due to regulatory actions, certain of these assets may no longer meet the criteria of Statement 71, and accordingly, a write-off of regulatory assets and stranded costs may be required.

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,						2008 vs. 2007					2007 vs. 2006
Financial Results	2008		2007		2006		Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Revenues	$	7,585.8	$	6,629.4	$	6,335.8	$	956.4		14	%	$	293.6		5	%
Cost of sales and fuel		7,475.1		6,382.0		6,062.0		1,093.1		17	%		320.0		5	%
Net margin		110.7		247.4		273.8		(136.7	)	(55	%)		(26.4	)	(10	%)
Operating costs		35.6		39.9		42.5		(4.3	)	(11	%)		(2.6	)	(6	%)
Depreciation and amortization		0.9		2.1		2.1		(1.2	)	(57	%)		-		0	%
Gain on sale of assets		1.5		-		-		1.5		100	%		-		0	%
Operating income	$	75.7	$	205.4	$	229.2	$	(129.7	)	(63	%)	$	(23.8	)	(10	%)
Capital expenditures	$	0.1	$	0.2	$	-	$	(0.1	)	(50	%)	$	0.2		100	%

Energy markets were affected by higher commodity prices during 2008, compared with 2007. The increase in commodity prices had a direct impact on our revenues and the cost of sales and fuel.

2008 vs. 2007 - Net margin decreased primarily due to the following:

·	a net decrease of $40.3 million in transportation margins, net of hedging activities, primarily due to decreased basis differentials between the Rocky Mountain and Mid-Continent regions, and increased transportation-related costs in 2008;

·	a decrease of $13.9 million in financial trading margins; and

·	a net decrease of $83.3 million in storage and marketing margins, net of hedging activities, primarily due to:

o	a net decrease of $87.3 million in physical storage margins net of hedging activities, as a result of:

·	hedging opportunities associated with weather related events that led to higher storage margins in 2007 compared with 2008;

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·	lower 2008 storage margins related to storage risk management positions and the impact of changes in natural gas prices on these positions; and

·	fewer opportunities to optimize storage capacity due to the significant decline in natural gas prices in the second half of 2008;

o	a decrease of $9.7 million in physical storage margins due to a lower of cost or market write-down on natural gas inventory; and

a decrease of $2.1 million due to colder than anticipated weather and market conditions that increased the supply cost of managing our peaking and load-following services and provided fewer opportunities to increase margins through optimization activities, primarily in the first quarter of 2008; partially offset by

o	an increase of $15.8 million from changes in the unrealized fair value of derivative instruments associated with storage and marketing activities and improved marketing margins, which benefited from price movements and optimization activities.

Operating costs decreased primarily due to lower employee-related costs and depreciation expense.

2007 vs. 2006 - Net margin decreased primarily due to:

·	a decrease of $22.0 million in transportation margins, net of hedging activities, associated with changes in the unrealized fair value of derivative instruments and the impact of a force majeure event on the Cheyenne Plains Gas Pipeline, as more fully described below;

·	a decrease of $5.0 million in retail activities from lower physical margins due to market conditions and increased competition;

·	a decrease of $4.3 million in financial trading margins that was partially offset by

·	an increase of $4.9 million in storage and marketing margins, net of hedging activities, related to:

o	an increase in physical storage margins, net of hedging activity, due to higher realized seasonal storage spreads and optimization activities; partially offset by

o	a decrease in marketing margins; and

o	a net increase in the cost associated with managing our peaking and load following services, slightly offset by higher demand fees collected for these services.

In September 2007, a portion of the volume contracted under our firm transportation agreement with Cheyenne Plains Gas Pipeline Company was curtailed due to a fire at a Cheyenne Plains pipeline compressor station. The fire damaged a significant amount of instrumentation and electrical wiring, causing Cheyenne Plains Gas Pipeline Company to declare a force majeure event on the pipeline. This firm commitment was hedged in accordance with Statement 133. The discontinuance of fair value hedge accounting on the portion of the firm commitment that was impacted by the force majeure event resulted in a loss of approximately $5.5 million that was recognized in the third quarter of 2007, of which $2.4 million of insurance proceeds were recovered and recognized in the first quarter of 2008. Cheyenne Plains Gas Pipeline Company resumed full operations in November 2007.

Operating costs decreased primarily due to decreased legal and employee-related costs, and reduced ad-valorem tax expense.

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	2008		2007		2006
Natural gas marketed (Bcf)		1,160		1,191		1,132
Natural gas gross margin ($/Mcf)	$	0.07	$	0.19	$	0.22
Physically settled volumes (Bcf)		2,359		2,370		2,288

Our natural gas in storage at December 31, 2008, was 81.9 Bcf, compared with 66.7 Bcf at December 31, 2007. At December 31, 2008, our total natural gas storage capacity under lease was 91 Bcf, compared with 96 Bcf at December 31, 2007.

Natural gas volumes marketed decreased slightly during 2008, compared with 2007, due to increased injections in the third quarter of 2008. In addition, demand for natural gas was impacted by weather-related events in the third quarter of 2008, including a 15 percent decrease in cooling degree-days and demand disruption caused by Hurricane Ike.

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Natural gas volumes marketed increased during 2007, compared with 2006, due to an increase in sales activity in the southeastern United States in the third quarter of 2007. Natural gas volumes were also impacted by a 14 percent increase in heating degree-days in our service territory, compared with the same period in 2006.

The acquisition of natural gas storage capacity is more competitive as a result of new market entrants. The increased demand for storage capacity has resulted in an increase in both the cost of leasing storage capacity and the required term of the lease. Longer terms and increased costs for storage capacity leases could result in significant increases in the cost of our contractual commitments.

The following table shows our margins by activity for the periods indicated.

	Years Ended December 31,
		2008			2007			2006
	(Millions of dollars)
Marketing, storage and transportation, gross		$	313.4		$	409.1		$	414.9
Less: Storage and transportation costs			(219.8	)		(191.9	)		(180.7	)
Marketing, storage and transportation, net			93.6			217.2			234.2
Retail marketing			14.8			14.0			19.0
Financial trading			2.3			16.2			20.6
Net margin		$	110.7		$	247.4		$	273.8

Marketing, storage and transportation, net, primarily includes physical marketing, purchases and sales, firm storage and transportation capacity expense, including the impact of cash flow and fair value hedges, and other derivative instruments used to manage our risk associated with these activities. Risk management and operational decisions have a significant impact on the net result of our marketing and storage activities. Origination gains are also a component of marketing activity, which is the fair value recognition of contracts that our wholesale marketing department structures to meet the risk management needs of our customers.

Retail marketing includes revenues from providing physical marketing and supply services, coupled with risk management services, to residential, municipal, and small commercial and industrial customers.

Financial trading margin includes activities that are generally executed 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 required to be reported on a net basis.

Contingencies

Legal Proceedings - We are a party to various litigation matters and claims that are 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 liquidity.

FERC Matter - As a result of a transaction that was brought to the attention of one of our affiliates by a third party, we conducted an internal review of transactions that may have violated FERC natural gas capacity release rules or related rules and determined that there were transactions that should be disclosed to the FERC. We notified the FERC of this review and filed a report with the FERC regarding these transactions in March 2008. We cooperated fully with the FERC in its investigation of this matter and have taken steps to better ensure that current and future transactions comply with applicable FERC regulations by implementing a compliance plan dealing with capacity release. We entered into a global settlement with the FERC to resolve this matter and other FERC enforcement matters, which was approved by the FERC on January 15, 2009. The global settlement provides for a total civil penalty of $4.5 million and approximately $2.2 million in disgorgement of profits and interest, of which $1.7 million of the civil penalty was allocated to ONEOK Partners. The amounts were recorded as a liability on our Consolidated Balance Sheet as of December 31, 2008. We made the required payments in January 2009.

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LIQUIDITY AND CAPITAL RESOURCES

General - Part of our strategy is to grow through acquisitions and internally generated growth projects that strengthen and complement our existing assets. We have relied primarily on operating cash flow, borrowings from commercial paper and credit agreements, and issuance of debt and equity in the capital markets for our liquidity and capital resource requirements. We expect to continue to use these sources for liquidity and capital resource needs on both a short- and long-term basis. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

During 2008 and continuing into 2009, the capital markets experienced volatility and disruption, which could limit our access to those markets or increase the cost of issuing new securities in the future. Higher commodity prices and wider basis differentials, particularly in 2008, have also resulted in higher collateral requirements and natural gas inventory costs in our Energy Services segment. Throughout this period, ONEOK has continued to have access to its $1.2 billion revolving credit agreement (ONEOK Credit Agreement); also, ONEOK Partners has continued to have access to the ONEOK Partners Credit Agreement, which has been adequate to fund short-term liquidity needs. In addition, beginning in August 2008, ONEOK had access to its new short-term credit agreement. In the third quarter of 2008, ONEOK began to utilize both of its credit agreements and lessened its use of commercial paper due to decreased liquidity and rising costs in the commercial paper market. See discussion below under “Short-term Liquidity.” Also in 2008, ONEOK Partners issued common units and received additional contributions from ONEOK Partners GP. See discussion below under “Long-term Financing.”

We expect continued deteriorating economic conditions in 2009, with downward pressures, relative to 2008, on commodity prices. We also expect continued volatility and disruption in the financial markets, which could result in an increased cost of capital. ONEOK and ONEOK Partners’ ability to continue to access capital markets for debt and equity financing under reasonable terms depends on the Company’s and Partnership’s respective financial condition, credit ratings and market conditions. ONEOK and ONEOK Partners anticipate that cash flow generated from operations, existing capital resources and ability to obtain financing will enable both to maintain current levels of operations and planned operations, collateral requirements and capital expenditures.

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

	Years Ended December 31,
		2008	2007
Long-term debt		67%	70%
Equity		33%	30%

Debt (including notes payable)		76%	71%
Equity		24%	29%

ONEOK does not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in the ONEOK Credit Agreement and ONEOK’s $400 million 364-day revolving credit facility dated August 6, 2008 (the 364-Day Facility), the debt of ONEOK Partners is excluded. At December 31, 2008, ONEOK’s capitalization structure, excluding the debt of ONEOK Partners, was 44 percent long-term debt and 56 percent equity, compared with 51 percent long-term debt and 49 percent equity at December 31, 2007. At December 31, 2008, ONEOK’s capitalization structure, including notes payable and excluding the debt of ONEOK Partners, was 59 percent debt and 41 percent equity, compared with 52 percent debt and 48 percent equity at December 31, 2007. In February 2008, ONEOK repaid $402.3 million of maturing long-term debt with cash from operations and short-term borrowings. In February 2009, ONEOK repaid $100 million of maturing long-term debt with cash from operations and short-term borrowings.

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 under FERC regulations. 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 subsidiary or the subsidiary provides cash to them.

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Short-term Liquidity - ONEOK’s principal sources of short-term liquidity consist of cash generated from operating activities, quarterly distributions from ONEOK Partners, the ONEOK Credit Agreement and the 364-Day Facility, as discussed below. ONEOK also has a commercial paper program that can be utilized for short-term liquidity needs, to the extent funds are available under the ONEOK Credit Agreement and the 364-Day Facility. ONEOK Partners’ principal sources of short-term liquidity consist of cash generated from operating activities and the ONEOK Partners Credit Agreement.

During late 2008, ONEOK and ONEOK Partners decided to borrow under their available credit facilities to fund their respective anticipated working capital requirements for the remainder of 2008 and into 2009.

In August 2008, ONEOK entered into the 364-Day Facility. The interest rate is based, at ONEOK’s election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate or (ii) the Eurodollar rate plus a set number of basis points based on ONEOK’s current long-term unsecured debt ratings by Moody’s and S&P. The 364-Day Facility is being used for working capital, capital expenditures and other general corporate purposes.

In September 2008, ONEOK entered into an amendment to the ONEOK Credit Agreement. The amendment changed certain sublimits but did not change the lenders’ aggregate commitment to lend up to $1.2 billion under the ONEOK Credit Agreement.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion. At December 31, 2008, ONEOK had no commercial paper outstanding, $1.4 billion in borrowings outstanding, $64.9 million in letters of credit issued, which includes $64.6 million under the ONEOK Credit Agreement and an additional $0.3 million in other letters of credit, and available cash and cash equivalents of approximately $332.4 million. Considering outstanding borrowings, commercial paper and letters of credit under the ONEOK Credit Agreement, ONEOK had $135.4 million of credit available at December 31, 2008, under the ONEOK Credit Agreement and the 364-Day Facility. As of December 31, 2008, ONEOK could have issued $1.5 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 $1.5 billion. At December 31, 2008, ONEOK Partners had $870 million in borrowings outstanding and $130 million of credit available under the ONEOK Partners Credit Agreement and available cash and cash equivalents of approximately $177.6 million. As of December 31, 2008, ONEOK Partners could have issued a $772.6 million of additional short- and long-term debt under the most restrictive provisions of its agreements.

ONEOK Partners has an outstanding $25 million letter of credit issued by Royal Bank of Canada, which is used for counterparty credit support.

ONEOK Partners also has a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is currently being used, and an agreement with Royal Bank of Canada, pursuant to which a $12 million letter of credit was issued. Both agreements are used to support various permits required by the KDHE for ONEOK Partners’ ongoing business in Kansas.

The ONEOK Credit Agreement and the 364-Day Facility contain 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 and the 364-Day Facility exclude the debt of ONEOK Partners. Upon breach of any covenant by ONEOK, amounts outstanding under the ONEOK Credit Agreement or the 364-Day Facility may become immediately due and payable. At December 31, 2008, ONEOK’s stand-alone debt-to-capital ratio was 58.2 percent, and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement and the ONEOK 364-Day Facility.

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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 plus minority interest in income of consolidated subsidiaries, distributions received from investments and EBITDA related to any approved capital projects less equity earnings from investments and the equity portion of AFUDC) 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, 2008, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.1 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

The average interest rate on ONEOK and ONEOK Partners short-term debt outstanding at December 31, 2008, was 4.51 percent and 4.22 percent, respectively, compared with a weighted average rate of 3.88 percent and 3.94 percent, respectively, for the year ended December 31, 2008. Based on the forward LIBOR curve, we expect the interest rate on ONEOK and ONEOK Partners’ short-term borrowings to decrease in 2009, compared with 2008.

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 sale/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/leaseback of facilities.

ONEOK and ONEOK Partners are subject, however, to changes in the equity and debt 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, altering the timing of controllable expenditures, restricting future acquisitions and capital projects, borrowing under existing credit facilities or pursuing other debt or equity financing alternatives. Some of these alternatives could involve higher costs or negatively affect their respective credit ratings. 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 Issuance - In September 2007, ONEOK Partners completed an underwritten public offering of $600 million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC.

ONEOK Partners may redeem the 2037 Notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amount of the 2037 Notes, 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 2037 Notes plus accrued and unpaid interest. The 2037 Notes are senior unsecured obligations, ranking equally in right of payment with all of ONEOK Partners’ existing and future unsecured senior indebtedness, and effectively junior to all of the existing debt and other liabilities of its non-guarantor subsidiaries. The 2037 Notes are non-recourse to ONEOK.

Debt Covenants - The terms of ONEOK’s long-term notes are governed by indentures containing covenants that include, among other provisions, limitations on ONEOK’s ability to place liens on its property or assets and its ability to sell and lease back its property.

We filed a new form of indenture in 2008. The new indenture includes covenants that are similar to those contained in our prior indentures. The new indenture does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series.

The indenture governing ONEOK Partners’ 2037 Notes does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and its ability to sell and lease back its property.

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upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2036 and 2037 to declare those notes immediately due and payable in full.

ONEOK Partners Equity Issuance - In March 2008, ONEOK purchased from ONEOK Partners, in a private placement, an additional 5.4 million of ONEOK Partners’ common units for a total purchase price of approximately $303.2 million. In addition, ONEOK Partners completed a public offering of 2.5 million common units at $58.10 per common unit and received net proceeds of $140.4 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ private placement and the public offering of common units, ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent general partner interest. ONEOK and ONEOK Partners GP funded these amounts with available cash and short-term borrowings.

ONEOK Partners used a portion of the proceeds from the sale of common units and the general partner contributions to repay borrowings under its existing ONEOK Partners Credit Agreement.

Capital Expenditures - ONEOK’s and ONEOK Partners’ capital expenditures are typically financed through operating cash flows, short- and long-term debt and the issuance of equity. Total capital expenditures for 2008 were $1,473.1 million, compared with $883.7 million in 2007, exclusive of acquisitions. Of these amounts, ONEOK Partners’ capital expenditures for 2008 were $1,253.9 million, compared with $709.9 million in 2007, exclusive of acquisitions. The increase in capital expenditures for 2008, compared with 2007, is driven primarily by ONEOK Partners’ internal capital projects discussed beginning on page 37, and ONEOK’s purchase of ONEOK Plaza. ONEOK and ONEOK Partners expect to continue to finance future capital expenditures with a combination of operating cash flows, short- and long-term debt, and the issuance of common units by ONEOK Partners.

The following table summarizes our 2009 projected capital expenditures, excluding AFUDC.

2009 Projected Capital Expenditures
	(Millions of dollars)
ONEOK Partners		$	425
Distribution			137
Energy Services			-
Other			19
Total projected capital expenditures		$	581

Projected 2009 capital expenditures are significantly less than 2008 capital expenditures, primarily due to the completion of the Overland Pass Pipeline and related projects and the Guardian Pipeline expansion and extension. Additional information about our capital expenditures is included under “Capital Projects” on page 37. ONEOK Partners anticipates spending $300 million to $500 million per year on growth capital expenditures for the years 2010 through 2015.

Investment in Northern Border Pipeline - Northern Border Pipeline anticipates an equity contribution of approximately $85 million that will be required of its partners in 2009, of which ONEOK Partners’ share will be approximately $43 million for its 50 percent equity interest.

Credit Ratings - Our credit ratings as of December 31, 2008, 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

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ONEOK’s commercial paper is rated P2 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 anticipate their respective credit ratings to be downgraded. However, if our credit ratings were downgraded, the interest rates on our commercial paper borrowings, the ONEOK Credit Agreement and the 364-Day Facility would increase, resulting in an increase in our cost to borrow funds, and we could potentially lose access to the commercial paper market. Likewise, ONEOK Partners would see increased borrowing costs under the ONEOK Partners Credit Agreement. 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, and the 364-Day Facility, which expires in August 2009. An adverse rating change alone is not a default under the ONEOK Credit Agreement, the 364-Day Facility or the ONEOK Partners Credit Agreement but could trigger repurchase obligations with respect to certain long-term debt. See additional discussion about our credit ratings under “Debt Covenants.”

If ONEOK Partners’ repurchase obligations are triggered, it may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause it 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.

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, 2008, we could have been required to fund approximately $36.2 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.

Other than ONEOK Partners’ note repurchase obligations and the margin requirements for our Energy Services segment described above, we have determined that we do not have significant exposure to rating triggers under ONEOK’s trust indentures, building leases, equipment leases and other various contracts. Rating triggers are defined as provisions that would create an automatic default or acceleration of indebtedness based on a change in our credit rating.

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 rating or a significant change in ONEOK’s or ONEOK Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK Partners could be asked to provide additional collateral in the form of cash, letters of credit or other negotiable instruments.

ONEOK Partners’ Class B Units - The units we received from ONEOK Partners were newly created Class B limited partner units. Distributions on the Class B limited partner units were prorated from the date of issuance. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on ONEOK Partners’ common units and generally have the same voting rights as the common units.

At a special meeting of the ONEOK Partners common unitholders held March 29, 2007, the unitholders approved a proposal to permit the conversion of all or a portion of the Class B limited partner units issued in the acquisition and consolidation of certain companies comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments in a series of transactions (collectively the ONEOK Transactions) into common units at the option of the Class B unitholder. The March 29, 2007, special meeting was adjourned to May 10, 2007, to allow unitholders additional time to vote on a proposal to approve amendments to the ONEOK Partners’ Partnership Agreement, which had the amendments been approved, would have granted voting rights for units held by us and our affiliates if a vote is held to remove us as the general partner and would have required fair market value compensation for our general partner interest if we are removed as general partner. While a majority of ONEOK Partners common unitholders voted in favor of the proposed amendments to the ONEOK Partners Partnership Agreement at the reconvened meeting of the common unitholders held May 10, 2007, the proposed amendments were not approved by the required two-thirds affirmative vote of the outstanding units, excluding the common units and Class B units held by us and our affiliates. As a result, effective April 7, 2007, the Class B limited partner units are entitled to receive increased quarterly distributions and distributions upon liquidation equal to 110 percent of the distributions paid with respect to the common units.

On June 21, 2007, we, as the sole holder of ONEOK Partners’ Class B limited partner units, waived our right to receive the increased quarterly distributions on the Class B units for the period April 7, 2007, through December 31, 2007, and

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continuing thereafter until we give ONEOK Partners no less than 90 days advance notice that we have withdrawn our waiver. 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 90 days following delivery of the notice.

In addition, since the proposed amendments to the ONEOK Partners’ Partnership Agreement were not approved by the common unitholders, if the common unitholders vote at any time to remove us or our affiliates as the general partner, quarterly distributions payable on 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.

Stock Repurchase Plan - For more information regarding the Stock Repurchase Plan, refer to discussion in Note G of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity price in either physical or financial energy contracts may impact our overall liquidity due to the impact the 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 63 under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk for information on our hedging activities.

Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans, including anticipated contributions, is included under Note J of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

At December 31, 2007, the funded status of our pension plans exceeded 94 percent as required by federal regulations. General market factors in 2008 negatively impacted the fair value of our plan assets, and as a result, we made a voluntary contribution to our pension plans of $112 million on December 31, 2008. We do not expect that our funding requirements in 2009 will have a material impact on our liquidity.

ENVIRONMENTAL LIABILITIES

Information about our environmental liabilities is included in Note K of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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 on sale of assets, minority interests in income of consolidated affiliates, undistributed earnings from equity investments in excess of distributions received, deferred income taxes, stock-based compensation expense, allowance for doubtful accounts, inventory adjustments and investment securities gains. 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,									2008 vs. 2007					2007 vs. 2006
	2008			2007			2006			Increase (Decrease)					Increase (Decrease)
	(Millions of dollars)
Total cash provided by (used in):
Operating activities	$	475.7		$	1,029.7		$	873.3		$	(554.0	)	(54	%)	$	156.4		18	%
Investing activities		(1,454.3	)		(1,151.8	)		(237.2	)		(302.5	)	(26	%)		(914.6	)	*
Financing activities		1,469.6			72.9			(618.8	)		1,396.7		*			691.7		*
Change in cash and cash equivalents		491.0			(49.2	)		17.3			540.2		*			(66.5	)	*
Cash and cash equivalents at beginning of period		19.1			68.3			7.9			(49.2	)	(72	%)		60.4		*
Effect of Accounting Change on Cash and Cash Equivalents		-			-			43.1			-		0	%		(43.1	)	(100	%)
Cash and cash equivalents at end of period	$	510.1		$	19.1		$	68.3		$	491.0		*		$	(49.2	)	(72	%)
* Percentage change is greater than 100 percent.

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Operating Cash Flows - Operating cash flows decreased by $554.0 million for 2008, compared with 2007, primarily due to changes in working capital. These changes decreased operating cash flows by $515.3 million for 2008, compared with an increase of $203.6 million for 2007, primarily due to decreases in accounts payable and increased funding for our pension plans, partially offset by decreases in accounts and notes receivable. The decrease in operating cash flows due to increases in working capital for 2008 was partially offset by higher net income.

Operating cash flows increased by $156.4 million for 2007, compared with 2006. Working capital increased operating cash flows by $203.6 million for 2007, compared with an increase of $59.7 million for 2006.

Investing Cash Flows - The increased use of cash during 2008 was primarily related to a $589.4 million increase in capital expenditures, compared with 2007. Capital expenditures increased $507.4 for 2007, compared with 2006. These increases are primarily related to ONEOK Partners’ capital projects.

In October 2007, ONEOK Partners acquired an interstate natural gas liquids and refined petroleum products pipeline system and related assets from a subsidiary of Kinder Morgan for approximately $300 million, before working capital adjustments.

In April 2006, our ONEOK Partners segment received $297.0 million for the sale of a 20 percent partnership interest in Northern Border Pipeline. Our Energy Services segment received $53.0 million for the sale of our discontinued component, Spring Creek, in October 2006.

Acquisitions in 2006 primarily relate to our ONEOK Partners segment acquiring the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners for approximately $77 million. We also purchased from TransCanada its 17.5 percent general partner interest in ONEOK Partners for $40 million. Additionally, ONEOK Partners paid $11.6 million to Williams for a 99 percent interest in, and initial capital expenditures related to, the Overland Pass Pipeline Company natural gas liquids pipeline joint venture.

We had a decrease in short-term investments of $31.1 million for 2007, compared with a total investment of $31.1 million for 2006. During 2007, we had less cash to invest following our repurchase of 7.5 million shares of our outstanding common stock in June.

Investing cash flows for 2006 also include the impact of the deconsolidation of Northern Border Pipeline and consolidation of Guardian Pipeline.

Financing Cash Flows - Net short-term borrowings were $2.1 billion for 2008, compared with $196.6 million for 2007. The increased short-term borrowings during 2008 were used to repay a portion of $402.3 million of maturing long-term debt. Short-term borrowings also increased as the result ONEOK’s and ONEOK Partners’ decision in late 2008 to borrow under their available credit facilities to fund their respective anticipated working capital requirements for the remainder of 2008 and into 2009, and ONEOK Partners’ capital projects.

During 2008, ONEOK Partners’ public sale of 2.6 million common units generated approximately $147 million, after deducting underwriting discounts but before offering expenses.

In 2007, short-term financing was primarily used to fund ONEOK Partners’ capital projects. ONEOK Partners’ $598 million debt issuance, net of discounts, was used to repay borrowings under the ONEOK Partners Credit agreement and finance the $300 million acquisition of assets, before working capital adjustments, from a subsidiary of Kinder Morgan in October 2007.

In 2006, we repaid the remaining $900 million outstanding on our $1.0 billion short-term bridge financing agreement. During the second quarter of 2006, ONEOK Partners borrowed $1.05 billion under its $1.1 billion 364-day credit facility dated April 6, 2006, (Bridge Facility) to finance a portion of the acquisition of the ONEOK Energy Assets and $77 million under its then existing credit agreement to acquire the 66-2/3 percent interest in Guardian Pipeline not previously owned by ONEOK Partners. During the third quarter of 2006, ONEOK Partners completed the underwritten public offering of senior notes totaling $1.4 billion in net proceeds, before offering expenses, which were used to repay all of the amounts outstanding of the $1.05 billion borrowed under the ONEOK Partners Bridge Facility and to repay $335 million of indebtedness outstanding under its then existing credit agreement.

On February 16, 2006, we successfully settled our 16.1 million equity units to 19.5 million shares of our common stock. With the settlement of the equity units, we received $402.4 million in cash, which we used to repay a portion of our commercial paper. We repaid a total of $641.5 million of our commercial paper during 2006. See Note G of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional discussion regarding the equity unit conversion.

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In March 2006, our ONEOK Partners segment borrowed $33 million under its then existing credit agreement to redeem all of the outstanding Viking Gas Transmission Series A, B, C and D senior notes and paid a redemption premium of $3.6 million.

During 2007, we paid $20.1 million for the settlement of the forward purchase contract related to our stock repurchase in February and approximately $370 million for our stock repurchase in June. We paid $281.4 million to repurchase shares in August 2006.

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, 2008. For additional discussion of the debt and operating lease agreements, see Notes I and K, respectively, of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.

	Payments Due by Period
Contractual Obligations	Total		2009		2010		2011		2012		2013		Thereafter
ONEOK	(Thousands of dollars)
$1.2 billion credit agreement	$	1,100,000	$	1,100,000	$	-	$	-	$	-	$	-	$	-
$400 million credit agreement		300,000		300,000		-		-		-		-		-
Long-term debt		1,584,053		106,265		6,284		406,306		6,329		6,205		1,052,664
Interest payments on debt		1,100,500		92,100		91,400		70,900		62,100		61,700		722,300
Operating leases		300,795		88,837		55,888		61,232		32,943		25,376		36,519
Firm transportation contracts		552,509		123,352		103,157		81,833		80,389		57,249		106,529
Financial and physical derivatives		927,635		816,319		97,225		13,623		468		-		-
Employee benefit plans		42,602		42,602		-		-		-		-		-
Other		850		567		283		-		-		-		-
	$	5,908,944	$	2,670,042	$	354,237	$	633,894	$	182,229	$	150,530	$	1,918,012

ONEOK Partners
$1 billion credit agreement	$	870,000	$	870,000	$	-	$	-	$	-	$	-	$	-
Long-term debt		2,596,711		11,931		261,931		236,931		361,062		7,650		1,717,206
Interest payments on debt		2,686,400		176,700		163,700		140,000		120,200		114,300		1,971,500
Operating leases		86,508		18,362		16,027		15,527		8,755		2,063		25,774
Firm transportation contracts		14,765		11,086		3,679		-		-		-		-
Financial and physical derivatives		48,467		48,467		-		-		-		-		-
Purchase commitments,
rights-of-way and other		35,582		30,914		977		976		977		977		761
	$	6,338,433	$	1,167,460	$	446,314	$	393,434	$	490,994	$	124,990	$	3,715,241
Total	$	12,247,377	$	3,837,502	$	800,551	$	1,027,328	$	673,223	$	275,520	$	5,633,253

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, storage contracts, office space, pipeline equipment, rights of way and vehicles. Operating lease obligations for ONEOK exclude intercompany payments related to the lease of a gas processing plant.

Firm Transportation Contracts - Our ONEOK Partners, Distribution and Energy Services segments are party to fixed-price transportation contracts. However, the costs 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. Firm transportation agreements with our ONEOK Partners segment’s natural gas gathering and processing joint ventures require minimum monthly payments.

Financial and Physical Derivatives - These are obligations arising from our ONEOK Partners and Energy Services segments’ physical and financial derivatives for fixed-price purchase commitments and are based on market information at December 31, 2008. Not included in these amounts are offsetting cash inflows from our Energy Services segment’s 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.

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Employee Benefit Plans - Employee benefit plans include our minimum required contribution to our pension and postretirement benefit plans for 2009. See Note J of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of our employee benefit plans.

Purchase Commitments - Purchase commitments include commitments related to ONEOK Partners’ growth capital expenditures and other rights of way 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 on Form 10-K are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. 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 on Form 10-K identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “could,” “may,” “continue,” “might,” “potential,” “scheduled,” and other words and terms of similar meaning.

You should not place undue reliance on forward-looking statements. 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 on our operations, including energy sales and demand for our services and energy prices;

·	competition from other United States and Canadian energy suppliers and transporters as well as alternative forms of energy, including, but not limited to, 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 or recovery of gas and gas transportation costs;

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

·	changes in demand for the use of natural gas 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 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 to our competitors that have less debt, or have other adverse consequences;

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

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·	the results of administrative proceedings and litigation, regulatory actions and receipt of expected clearances involving the OCC, KCC, Texas regulatory authorities or any other local, state or federal regulatory body, including the FERC;

·	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 increasing liquidity risks in United States credit markets;

·	the impact of recently issued and future accounting pronouncements 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 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

·	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 on Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

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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 prices. Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in commodity 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, primarily with respect to NGLs, 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 processing contracts. ONEOK Partners is also exposed to the risk of price fluctuations and the cost of intervening transportation at 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.

The following table sets forth ONEOK Partners’ hedging information for the year ending December 31, 2009.

	Year Ending December 31, 2009
	Volumes Hedged		Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	5,010	$	1.18	/ gallon	57%
Condensate (Bbl/d) (a)	666	$	3.23	/ gallon	32%
Total liquid sales (Bbl/d)	5,676	$	1.42	/ gallon	52%
(a) - Hedged with fixed-price swaps.

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ONEOK Partners’ commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at December 31, 2008, 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 $1.0 million; and

·	a $0.10 per MMBtu decrease in the price of natural gas would decrease annual net margin by approximately $0.6 million.

The above estimates of commodity price risk do not include any effects on demand for its services that might be caused by, or arise in conjunction with, price changes. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing margins, NGL exchange revenues, natural gas deliveries, and NGL volumes shipped and fractionated.

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. 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 collect 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, 2008, 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 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 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 $21.0 million of net liabilities from derivative instruments declared as either fair value or cash flow hedges.

Fair Value Component of Energy Marketing and Risk Management Assets and Liabilities
	(Thousands of dollars)
Net fair value of derivatives outstanding at December 31, 2007		$	25,171
Derivatives reclassified or otherwise settled during the period			(55,874	)
Fair value of new derivatives entered into during the period			236,772
Other changes in fair value			52,731
Net fair value of derivatives outstanding at December 31, 2008 (a)		$	258,800

(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: $225.0 million matures through March 2009, $33.9 million matures through March 2012 and $(0.1) million matures through March 2014.

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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. Fair value of new derivatives entered into during the period includes $298.8 million of cash flow hedges reclassified into earnings from accumulated other comprehensive income (loss) related to the write-down of our natural gas in storage to its lower of weighted-average cost or market.

For further discussion of fair value measurements and trading activities and assumptions used in our trading activities, see the “Critical Accounting Policies and Estimates” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation. Also, see Notes C and D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Value-at-Risk (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. Inputs to the calculation include prices, volatilities, positions, instrument valuations and the variance-covariance matrix. 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. 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.

The potential impact on our future earnings, as measured by VAR, was $7.9 million and $6.0 million at December 31, 2008 and 2007, respectively. The following table details the average, high and low VAR calculations for the periods indicated.

	Years Ended December 31,
Value-at-Risk		2008		2007
	(Millions of dollars)
Average		$	12.3	$	8.9
High		$	24.9	$	23.0
Low		$	4.0	$	3.4

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 increase in average VAR for 2008, compared with 2007, was primarily due to a significant increase in natural gas prices during the second quarter of 2008.

Our VAR calculation uses historical prices, placing more emphasis on the most recent price movements. We revised our assumptions in the third quarter of 2008 to decrease the weight given to the most recent price changes and spread the relative weighting over more historical data. This methodology reduces the effects of the market anomalies and better reflects an efficient market. We believe this methodology is more reflective of portfolio risk and have applied the change on a prospective basis.

During 2008, we also began calculating 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. These transactions are subject to mark-to-market accounting treatment because they are not part of a hedging relationship under Statement 133. VAR associated with these derivative positions was not material during 2008. 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.

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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 are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. At December 31, 2008, the interest rate on 89.3 percent of our long-term debt, exclusive of the debt of our ONEOK Partners segment, was fixed after considering the impact of interest-rate swaps. At December 31, 2008, the interest rate on all of ONEOK Partners’ long-term debt was fixed.

We terminated a $100 million interest-rate swap in the fourth quarter of 2008. The total value we received was $19.2 million, which includes $0.3 million of swap savings previously recorded. The remaining savings of $18.9 million will be recognized in interest expense over the remaining term of the debt instrument originally hedged.

In the fourth quarter of 2008, our counterparties exercised the option to terminate two additional interest-rate swap agreements totaling $140 million. The swap terminations were effective in December 2008 and January 2009. The total value we received for the terminated swaps was not material.

At December 31, 2008, a 100 basis point move in the annual interest rate on all of our swapped long-term debt would change our annual interest expense by $1.7 million before taxes. This 100 basis point change assumes a parallel shift in the yield curve. If interest rates changed significantly, we would take actions to manage our exposure to the change. Since a specific action and the possible effects are uncertain, no change has been assumed.

Fair Value Hedges - See Note D of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion of the impact of interest-rate swaps and net interest expense savings from terminated swaps.

Total net swap savings for 2008 were $17.4 million, compared with $8.2 million for 2007. Total swap savings for 2009 are expected to be $10.5 million.

CURRENCY EXCHANGE RATE RISK

As a result of our Energy Services segment’s operations in Canada, we are exposed to currency exchange rate risk from our commodity purchases and sales related to our firm transportation and storage contracts. 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 since we exchange U.S. dollars for Canadian dollars with another party. We have not designated these transactions for hedge accounting treatment; therefore, the gains and losses associated with the change in fair value are recorded in net margin. At December 31, 2008 and 2007, our exposure to risk from currency translation was not material. We recognized a currency translation loss of $3.1 million during 2008 and currency translation gains of $4.1 million and $2.5 million during 2007 and 2006, respectively.

COUNTERPARTY CREDIT RISK

ONEOK and ONEOK Partners assess the creditworthiness of their counterparties on an on going basis and require security, including prepayments and other forms of cash 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 and 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, 2008 and 2007, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2008, 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, 2008, 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, 2008. 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

February 24, 2009

Tulsa, Oklahoma

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

ONEOK, Inc.:

We have audited the accompanying consolidated statement of income, cash flows, and shareholders’ equity and comprehensive income of ONEOK, Inc. and subsidiaries as of December 31, 2006. The consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of ONEOK, Inc. and subsidiaries for the year ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note A of Notes to the Consolidated Financial Statements, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” Emerging Issues Task Force Issue 04-5, “Determining Whether a General Partner, or General Partners as a Group Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights,” and SFAS No. 123R, “Share-Based Payment.”

/s/ KPMG LLP

Tulsa, Oklahoma

February 28, 2007

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
		Years Ended December 31,
		2008			2007			2006
	(Thousands of dollars, except per share amounts)

Revenues		$	16,157,433		$	13,477,414		$	11,920,326
Cost of sales and fuel			14,221,906			11,667,306			10,198,342
Net Margin			1,935,527			1,810,108			1,721,984
Operating Expenses
Operations and maintenance			694,597			675,575			662,681
Depreciation and amortization			243,927			227,964			235,543
General taxes			82,315			85,935			78,086
Total Operating Expenses			1,020,839			989,474			976,310
Gain (Loss) on Sale of Assets			2,316			1,909			116,528
Operating Income			917,004			822,543			862,202
Equity earnings from investments (Note O)			101,432			89,908			95,883
Allowance for equity funds used during construction			50,906			12,538			2,205
Other income			16,838			21,932			26,030
Other expense			(27,475	)		(7,879	)		(24,154	)
Interest expense			(264,167	)		(256,325	)		(239,725	)
Income before Minority Interests and Income Taxes			794,538			682,717			722,441
Minority interests in income of consolidated subsidiaries			(288,558	)		(193,199	)		(222,000	)
Income taxes (Note L)			(194,071	)		(184,597	)		(193,764	)
Income from Continuing Operations			311,909			304,921			306,677
Gain (Loss) from operations of discontinued components, net of tax			-			-			(365	)
Net Income		$	311,909		$	304,921		$	306,312

Earnings Per Share of Common Stock (Note P)
Net Earnings Per Share, Basic		$	2.99		$	2.84		$	2.74
Net Earnings Per Share, Diluted		$	2.95		$	2.79		$	2.68

Average Shares of Common Stock (Thousands)
Basic			104,369			107,346			112,006
Diluted			105,760			109,298			114,477

Dividends Declared Per Share of Common Stock		$	1.56		$	1.40		$	1.22
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	December 31,		December 31,
	2008		2007
Assets	(Thousands of dollars)

Current Assets
Cash and cash equivalents	$	510,058	$	19,105
Accounts receivable, net		1,265,300		1,723,212
Gas and natural gas liquids in storage		858,966		841,362
Commodity exchanges and imbalances		56,248		82,938
Energy marketing and risk management assets (Notes C and D)		362,808		143,941
Other current assets		324,222		140,917
Total Current Assets		3,377,602		2,951,475

Property, Plant and Equipment
Property, plant and equipment		9,476,619		7,893,492
Accumulated depreciation and amortization		2,212,850		2,048,311
Net Property, Plant and Equipment (Note A)		7,263,769		5,845,181

Investments and Other Assets
Goodwill and intangible assets (Note E)		1,038,226		1,043,773
Energy marketing and risk management assets (Notes C and D)		45,900		3,978
Investments in unconsolidated affiliates (Note O)		755,492		756,260
Other assets		645,073		461,367
Total Investments and Other Assets		2,484,691		2,265,378
Total Assets	$	13,126,062	$	11,062,034
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
	December 31,			December 31,
	2008			2007
Liabilities and Shareholders’ Equity	(Thousands of dollars)

Current Liabilities
Current maturities of long-term debt (Note I)	$	118,195		$	420,479
Notes payable		2,270,000			202,600
Accounts payable		1,122,761			1,436,005
Commodity exchanges and imbalances		188,030			252,095
Energy marketing and risk management liabilities (Notes C and D)		175,006			133,903
Other current liabilities		319,772			436,585
Total Current Liabilities		4,193,764			2,881,667

Long-term Debt, excluding current maturities (Note I)		4,112,581			4,215,046

Deferred Credits and Other Liabilities
Deferred income taxes		890,815			680,543
Energy marketing and risk management liabilities (Notes C and D)		46,311			26,861
Other deferred credits		715,052			486,645
Total Deferred Credits and Other Liabilities		1,652,178			1,194,049

Commitments and Contingencies (Note K)

Minority Interests in Consolidated Subsidiaries		1,079,369			801,964

Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 121,647,007 shares
and outstanding 104,845,231 shares at December 31, 2008;
issued 121,115,217 shares and outstanding 103,987,476
shares at December 31, 2007		1,216			1,211
Paid in capital		1,301,153			1,273,800
Accumulated other comprehensive loss (Note F)		(70,616	)		(7,069	)
Retained earnings		1,553,033			1,411,492
Treasury stock, at cost: 16,801,776 shares at December 31,
2008 and 17,127,741 shares at December 31, 2007		(696,616	)		(710,126	)
Total Shareholders’ Equity		2,088,170			1,969,308
Total Liabilities and Shareholders’ Equity	$	13,126,062		$	11,062,034
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Years Ended December 31,
	2008			2007			2006
Operating Activities	(Thousands of dollars)
Net income	$	311,909		$	304,921		$	306,312
Depreciation and amortization		243,927			227,964			235,543
Allowance for equity funds used during construction		(50,906	)		(12,538	)		(2,205	)
Gain on sale of assets		(2,316	)		(1,909	)		(116,528	)
Minority interests in income of consolidated subsidiaries		288,558			193,199			222,000
Equity earnings from investments		(101,432	)		(89,908	)		(95,883	)
Distributions received from unconsolidated affiliates		93,261			103,785			123,427
Deferred income taxes		165,191			65,017			115,384
Stock-based compensation expense		30,791			20,909			16,499
Allowance for doubtful accounts		13,476			14,578			9,056
Inventory adjustment, net		9,658			-			-
Investment securities gains		(11,142	)		-			-
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts and notes receivable		433,859			(378,876	)		649,415
Gas and natural gas liquids in storage		(370,662	)		88,937			(13,801	)
Accounts payable		(340,584	)		343,144			(425,715	)
Commodity exchanges and imbalances, net		(37,375	)		40,572			18,001
Unrecovered purchased gas costs		(35,790	)		9,530			(73,534	)
Accrued interest		16,002			9,001			25,329
Energy marketing and risk management assets and liabilities		60,846			41,649			(63,040	)
Fair value of firm commitments		505			5,631			190,795
Pension and postretirement benefit plans		(83,254	)		28,573			(14,496	)
Other assets and liabilities		(158,845	)		15,481			(233,283	)
Cash Provided by Operating Activities		475,677			1,029,660			873,276
Investing Activities
Changes in investments in unconsolidated affiliates		3,963			(3,668	)		(6,608	)
Acquisitions		2,450			(299,560	)		(148,892	)
Capital expenditures (less allowance for equity funds used during construction)		(1,473,136	)		(883,703	)		(376,306	)
Proceeds from sale of discontinued component		-			-			53,000
Proceeds from sale of assets		2,630			4,022			298,964
Proceeds from insurance		9,792			-			-
Changes in short-term investments		-			31,125			(31,125	)
Increase in cash and cash equivalents attributable to previously unconsolidated subsidiaries		-			-			1,334
Decrease in cash and cash equivalents attributable to previously consolidated subsidiaries		-			-			(22,039	)
Other investing activities		-			-			(5,565	)
Cash Used in Investing Activities		(1,454,301	)		(1,151,784	)		(237,237	)
Financing Activities
Borrowing (repayment) of notes payable, net		1,197,400			196,600			(842,000	)
Borrowing (repayment) of notes payable with maturities over 90 days		870,000			-			(900,000	)
Issuance of debt, net of issuance costs		-			598,146			1,397,328
Long-term debt financing costs		-			(5,805	)		(12,003	)
Payment of debt		(416,040	)		(13,588	)		(44,359	)
Equity unit conversion		-			-			402,448
Repurchase of common stock		(29	)		(390,213	)		(281,444	)
Issuance of common stock		16,495			20,730			10,829
Issuance of common units, net of discounts		146,969			-			-
Dividends paid		(162,785	)		(150,188	)		(135,451	)
Distributions to minority interests		(201,658	)		(182,891	)		(165,283	)
Other financing activities		19,225			170			(48,841	)
Cash Provided by (Used in) Financing Activities		1,469,577			72,961			(618,776	)
Change in Cash and Cash Equivalents		490,953			(49,163	)		17,263
Cash and Cash Equivalents at Beginning of Period		19,105			68,268			7,915
Effect of Accounting Change on Cash and Cash Equivalents		-			-			43,090
Cash and Cash Equivalents at End of Period	$	510,058		$	19,105		$	68,268
Supplemental Cash Flow Information:
Cash Paid for Interest	$	237,577		$	253,678		$	225,998
Cash Paid for Taxes	$	82,965		$	57,281		$	262,504
See accompanying Notes to Consolidated Financial Statements.

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


	Common
	Stock		Common		Paid-in			Unearned
	Issued		Stock		Capital			Compensation
	(Shares)		(Thousands of dollars)

December 31, 2005		107,973,436	$	1,080	$	1,044,283		$	(105	)
Net income		-		-		-			-
Other comprehensive income (loss)		-		-		-			-
Total comprehensive income
Adoption of Statement 158		-		-		-			-
Equity unit conversion		11,208,998		112		177,572			-
Repurchase of common stock		-		-		-			-
Common stock issued		1,151,474		11		36,862			158
Common stock dividends -
$1.22 per share		-		-		-			(53	)
December 31, 2006		120,333,908		1,203		1,258,717			-
Net income		-		-		-			-
Other comprehensive income (loss)		-		-		-			-
Total comprehensive income
Repurchase of common stock		-		-		(11,103	)		-
Common stock issued		781,309		8		26,186			-
Common stock dividends -
$1.40 per share		-		-		-			-
December 31, 2007		121,115,217		1,211		1,273,800			-
Net income		-		-		-			-
Other comprehensive income (loss)		-		-		-			-
Total comprehensive income
Repurchase of common stock		-		-		-			-
Common stock issued		531,790		5		27,353			-
Common stock dividends -
$1.56 per share		-		-		-			-
Change in measurement date for
employee benefit plans		-		-		-			-
December 31, 2008		121,647,007	$	1,216	$	1,301,153		$	-
See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(Continued)
	Accumulated
	Other
	Comprehensive			Retained			Treasury
	Income (Loss)			Earnings			Stock			Total
	(Thousands of dollars)

December 31, 2005	$	(56,991	)	$	1,085,845		$	(279,355	)	$	1,794,757
Net income		-			306,312			-			306,312
Other comprehensive income (loss)		63,878			-			-			63,878
Total comprehensive income											370,190
Adoption of Statement 158		32,645			-			-			32,645
Equity unit conversion		-			-			224,764			402,448
Repurchase of common stock		-			-			(285,662	)		(285,662	)
Common Stock issued		-			-			-			37,031
Common stock dividends -
$1.22 per share		-			(135,398	)		-			(135,451	)
December 31, 2006		39,532			1,256,759			(340,253	)		2,215,958
Net income		-			304,921			-			304,921
Other comprehensive income (loss)		(46,601	)		-			-			(46,601	)
Total comprehensive income											258,320
Repurchase of common stock		-			-			(379,110	)		(390,213	)
Common stock issued		-			-			9,237			35,431
Common stock dividends -
$1.40 per share		-			(150,188	)		-			(150,188	)
December 31, 2007		(7,069	)		1,411,492			(710,126	)		1,969,308
Net income		-			311,909			-			311,909
Other comprehensive income (loss)		(63,547	)		-			-			(63,547	)
Total comprehensive income											248,362
Repurchase of common stock		-			-			(29	)		(29	)
Common stock issued		-			-			13,539			40,897
Common stock dividends -
$1.56 per share		-			(162,785	)		-			(162,785	)
Change in measurement date for
employee benefit plans		-			(7,583	)					(7,583	)
December 31, 2008	$	(70,616	)	$	1,553,033		$	(696,616	)	$	2,088,170

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ONEOK, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

A. SUMMARY OF 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 47.7 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest publicly traded master limited partnerships.

We have divided our operations into four reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are as follows:

·	ONEOK Partners

·	Distribution

·	Energy Services

Other

Our ONEOK Partners segment is engaged in the gathering and processing of unprocessed natural gas and fractionation of NGLs, primarily in the Mid-Continent and Rocky Mountain regions covering Oklahoma, Kansas, Montana, North Dakota and Wyoming. These operations include the gathering of unprocessed natural gas produced from crude oil and natural gas wells. Through gathering systems, unprocessed 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. This stream is then separated by a distillation process, referred to as fractionation, into marketable product components such as ethane, ethane/propane (E/P), propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products can then be stored, transported and marketed to a diverse customer base of end-users.

ONEOK Partners also 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, the Texas panhandle and the Rocky Mountain region to fractionators it owns in Oklahoma, Kansas and Texas. 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’ 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.

ONEOK Partners operates interstate and intrastate natural gas transmission pipelines, natural gas storage facilities and non-processable natural gas gathering facilities. ONEOK Partners’ interstate assets transport natural gas through FERC-regulated interstate natural gas pipelines that access supply from Canada, and the Mid-Continent, Rocky Mountain and Gulf Coast regions.

ONEOK Partners’ intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. ONEOK Partners also has access to the major natural gas producing area in south central Kansas. In Texas, its intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market. ONEOK Partners owns or leases storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas. ONEOK Partners’ natural gas pipelines primarily serve LDCs, large industrial companies, municipalities, irrigation customers, power generation facilities and marketing companies.

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. In addition, 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.

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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 transportation and storage capacity and natural gas supply. These services include meeting our customers’ baseload, swing and peaking natural gas commodity requirements on a year-round basis. To provide these bundled services, we lease storage and transportation capacity. Our contracted storage and transportation capacity connects major supply and demand centers throughout the United States and into Canada. With these contracted assets, our business strategies include identifying, developing and delivering specialized services and products valued by our customers, which are primarily LDCs, electric utilities, and commercial and industrial end users. Our storage and transportation capacity allows us opportunities to optimize value through our application of market knowledge and risk management skills.

Critical Accounting Policies

The following is a summary of our most critical accounting policies, which are defined as those policies most important to the portrayal of our financial condition and results of operations and requiring our 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 critical accounting policies and estimates with the Audit Committee of our Board of Directors.

Fair Value Measurements - General - In September 2006, the FASB issued Statement 157, “Fair Value Measurements” that establishes a framework for measuring fair value and requires additional disclosures about fair value measurements. Beginning January 1, 2008, we partially applied Statement 157 as allowed by FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157” that delayed the effective date of Statement 157 for nonrecurring fair value measurements associated with our nonfinancial assets and liabilities. As of January 1, 2008, we applied the provisions of Statement 157 to our recurring fair value measurements, and the impact was not material upon adoption. As of January 1, 2009, we have applied the provisions of Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities, and the impact was not material. FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarified the application of Statement 157 in inactive markets, was issued in October 2008 and was effective for our September 30, 2008, unaudited consolidated financial statements. FSP 157-3 did not have a material impact on our consolidated financial statements.

In February 2007, the FASB issued Statement 159, “The Fair Value Option for Financial Assets and Financial Liabilities” that allows companies to elect to measure specified financial assets and liabilities, firm commitments, and nonfinancial warranty and insurance contracts at fair value on a contract-by-contract basis, with changes in fair value recognized in earnings each reporting period. At January 1, 2008, we did not elect the fair value option under Statement 159, and therefore there was no impact on our consolidated financial statements.

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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 - Generally unobservable inputs, which are developed based on the best information available and may include our own internal data.

See Note C for more discussion of our fair value measurements.

Under Statement 133, entities are required to record all derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. See previous discussion in “Fair Value Measurements” for additional information. 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 we will determine if the hedging instrument is effective. 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 a 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, 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 of exposure to changes in fair values or cash flows. 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. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change, together with the offsetting gain or loss on the hedged item attributable to the risk being hedged.

·	all financially settled derivative contracts are reported on a net basis;

·	derivative instruments considered held for trading purposes that result in physical delivery are reported on a net basis;

·	derivative instruments not considered held for trading purposes that result in physical delivery or services rendered are reported on a gross basis; and

·	derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are reported on a gross basis.

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We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery.

See Note D for more discussion of derivatives and risk management activities.

We assess our goodwill and indefinite-lived intangible assets for impairment at least annually based on Statement 142, “Goodwill and Other Intangible Assets.” There were no impairment charges resulting from our July 1, 2008, impairment test. As a result of recent events in the financial markets and current economic conditions, we performed a review and determined that interim testing of goodwill as of December 31, 2008, was not necessary. As a 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.

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 result in material changes in the costs and liabilities we recognize. See Note J for more discussion of pension and postretirement employee benefits.

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In September 2006, the FASB issued Statement 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans,” which required us to record a balance sheet liability equal to the difference between our benefit obligations and plan assets. Statement 158 also required us to change our measurement date from September 30 to December 31. Statement 158 was effective for our year ended December 31, 2006, except for the measurement date change, which was effective for our year ending December 31, 2008. We determined our net periodic benefit cost for the period October 1, 2007, through December 31, 2008, based on a measurement date of September 30, 2007. The net periodic benefit cost for the period of October 1, 2007, through December 31, 2007, was reflected as an adjustment to retained earnings as of December 31, 2008. The impact of this adjustment was a $7.6 million reduction to retained earnings, net of taxes.

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 in accordance with Statement 5, “Accounting for Contingencies.” We base our estimates on currently available facts and our estimates of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Actual results may differ from our estimates resulting in an impact, positive or negative, on earnings. See Note K for additional discussion of contingencies.

Significant Accounting Policies

Consolidation - Our consolidated financial statements include the accounts of ONEOK and our subsidiaries over which we have control. We have recorded minority interests in consolidated subsidiaries on our Consolidated Balance Sheets to recognize the percent of ONEOK Partners that we do not own. We reflected our percent share of ONEOK Partners’ accumulated other comprehensive income (loss) in our consolidated accumulated other comprehensive income (loss). The remaining percent is reflected as an adjustment to minority interests in consolidated subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. Investments in 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.

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.

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.

Accounts Receivable, net - Accounts receivable represent valid claims against non-affiliated customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the credit worthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of cash collateral, when appropriate. Outstanding customer receivables are regularly reviewed for possible non-payment indicators and allowances for doubtful accounts are recorded based upon management’s estimate of collectibility at each balance sheet date.

Inventories - Our 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.

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Through December 31, 2007, the cost of current natural gas in storage for Oklahoma Natural Gas was determined under the last-in, first-out (LIFO) methodology. The estimated replacement cost of current natural gas in storage was $72.4 million at December 31, 2007, compared with its value under the LIFO method of $85.4 million at December 31, 2007. As of January 1, 2008, Oklahoma Natural Gas was required to change from LIFO to the weighted-average cost methodology based on a change in state law. The impact of this change on our consolidated financial statements was immaterial, as the actual cost of gas is recovered from our rate payers through our purchased gas recovery mechanism.

Natural Gas Imbalances and Commodity Exchanges - Natural gas imbalances and NGL exchanges are valued at market or their contractually stipulated rate. Imbalances and NGL exchanges are settled in cash or made up in-kind, subject to the terms of the pipelines’ tariffs or by agreement.

EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” defines when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction. EITF 04-13 was effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We reviewed the applicability of EITF 04-13 to our operations and determined that it did not have a material impact on our financial position or results of operations.

Property, Plant and Equipment - The following table sets forth our property, plant and equipment by segment, for the periods presented.

	December 31,		December 31,
	2008		2007
	(Thousands of dollars)
Non-Regulated
ONEOK Partners	$	2,465,369	$	2,112,394
Energy Services		7,907		7,845
Other		225,479		177,356
Regulated
ONEOK Partners		3,343,310		2,323,977
Distribution		3,434,554		3,271,920
Property, plant and equipment		9,476,619		7,893,492
Accumulated depreciation and amortization		2,212,850		2,048,311
Net property, plant and equipment	$	7,263,769	$	5,845,181

Our properties are stated at cost which includes 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 transfers 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 expense during the construction or upgrade of qualifying assets. Interest expense capitalized in 2008, 2007 and 2006 was $39.9 million, $15.4 million and $2.0 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 deprecation 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, then 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 result of operations.

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The average depreciation rates for our regulated property are set forth in the following table for the periods indicated.

	Years Ended December 31,
Regulated Property	2008			2007			2006
ONEOK Partners		2.0% - 2.4	%		2.4% - 2.5	%		2.4% - 2.6	%
Distribution		2.7% - 3.0	%		2.7% - 3.0	%		2.7% - 3.3	%

ONEOK Partners’ average depreciation rates for its regulated property decreased in 2008, compared with 2007, due to placing newly constructed natural gas liquids pipeline assets with longer economic lives in service.

Property, plant and equipment on our Consolidated Balance Sheets includes construction work in process for capital projects that have not yet been put in service and therefore are not being depreciated. The following table sets forth our construction work in process, by segment, for the periods presented.

		December 31,		December 31,
		2008		2007
	(Millions of dollars)
ONEOK Partners		$	810.0	$	859.8
Distribution			57.0		51.3
Other			11.0		7.1
Total construction work in process		$	878.0	$	918.2

Assets are transferred out of construction work in process when they are substantially complete and ready for their intended use, in accordance with Statement 34, “Capitalization of Interest Cost.”

Revenue Recognition - Our ONEOK Partners segment includes natural gas gathering and processing, natural gas liquids gathering and fractionation, natural gas pipelines, and natural gas liquids pipelines operations. ONEOK Partners’ natural gas gathering and processing operations record revenue when gas is processed in or transported through company facilities. ONEOK Partners’ natural gas liquids gathering and fractionation operations record revenues based upon contracted services and actual volumes exchanged or stored under service agreements in the month services are provided. Revenue for ONEOK Partners’ natural gas pipelines and natural gas liquids pipelines 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 as of the end of each month. All natural gas residential distribution customers and some 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 as of the end of each month based on physical sales. Retail customers are invoiced on a cyclical basis throughout the month, and we accrue unbilled revenues at the end of each month. 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 Note D “Accounting Treatment” for additional information.

Income Taxes - Income taxes are accounted for using the provisions of Statement 109, “Accounting for Income Taxes.” Deferred income taxes are provided 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. 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.

In June 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109,” which was effective for our year beginning January 1, 2007. This interpretation was issued to clarify the accounting for uncertainty in income taxes recognized in the financial statements by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 requires the recognition of penalties and interest on any unrecognized tax benefits. Our policy is to

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reflect penalties and interest as part of income tax expense as they become applicable. The adoption of FIN 48 had an immaterial impact on our consolidated financial statements, and the impact for 2008 and 2007 was not material.

We file numerous consolidated and separate income tax returns in the United States federal jurisdiction and in many state jurisdictions. We also file returns in Canada. No extensions of statute of limitations have been requested or granted. Our 2007 and 2006 United States federal income tax returns are currently under audit.

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 contained in Statement 71, “Accounting for the Effects of Certain Types of Regulation.” 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 affect 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. If all or a portion of the regulated operations are no longer subject to the provisions of Statement 71, a write-off of regulatory assets and costs not recovered may be required.

At December 31, 2008 and 2007, we recorded regulatory assets of approximately $523.3 million and $309.4 million, respectively, which are being recovered through various rate cases or are expected to be recovered. 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.

Asset Retirement Obligations - Statement 143, “Accounting for Asset Retirement Obligations,” applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. Statement 143 requires that 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. 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 is 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 as defined by Statement 143. However, these non-legal asset-removal obligations are accounted for as a regulatory liability under Statement 71. Historically, the regulatory authorities that have jurisdiction over our regulated operations have not required us to track this amount; rather, these costs are addressed prospectively as 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 have reclassified the estimated non-legal asset removal obligation from accumulated deprecation and amortization to 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 Payment - Statement 123R, “Share-Based Payment,” requires companies to expense the fair value of share-based payments net of estimated forfeitures. We adopted Statement 123R as of January 1, 2006, and elected to use the modified prospective method. Statement 123R did not have a material impact on our consolidated financial statements as we have been expensing share-based payments since our adoption of Statement 148, “Accounting for Stock-Based Compensation - Transition and Disclosure,” on January 1, 2003. Awards granted after the adoption of Statement 123R are expensed under the requirements of Statement 123R, while equity awards granted prior to the adoption of Statement 123R will continue to be expensed under Statement 148.

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

Other

Master Netting Arrangements - In April 2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39,” which requires entities that offset the fair value amounts recognized for derivative receivables and payables to also offset the fair value amounts recognized for the right to reclaim cash collateral with the same counterparty under a master netting arrangement. We applied the provisions of FSP FIN 39-1 to our consolidated financial statements beginning January 1, 2008, and the impact was not material. See Note C for applicable disclosures.

Business Combinations - In December 2007, the FASB issued Statement 141R, “Business Combinations,” which will require most identifiable assets, liabilities, noncontrolling interest (previously referred to as minority interest) and goodwill acquired in a business combination to be recorded at fair value. Statement 141R was effective for our year beginning January 1, 2009. Because the provisions of Statement 141R are applied prospectively, our 2009 and subsequent consolidated financial statements will not be impacted unless we complete a business combination.

Noncontrolling Interests - In December 2007, the FASB issued Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to ARB No. 51,” which requires a noncontrolling interest (previously referred to as minority interest) to be reported as a component of equity. Statement 160 was effective for our year beginning January 1, 2009, and requires retroactive adoption of the presentation and disclosure requirements for existing minority interests beginning with our March 31, 2009, Quarterly Report on Form 10-Q. Statement 160 is not expected to have a material impact on our consolidated financial statements; however, certain financial statement presentation changes and additional required disclosures will be made.

Derivative Instruments and Hedging Activities Disclosure - In March 2008, the FASB issued Statement 161, “Disclosures about Derivative Instruments and Hedging Activities - an amendment to FASB Statement No. 133,” which requires enhanced disclosures about how derivative and hedging activities affect our financial position, financial performance and cash flows. Statement 161 was effective for our year beginning January 1, 2009, and will be applied prospectively beginning with our March 31, 2009, Quarterly Report on Form 10-Q.

Equity Method Investments - In November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting Considerations,” which clarified certain issues that arose following the issuance of Statements 141R and 160 related to the accounting for equity method investments. EITF 08-6 was effective for our year beginning January 1, 2009, and is not expected to have a material impact on our consolidated financial statements.

Postretirement Benefit Plan Assets - In December 2008, the FASB issued FSP FAS 132R-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which amends Statement 132R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to require enhanced disclosures about our plan assets, including our investment policies, major categories of plan assets, significant concentrations of risk within plan assets, and inputs and valuation techniques used to measure the fair value of plan assets. FSP FAS 132R-1 is effective for our fiscal year ending December 31, 2009, and will be applied prospectively.

Reclassifications - Certain amounts in our consolidated financial statements have been reclassified to conform to the 2008 presentation. These reclassifications did not impact previously reported net income or shareholders’ equity.

B. ACQUISITIONS AND DIVESTITURES

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ownership of Heartland. ConocoPhillips owns the other 50 percent of Heartland and is the managing partner of the Heartland joint venture, which consists primarily of a refined petroleum products terminal and pipelines with access to two other refined petroleum products terminals. ONEOK Partners’ investment in Heartland is accounted for under the equity method of accounting. Financing for this transaction came from a portion of the proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent Senior Notes due 2037 (the 2037 Notes). See Note I for a discussion of the 2037 Notes. The working capital settlement was finalized in April 2008, with no material adjustments.

Overland Pass Pipeline Company - In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture called Overland Pass Pipeline Company. In November 2008, Overland Pass Pipeline Company completed construction of a 760-mile natural gas liquids pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market center in Conway, Kansas. The Overland Pass Pipeline is designed to transport approximately 110 MBbl/d of unfractionated NGLs and can be increased to approximately 255 MBbl/d with additional pump facilities. During 2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its interest in the joint venture and for reimbursement of initial capital expenditures. A subsidiary of ONEOK Partners owns 99 percent of the joint venture, managed the construction project, advanced all costs associated with construction and is currently operating the pipeline. On or before November 17, 2010, Williams will have the option to increase its ownership up to 50 percent, with the purchase price being determined in accordance with the joint venture’s operating agreement. If Williams exercises its option to increase its ownership to the full 50 percent, Williams would have the option to become operator. The pipeline project cost was approximately $575 million, excluding AFUDC.

As part of a long-term agreement, Williams dedicated its NGL production from two of its natural gas processing plants in Wyoming to the Overland Pass Pipeline. Subsidiaries of ONEOK Partners will provide downstream fractionation, storage and transportation services to Williams.

ONEOK Partners - In April 2006, we sold certain assets comprising our former gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners for approximately $3 billion, including $1.35 billion in cash, before adjustments, and approximately 36.5 million Class B limited partner units in ONEOK Partners. The Class B limited partner units and the related general partner interest contribution were valued at approximately $1.65 billion. We also purchased, through ONEOK Partners GP, from an affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK Partners for $40 million. This purchase resulted in our ownership of the entire 2 percent general partner interest in ONEOK Partners. Following the completion of the transactions, we owned a total of approximately 37.0 million common and Class B limited partner units and the entire 2 percent general partner interest and control the partnership. Our overall interest in ONEOK Partners, including the 2 percent general partner interest, was 45.7 percent at the date of acquisition.

Disposition of 20 percent interest in Northern Border Pipeline - In April 2006, in connection with the transactions described immediately above, our ONEOK Partners segment completed the sale of a 20 percent partnership interest in Northern Border Pipeline to TC PipeLines for approximately $297 million. Our ONEOK Partners segment recorded a gain on the sale of approximately $113.9 million in the second quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50 percent interest in Northern Border Pipeline, and an affiliate of TransCanada became operator of the pipeline in April 2007. Neither ONEOK Partners nor TC PipeLines has control of Northern Border Pipeline, as control is shared equally through Northern Border Pipeline’s Management Committee. As a result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline has been accounted for as an investment under the equity method, applied on a retroactive basis to January 1, 2006.

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C. FAIR VALUE MEASUREMENTS

See Note A for a discussion of our fair value measurements and the fair value hierarchy.

Recurring Fair Value Measurements - The following table sets forth our recurring fair value measurements for the period indicated.

	December 31, 2008
	Level 1			Level 2			Level 3			Netting (a)			Total
	(Thousands of dollars)
Assets
Derivatives	$	580,029		$	215,116		$	454,377		$	(840,814	)	$	408,708
Trading securities		4,910			-			-			-			4,910
Available-for-sale investment securities		1,665			-			-			-			1,665
Fair value of firm commitments		-			-			42,179			-			42,179
Total assets	$	586,604		$	215,116		$	496,556		$	(840,814	)	$	457,462

Liabilities
Derivatives	$	(501,726	)	$	(55,705	)	$	(412,022	)	$	748,136		$	(221,317	)
Long-term debt swapped to floating		-			-			(171,455	)		-			(171,455	)
Total liabilities	$	(501,726	)	$	(55,705	)	$	(583,477	)	$	748,136		$	(392,772	)
(a) - Our derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis. We net derivative assets and liabilities, including cash collateral in accordance with FSP FIN 39-1, when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract. At December 31, 2008, we held $92.7 million of cash collateral.

For derivatives for which fair value is determined based on multiple inputs, Statement 157 requires that the measurement for an individual derivative be categorized within a single level based on the lowest-level input that is significant to the fair value measurement in its entirety.

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

Our Level 2 fair value inputs are based on NYMEX-settled prices that are utilized to determine the fair value of certain non-exchange-traded financial instruments, including natural gas and crude oil swaps.

Our Level 3 inputs are based on over-the-counter quotes, market volatilities derived from NYMEX-settled prices, internally developed basis curves incorporating observable and unobservable market data, modeling techniques using observable market data and historical correlations of NGL product prices to crude oil, and spot and forward LIBOR curves. The derivatives categorized as Level 3 include over-the-counter swaps and options for natural gas and crude oil, NGL swaps and forwards, natural gas basis and swing swaps and physical forward contracts, and interest-rate swaps. Also included in Level 3 are the fair values of firm commitments and long-term debt that have been hedged.

Transfers in and out of Level 3 typically result from derivatives for which fair value is determined based on multiple inputs. Since we categorize our derivatives based on the lowest level input that is significant, a derivative can move between Level 2 and Level 3 as the value of the various inputs changes.

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The following table sets forth the reconciliation of our Level 3 fair value measurements for the period indicated.

	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Long-Term Debt			Total
	(Thousands of dollars)
January 1, 2008	$	(54,582	)	$	42,684		$	(338,538	)	$	(350,436	)
Total realized/unrealized gains (losses):
Included in earnings (a)		6,080			(505	)		(2,917	)		2,658
Included in other comprehensive income (loss)		84,592			-			-			84,592
Terminations prior to maturity		(5,074	)		-			170,000			164,926
Transfers in and/or out of Level 3		11,339			-			-			11,339
December 31, 2008	$	42,355		$	42,179		$	(171,455	)	$	(86,921	)

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, 2008 (a)	$	(116,127	)	$	153,221		$	(2,917	)	$	34,177
(a) - Reported in revenues in our Consolidated Statements of Income.

Realized/unrealized gains (losses) include the realization of our fair value derivative contracts through maturity, changes in fair value of our hedged firm commitments and fixed-rate debt swapped to floating. Terminations prior to maturity represents swap contracts terminated prior to maturity that will remain in accumulated other comprehensive income (loss) until the underlying forecasted transaction occurs; and the long-term debt associated with the interest rate swaps that were terminated during the period. Transfers into Level 3 represent existing assets or liabilities that were previously categorized at a higher level for which the inputs to our models became unobservable. Transfers out of Level 3 represent existing assets and liabilities that were previously classified as Level 3 for which the inputs became observable in accordance with our hierarchy policy discussed on page 78.

Fair Value - The following table represents the fair value of our energy marketing and risk management assets and liabilities for the periods indicated.

	December 31, 2008				December 31, 2007
	Assets		Liabilities		Assets		Liabilities
	(Thousands of dollars)
Energy Services - financial non-trading instruments:
Natural gas
Exchange-traded instruments	$	31,509	$	640	$	4,739	$	14,853
Over-the-counter swaps		73,095		1,624		41,633		19,160
Options		186		-		1,887		2,467
Other (a)		39,453		2,515		7,469		2,741
		144,243		4,779		55,728		39,221
Energy Services - financial trading instruments:
Natural gas
Exchange-traded instruments		6,158		144		1,641		888
Over-the-counter swaps		14,002		321		11,258		8,013
Options		7,043		191		14,173		18,654
Other (a)		358		249		420		287
		27,561		905		27,492		27,842
ONEOK Partners - cash flow hedges		63,780		-		-		21,304
Distribution - natural gas swaps		-		23,003		-		9,752
Energy Services - cash flow hedges		62,250		44,248		57,966		8,344
Energy Services - fair value hedges		109,419		148,382		5,237		51,343
Interest rate swaps - fair value hedges		1,455		-		1,496		2,958

Total fair value	$	408,708	$	221,317	$	147,919	$	160,764
(a) - Other includes physical natural gas.

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Financial Instruments - The following information represents the carrying amounts and estimated fair values of our financial instruments for the periods indicated, excluding energy marketing and risk management assets and liabilities, which are listed in the table above.

The approximate fair value of cash and cash equivalents, short-term investments, accounts and notes receivable and accounts and notes payable is equal to book value, due to their short-term nature. The estimated fair value of long-term debt has been determined using quoted market prices of the same or similar issues, discounted cash flows, and/or rates currently available to us for debt with similar terms and remaining maturities. The book value of our long-term debt was $4.23 billion and $4.64 billion at December 31, 2008 and 2007, respectively. The approximate fair value of our long-term debt was $3.95 billion and $4.75 billion at December 31, 2008 and 2007, respectively.

The tables below show information about our investment securities classified as available-for-sale.

		December 31,
		2008		2007		2006
	(Thousands of dollars)
Available-for-sale securities held
Aggregate fair value		$	1,665	$	24,151	$	22,416
Reported in accumulated other comprehensive income (loss) for net unrealized holding gains		$	815	$	13,678	$	12,614

	Years Ended December 31,
	2008		2007		2006
	(Thousands of dollars)
Available-for-sale securities held
Gains reclassified to earnings from accumulated other comprehensive income (loss)	$	11,142	$	-	$	-

Available-for-sale securities sold
Proceeds from sale (a)	$	3,886	$	-	$	-
Gain from sale (a)	$	3,369	$	-	$	-
(a) - We sold a portion of our available-for-sale securities and used specific identification to determine the cost of the securities sold.

We transferred securities from available-for-sale to trading during the year ended December 31, 2008, and recognized a $7.7 million gain, due to a reconsideration event in August 2008 when our NYMEX Holding, Inc. Class A shares held were converted to CME Group, Inc. (CME) Class A shares due to the NYMEX Holding, Inc. and CME merger. A modification was made to the number of shares required to be maintained by NYMEX Holding, Inc. Class A Members which resulted in our sale of certain shares and the reclassification of the remaining shares to trading. These trading securities were still held as of December 31, 2008.

The gains reclassified into earnings from accumulated other comprehensive income (loss) for the year ended December 31, 2008, of $11.1 million include the $7.7 million gain discussed in the previous paragraph, as well as a $3.4 million realized gain on the sale of available-for-sale securities.

D. ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES

Risk Policy and Oversight - Market risks are monitored by our risk control group that is responsible for ensuring compliance with our risk management policies.

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

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trading activities. The committee also monitors risk metrics including value-at-risk (VAR) and mark-to-market losses. We have a corporate risk control organization that is assigned responsibility for establishing and enforcing the policies and procedures and monitoring certain risk metrics. Key risk control activities include credit review and approval, credit and performance risk measurement and monitoring, validation of transactions, portfolio valuation, VAR and other risk metrics.

Commodity and Interest Rate Risk Management Activities - Our operating results are affected by commodity price fluctuations. We routinely enter into derivative financial instruments to minimize the risk of commodity price fluctuations related to anticipated sales of natural gas and condensate, NGLs, purchase and sale commitments, fuel requirements, currency exposure, transportation and storage contracts, and natural gas inventories. We are also subject to the risk of interest-rate fluctuations 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.

Our Energy Services segment includes our wholesale and retail natural gas marketing and financial trading operations. Our Energy Services segment mitigates the commodity risk associated with our fixed-price physical purchase and sale commitments through the use of derivative instruments. With respect to the net open positions that exist within our marketing and financial trading operations, fluctuating commodity market prices can impact our financial position and results of operations, either favorably or unfavorably. 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.

Operating margins associated with ONEOK Partners’ natural gas gathering and processing and natural gas liquids gathering and fractionation businesses are sensitive to changes in natural gas, condensate and NGL prices, principally as a result of contractual terms under which natural gas is processed and products are sold. ONEOK Partners uses physical forward sales and derivative instruments to secure a certain price for natural gas, condensate and NGL products.

Our Distribution segment also 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 mechanism.

Accounting Treatment - We account for derivative instruments and hedging activities in accordance with Statement 133. Under Statement 133, entities are required to record derivative instruments at fair value, with the exception of normal purchases and normal sales that are expected to result in physical delivery. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, we account for changes in fair value of the derivative instrument in earnings as they occur. We record changes in the fair value of derivative instruments that are considered held for trading purposes as revenues and derivative instruments considered not held for trading purposes as cost of sales and fuel in our Consolidated Statements of Income. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposure to changes in fair values, cash flows or foreign currencies. For hedges of exposure to changes in fair value, the gain or loss on the derivative instrument is recognized in earnings during the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. The difference between the change in fair value of the derivative instrument and the change in fair value of the hedged item represents hedge ineffectiveness, which is reported in earnings during the period the ineffectiveness occurs. 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 in earnings when the forecasted transaction affects earnings.

As required by Statement 133, 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 by performing a regression analysis on our cash flow and fair value hedging relationships quarterly to ensure the hedge relationships are highly effective on a retrospective and prospective basis, as required by Statement 133. We also document our normal physical purchases and physical sales transactions that we elect to exempt from fair value accounting treatment. Although we believe we have appropriate internal controls over our accounting for derivatives, interpreting Statement 133 and the related documentation requirements is very complex. In addition, future interpretations may impact our application of Statement 133.

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EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined in EITF Issue No. 02-3,” provides that the determination of whether realized gains and losses on physically settled derivative contracts not held for trading purposes should be reported in the Consolidated Statements of Income on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. Consideration of the facts and circumstances should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts.

We evaluate the accounting treatment related to the presentation of revenues from the different types of activities to determine which amounts should be reported on a gross or net basis under the guidance in EITF 03-11. For derivative instruments considered held for trading purposes that result in physical delivery, the indicators in EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” are used to determine the proper treatment. These activities and all financially settled derivative contracts are reported on a net basis.

For derivative instruments that are not considered held for trading purposes and that result in physical delivery, the indicators in EITF 03-11 and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” are used to determine the proper treatment. We account for the realized revenues and purchase costs of these contracts that result in physical delivery on a gross basis. We apply the indicators in EITF 99-19 to determine the appropriate accounting treatment for non-derivative contracts that result in physical delivery. Derivatives that qualify for the normal purchase or sale exception as defined in Statement 133 are also reported on a gross basis.

Cash flows from futures, forwards, options and swaps that are accounted for as hedges are included in the same cash flow statement category as the cash flows from the related hedged items.

Fair Value Hedges - In 2008 and prior years, we and ONEOK Partners 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. Net interest expense savings for 2008 from amortization of terminated swaps was $10.5 million, and the remaining net savings for all terminated swaps will be recognized over the following periods.

			ONEOK
	ONEOK		Partners		Total
	(Millions of dollars)
2009	$	6.5	$	3.7	$	10.2
2010	$	6.4	$	3.7	$	10.1
2011	$	3.4	$	0.9	$	4.3
2012	$	1.7	$	-	$	1.7
2013	$	1.7	$	-	$	1.7
Thereafter	$	25.3	$	-	$	25.3

At December 31, 2008, the interest on $170 million of our fixed-rate debt was swapped to floating using interest-rate swaps. The floating rate was based on both the three- and six-month LIBOR, depending upon the swap. Based on the actual performance for the year ended December 31, 2008, the weighted-average interest rate on the swapped debt decreased from 6.17 percent to 4.39 percent. At December 31, 2008, we recorded a net asset of $1.5 million to recognize the interest-rate swaps at fair value. Long-term debt includes an additional $1.5 million to recognize the change in the fair value of the related hedged debt. ONEOK Partners had no interest-rate swap agreements at December 31, 2008. See Note I for additional discussion of long-term debt.

Our Energy Services segment uses basis swaps to hedge the fair value of certain firm transportation commitments. Net gains or losses from the fair value hedges and ineffectiveness are recorded to cost of sales and fuel. The ineffectiveness related to these hedges included losses of $3.3 million, $5.3 million and $9.0 million for 2008, 2007 and 2006, respectively.

In September 2007, our Energy Services segment was notified that a portion of the volume contracted under our firm transportation agreement with Cheyenne Plains Gas Pipeline Company would be curtailed due to a fire at a Cheyenne Plains pipeline compressor station. The fire damaged a significant amount of instrumentation and electrical wiring, causing Cheyenne Plains Gas Pipeline Company to declare a force majeure event on the pipeline. This firm commitment was hedged in accordance with Statement 133. The discontinuance of fair value hedge accounting on the portion of the firm commitment

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that was impacted by the force majeure event resulted in a loss of approximately $5.5 million in the third quarter of 2007, of which $2.4 million of insurance proceeds were recovered and recognized in the first quarter of 2008.

Cash Flow Hedges - Our Energy Services segment uses derivative instruments to hedge the cash flows associated with our anticipated purchases and sales of natural gas and the cost of fuel used in transportation of natural gas. Accumulated other comprehensive income (loss) at December 31, 2008, includes gains of approximately $10.3 million, net of tax, related to these hedges that will be realized within the next 24 months as forecasted transactions affect earnings. If prices remain at current levels, we will recognize $7.2 million in net gains over the next 12 months, and we will recognize net gains of $3.1 million thereafter. In accordance with Statement 133, the actual gains or losses will be reclassified into earnings when the related physical transactions affect earnings.

During the third and fourth quarters of 2008, the carrying value of natural gas in storage was written down by $308.5 million in order to record inventory at the lower of cost or market. As required by Statement 133, we reclassified $298.8 million of deferred gains, before income taxes, on associated cash flow hedges from accumulated other comprehensive income (loss) into earnings.

Through an affiliate, our ONEOK Partners segment periodically enters into derivative instruments to hedge the cash flows associated with its exposure to changes in the price of natural gas, NGLs and condensate. At December 31, 2008, our ONEOK Partners’ segment reflected an unrealized gain of $20.1 million, net of tax, in accumulated other comprehensive income (loss), with a corresponding offset in energy marketing and risk management assets and liabilities, all of which will be recognized over the next 12 months.

Ineffectiveness related to our cash flow hedges resulted in gains of approximately $1.4 million, $0.2 million and $15.0 million in 2008, 2007 and 2006, respectively. In the event that it becomes probable that a forecasted transaction will not occur, we would discontinue cash flow hedge treatment, which would affect earnings. There were no material gains or losses in 2008, 2007 or 2006 due to the discontinuance of cash flow hedge treatment.

Credit Risk - 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 and credit default swap rates), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposures associated with a single counterparty.

Our counterparties consist primarily of financial institutions, major energy companies, LDCs, electric utilities 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.

E. GOODWILL AND INTANGIBLE ASSETS

Goodwill

Carrying Amount - The following table sets forth goodwill recorded on our Consolidated Balance Sheets for the periods indicated.

	December 31,
	2008		2007
	(Thousands of dollars)
ONEOK Partners	$	433,537	$	431,418
Distribution		157,953		157,953
Energy Services		10,255		10,255
Other		1,099		1,099
Total Goodwill	$	602,844	$	600,725

Equity Method Goodwill - For the investments we account for under the equity method, the premium or excess cost over underlying fair value of net assets is referred to as equity method goodwill. Investment in unconsolidated affiliates on our accompanying Consolidated Balance Sheets includes equity method goodwill of $185.6 million as of December 31, 2008 and 2007.

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Impairment Test - We apply the provisions of Statement 142 and perform our annual impairment test on July 1. There were no impairment charges resulting from our July 1, 2008, impairment test. As a result of recent events in the financial markets and current economic conditions, we performed a review and determined that interim testing of goodwill as of December 31, 2008, was not necessary.

Black Mesa - During 2006, we recorded a goodwill and asset impairment related to ONEOK Partners’ Black Mesa Pipeline of $8.4 million and $3.6 million, respectively, which was recorded as depreciation and amortization. The reduction to our net income, net of minority interests and income taxes, was $3.0 million.

Intangible Assets

Our ONEOK Partners segment had $279.8 million of intangible assets primarily related to acquired contracts, 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 both 2008 and 2007 was $7.7 million, and the aggregate amortization expense for each of the next five years is estimated to be approximately $7.7 million. The following table reflects the gross carrying amount and accumulated amortization of intangible assets for the periods presented.

		Gross		Accumulated			Net
		Intangible Assets		Amortization			Intangible Assets
	(Thousands of dollars)
December 31, 2007		$	462,214	$	(19,166	)	$	443,048
December 31, 2008		$	462,214	$	(26,832	)	$	435,382

F. OTHER COMPREHENSIVE INCOME (LOSS)

The table below shows the gross amount of other comprehensive income (loss) and related tax (expense) benefit for the periods indicated.

				Year Ended									Year Ended
	December 31, 2008									December 31, 2007
	Gross			Tax (Expense) or Benefit			Net			Gross			Tax (Expense) or Benefit			Net
	(Thousands of dollars)
Unrealized gains on energy marketing and risk management assets/liabilities	$	276,400			(103,705	)	$	172,695		$	48,888		$	(21,836	)	$	27,052
Less: Gains on energy marketing and risk management assets/liabilities recognized in net income		277,413			(107,303	)		170,110			149,535			(57,840	)		91,695
Unrealized holding gains (losses) on investment securities arising during the period		(9,837	)		3,805			(6,032	)		1,735			(671	)		1,064
Less: Gains on investment securities recognized in net income		11,142			(4,310	)		6,832			-			-			-
Change in pension and postretirement benefit plan liability		(86,869	)		33,601			(53,268	)		27,687			(10,709	)		16,978
Other comprehensive income (loss)	$	(108,861	)	$	45,314		$	(63,547	)	$	(71,225	)	$	24,624		$	(46,601	)

The gains on energy marketing and risk management assets/liabilities recognized in net income presented in the table above include the reclassification of gains on our cash flow hedges from accumulated other comprehensive income (loss) into earnings as discussed in Note D.

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The table below shows 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, 2006	$	89,971	$	12,614	$	(63,053)	$	39,532
Other comprehensive income (loss)		(64,643)		1,064		16,978		(46,601)
December 31, 2007	$	25,328	$	13,678	$	(46,075)	$	(7,069)
Other comprehensive income (loss)		2,585		(12,864)		(53,268)		(63,547)
December 31, 2008	$	27,913	$	814	$	(99,343)	$	(70,616)

G. CAPITAL STOCK

Series A and B Convertible Preferred Stock - There are no shares of Series A or Series B currently 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, 2008, we had approximately 175 million shares of authorized and unreserved common stock available for issuance.

Stock Repurchase Plan - On May 17, 2007, our Board of Directors authorized a stock buy back program to repurchase up to 7.5 million shares of our currently issued and outstanding common stock. On June 28, 2007, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with Bank of America, N.A. (Bank of America) at an initial price of $49.33 per share for a total of $370 million. Bank of America borrowed 7.5 million of our shares from third parties and purchased shares in the open market to settle its short position. Our repurchase was subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by Bank of America over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In September 2007, the accelerated share repurchase agreement with Bank of America was settled, which resulted in Bank of America delivering an additional 186,402 shares of our common stock to us at no additional cost. All shares under this accelerated repurchase agreement were recorded as treasury shares in our Consolidated Balance Sheets. These transactions completed the plan approved by our Board of Directors and we have no remaining shares available for repurchase under our stock repurchase plan.

On August 7, 2006, under a previously authorized stock repurchase plan, we repurchased 7.5 million shares of our outstanding common stock under an accelerated share repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52 per share for a total of $281.4 million. These shares were recorded as treasury shares in our Consolidated Balance Sheets. UBS borrowed 7.5 million of our shares from third parties and purchased shares in the open market to settle its short position. Our repurchase was subject to a financial adjustment based on the volume-weighted average price, less a discount, of the shares subsequently repurchased by UBS over the course of the repurchase period. The price adjustment could have been settled, at our option, in cash or in shares of our common stock. In February 2007, the forward purchase contract with UBS was settled for a cash payment of $20.1 million, which was recorded in equity.

In accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share Repurchase Program,” the repurchases were accounted for as two separate transactions: (i) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date; and (ii) as a forward contract indexed to our common stock. Additionally, we classified the forward contracts as equity under EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.”

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Dividends - Quarterly dividends paid on our common stock for shareholders of record as of the close of business on January 31, 2008, April 30, 2008, July 31, 2008, and October 31, 2008, were $0.38 per share, $0.38 per share, $0.40 per share and $0.40 per share, respectively. Additionally, a quarterly dividend of $0.40 per share was declared in January 2009, payable in the first quarter of 2009.

Equity Units - On February 16, 2006, we successfully settled our 16.1 million equity units to 19.5 million shares of our common stock. Of this amount, 8.3 million shares were issued from treasury stock and approximately 11.2 million shares were newly issued. Holders of the equity units received 1.2119 shares of our common stock for each equity unit they owned. The number of shares that we issued for each stock purchase contract was determined based on our average closing price over the 20 trading day period ending on the third trading day prior to February 16, 2006. With the settlement, we received $402.4 million in cash, which was used to pay down our short-term bridge financing agreement.

H. CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK Credit Agreement - In July 2006 and September 2008, ONEOK amended and restated its $1.2 billion credit agreement (ONEOK Credit Agreement). The amended agreement includes revised pricing, an extension of the maturity date from 2009 to 2011, an option for additional extensions of the maturity date with the consent of the lenders, an option to request an increase in the commitments of the lenders of up to an additional $500 million and a change in certain sublimits. The interest rates applicable to extensions of credit under this agreement are based, at ONEOK’s election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds; or (ii) the Eurodollar rate plus a set number of basis points based on ONEOK’s current long-term unsecured debt ratings.

Under the ONEOK Credit Agreement, 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 our 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.

ONEOK 364-Day Facility - In August 2008, ONEOK entered into a $400 million 364-day credit agreement (364-Day Facility). The interest rate is based, at ONEOK’s election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate; or (ii) the Eurodollar rate plus a set number of basis points based on ONEOK’s current long-term unsecured debt ratings by Moody’s and S&P. The 364-Day Facility is being used as an additional back-up to ONEOK’s commercial paper program and for working capital, capital expenditures and other general corporate purposes. The 364-Day Facility contains substantially similar affirmative and negative covenants as the ONEOK Credit Agreement.

The debt covenant calculations in the ONEOK Credit Agreement and the 364-Day Facility exclude the debt of ONEOK Partners. Upon breach of any covenant by ONEOK, amounts outstanding under the ONEOK Credit Agreement or the 364-Day Facility may become immediately due and payable. At December 31, 2008, ONEOK’s stand-alone debt-to-capital ratio was 58.2 percent and ONEOK was in compliance with all covenants under the ONEOK Credit Agreement and the ONEOK 364-Day Facility.

At December 31, 2008, ONEOK had no commercial paper outstanding, $1.4 billion in borrowings outstanding and $64.6 million in letters of credit issued under the ONEOK Credit Agreement, leaving $135.4 million of credit available under the ONEOK Credit Agreement and 364-Day Facility. The ONEOK Credit Agreement and the 364-Day Facility also serve as a back-up to ONEOK’s commercial paper program.

The average interest rate on ONEOK’s short-term debt outstanding was 4.51 percent and 5.00 percent at December 31, 2008 and 2007, respectively.

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At December 31, 2007, ONEOK had $102.6 million in commercial paper outstanding, no borrowings outstanding and $38.1 million in letters of credit issued under the ONEOK Credit Agreement, leaving $1.1 billion of credit available under the ONEOK Credit Agreement. In addition, ONEOK had $20.6 million in other letters of credit issued at December 31, 2007.

ONEOK Partners Credit Agreement - In March 2007, ONEOK Partners amended and restated its revolving credit facility agreement (ONEOK Partners Credit Agreement), with several banks and other financial institutions and lenders in the following principal ways: (i) revised the pricing; (ii) extended the maturity by one year to March 2012; (iii) eliminated the interest coverage ratio covenant; (iv) increased the permitted ratio of indebtedness to EBITDA to 5 to 1 (from 4.75 to 1); (v) increased the swingline sub-facility commitments from $15 million to $50 million; and (vi) changed the permitted amount of subsidiary indebtedness from $35 million to 10 percent of ONEOK Partners’ consolidated indebtedness. The interest rates applicable to extensions of credit under this agreement are based, at ONEOK Partners’ election, on either (i) the higher of prime or one-half of one percent above the Federal Funds Rate, which is the rate that banks charge each other for the overnight borrowing of funds; or (ii) the Eurodollar rate plus a set number of basis points, depending on ONEOK Partners’ current long-term unsecured debt ratings.

In July 2007, ONEOK Partners exercised the accordion feature in the ONEOK Partners Credit Agreement to increase the commitment amounts by $250 million to a total of $1.0 billion.

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 plus minority interest in income of consolidated subsidiaries, distributions received from investments and EBITDA related to any approved capital projects less equity earnings from investments and the equity portion of AFUDC) 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 breach of any covenant, discussed above, amounts outstanding under the ONEOK Partners Credit Agreement may become immediately due and payable. At December 31, 2008, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.1 to 1, and ONEOK Partners was in compliance with all covenants under the ONEOK Partners Credit Agreement.

The average interest rate of borrowings under the ONEOK Partners Credit Agreement was 4.22 percent and 5.40 percent at December 31, 2008 and 2007, respectively. ONEOK Partners had $870 million and $100 million of borrowings outstanding and $130 million and $900 million available under the ONEOK Partners Credit Agreement at December 31, 2008 and 2007, respectively.

ONEOK Partners has an outstanding $25 million letter of credit issued by Royal Bank of Canada, which is used for counterparty credit support.

ONEOK Partners also has a $15 million Senior Unsecured Letter of Credit Facility and Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is being used, and an agreement with Royal Bank of Canada, pursuant to which a $12 million letter of credit was issued. Both agreements are used to support various permits required by the KDHE for ONEOK Partners’ ongoing business in Kansas.

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I. LONG-TERM DEBT

The following table sets forth our long-term debt for the periods indicated. All notes are senior unsecured obligations, ranking equally in right of payment with all of our existing and future unsecured senior indebtedness.

	December 31,			December 31,
	2008			2007
	(Thousands of dollars)
ONEOK
$402,500 at 5.51% due 2008	$	-		$	402,303
$100,000 at 6.0% due 2009		100,000			100,000
$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		91,371			92,000
$100,000 at 6.5% due 2028		89,970			90,902
$100,000 at 6.875% due 2028		100,000			100,000
$400,000 at 6.0% due 2035		400,000			400,000
Other		2,712			2,958
		1,584,053			1,988,163
ONEOK Partners
$250,000 at 8.875% due 2010		250,000			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
$600,000 at 6.65% due 2036		600,000			600,000
$600,000 at 6.85% due 2037		600,000			600,000
		2,475,000			2,475,000

Guardian Pipeline
Average 7.85%, due 2022		121,711			133,641

Total long-term notes payable		4,180,764			4,596,804
Unamortized portion of terminated swaps and fair value of hedged debt		55,035			43,682
Unamortized debt premium		(5,023	)		(4,961	)
Current maturities		(118,195	)		(420,479	)
Long-term debt	$	4,112,581		$	4,215,046

The aggregate maturities of long-term debt outstanding for the years 2009 through 2013 are shown below.

			ONEOK	Guardian
	ONEOK		Partners	Pipeline		Total
	(Millions of dollars)
2009	$	106.3	$ -	$	11.9	$ 118.2
2010	$	6.3	$ 250.0	$	11.9	$ 268.2
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

Additionally, $181.4 million of our debt is callable at par at our option from now until maturity, which is 2019 for $91.4 million and 2028 for $90.0 million. Certain debt agreements have negative covenants that relate to liens and sale/leaseback transactions.

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ONEOK Partners’ Debt Issuance - In September 2007, ONEOK Partners completed an underwritten public offering of $600 million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued under ONEOK Partners’ existing shelf registration statement filed with the SEC.

The indenture governing the 2037 Notes does not limit the aggregate principal amount of debt securities that may be issued and provides that debt securities may be issued from time to time in one or more additional series. The indenture contains covenants including, among other provisions, limitations on ONEOK Partners’ ability to place liens on its property or assets and its ability to sell and lease back its property.

ONEOK Partners’ $250 million and $225 million senior notes, due 2010 and 2011, respectively, contain provisions that require ONEOK Partners to offer to repurchase the senior notes at par value if its Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment grade rating is not reinstated within a period of 40 days. Further, the indentures governing ONEOK Partners’ senior notes due 2010 and 2011 include an event of default upon acceleration of other indebtedness of $25 million or more and the indentures governing the senior notes due 2012, 2016, 2036 and 2037 include an event of default upon the acceleration of other indebtedness of $100 million or more that would be triggered by such an offer to repurchase. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes due 2010, 2011, 2012, 2016, 2036 and 2037 to declare those notes immediately due and payable in full.

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 $121.7 million in notes outstanding at December 31, 2008, 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 (net income plus interest expense, income taxes, operating lease expense and depreciation and amortization) 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 5.75 to 1. Upon any breach of these covenants, all amounts outstanding under the master shelf agreement may become due and payable immediately. At December 31, 2008, Guardian Pipeline’s EBITDAR-to-fixed-charges ratio was 4.95 to 1, the ratio of total indebtedness to EBITDAR was 3.34 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.

J. EMPLOYEE BENEFIT PLANS

Retirement and Other Postretirement Benefit Plans

Retirement Plans - We have defined benefit retirement plans covering certain full-time employees. Nonbargaining unit employees hired after December 31, 2004, are not eligible for our defined benefit pension plan; however, they are covered by a defined contribution profit-sharing plan. Certain officers and key employees are also eligible to participate in supplemental

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retirement plans. We generally fund pension costs at a level equal to the minimum amount required under the Employee Retirement Income Security Act of 1974.

Other 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.

Statement 158 - See Note A for a discussion of the impact of the adoption of Statement 158, including the change in our measurement date from September 30 to December 31.

Regulatory Treatment - The OCC, KCC, and regulatory authorities in Texas have approved the recovery of pension costs and other 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.

Our regulated entities have historically recovered pension and other postretirement benefit costs, as determined by Statement 87, “Employers’ Accounting for Pensions,” and Statement 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” respectively, through rates. We believe it is probable that regulators will continue to include the net periodic pension and other 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 other 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 other postretirement benefit plans benefit obligations and fair value of plan assets for the periods indicated. Due to the change in our measurement date as discussed in Note A, the changes in benefit obligation and plan assets shown in the following tables are for the 15-month period from October 1, 2007 through December 31, 2008.

		Pension Benefits						Postretirement Benefits
		December 31,						December 31,
		2008			2007			2008			2007
Change in Benefit Obligation	(Thousands of dollars)
Benefit obligation, beginning of period		$	819,999		$	832,980		$	294,730		$	271,510
Service cost			25,577			21,050			7,198			6,392
Interest cost			61,649			48,608			22,206			15,830
Plan participants' contributions			-			-			3,299			2,882
Actuarial (gain) loss			46,967			(32,697	)		(21,983	)		14,742
Benefits paid			(66,629	)		(49,942	)		(26,685	)		(16,626	)
Benefit obligation, end of period		$	887,563		$	819,999		$	278,765		$	294,730

Change in Plan Assets
Fair value of plan assets, beginning of period		$	771,878		$	710,377		$	79,314		$	68,440
Actual return on plan assets			(220,955	)		107,305			(17,644	)		5,214
Employer contributions			117,597			4,138			12,444			14,925
Transfers in			-			-			3,573			-
Benefits paid			(66,629	)		(49,942	)		-			-
Fair value of assets, end of period		$	601,891		$	771,878		$	77,687		$	88,579
Balance at December 31		$	(285,672	)	$	(48,121	)	$	(201,078	)	$	(206,151	)

Non-current assets		$	-		$	10,028		$	-		$	-
Current liabilities			(2,706	)		(2,497	)		-			-
Non-current liabilities			(282,966	)		(55,652	)		(201,078	)		(206,151	)
Balance at December 31		$	(285,672	)	$	(48,121	)	$	(201,078	)	$	(206,151	)

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The accumulated benefit obligation for our pension plans was $824.7 million and $759.2 million at December 31, 2008 and 2007, respectively.

There are no plan assets expected to be withdrawn and returned to us in 2009.

Components of Net Periodic Benefit Cost - The following tables set forth the components of net periodic benefit cost for our pension and other postretirement benefit plans for the periods indicated.

		Pension Benefits
		Years Ended December 31,
		2008			2007			2006
Components of Net Periodic Benefit Cost	(Thousands of dollars)
Service cost		$	20,165		$	21,050		$	20,980
Interest cost			49,801			48,608			43,425
Expected return on plan assets			(61,268	)		(58,154	)		(57,586	)
Amortization of unrecognized prior service cost			1,551			1,486			1,511
Amortization of net loss			9,548			16,139			13,314
Net periodic benefit cost		$	19,797		$	29,129		$	21,644

	Postretirement Benefits
	Years Ended December 31,
	2008			2007			2006
Components of Net Periodic Benefit Cost	(Thousands of dollars)
Service cost	$	5,675		$	6,392		$	6,332
Interest cost		17,899			15,830			14,156
Expected return on plan assets		(7,421	)		(6,389	)		(4,565	)
Amortization of unrecognized net asset at adoption		3,189			3,189			3,189
Amortization of unrecognized prior service cost		(2,003	)		(2,277	)		(2,286	)
Amortization of net loss		10,972			9,927			9,085
Net periodic benefit cost	$	28,311		$	26,672		$	25,911

Other Comprehensive Income (Loss) - The following table sets forth the amounts recognized in other comprehensive income (loss) for 2008 related to our pension benefits and postretirement benefits.

	Pension Benefits			Postretirement Benefits
	December 31, 2008			December 31, 2008
	(Thousands of dollars)
Regulatory asset gain (loss)	$	252,747		$	492
Net gain (loss) arising during the period		(343,274	)		(1,531	)
Amortization of regulatory asset		(11,465	)		(12,911	)
Amortization of transition obligation		-			3,986
Amortization of prior service (cost) credit		1,941			(2,504	)
Amortization of loss		11,935			13,715
Deferred income taxes		34,417			(816	)
Total recognized in other comprehensive income (loss)	$	(53,699	)	$	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.

	Pension Benefits						Postretirement Benefits
	December 31,						December 31,
	2008			2007			2008			2007
	(Thousands of dollars)
Transition obligation	$	-		$	-		$	(12,724	)	$	(16,711	)
Prior service credit (cost)		(6,852	)		(8,791	)		8,384			10,888
Accumulated gain (loss)		(455,089	)		(123,750	)		(113,228	)		(125,412	)
Accumulated other comprehensive income (loss) before regulatory assets		(461,941	)		(132,541	)		(117,568	)		(131,235	)
Regulatory asset for regulated entities		331,882			90,600			85,619			98,038
Accumulated other comprehensive income (loss) after regulatory assets		(130,059	)		(41,941	)		(31,949	)		(33,197	)
Deferred income taxes		50,307			16,222			12,358			12,841
Accumulated other comprehensive income (loss), net of tax	$	(79,752	)	$	(25,719	)	$	(19,591	)	$	(20,356	)

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 2009	(Thousands of dollars)
Transition obligation		$	-	$	3,189
Prior service credit (cost)		$	1,565	$	(2,003	)
Net loss		$	17,322	$	9,660

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,
	2008	2007		2008	2007
Discount rate	6.25%	6.25%		6.25%	6.25%
Compensation increase rate	4.3% - 4.8%	3.5% - 4.5%		4.3% - 4.8%	3.5% - 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,
	2008	2007		2008	2007
Discount rate	6.25%	6.00%		6.25%	6.00%
Expected long-term return on plan assets	8.50%	8.75%		8.50%	8.75%
Compensation increase rate	3.5% - 4.5%	3.5% - 4.5%		3.5% - 4.0%	3.5% - 4.0%

We determine our overall expected long-term rate of return on plan assets assumption based on our review of historical returns and the economic growth models from our consultants.

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Our discount rates for 2008 and 2007 are based on matching the amount and timing of the projected benefit payments to a spot-rate yield curve, which provides zero-coupon interest rates into the future. The methodology for developing the yield curve includes selecting the bonds to be included (only bonds rated Aa by Moody’s but excluding callable bonds, bonds with less than a minimum issue size, yield “outliers” and various other filtering criteria to remove unsuitable bonds). Once the bonds are selected, a best-fit regression curve to the bond data is determined, modeling yield to maturity as a function of years to maturity. This coupon yield curve is converted to a spot-yield curve using the calculation technique that assumes the price of a coupon bond for a given maturity equals the present value of the underlying bond cash flows using zero-coupon spot rates. Once the yield curve is developed, the projected cash flows for the plan for each year in the future are calculated. These projected cash flows values are based on the most recent valuation. Each annual cash flow of the plan obligations is discounted using the yield at the appropriate point on the curve, and then the single equivalent discount rate that would yield the same value for the cash flow is determined.

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

	2008	2007
Health care cost trend rate assumed for next year	5.0% - 9.0%	6.6% - 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	2018	2012

	One-Percentage		One-Percentage
	Point Increase		Point Decrease
	(Thousands of dollars)
Effect on total of service and interest cost	$	1,989	$	(1,706	)
Effect on postretirement benefit obligation	$	19,585	$	(17,171	)

Plan Assets - The following table sets forth our pension and postretirement benefit plan weighted-average asset allocations as of the measurement date.

	Pension Benefits							Postretirement Benefits
	Percentage of Plan Assets							Percentage of Plan Assets
Asset Category		2008			2007			2008			2007
Corporate bonds			5	%		6	%		25	%		14	%
Insurance contracts			13	%		11	%		-			-
High yield corporate bonds			9	%		10	%		-			-
Large-cap value equities			12	%		15	%		14	%		15	%
Large-cap growth equities			14	%		18	%		17	%		22	%
Mid-cap equities			9	%		13	%		6	%		8	%
Small-cap equities			7	%		11	%		12	%		16	%
International equities			12	%		16	%		10	%		13	%
Other (a)			19	%		-			16	%		12	%
Total			100	%		100	%		100	%		100	%
(a) - Primarily money market funds

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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 US 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.

Corporate bonds / insurance contracts	20	%
High yield corporate bonds	10	%
Large-cap value equities	16	%
Large-cap growth equities	16	%
Mid- and small-cap value equities	10	%
Mid- and small-cap growth equities	10	%
International equities	15	%
Alternative investments	2	%
Venture capital	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.

Contributions - For 2008, $113.7 million and $8.0 million of contributions were made to our pension plan and other postretirement benefit plan, respectively. We presently anticipate our total 2009 contributions will be $31.2 million for the pension plan and $11.4 million for the other postretirement benefit plan.

Pension and Other Postretirement Benefit Payments - Benefit payments for our pension and other postretirement benefit plans for the 15-month period ending December 31, 2008, were $66.6 million and $26.7 million, respectively. The following table sets forth the pension benefits and postretirement benefit payments expected to be paid in 2009-2018.

	Pension Benefits	Postretirement Benefits
Benefits to be paid in:	(Thousands of dollars)
2009	$ 52,958	$	16,155
2010	$ 54,317	$	17,253
2011	$ 55,882	$	18,300
2012	$ 58,275	$	19,238
2013	$ 60,136	$	19,354
2014 through 2018	$ 339,437	$	113,661

The expected benefits to be paid are based on the same assumptions used to measure our benefit obligation at December 31, 2008, and include estimated future employee service.

Other Employee Benefit Plans

Thrift Plan - We have a Thrift Plan covering all full-time employees. 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 $14.7 million, $13.2 million and $12.8 million in 2008, 2007 and 2006, respectively.

Profit-Sharing Plan - We have a profit-sharing plan for all nonbargaining unit employees hired after December 31, 2004. Nonbargaining unit employees who were employed prior to January 1, 2005, 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. 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 $3.2 million, $2.7 million and $1.6 million in 2008, 2007 and 2006, respectively.

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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 2008, 2007 and 2006.

K. COMMITMENTS AND CONTINGENCIES

Operating Leases - In July 2007, ONEOK Leasing Company, our subsidiary, gave notice of its intent to exercise its option to purchase ONEOK Plaza on or before the end of the current lease term set to expire on September 30, 2009. In March 2008, ONEOK Leasing Company purchased ONEOK Plaza for a total purchase price of approximately $48 million, which included $17.1 million for the present value of the remaining lease payments and $30.9 million for the base purchase price.

We lease excess office space in ONEOK Plaza. We received rental revenue of $2.6 million in 2008 and $2.9 million in 2007 and 2006. Estimated minimum future rental payments to be received under existing contracts for subleases are $1.9 million in 2009, $0.8 million in 2010 and $0.7 million in 2011.

Future minimum lease payments under non-cancelable operating leases on a gas processing plant, storage contracts, office space, pipeline equipment, rights-of-way and vehicles are shown in the table below.

	ONEOK	ONEOK Partners	Total
	(Millions of dollars)
2009	$ 88.8	$ 18.4	$ 107.2
2010	$ 55.9	$ 16.0	$ 71.9
2011	$ 61.2	$ 15.5	$ 76.7
2012	$ 32.9	$ 8.8	$ 41.7
2013	$ 25.4	$ 2.1	$ 27.5

The amounts in the ONEOK column above include the following minimum lease payments relating to the lease of a gas processing plant for $24.0 million in 2009, $24.2 million in 2010, and $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 column above exclude intercompany payments relating to the lease of a gas processing plant.

Environmental Liabilities - We are subject to multiple environmental, historical and wildlife preservation laws and 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 our lines or facilities, in the process of transporting natural gas, NGLs, or refined products, 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. 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, 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.

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

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

To date, we have incurred remediation costs of $7.8 million and have accrued an additional $4.2 million related to the sites where soil remediation has yet to be completed. These estimates are recorded on an undiscounted basis. For the site that is currently in the assessment phase, we have completed some analysis but are unable at this point to accurately estimate aggregate costs that may be required to satisfy our remedial obligations at this site. Until the site assessment is complete and the KDHE approves the remediation plan, we will not have complete information available to us to accurately estimate remediation costs.

The costs associated with these sites do not include other potential expenses that might be incurred, such as ongoing and additional water monitoring and remediation, unasserted property damage claims, personal injury or natural resource claims, unbudgeted legal expenses or other costs for which we may be held liable but with respect to which we cannot reasonably estimate an amount. As of this date, we have no knowledge of any of these types of claims. The foregoing estimates do not consider potential insurance recoveries, recoveries through rates or recoveries from unaffiliated parties, to which we may be entitled. We have filed claims with our insurance carriers relating to these sites, and we have recovered a portion of our costs incurred to date. We have not recorded any amounts for potential insurance recoveries or recoveries from unaffiliated parties, and we are not recovering any environmental amounts in rates. As more information related to the site investigations and remediation activities becomes available, and to the extent such amounts are expected to exceed our current estimates, additional expenses could be recorded. Such amounts could be material to our results of operations and cash flows depending on the remediation and number of years over which the remediation is required to be completed.

Our expenditures for environmental evaluation, mitigation and remediation to date have not been significant in relation to our results of operations, and there were no material effects upon earnings during 2008, 2007 or 2006 related to compliance with environmental regulations.

Legal Proceedings - We are a party to various litigation matters and claims that are 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.

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L. INCOME TAXES

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

	Years Ended December 31,
		2008		2007		2006
Current income taxes	(Thousands of dollars)
Federal		$	18,833	$	100,517	$	69,698
State			10,047		19,063		10,312
Total current income taxes from continuing operations			28,880		119,580		80,010
Deferred income taxes
Federal			143,807		56,887		96,464
State			21,384		8,130		17,290
Total deferred income taxes from continuing operations			165,191		65,017		113,754

Total provision for income taxes before discontinued operations			194,071		184,597		193,764
Discontinued operations			-		-		(232	)
Total provision for income taxes		$	194,071	$	184,597	$	193,532

The following table is a reconciliation of our income tax expense for the periods indicated.

	Years Ended December 31,
	2008			2007			2006
	(Thousands of dollars)
Pretax income from continuing operations	$	505,980		$	489,518		$	500,441
Federal statutory income tax rate		35	%		35	%		35	%
Provision for federal income taxes		177,093			171,331			175,154
Amortization of distribution property investment tax credit		(455	)		(505	)		(525	)
State income taxes, net of federal tax benefit		20,431			17,676			18,809
Other, net		(2,998	)		(3,905	)		326
Income tax expense	$	194,071		$	184,597		$	193,764

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,
	2008		2007
Deferred tax assets	(Thousands of dollars)
Employee benefits and other accrued liabilities	$	161,947	$	134,056
Net operating loss carryforward		4,226		4,715
Other comprehensive income		43,747		-
Other		23,051		27,374
Total deferred tax assets		232,971		166,145

Deferred tax liabilities
Excess of tax over book depreciation and depletion		372,123		344,601
Purchased gas adjustment		20,047		9,015
Investment in joint ventures		564,234		490,093
Regulatory assets		180,037		115,689
Other comprehensive income		-		1,567
Other		746		2,720
Total deferred tax liabilities		1,137,187		963,685
Net deferred tax liabilities	$	904,216	$	797,540

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At December 31, 2008, ONEOK Partners had approximately $4.2 million of tax benefits available related to net operating loss carryforwards, which will expire between the years 2022 and 2027. We believe that it is more likely than not that the tax benefits of the net operating loss carryforwards will be utilized prior to their expiration; therefore, no valuation allowance is necessary.

We had income taxes receivable of approximately $77.1 million and $13.2 million at December 31, 2008 and 2007, respectively.

M. SEGMENTS

Segment Descriptions - We have divided our operations into four reportable business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment. These segments are 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 delivers natural gas to residential, commercial and industrial customers, and transports natural gas; (iii) our Energy Services segment markets natural gas to wholesale and retail customers; and (iv) our Other segment primarily consists of the operating and leasing operations of our headquarters building and a related parking facility. Our Distribution segment is comprised of regulated public utilities, and portions of our ONEOK Partners segment are also regulated.

Accounting Policies - The accounting policies of the segments are described in Note A. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. Overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income.

Customers - The primary customers for our ONEOK Partners segment include major and independent oil and gas production companies, natural gas gathering and processing companies, petrochemical, refining and NGL marketing companies, LDCs, power generating companies, natural gas marketing companies, NGL gathering companies and propane distributors. Our Distribution segment provides natural gas to residential, commercial, industrial, wholesale, public authority and transportation customers. Our Energy Services segment buys natural gas from producers and other marketing companies and sells natural gas to LDCs, municipalities, producers, large industrials, power generators, retail aggregators and other marketing companies, as well as residential and small commercial/industrial companies.

In 2008, 2007 and 2006, we had no single external customer from which we received 10 percent or more of our consolidated gross revenues.

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

Year Ended December 31, 2008	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	6,975,320	$	2,177,615		$	7,001,296	$	3,202		$	16,157,433
Intersegment revenues		744,886		7			584,507		(1,329,400	)		-
Total revenues	$	7,720,206	$	2,177,622		$	7,585,803	$	(1,326,198	)	$	16,157,433

Net margin	$	1,140,659	$	680,971		$	110,716	$	3,181		$	1,935,527
Operating costs		371,797		375,328			35,593		(5,806	)		776,912
Depreciation and amortization		124,765		116,782			921		1,459			243,927
Gain or (loss) on sale of assets		713		(21	)		1,500		124			2,316
Operating income	$	644,810	$	188,840		$	75,702	$	7,652		$	917,004

Equity earnings from investments	$	101,432	$	-		$	-	$	-		$	101,432
Investments in unconsolidated affiliates	$	755,492	$	-		$	-	$	-		$	755,492
Minority interests in consolidated subsidiaries	$	5,941	$	-		$	-	$	1,073,428		$	1,079,369
Total assets	$	7,254,272	$	3,063,374		$	1,752,256	$	1,056,160		$	13,126,062
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 $439.3 million, net margin of $334.1 million and operating income of $158.8 million.
(b) - All of our Distribution segment's operations are regulated.

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Year Ended December 31, 2007	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	5,204,794	$	2,099,056		$	6,170,084	$	3,480		$	13,477,414
Intersegment revenues		626,764		7			459,319		(1,086,090	)		-
Total revenues	$	5,831,558	$	2,099,063		$	6,629,403	$	(1,082,610	)	$	13,477,414

Net margin	$	895,893	$	663,648		$	247,402	$	3,165		$	1,810,108
Operating costs		337,356		377,778			39,920		6,456			761,510
Depreciation and amortization		113,704		111,615			2,147		498			227,964
Gain or (loss) on sale of assets		1,950		(56	)		-		15			1,909
Operating income	$	446,783	$	174,199		$	205,335	$	(3,774	)	$	822,543

Equity earnings from investments	$	89,908	$	-		$	-	$	-		$	89,908
Investments in unconsolidated affiliates	$	756,260	$	-		$	-	$	-		$	756,260
Minority interests in consolidated subsidiaries	$	5,802	$	-		$	-	$	796,162		$	801,964
Total assets	$	6,112,065	$	3,045,249		$	1,549,012	$	355,708		$	11,062,034
Capital expenditures	$	709,858	$	162,044		$	158	$	11,643		$	883,703
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $344.3 million, net margin of $273.7 million and operating income of $122.4 million.
(b) - All of our Distribution segment's operations are regulated.

Year Ended December 31, 2006	ONEOK Partners (a)		Distribution (b)		Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	4,142,546	$	1,958,192	$	5,846,258	$	(26,670	)	$	11,920,326
Intersegment revenues		595,702		7		489,549		(1,085,258	)		-
Total revenues	$	4,738,248	$	1,958,199	$	6,335,807	$	(1,111,928	)	$	11,920,326

Net margin	$	843,548	$	599,797	$	273,818	$	4,821		$	1,721,984
Operating costs		325,774		371,460		42,464		1,069			740,767
Depreciation and amortization		122,045		110,858		2,149		491			235,543
Gain on sale of assets		115,483		18		-		1,027			116,528
Operating income	$	511,212	$	117,497	$	229,205	$	4,288		$	862,202

Equity earnings from investments	$	95,883	$	-	$	-	$	-		$	95,883
Investments in unconsolidated affiliates	$	748,879	$	-	$	-	$	-		$	748,879
Minority interests in consolidated subsidiaries	$	5,606	$	-	$	-	$	795,039		$	800,645
Total assets	$	4,921,717	$	2,940,514	$	2,023,663	$	505,188		$	10,391,082
Capital expenditures	$	201,746	$	159,026	$	-	$	15,534		$	376,306
(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment's regulated operations had revenues of $335.9 million, net margin of $261.8 million and operating income of $240.1 million, including $113.9 million from a gain on sale of assets, for the year ended December 31, 2006.
(b) - All of our Distribution segment's operations are regulated.

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N. STOCK-BASED COMPENSATION

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 approximately 5.0 million shares of common stock for issuance under the plan. In December 2008, we amended the Equity Compensation Plan to allow for the deferral of awards granted in stock or cash, in accordance with Internal Revenue Code section 409A requirements. This deferral option is applicable for certain awards granted in 2006 and later, and vesting after 2008.

Restricted Stock Incentive Units - Restricted stock incentive units may be granted to key employees with ownership of the common stock underlying the incentive unit vesting over a period determined by the Committee. Awards granted to date vest over a three-year period. Awards granted in 2008, 2007 and 2006 entitle the grantee to receive shares of our common stock. Awards granted in 2005 entitled the grantee to receive two-thirds of the grant in our common stock (equity awards) and one-third of the grant in cash (liability awards). The equity 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. The portion of the grants that are settled in cash are classified as liability awards with fair value based on the fair market value of our common stock, reduced by expected dividend payments and adjusted for estimated forfeitures, at each reporting date. No dividends are paid on the restricted stock incentive 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. Performance units granted to date 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 performance unit awards granted in 2008, 2007 and 2006 entitle the grantee to receive the grant in shares of our common stock. Under Statement 123R, our 2008, 2007 and 2006 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.

The performance unit awards granted in 2005 entitled the grantee to receive two-thirds of the grant in shares of our common stock (equity awards) and one-third of the grant in cash (liability awards). The fair values of these performance units that were classified as equity awards were calculated as of the date of grant were not adjusted upon adoption of Statement 123R. The fair values of the one-third liability portion of the performance units were estimated at each reporting date based on a Monte Carlo model.

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. Options issued to date become void upon voluntary termination of employment other than retirement. In the event of retirement or involuntary termination, the optionee may exercise the option within a period determined by the Executive Compensation Committee (the 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. A portion of the options issued to date

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can be exercised after one year from grant date and an option must be exercised no later than 10 years after grant date. Effective January 1, 2007, we eliminated the restored option feature for outstanding stock option grants.

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.

Options - Options may be granted to non-employee directors on the same terms as those granted under the LTIP.

General

Effective January 1, 2006, we adopted Statement 123R. See Note A for additional information. For all awards outstanding, we used a forfeiture rate ranging from zero percent to 13 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 $13.1 million, $12.0 million and $17.6 million 2008, 2007 and 2006, respectively, which is net of $8.3 million, $7.5 million and $11.2 million of tax benefits, respectively. No compensation cost was capitalized for 2008, 2007 and 2006.

Cash received from the exercise of awards under all share-based payment arrangements was $3.8 million and $7.4 million for 2008 and 2007, respectively. The actual tax benefit realized for the anticipated tax deductions of the exercise of share-based payment arrangements totaled $1.4 million and $4.6 million for 2008 and 2007, respectively. No cash was used to settle the equity portion of the restricted stock unit and performance unit awards granted under share-based payment arrangements.

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, 2007		953,146		$	24.69
Exercised		(176,215	)	$	25.72
Expired		(2,625	)	$	28.69
Outstanding December 31, 2008		774,306		$	24.44

Exercisable December 31, 2008		774,306		$	24.44

The aggregate intrinsic value in the table below represents the total pre-tax intrinsic value, based on our year-end closing stock price of $29.12, that would have been received by the option holders had all option holders exercised their options as of December 31, 2008.

	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)
$14.58 to $21.87	376,485	3.04	$	16.98	$	4,571
$21.88 to $32.82	179,666	1.86	$	24.69	$	796
$32.83 to $43.67	218,155	2.15	$	37.11	$	-

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The fair value of each restored option was estimated on the date of grant using the Black-Scholes model and the assumptions in the table below.

		December 31, 2006
Volatility (a)		15.43% to 25.23%
Dividend Yield		3.24% to 4.00%
Risk-free Interest Rate		4.39% to 5.18%
(a) - Volatility was based on historical volatility over twelve months using daily stock price observations.

The weighted-average period of outstanding options is 2.5 years. As of December 31, 2008, all stock options were fully vested and expensed. The following table sets forth various statistics relating to our stock option activity.

	December 31, 2008		December 31, 2007		December 31, 2006
Weighted-average grant date fair value of options restored (per share)	(a)		(a)		$	5.57
Intrinsic value of options exercised (thousands of dollars)	$	3,652	$	12,129	$	10,246
Fair value of options granted (thousands of dollars)	(a)		(a)		$	1,990
(a) - Due to our elimination of the restored option feature effective January 1, 2007, no grants were restored in 2007 or 2008.

Restricted Stock Unit Activity

The total fair value of shares vested during 2008 was $5.9 million. As of December 31, 2008, there was $5.5 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 the equity portion of the restricted stock unit awards.

	Number of			Weighted
	Shares			Average Price
Nonvested December 31, 2007		461,627		$	31.56
Granted		53,550		$	47.44
Released to participants		(86,076	)	$	25.34
Forfeited		(1,969	)	$	38.16
Nonvested December 31, 2008		427,132		$	34.78

	December 31, 2008		December 31, 2007		December 31, 2006
Weighted-average grant date fair value (per share)	$	43.22	$	36.82	$	25.98
Fair value of shares granted (thousands of dollars)	$	2,314	$	9,733	$	3,761

The following table sets forth activity for the liability portion of the restricted stock unit awards.

	Number of			Weighted
	Shares			Average Price
Nonvested December 31, 2007		40,583		$	25.07
Released to participants		(40,583	)	$	25.19
Forfeited		-		$	-
Nonvested December 31, 2008		-		$	-

Performance Unit Activity

The total fair value of shares vested during 2008 was $14.9 million. As of December 31, 2008, there was $14.5 million of total unrecognized compensation cost related to the nonvested performance unit awards, which is expected to be recognized

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over a weighted-average period of 1.1 years. The following tables set forth activity and various statistics related to the performance unit equity awards and the assumptions used in the valuations of the 2008, 2007 and 2006 grants at the grant date.

	Number of			Weighted
	Units			Average Price
Nonvested December 31, 2007		936,916		$	29.63
Granted		387,125		$	47.44
Released to participants (a)		(211,517	)	$	25.48
Forfeited		(20,975	)	$	38.32
Nonvested December 31, 2008		1,091,549		$	36.58
(a) - Performance awards granted in 2005 and released in 2008 were adjusted with a 150 percent performance factor; for the equity awards, this resulted in an additional 105,760 shares released to participants.

	2008	2007	2006
Volatility (a)	22.50%	20.30%	18.80%
Dividend Yield	3.20%	3.79%	3.70%
Risk-free Interest Rate	2.46%	4.80%	4.32%
(a) - Volatility was based on historical volatility over three years using daily stock price observations.

	December 31, 2008		December 31, 2007		December 31, 2006
Weighted-average grant date fair value (per share)	$	43.88	$	37.58	$	25.98
Fair value of shares granted (thousands of dollars)	$	16,987	$	12,366	$	12,444

The following tables set forth activity for the performance unit liability awards and the assumptions used in the valuations at the end of each period indicated.

	Number of			Weighted
	Units			Average Price
Nonvested December 31, 2007		106,139		$	25.48
Released to participants (a)		(105,758	)	$	25.48
Forfeited		(381	)	$	26.57
Nonvested December 31, 2008		-		$	-
(a) - Performance awards granted in 2005 and released in 2008 were adjusted with a 150 percent performance factor; for the liability awards, this resulted in an additional 52,880 liability units released to participants.

	2008	2007	2006
Volatility (a)	(b)	21.80%	20.30%
Dividend Yield	(b)	3.05%	3.62%
Risk-free Interest Rate	(b)	3.07%	4.74%
(a) - Volatility was based on historical volatility over three years using daily stock price observations.
(b) - Nonvested balance at December 31, 2008 was zero.

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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 52 percent, 59 percent and 63 percent of employees participated in the plan in 2008, 2007 and 2006, respectively. Under the plan, we sold 297,864 shares at $24.41 in 2008, 217,369 shares at $36.85 per share in 2007, and 340,364 shares at $22.57 per share in 2006.

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, and 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. We have reserved a total of 300,000 shares of common stock for issuance under this program.

There were no shares issued to employees under this program in 2008. Shares issued to employees under this program totaled 44,099 and 40,705 for the years ended December 31, 2007 and 2006, respectively. Compensation expense related to the Employee Stock Award Plan was $2.2 million and $1.6 million in 2007 and 2006, respectively.

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 and/or meeting fees, plus accrued interest. Under the phantom stock option, directors may defer all or a portion of their annual retainer and/or meeting 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. In December 2008, we amended the Deferred Compensation Plan for Non-Employee Directors in accordance with Internal Revenue Code section 409A requirements.

O. UNCONSOLIDATED AFFILIATES

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

	Net
	Ownership		December 31,			December 31,
	Interest		2008			2007
			(Thousands of dollars)
Northern Border Pipeline		50 %	$	392,601		$	418,982
Bighorn Gas Gathering, L.L.C.		49 %		97,289			97,716
Fort Union Gas Gathering		37 %		108,642			85,197
Lost Creek Gathering Company, L.L.C. (a)		35 %		77,773			75,612
Other	Various			79,187			78,753
Investments in unconsolidated affiliates			$	755,492	(b)	$	756,260	(b)

(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 E) was $185.6 million at December 31, 2008 and 2007.

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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,
	2008		2007		2006
	(Thousands of dollars)
Northern Border Pipeline (a)	$	65,912	$	62,008	$	72,393
Bighorn Gas Gathering, L.L.C.		8,195		7,416		8,223
Fort Union Gas Gathering		14,172		9,681		9,030
Lost Creek Gathering Company, L.L.C.		5,365		4,790		5,363
Other		7,788		6,013		874
Equity Earnings From Investments	$	101,432	$	89,908	$	95,883

(a) - For the first three months of 2006, ONEOK Partners included 70 percent of Northern Border Pipeline’s income in equity earnings from investments. After the sale of a 20 percent interest in Northern Border Pipeline in April 2006, ONEOK Partners included 50 percent of Northern Border Pipeline’s income in equity earnings from investments (Note B).

Unconsolidated Affiliates Financial Information - Summarized combined financial information of our unconsolidated affiliates is presented below.

	December 31,
	2008			2007
	(Thousands of dollars)
Balance Sheet
Current assets	$	106,833		$	102,805
Property, plant and equipment, net	$	1,777,350		$	1,724,330
Other noncurrent assets	$	27,547		$	25,882
Current liabilities	$	279,996		$	79,593
Long-term debt	$	543,894		$	717,301
Other noncurrent liabilities	$	14,360		$	10,278
Accumulated other comprehensive income (loss)	$	(5,708	)	$	(2,441	)
Owners' equity	$	1,079,188		$	1,048,286

	Years Ended December 31,
	2008		2007		2006
	(Thousands of dollars)
Income Statement
Operating revenue	$	415,552	$	404,399	$	386,448
Operating expenses	$	179,380	$	172,997	$	159,452
Net income	$	209,915	$	184,434	$	183,732

Distributions paid to us	$	118,010	$	103,785	$	123,427

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P. EARNINGS PER SHARE INFORMATION

The following table sets forth the computation of basic and diluted EPS from continuing operations for the periods indicated.

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

		Year Ended December 31, 2007
						Per Share
		Income		Shares		Amount
Basic EPS from continuing operations	(Thousands, except per share amounts)
Income from continuing operations available for common stock		$	304,921		107,346		$	2.84
Diluted EPS from continuing operations
Effect of other dilutive securities:
Options and other dilutive securities			-		1,952
Income from continuing operations available for common stock
and common stock equivalents		$	304,921		109,298		$	2.79

		Year Ended December 31, 2006
						Per Share
		Income		Shares		Amount
Basic EPS from continuing operations	(Thousands, except per share amounts)
Income from continuing operations available for common stock		$	306,677		112,006		$	2.74
Diluted EPS from continuing operations
Effect of other dilutive securities:
Mandatory convertible units			-		629
Options and other dilutive securities			-		1,842
Income from continuing operations available for common stock
and common stock equivalents		$	306,677		114,477		$	2.68

There were 64,989, 4,601 and 66,463 option shares excluded from the calculation of diluted EPS for 2008, 2007 and 2006, respectively, since their inclusion would be anti-dilutive.

Q. ONEOK PARTNERS

Ownership Interest in ONEOK Partners - See Note B for discussion of the acquisition of the additional general partner interest in ONEOK Partners.

In April 2006, we received newly created Class B limited partner units from ONEOK Partners. As of April 7, 2007, the Class B limited partner units are no longer subordinated to distributions on ONEOK Partners’ common units and generally have the same voting rights as the common units and are entitled to receive increased quarterly distributions and distributions on liquidation equal to 110 percent of the distributions paid with respect to the common units. On June 21, 2007, we, as the sole holder of ONEOK Partners Class B limited partner units, waived our right to receive the increased quarterly distributions on the Class B units for the period April 7, 2007, through December 31, 2007, and continuing thereafter until we give

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ONEOK Partners no less than 90 days advance notice that we have withdrawn our waiver. 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 90 days following delivery of the notice.

Under the ONEOK Partners’ partnership agreement and in conjunction with the issuance of additional common units by ONEOK Partners, we, as the general partner, are required to make equity contributions in order to maintain our representative general partner interest.

Our ownership interest in ONEOK Partners is shown in the table below for the periods presented.

	December 31,		December 31,		December 31,
	2008		2007		2006
General partner interest	2.00%		2.00%		2.00%
Limited partner interest	45.70%	(a)	43.70%	(b)	43.70%	(b)
Total ownership interest	47.70%		45.70%		45.70%
(a) - Represents 5.9 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units.
(b) - Represents 0.5 million common units and approximately 36.5 million Class B units, which are convertible, at our option, into common units.

In March 2008, we purchased from ONEOK Partners, in a private placement, an additional 5.4 million of ONEOK Partners’ common units for a total purchase price of approximately $303.2 million. In addition, ONEOK Partners completed a public offering of 2.5 million common units at $58.10 per common unit and received net proceeds of $140.4 million after deducting underwriting discounts but before offering expenses. In conjunction with ONEOK Partners’ private placement and public offering of common units, ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent general partner interest. We and ONEOK Partners GP funded these amounts with available cash and short-term borrowings.

In April 2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per common unit to the underwriters of the public offering upon their partial exercise of their option to purchase additional common units to cover over-allotments. ONEOK Partners received net proceeds of approximately $7.2 million from the sale of these common units after deducting underwriting discounts but before offering expenses. In conjunction with the partial exercise by the underwriters, ONEOK Partners GP contributed $0.2 million to ONEOK Partners in order to maintain its 2 percent general partner interest.

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’ 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.

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The following table shows ONEOK Partners’ general partner and incentive distributions related to the periods indicated.

		Years Ended December 31,
		2008		2007		2006
	(Thousands of dollars)
General partner distributions		$	9,456	$	7,842	$	6,228
Incentive distributions			76,042		50,627		31,102
Total distributions to general partner		$	85,498	$	58,469	$	37,330

The quarterly distributions paid by ONEOK Partners to limited partners in the first, second, third and fourth quarters of 2008 were $1.025 per unit, $1.04 per unit, $1.06 per unit, and $1.08 per unit, respectively.

In January 2009, ONEOK Partners declared a cash distribution of $1.08 per unit payable in the first quarter. On February 13, 2009, we received the related incentive distribution of $20.3 million for the fourth quarter of 2008, which is included in the table above.

Relationship - We own 47.7 percent of ONEOK Partners and consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows from ONEOK Partners except for our distributions. Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of its partnership agreement. For the years ended December 31, 2008, 2007 and 2006, cash distributions declared from ONEOK Partners to us totaled $266.1 million, $207.4 million and $145.1 million, respectively. See Note M for more information on ONEOK Partners results.

Affiliate Transactions - We have certain transactions with our ONEOK Partners affiliate 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 large portion of ONEOK Partners’ revenues from its natural gas pipelines businesses are from our Energy Services and Distribution segments, which utilize ONEOK Partners’ natural gas transportation and storage services. ONEOK Partners also purchases natural gas from our Energy Services segment for its natural gas liquids operations and its 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 OBPI. In exchange, ONEOK Partners pays us for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of our obligations under equipment leases covering the Bushton Plant.

We provide a variety of services to our affiliates, including cash management and financial services, employee benefits provided through our benefit plans, 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, earnings before interest and taxes and payroll expense.

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The following table shows transactions with ONEOK Partners for the periods shown.

	Years Ended December 31,
	2008		2007		2006
	(Thousands of dollars)
Revenues	$	744,886	$	626,764	$	595,702

Expenses
Cost of sales and fuel	$	107,983	$	89,792	$	177,367
Administrative and general expenses		191,798		171,741		175,270
Interest expense		-		-		21,372
Total expenses	$	299,781	$	261,533	$	374,009

See “Ownership Interest in ONEOK Partners” above for additional discussion of our purchase of common units and ONEOK Partners GP’s additional general partner contributions in March and April 2008.

R. QUARTERLY FINANCIAL DATA (UNAUDITED)

	First		Second		Third		Fourth
Year Ended December 31, 2008	Quarter		Quarter		Quarter		Quarter
	(Thousands of dollars, except per share amounts)
Total Revenues	$	4,902,076	$	4,172,866	$	4,239,246	$	2,843,245
Net Margin	$	585,912	$	420,828	$	455,026	$	473,761
Operating Income	$	333,123	$	173,012	$	192,179	$	218,690
Net Income	$	143,837	$	41,865	$	58,033	$	68,174
Earnings per share from continuing operations
Basic	$	1.38	$	0.40	$	0.56	$	0.65
Diluted	$	1.36	$	0.39	$	0.55	$	0.65

	First		Second		Third		Fourth
Year Ended December 31, 2007	Quarter		Quarter		Quarter		Quarter
	(Thousands of dollars, except per share amounts)
Total Revenues	$	3,806,208	$	2,876,241	$	2,809,997	$	3,984,968
Net Margin	$	564,850	$	367,699	$	340,160	$	537,399
Operating Income	$	328,301	$	135,745	$	102,770	$	255,727
Net Income	$	152,880	$	35,203	$	13,914	$	102,924
Earnings per share from continuing operations
Basic	$	1.38	$	0.32	$	0.13	$	0.99
Diluted	$	1.36	$	0.31	$	0.13	$	0.98

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

We have established disclosure controls and procedures to ensure that information required to be disclosed by us, including our consolidated entities, in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Under the supervision and with the

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participation of senior management, including our Chief Executive Officer (“Principal Executive Officer”) and our Chief Financial Officer (“Principal Financial Officer”), we evaluated our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Exchange Act. Based on this evaluation, our Principal Executive Officer and our Principal Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2008.

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, 2008.

Our internal control over financial reporting as of December 31, 2008, 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

We have made no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2008, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not applicable.

PART III.

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors of the Registrant

Information concerning our directors is set forth in our 2009 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 on Form 10-K.

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 2009 definitive Proxy Statement and is incorporated herein by this reference.

Code of Ethics

Information concerning the code of ethics, or code of business conduct, is set forth in our 2009 definitive Proxy Statement and is incorporated herein by this reference.

Nominating Committee Procedures

Information concerning the nominating committee procedures is set forth in our 2009 definitive Proxy Statement and is incorporated herein by this reference.

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Audit Committee

Information concerning the Audit Committee is set forth in our 2009 definitive Proxy Statement and is incorporated herein by this reference.

Audit Committee Financial Expert

Information concerning the Audit Committee Financial Expert is set forth in our 2009 definitive Proxy Statement and is incorporated herein by this reference.

ITEM 11. EXECUTIVE COMPENSATION

Information on executive compensation is set forth in our 2009 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 2009 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 2009 definitive Proxy Statement and is incorporated herein by this reference.

Equity Compensation Plan Information

The following table sets forth certain information concerning our equity compensation plans as of December 31, 2008.

							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)			2,300,035		$31.71			6,053,331
Equity compensation plans
not approved by security holders (2)			179,133		$27.03	(3)		4,153,578
Total			2,479,168		$31.37			10,206,909

(1) -	Includes shares granted under our Employee Stock Purchase Plan, Employee Stock Award Program, 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 N of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Column (c) includes 1,408,443, 155,648, 2,120,616 and 2,368,624 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 N of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Column (c) includes 503,602, 2,707,003 and 942,973 shares available for future issuance under our Stock Compensation Plan for Non-Employee Directors, Thrift Plan and Profit Sharing Plan, respectively.
(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 $29.12, which represents the year-end closing price of our common stock on the NYSE.

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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 2009 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 2009 definitive Proxy Statement and is incorporated herein by this reference.

PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(1) Financial Statements		Page No.
(a)	Reports of Independent Registered Public Accounting Firms	67-68
(b)	Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006	69
(c)	Consolidated Balance Sheets as of December 31, 2008 and 2007	70-71
(d)	Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 200	73
(e)	Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the years ended December 31, 2008, 2007 and 2006	74-75
(f)	Notes to Consolidated Financial Statements	76-117

(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).

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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 filed September 24, 1998).

4.6

Second Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 5(b) to Form 8-K filed September 24, 1998).

4.7

Third Supplemental Indenture dated February 8, 1999, between ONEOK, Inc. and Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K filed February 8, 1999).

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

First Supplemental Indenture, dated as of January 28, 2003, between ONEOK, Inc. and SunTrust Bank (incorporated by reference from Exhibit 4.22 to Registration Statement on Form 8-A/A filed January 31, 2003).

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

Form of Senior Note Due 2008 (included in Exhibit 4.13).

4.17

Form of 5.20 percent Notes Due 2015 (included in Exhibit 4.14).

4.18

Form of 6.00 percent Notes due 2035 (included in Exhibit 4.15).

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4.19

Not used.

4.20 Not used.

4.21

Not used.

4.22

Not used.

4.23

Not used.

4.24

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).

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.

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

ONEOK, Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit 10(f) to Form 10-K for the fiscal year ended December 31, 2001, filed March 14, 2002).

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.

10.9

ONEOK, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated, dated December 18, 2008.

10.10

Not used.

10.11

Not used.

10.12

Not used.

10.13

Not used.

10.14

Not used.

10.15

Not used.

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10.16

Not used.

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

Not used.

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

Not used.

10.23

Not used.

10.24

Not used.

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. and its affiliates and 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).

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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.

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

First Amendment to Letter of Credit Reimbursement Agreement by and between KBC Bank N.V. and ONEOK, Inc. dated December 19, 2005 (incorporated by reference from Exhibit 10.47 to our Form 10-K for the year ended December 31, 2006, filed March 1, 2007).

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

Purchase Agreement dated June 27, 2007, by and between ONEOK, Inc. (the “Issuer”), and Bank of America, N.A., acting through Banc of America Securities LLC (“Agent”) as agent (incorporated by reference from Exhibit 10.1 to our Form 10-Q filed August 3, 2007).

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

$400,000,000 364-Day Revolving Credit Agreement dated as of August 6, 2008, among ONEOK, Inc., as Borrower, Bank of America, N.A., as the Administrative Agent and Swing Line Lender, the lenders named therein, Barclays Bank, PLC, BNP Paribas, Suntrust Bank and UBS Loan Finance LLC as Co-Documentation Agents, and Banc of America Securities LLC as sole Lead Arranger and sole Book Manager (incorporated by reference from Exhibit 10.4 to the Form 10-Q for the quarter ended June 30, 2008, filed August 6, 2008).

10.53

Common Unit Purchase Agreement between ONEOK, Inc. and ONEOK Partners, L.P. dated March 11, 2008 (incorporated by reference from Exhibit 1.1 to our Form 8-K filed March 12, 2008).

10.54

Form of Performance Unit Award Agreement dated January 15, 2009.

10.55

Form of Restricted Unit Stock Bonus Award Agreement dated January 15, 2009.

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Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2008, 2007, 2006, 2005 and 2004.

16.1

Letter from KPMG LLP dated May 2, 2007, to the Securities and Exchange Commission regarding change in certifying accountant (incorporated by reference to Exhibit 16.1 to our Form 8-K filed on May 2, 2007).

Required information concerning the registrant’s subsidiaries.

23.1

Consent of Independent Registered Public Accounting Firm - PricewaterhouseCoopers LLP.

23.2

Consent of Independent Registered Public Accounting Firm - KPMG LLP.

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)).

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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 24, 2009 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 24th day of February 2009.

/s/ John W. Gibson		/s/ David L. Kyle
John W. Gibson		David L. Kyle
Chief Executive Officer		Chairman of the
		Board of Directors

/s/ Caron A. Lawhorn		/s/ James C. Day
Caron A. Lawhorn		James C. Day
Senior Vice President and		Director
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/ Pattye L. Moore		/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/ Mollie B. Williford
Mollie B. Williford
Director

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