Edgar Filing: ONEOK INC /NEW/

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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

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 checkmark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer X		Accelerated filer		Non-accelerated filer		Smaller reporting company

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes No X

On October 31, 2008, the Company had 104,499,119 shares of common stock outstanding.

ONEOK, Inc.

QUARTERLY REPORT ON FORM 10-Q


Part I.	Financial Information	Page No.

Item 1.	Financial Statements (Unaudited)

	Consolidated Statements of Income - Three and Nine Months Ended September 30, 2008 and 2007	5

	Consolidated Balance Sheets - September 30, 2008 and December 31, 2007	6-7

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2008 and 2007	9

	Consolidated Statement of Shareholders’ Equity and Comprehensive Income - Nine Months Ended September 30, 2008	10-11

	Notes to Consolidated Financial Statements	12-29

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30-52

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52-55

Item 4.	Controls and Procedures	55

Part II.	Other Information

Item 1.	Legal Proceedings	56

Item 1A.	Risk Factors	56-57

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	57

Item 3.	Defaults Upon Senior Securities	57

Item 4.	Submission of Matters to a Vote of Security Holders	57

Item 5.	Other Information	57

Item 6.	Exhibits	57-58

Signature		59

As used in this Quarterly Report on Form 10-Q, references to “we,” “our” or “us” refers to ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.

The statements in this Quarterly Report on Form 10-Q 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 our goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Forward-Looking Statements” and Part II, Item 1A, “Risk Factors” in this Quarterly Report on Form 10-Q and under Part I, Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Glossary

The abbreviations, acronyms and industry terminology used in this Quarterly Report on Form 10-Q are defined as follows:


AFUDC		Allowance for funds used during construction
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
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
EITF		Emerging Issues Task Force
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
KCC		Kansas Corporation Commission
KDHE		Kansas Department of Health and Environment
LDC		Local Distribution Company
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
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
OBPI		ONEOK Bushton Processing Inc.
OCC		Oklahoma Corporation Commission
ONEOK		ONEOK, Inc.
ONEOK Partners		ONEOK Partners, L.P.
ONEOK Partners GP		ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK, Inc. and the sole general partner of ONEOK Partners, L.P.
OPIS		Oil Price Information Service
Overland Pass Pipeline Company		Overland Pass Pipeline Company LLC
S&P		Standard & Poor’s Rating Group
SEC		Securities and Exchange Commission
Statement		Statement of Financial Accounting Standards

AVAILABLE INFORMATION

You can access financial and other information, including news releases, webcasts and presentations, environmental safety and health information, and corporate governance information at our website at www.oneok.com. We also make available on our website 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.

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PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(Unaudited)	2008			2007			2008			2007
	(Thousands of dollars, except per share amounts)
Revenues	$	4,239,246		$	2,809,997		$	13,314,188		$	9,492,446
Cost of sales and fuel		3,784,220			2,469,837			11,852,422			8,219,737
Net Margin		455,026			340,160			1,461,766			1,272,709
Operating Expenses
Operations and maintenance		179,840			160,352			519,263			477,011
Depreciation and amortization		60,249			56,364			179,429			168,458
General taxes		24,068			20,733			66,079			62,317
Total Operating Expenses		264,157			237,449			764,771			707,786
Gain (Loss) on Sale of Assets		1,310			59			1,319			1,893
Operating Income		192,179			102,770			698,314			566,816
Equity earnings from investments (Note K)		29,412			22,162			74,805			64,975
Allowance for equity funds used during construction		15,616			3,691			35,788			6,686
Other income		12,723			1,756			16,659			17,444
Other expense		(11,332	)		(654	)		(16,347	)		(2,213	)
Interest expense		(61,180	)		(62,675	)		(183,100	)		(187,503	)
Income before Minority Interests and Income Taxes		177,418			67,050			626,119			466,205
Minority interests in income of consolidated subsidiaries		(95,354	)		(44,998	)		(235,411	)		(135,013	)
Income taxes		(24,031	)		(8,138	)		(146,973	)		(129,195	)
Net Income	$	58,033		$	13,914		$	243,735		$	201,997

Earnings Per Share of Common Stock (Note L)
Net Earnings Per Share, Basic	$	0.56		$	0.13		$	2.34		$	1.86
Net Earnings Per Share, Diluted	$	0.55		$	0.13		$	2.30		$	1.83


Average Shares of Common Stock (Thousands)
Basic		104,446			103,882			104,319			108,543
Diluted		105,636			105,931			105,843			110,548


Dividends Declared Per Share of Common Stock	$	0.40		$	0.36		$	1.16		$	1.04

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


	September 30,		December 31,
(Unaudited)	2008		2007
Assets	(Thousands of dollars)

Current Assets
Cash and cash equivalents	$	72,944	$	19,105
Trade accounts and notes receivable, net		1,066,606		1,723,212
Gas and natural gas liquids in storage		1,120,077		841,362
Commodity exchanges and imbalances		80,372		82,938
Energy marketing and risk management assets (Note D)		314,905		168,609
Other current assets		365,746		116,249

Total Current Assets		3,020,650		2,951,475


Property, Plant and Equipment
Property, plant and equipment		9,067,172		7,893,492
Accumulated depreciation and amortization		2,174,001		2,048,311
Net Property, Plant and Equipment (Note A)		6,893,171		5,845,181

Investments and Other Assets
Goodwill and intangible assets		1,040,142		1,043,773
Energy marketing and risk management assets (Note D)		45,769		3,978
Investments in unconsolidated affiliates (Note K)		756,449		756,260
Other assets		465,882		461,367
Total Investments and Other Assets		2,308,242		2,265,378
Total Assets	$	12,222,063	$	11,062,034

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
(Unaudited)	2008			2007
Liabilities and Shareholders’ Equity		(Thousands of dollars)

Current Liabilities
Current maturities of long-term debt	$	118,190		$	420,479
Notes payable		1,322,214			202,600
Accounts payable		1,294,630			1,436,005
Commodity exchanges and imbalances		246,392			252,095
Energy marketing and risk management liabilities (Note D)		303,574			133,903
Other current liabilities		332,469			436,585
Total Current Liabilities		3,617,469			2,881,667

Long-term Debt, excluding current maturities		4,102,250			4,215,046

Deferred Credits and Other Liabilities
Deferred income taxes		832,407			680,543
Energy marketing and risk management liabilities (Note D)		59,796			26,861
Other deferred credits		493,284			486,645
Total Deferred Credits and Other Liabilities		1,385,487			1,194,049

Commitments and Contingencies (Note I)

Minority Interests in Consolidated Subsidiaries		1,058,842			801,964

Shareholders’ Equity
Common stock, $0.01 par value:
authorized 300,000,000 shares; issued 121,568,386 shares and outstanding 104,468,756 shares at September 30, 2008; issued 121,115,217 shares and outstanding 103,987,476 shares at December 31, 2007		1,216			1,211
Paid in capital		1,300,286			1,273,800
Accumulated other comprehensive loss (Note E)		(68,763	)		(7,069	)
Retained earnings		1,534,241			1,411,492
Treasury stock, at cost: 17,099,630 shares at September 30, 2008 and 17,127,741 shares at December 31, 2007		(708,965	)		(710,126	)
Total Shareholders’ Equity		2,058,015			1,969,308


Total Liabilities and Shareholders’ Equity	$	12,222,063		$	11,062,034

See accompanying Notes to Consolidated Financial Statements.

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ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	September 30,
(Unaudited)	2008			2007
Operating Activities		(Thousands of dollars)
Net income	$	243,735		$	201,997
Depreciation and amortization		179,429			168,458
Allowance for equity funds used during construction		(35,788	)		(6,686	)
Gain on sale of assets		(1,319	)		(1,893	)
Minority interests in income of consolidated subsidiaries		235,411			135,013
Equity earnings from investments		(74,805	)		(64,975	)
Distributions received from unconsolidated affiliates		67,812			77,144
Deferred income taxes		72,884			61,919
Stock-based compensation expense		26,776			22,448
Allowance for doubtful accounts		11,668			12,574
Inventory adjustment, net		9,659			-
Investment securities gains		(11,142	)		-
Changes in assets and liabilities (net of acquisition and disposition effects):
Trade accounts and notes receivable		634,361			412,471
Gas and natural gas liquids in storage		(482,360	)		(46,594	)
Accounts payable		(210,768	)		(97,254	)
Commodity exchanges and imbalances, net		(3,137	)		19,311
Unrecovered purchased gas costs		(51,959	)		11,227
Accrued interest		48,736			42,488
Energy marketing and risk management assets and liabilities		49,904			70,741
Fair value of firm commitments		(135,826	)		(38,340	)
Other assets and liabilities		(94,873	)		(30,092	)
Cash Provided by Operating Activities		478,398			949,957
Investing Activities
Changes in investments in unconsolidated affiliates		3,063			(5,546	)
Capital expenditures (less allowance for equity funds used during construction)		(1,033,063	)		(527,497	)
Changes in short-term investments		-			31,125
Proceeds from sale of assets		1,774			3,999
Proceeds from insurance		9,792			-
Other		2,450			-
Cash Used in Investing Activities		(1,015,984	)		(497,919	)
Financing Activities
Borrowing (payment) of notes payable, net		1,119,614			359,000
Issuance of debt, net of issuance costs		-			598,146
Payment of debt		(412,219	)		(10,403	)
Repurchase of common stock		(29	)		(390,193	)
Issuance of common stock		7,249			11,443
Issuance of common units, net of discounts		146,969			-
Dividends paid		(120,986	)		(112,842	)
Distributions to minority interests		(149,173	)		(136,462	)
Other		-			(5,250	)
Cash Provided by Financing Activities		591,425			313,439
Change in Cash and Cash Equivalents		53,839			765,477
Cash and Cash Equivalents at Beginning of Period		19,105			68,268
Cash and Cash Equivalents at End of Period	$	72,944		$	833,745

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME


(Unaudited)	Common Stock Issued	Common Stock		Paid in Capital		Accumulated Other Comprehensive Loss
	(Shares)	(Thousands of dollars)
December 31, 2007	121,115,217	$	1,211	$	1,273,800	$	(7,069	)
Net income	-		-		-		-
Other comprehensive income (loss) (Note E)	-		-		-		(61,694	)
Total comprehensive income
Repurchase of common stock	-		-		-		-
Common stock issued	453,169		5		26,486		-
Common stock dividends - $1.16 per share (Note F)	-		-		-		-
September 30, 2008	121,568,386	$	1,216	$	1,300,286	$	(68,763	)

See accompanying Notes to Consolidated Financial Statements.

ONEOK, Inc. and Subsidiaries

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)


(Unaudited)	Retained Earnings			Treasury Stock			Total
		(Thousands of dollars)
December 31, 2007	$	1,411,492		$	(710,126	)	$	1,969,308
Net income		243,735			-			243,735
Other comprehensive income (loss) (Note E)		-			-			(61,694	)

Total comprehensive income								182,041

Repurchase of common stock		-			(29	)		(29	)
Common stock issued		-			1,190			27,681
Common stock dividends— $1.16 per share (Note F)		(120,986	)		-			(120,986	)
September 30, 2008	$	1,534,241		$	(708,965	)	$	2,058,015

ONEOK, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

A.	SUMMARY OF ACCOUNTING POLICIES

Our accompanying unaudited consolidated financial statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair presentation of the results for the interim periods presented. All such adjustments are of a normal recurring nature. These unaudited consolidated financial statements should be read in conjunction with our audited consolidated financial statements in our Annual Report on Form 10-K for the year ended December 31, 2007. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2008, are not necessarily indicative of the results that may be expected for a 12-month period.

Our accounting policies are consistent with those disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007.

Critical Accounting Policies

Fair Value Measurements

General - In September 2006, the FASB issued Statement 157, “Fair Value Measurements,” which 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,” which 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. Under FSP 157-2, we will be required to apply Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities beginning January 1, 2009. We are currently reviewing the impact of Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities, as well as the potential impact on our consolidated financial statements. 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, 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,” which 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. 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.

•

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. During the third quarter of 2008, we revised our categorization of fair value measurements for non-exchange traded derivative contracts from Level 1 to Level 2.

See Note C for more discussion of our 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, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

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 such changes occur. Commodity price volatility may have a significant impact on the gain or loss in a given period.

To minimize the risk of fluctuations in natural gas, NGLs and condensate prices, we periodically enter into futures, collars 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 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.

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 for more discussion of derivatives and risk management activities.

Impairment of Goodwill and Intangible Assets - We apply the provisions of Statement 142, “Goodwill and Other Intangible Assets,” and perform our annual impairment test on July 1. There were no impairment charges resulting from our July 1, 2008, impairment testing, and no events indicating an impairment have occurred subsequent to that date.

Significant Accounting Policies

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


	September 30,		December 31,
	2008		2007
		(Thousands of dollars)
Non-Regulated
ONEOK Partners	$	2,397,459	$	2,112,394
Energy Services		7,859		7,845
Other		223,308		177,356
Regulated
ONEOK Partners		3,046,582		2,323,977
Distribution		3,391,964		3,271,920
Property, plant and equipment		9,067,172		7,893,492
Accumulated depreciation and amortization		2,174,001		2,048,311
Net property, plant and equipment	$	6,893,171	$	5,845,181

At September 30, 2008, property, plant and equipment on our Consolidated Balance Sheet included construction work in process of $1,465.6 million that had not yet been put in service and therefore was not being depreciated. Of this amount, $1,420.7 million was related to our ONEOK Partners segment, $36.1 million was related to our Distribution segment and $8.8 million was related to our Other segment.

At December 31, 2007, property, plant and equipment on our Consolidated Balance Sheet included construction work in process of $918.2 million that had not yet been put in service and therefore was not being depreciated. Of this amount, $859.8 million was related to our ONEOK Partners segment, $51.3 million was related to our Distribution segment and $7.1 million was related to our Other segment.

Income Taxes - Our effective tax rate decreased for the three and nine months ended September 30, 2008, compared with the same periods in 2007, primarily due to the utilization of state income tax credits.

Other

Pension and Postretirement Employee Benefits - 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 was effective for our year ended December 31, 2006, except for the measurement date change from September 30 to December 31, which is 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, will be reflected as an adjustment to retained earnings as of December 31, 2008. The impact of this adjustment will be a $12.4 million reduction to retained earnings and a $1.3 million reduction to accumulated other comprehensive income (loss). The net periodic benefit cost for the period January 1, 2008, through December 31, 2008, is being recognized during 2008.

Master Netting Arrangements - In April 2007, the FASB issued Staff Position No. 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 agreement. We have applied the provisions of 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 is effective for our year beginning January 1, 2009, and will be applied prospectively. 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 Interests in Consolidated Financial Statements - an amendment of ARB No. 51,” which requires noncontrolling interest (previously referred to as minority interest) to be reported as a component of equity. Statement 160 is effective for our year beginning January 1, 2009, and will require retroactive adoption of the presentation and disclosure requirements for existing minority interests. Based upon our initial review of Statement 160, we do not expect the provisions of Statement 160 to have a material impact on our consolidated financial statements; however, certain financial statement presentation changes and additional required disclosures will be applicable to us.

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 is effective for our year beginning January 1, 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.	ACQUISITION

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 Energy Partners, L.P. 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 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 three refined petroleum products terminals and connecting pipelines. 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 working capital settlement was finalized in April 2008, with no material adjustments.

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.

September 30, 2008

Level 1

Level 2

Level 3

Netting (a)

Total

(Thousands of dollars)

Assets

Derivatives

410,590

151,442

641,202

(865,569

)

337,665

Trading securities

8,765

Available-for-sale investment securities

2,972

Fair value of firm commitments

178,509

Total assets

422,327

151,442

819,711

(865,569

)

527,911

Liabilities

Derivatives

(404,519

)

(37,471

)

(816,740

)

916,397

(342,333

)

Long-term debt swapped to floating

(343,512

)

(343,512

)

Total liabilities

(404,519

)

(37,471

)

(1,160,252

)

916,397

(685,845

)

(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 FIN 39-1, when a legally enforceable master netting arrangement exists between us and the counterparty to a derivative contract. At September 30, 2008, we held $38.5 million of cash collateral and had posted $89.3 million of cash collateral with various counterparties.

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, which 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 which 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.

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


	Derivative Assets (Liabilities)			Fair Value of Firm Commitments			Long-Term Debt			Total
	(Thousands of dollars)
June 30, 2008	$	(410,361	)	$	393,310		$	(340,208	)	$	(357,259	)
Total realized/unrealized gains (losses):
Included in earnings (a)		193,256			(214,801	)		(3,304	)		(24,849	)
Included in other comprehensive income (loss)		49,429			-			-			49,429
Transfers in and/or out of Level 3		(7,862	)		-			-			(7,862	)
September 30, 2008	$	(175,538	)	$	178,509		$	(343,512	)	$	(340,541	)

Total gains (losses) for the three-month period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of September 30, 2008(a)	$	116,031		$	(134,270	)	$	(3,304	)	$	(21,543	)

(a) - Reported in revenues in our Consolidated Statements of Income.


	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)		(190,655	)		135,825		(4,974	)		(59,804	)
Included in other comprehensive income (loss)		45,423			-		-			45,423
Transfers in and/or out of Level 3		24,276			-		-			24,276
September 30, 2008	$	(175,538	)	$	178,509	$	(343,512	)	$	(340,541	)

Total gains (losses) for the nine-month period included in earnings attributable to the change in unrealized gains (losses) relating to assets and liabilities still held as of September 30, 2008(a)	$	(228,420	)	$	226,264	$	(4,974	)	$	(7,130	)

(a) - Reported in revenues in our Consolidated Statements of Income.

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


	September 30,		December 31,
	2008		2007
	(Thousands of dollars)
Available-for-sale securities held
Aggregate fair value	$	2,972	$	24,151
Reported in accumulated other comprehensive income (loss) for net unrealized holding gains	$	1,616	$	13,678

Three Months Ended

Nine Months Ended

September 30,

2008

2007

2008

2007

(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 three and nine months ended September 30, 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 September 30, 2008.

The gains reclassified into earnings from accumulated other comprehensive income (loss) for the three months ended September 30, 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

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 our 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 purchases and normal 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.

Refer to Note D of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, for additional discussion.

Fair Value Hedges - In 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 the nine months ended September 30, 2008, from amortization of terminated swaps was $7.8 million, and the remaining net savings for all terminated swaps will be recognized over the following periods.


	ONEOK		ONEOK Partners		Total
	(Millions of dollars)
Remainder of 2008	$	1.7	$	0.9	$	2.6
2009		5.6		3.7		9.3
2010		5.5		3.7		9.2
2011		2.5		0.9		3.4
2012		0.8		-		0.8
Thereafter		12.0		-		12.0

At September 30, 2008, the interest on $340 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 through September 30, 2008, the weighted-average interest rate on the swapped debt decreased from 6.44 percent to 5.01 percent. At September 30, 2008, we recorded a net asset of $3.5 million to recognize the interest-rate swaps at fair value. Long-term debt includes an additional $3.5 million to recognize the change in the fair value of the related hedged debt. ONEOK Partners had no interest-rate swap agreements at September 30, 2008.

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 $3.6 million and losses of $1.0 million for the three months ended September 30, 2008 and 2007, respectively. The ineffectiveness related to these hedges included losses of $3.2 million and losses of $6.8 million for the nine months ended September 30, 2008 and 2007, 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 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 cost of fuel used in the transportation of natural gas. Accumulated other comprehensive income (loss) at September 30, 2008, includes losses of approximately $24.0 million, net of tax, related to these hedges that will be realized within the next 16 months as the forecasted transactions affect earnings. If prices remain at current levels, we will recognize $23.6 million in net losses over the next 12 months, and we will recognize net losses of $0.4 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 quarter of 2008, the carrying value of natural gas in storage was written down by $158.6 million in order to record inventory at the lower of cost or market. As required by Statement 133, we reclassified $148.9 million of deferred gains, before income taxes, on our 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 September 30, 2008, our ONEOK Partners’ segment reflected an unrealized gain of $8.6 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 15 months. If prices remain at current levels, our ONEOK Partners segment will recognize $6.6 million in net gains over the next 12 months, and net gains of $2.0 million thereafter.

Ineffectiveness related to our cash flow hedges resulted in gains of approximately $1.2 million and gains of approximately $0.4 million for the three months ended September 30, 2008 and 2007, respectively. Ineffectiveness related to our cash flow hedges resulted in losses of approximately $0.6 million and losses of approximately $0.3 million for the nine months ended September 30, 2008 and 2007, 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 gains or losses during the three and nine months ended September 30, 2008 and 2007, due to the discontinuance of cash flow hedge treatment.

E.	OTHER COMPREHENSIVE INCOME (LOSS)

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


	Three Months Ended September 30, 2008									Three Months Ended September 30, 2007
	Gross			Tax (Expense) Benefit			Net			Gross			Tax (Expense) Benefit			Net
	(Thousands of dollars)
Unrealized gains on energy marketing and risk management assets/liabilities	$	233,077		$	(90,154	)	$	142,923		$	59,841		$	(23,487	)	$	36,354
Less: Gains on energy marketing and risk management assets/liabilities recognized in net income		145,476			(56,270	)		89,206			7,127			(2,757	)		4,370
Unrealized holding gains (losses) on investment securities arising during the period		352			(136	)		216			822			(319	)		503
Less: Gains on investment securities recognized in net income		11,142			(4,310	)		6,832			-			-			-
Change in pension and postretirement benefit plan liability		(4,025	)		1,557			(2,468	)		(4,081	)		1,579			(2,502	)
Other comprehensive income	$	72,786		$	(28,153	)	$	44,633		$	49,455		$	(19,470	)	$	29,985


	Nine Months Ended September 30, 2008									Nine Months Ended September 30, 2007
	Gross			Tax (Expense) Benefit			Net			Gross			Tax (Expense) Benefit			Net
	(Thousands of dollars)
Unrealized gains on energy marketing and risk management assets/liabilities	$	70,424		$	(24,033	)	$	46,391		$	36,930		$	(15,713	)	$	21,217
Less: Gains on energy marketing and risk management assets/liabilities recognized in net income		144,516			(55,898	)		88,618			135,447			(52,391	)		83,056
Unrealized holding gains (losses) on investment securities arising during the period		(8,529	)		3,299			(5,230	)		1,115			(432	)		683
Less: Gains on investment securities recognized in net income		11,142			(4,310	)		6,832			-			-			-
Change in pension and postretirement benefit plan liability		(12,075	)		4,670			(7,405	)		(9,948	)		3,848			(6,100	)
Other comprehensive loss	$	(105,838	)	$	44,144		$	(61,694	)	$	(107,350	)	$	40,094		$	(67,256	)

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

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 Loss
	(Thousands of dollars)
December 31, 2007	$	25,328		$	13,678		$	(46,075	)	$	(7,069	)
Other comprehensive loss		(49,059	)		(5,230	)		(7,405	)		(61,694	)
September 30, 2008	$	(23,731	)	$	8,448		$	(53,480	)	$	(68,763	)

F.	CAPITAL STOCK

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 authorized for repurchase.

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: (1) as shares of common stock acquired in a treasury stock transaction recorded on the acquisition date and (2) 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.”

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

G.	CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

ONEOK’s $1.2 billion credit agreement (ONEOK Credit Agreement) and ONEOK Partners’ revolving credit agreement (ONEOK Partners Credit Agreement) contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007. At September 30, 2008, ONEOK and ONEOK Partners were in compliance with all covenants.

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.

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

At September 30, 2008, ONEOK had $292.2 million in commercial paper outstanding, $750 million in borrowings outstanding and $84.6 million in letters of credit issued under the ONEOK Credit Agreement, leaving $473.2 million of credit available under the ONEOK Credit Agreement and 364-Day Facility. The ONEOK Credit Agreement and the 364-Day Facility primarily act as a back-up to ONEOK’s commercial paper program. In addition, ONEOK had $30.3 million in other letters of credit issued at September 30, 2008.

At September 30, 2008, ONEOK Partners had $280 million in borrowings outstanding and $720 million of credit available under the ONEOK Partners Credit Agreement. ONEOK Partners 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.

In October 2008, ONEOK borrowed an additional $350 million under the ONEOK Credit Agreement and $300 million under the 364-Day Facility. With this borrowing, ONEOK had $1.4 billion outstanding and $115 million available under the ONEOK Credit Agreement and the 364-Day Facility at October 31, 2008.

H.	EMPLOYEE BENEFIT PLANS

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 Three Months Ended September 30,						Pension Benefits Nine Months Ended September 30,
	2008			2007			2008			2007
Components of Net Periodic Benefit Cost		(Thousands of dollars)
Service cost	$	5,042		$	5,262		$	15,124		$	15,788
Interest cost		12,448			12,152			37,350			36,457
Expected return on assets		(15,317	)		(14,538	)		(45,951	)		(43,615	)
Amortization of unrecognized prior service cost		387			371			1,163			1,114
Amortization of net loss		2,389			4,035			7,161			12,104
Net periodic benefit cost	$	4,949		$	7,282		$	14,847		$	21,848


	Postretirement Benefits Three Months Ended September 30,						Postretirement Benefits Nine Months Ended September 30,
	2008			2007			2008			2007
Components of Net Periodic Benefit Cost		(Thousands of dollars)
Service cost	$	1,418		$	1,598		$	4,256		$	4,794
Interest cost		4,474			3,957			13,424			11,872
Expected return on assets		(1,856	)		(1,597	)		(5,566	)		(4,791	)
Amortization of unrecognized net asset at adoption		798			797			2,392			2,392
Amortization of unrecognized prior service cost		(500	)		(569	)		(1,502	)		(1,708	)
Amortization of net loss		2,743			2,482			8,229			7,446
Net periodic benefit cost	$	7,077		$	6,668		$	21,233		$	20,005

I.	COMMITMENTS AND CONTINGENCIES

Operating Leases - In July 2007, ONEOK Leasing Company, L.L.C., our subsidiary, 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, L.L.C., 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 Liabilities - We own or retain legal responsibility for the environmental conditions at 12 former manufactured gas sites in Kansas. These sites contain potentially harmful materials that are subject to control or remediation under various environmental laws and regulations. A consent agreement with the KDHE presently governs all work at these sites. The terms of the consent agreement allow us to investigate these sites and set remediation activities based upon the results of the investigations and risk analysis. Remediation typically involves the management of contaminated soils and may involve removal of structures and monitoring and/or remediation of groundwater.

Of the 12 sites, we have 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.

Our expenditures for environmental evaluation and remediation to date have not been significant in relation to our results of operations, and there have been no material effects upon earnings during 2008 related to compliance with environmental regulations. See Note K of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, for additional discussion.

FERC Matter - As a result of an internal review 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 have been 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 are cooperating fully with the FERC and have taken steps to ensure that current and future transactions comply with applicable FERC regulations. We are unable to predict the outcome of any FERC action in this matter. At this time, we do not believe that penalties associated with potential violations will have a material impact on our results of operations, financial position or liquidity.

J.	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 the same as those described in Note A and Note M of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007. Intersegment sales are recorded on the same basis as sales to unaffiliated customers. Corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income.

Customers - We had no single external customer from which we received 10 percent or more of our consolidated revenues.

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


Three Months Ended September 30, 2008	ONEOK Partners (a)		Distribution (b)			Energy Services			Other and Eliminations			Total
	(Thousands of dollars)

Sales to unaffiliated customers	$	2,032,345	$	270,719		$	1,935,414		$	768		$	4,239,246
Intersegment sales		208,762		2			103,033			(311,797	)		-
Total revenues	$	2,241,107	$	270,721		$	2,038,447		$	(311,029	)	$	4,239,246

Net margin	$	325,400	$	123,929		$	4,819		$	878		$	455,026
Operating costs		97,488		97,558			9,465			(603	)		203,908
Depreciation and amortization		30,408		29,271			178			392			60,249
Gain (loss) on sale of assets		22		(3	)		1,288			3			1,310
Operating income (loss)	$	197,526	$	(2,903	)	$	(3,536	)	$	1,092		$	192,179

Equity earnings from investments	$	29,412	$	-		$	-		$	-		$	29,412
Capital expenditures	$	335,580	$	56,052		$	-		$	1,383		$	393,015

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $105.7 million, net margin of $82.5 million and operating income of $37.3 million for the three months ended September 30, 2008. (b) - All of our Distribution segment’s operations are regulated.

Three Months Ended September 30, 2007	ONEOK Partners (a)		Distribution (b)			Energy Services			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	1,239,681	$	234,064		$	1,335,371		$	881		$	2,809,997
Intersegment sales		170,576		2			63,783			(234,361	)		-
Total revenues	$	1,410,257	$	234,066		$	1,399,154		$	(233,480	)	$	2,809,997

Net margin	$	213,884	$	117,010		$	8,455		$	811		$	340,160
Operating costs		80,079		91,620			8,599			787			181,085
Depreciation and amortization		28,800		26,903			537			124			56,364
Gain (loss) on sale of assets		111		(56	)		-			4			59
Operating income (loss)	$	105,116	$	(1,569	)	$	(681	)	$	(96	)	$	102,770

Equity earnings from investments	$	22,162	$	-		$	-		$	-		$	22,162
Capital expenditures	$	201,962	$	40,213		$	-		$	3,556		$	245,731

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $80.9 million, net margin of $66.0 million and operating income of $30.0 million for the three months ended September 30, 2007.

(b) - All of our Distribution segment’s operations are regulated.


Nine Months Ended September 30, 2008	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	5,847,615	$	1,558,495		$	5,905,638	$	2,440		$	13,314,188
Intersegment sales		596,419		6			502,276		(1,098,701	)		-
Total revenues	$	6,444,034	$	1,558,501		$	6,407,914	$	(1,096,261	)	$	13,314,188

Net margin	$	874,858	$	490,610		$	93,857	$	2,441		$	1,461,766
Operating costs		272,728		285,623			27,987		(996	)		585,342
Depreciation and amortization		90,383		87,295			754		997			179,429
Gain (loss) on sale of assets		50		(21	)		1,288		2			1,319
Operating income	$	511,797	$	117,671		$	66,404	$	2,442		$	698,314

Equity earnings from investments	$	74,805	$	-		$	-	$	-		$	74,805
Investments in unconsolidated affiliates	$	756,449	$	-		$	-	$	-		$	756,449
Minority interests in consolidated subsidiaries	$	5,947	$	-		$	-	$	1,052,895		$	1,058,842
Total assets	$	6,992,295	$	2,934,614		$	1,786,002	$	509,152		$	12,222,063
Capital expenditures	$	860,167	$	126,407		$	15	$	46,474		$	1,033,063

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $329.7 million, net margin of $243.4 million and operating income of $112.0 million for the nine months ended September 30, 2008. (b) - All of our Distribution segment’s operations are regulated.

Nine Months Ended September 30, 2007	ONEOK Partners (a)		Distribution (b)			Energy Services		Other and Eliminations			Total
		(Thousands of dollars)
Sales to unaffiliated customers	$	3,462,539	$	1,472,354		$	4,554,930	$	2,623		$	9,492,446
Intersegment sales		491,706		5			373,400		(865,111	)		-
Total revenues	$	3,954,245	$	1,472,359		$	4,928,330	$	(862,488	)	$	9,492,446

Net margin	$	636,824	$	474,606		$	158,917	$	2,362		$	1,272,709
Operating costs		237,383		278,949			27,683		(4,687	)		539,328
Depreciation and amortization		84,326		82,148			1,612		372			168,458
Gain (loss) on sale of assets		1,935		(56	)		-		14			1,893
Operating income	$	317,050	$	113,453		$	129,622	$	6,691		$	566,816

Equity earnings from investments	$	64,975	$	-		$	-	$	-		$	64,975
Investments in unconsolidated affiliates	$	741,310	$	-		$	-	$	-		$	741,310
Minority interests in consolidated subsidiaries	$	5,761	$	-		$	-	$	789,043		$	794,804
Total assets	$	6,064,920	$	2,729,760		$	1,640,902	$	486,802		$	10,922,384
Capital expenditures	$	408,353	$	108,741		$	-	$	10,403		$	527,497

(a) - Our ONEOK Partners segment has regulated and non-regulated operations. Our ONEOK Partners segment’s regulated operations had revenues of $238.9 million, net margin of $195.0 million and operating income of $89.5 million for the nine months ended September 30, 2007.

(b) - All of our Distribution segment’s operations are regulated.

K.	UNCONSOLIDATED AFFILIATES

Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated. All amounts in the table below are equity earnings from investments in our ONEOK Partners segment.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(Thousands of dollars)
Northern Border Pipeline	$	20,090	$	16,363	$	48,752	$	44,915
Bighorn Gas Gathering, L.L.C.		2,044		1,782		6,367		5,482
Fort Union Gas Gathering		4,033		2,224		9,792		7,379
Lost Creek Gathering Company, L.L.C.		1,345		1,694		4,427		3,327
Other		1,900		99		5,467		3,872
Equity earnings from investments	$	29,412	$	22,162	$	74,805	$	64,975

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(Unaudited)	2008		2007		2008		2007
	(Thousands of dollars)
Income Statement
Revenues	$	98,298	$	102,417	$	304,733	$	291,304
Operating expenses		44,382		42,817		132,927		125,522
Net income		64,217		47,571		153,965		131,054
Distributions paid to ONEOK Partners	$	30,466	$	20,078	$	91,093	$	77,144

L.	EARNINGS PER SHARE INFORMATION

We compute earnings per common share (EPS) as described in Note Q of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007.

The following tables set forth the computations of the basic and diluted EPS for the periods indicated.


	Three Months Ended September 30, 2008
	Income		Shares	Per Share Amount
Basic EPS from continuing operations	(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	58,033	104,446	$	0.56
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-	1,190
Income from continuing operations available for common stock and common stock equivalents	$	58,033	105,636	$	0.55


	Three Months Ended September 30, 2007
	Income		Shares	Per Share Amount
Basic EPS from continuing operations	(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	13,914	103,882	$	0.13
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-	2,049
Income from continuing operations available for common stock and common stock equivalents	$	13,914	105,931	$	0.13


	Nine Months Ended September 30, 2008
	Income		Shares	Per Share Amount
Basic EPS from continuing operations	(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	243,735	104,319	$	2.34
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-	1,524
Income from continuing operations available for common stock and common stock equivalents	$	243,735	105,843	$	2.30


	Nine Months Ended September 30, 2007
	Income		Shares	Per Share Amount
Basic EPS from continuing operations	(Thousands, except per share amounts)
Income from continuing operations available for common stock	$	201,997	108,543	$	1.86
Diluted EPS from continuing operations
Effect of options and other dilutive securities		-	2,005
Income from continuing operations available for common stock and common stock equivalents	$	201,997	110,548	$	1.83

There were 13,746 option shares excluded from the calculation of diluted EPS for the three months ended September 30, 2008, since their inclusion would have been anti-dilutive. There were no anti-dilutive option shares for the three months ended September 30, 2007. There were 4,582 and 6,134 option shares excluded from the calculation of diluted EPS for the nine months ended September 30, 2008 and 2007, respectively, since their inclusion would have been anti-dilutive.

M.	ONEOK PARTNERS

Ownership Interest in ONEOK Partners - Our ownership interest in ONEOK Partners is shown in the following table for the periods indicated.


	September 30, 2008	December 31, 2007
General partner interest	2.0%	2.0%
Limited partner interest	45.7% (a)	43.7% (b)
Total equity ownership interest	47.7%	45.7%

(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. Following these transactions, our equity interest in ONEOK Partners is 47.7 percent.

Cash Distributions - Under 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.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(Thousands of dollars)
General partner distributions	$	2,419	$	1,973	$	7,038	$	5,819
Incentive distributions		20,320		12,955		55,722		36,478
Total distributions from ONEOK Partners	$	22,739	$	14,928	$	62,760	$	42,297

The quarterly distributions paid by ONEOK Partners to limited partners in the first, second and third quarters of 2008 were $1.025 per unit, $1.04 per unit and $1.06 per unit, respectively. The quarterly distributions paid by ONEOK Partners to limited partners in the first, second and third quarters of 2007 were $0.98 per unit, $0.99 per unit and $1.00 per unit, respectively.

In October 2008, ONEOK Partners declared a third-quarter 2008 cash distribution of $1.08 per unit payable in the fourth quarter.

Relationship - We consolidate ONEOK Partners in our consolidated financial statements; however, we are restricted from the assets and cash flows of ONEOK Partners except for our distributions. Distributions are declared quarterly by ONEOK Partners’ general partner based on the terms of its partnership agreement. For the three months ended September 30, 2008 and 2007, cash distributions declared from ONEOK Partners to us totaled $68.5 million and $52.3 million, respectively. For the nine months ended September 30, 2008 and 2007, cash distributions declared from ONEOK Partners to us totaled $197.6 million and $153.3 million, respectively. See Note J 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 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 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 are 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 through a modified Distrigas method, a method using a combination of ratios that include gross plant and investment, earnings before interest and taxes and payroll expense.

The following table sets forth transactions with ONEOK Partners for the periods indicated.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(Thousands of dollars)
Revenues	$	208,762	$	170,576	$	596,419	$	491,706
Administrative and general expenses	$	53,154	$	36,771	$	143,387	$	121,981

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.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q, as well as our Annual Report on Form 10-K for the year ended December 31, 2007. Due to the seasonal nature of our business, the results of operations for the three and nine months ended September 30, 2008, are not necessarily indicative of the results that may be expected for a 12-month period.

EXECUTIVE SUMMARY

The following discussion highlights some of our achievements and significant issues affecting us for the periods presented. 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 Operations and our Consolidated Financial Statements for additional information.

Diluted earnings per share of common stock from continuing operations (EPS) increased to $0.55 for the three months ended September 30, 2008, compared with $0.13 for the same period in 2007. For the nine-month period, EPS increased to $2.30 from $1.83 for the same period last year. Operating income for the three months ended September 30, 2008, increased to $192.2 million from $102.8 million for the same period in 2007, and for the nine months ended September 30, 2008, increased to $698.3 million from $566.8 million for the same period in 2007. These increases were primarily due to wider NGL product price differentials, increased NGL gathering and fractionation volumes, higher realized commodity prices and incremental operating income associated with the assets acquired from Kinder Morgan Energy Partners, L.P. (Kinder Morgan), all in our ONEOK Partners segment. For the nine months ended September 30, 2008, this increase in operating income was partially offset by a decrease in storage, marketing and transportation margins, net of hedging activities, in our Energy Services segment.

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 equity interest in ONEOK Partners is 47.7 percent.

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

We declared a quarterly dividend of $0.40 per share ($1.60 per share on an annualized basis) in October 2008, an increase of approximately 11 percent over the $0.36 per share declared in October 2007. ONEOK Partners declared an increase in its cash distribution to $1.08 per unit ($4.32 per unit on an annualized basis) in October 2008, an increase of approximately 7 percent over the $1.01 per unit declared in October 2007.

Partial operations began in October 2008 on the Overland Pass Pipeline. In September 2008, the Woodford Shale natural gas liquids pipeline extension was placed into service, and the final phase of the Fort Union Gas Gathering expansion project was placed into service in July 2008. In January 2008, Midwestern Gas Transmission, a ONEOK Partners subsidiary, placed its eastern extension pipeline into service. All of these projects are in our ONEOK Partners segment.

SIGNIFICANT ACQUISITION

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 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 three refined petroleum products terminals and connecting pipelines. 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 working capital settlement was finalized in April 2008, with no material adjustments.

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 final project cost is estimated to be $36 million, excluding AFUDC. These two plants are expected to 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. Overland Pass Pipeline Company is building 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 and is managing the construction project, advancing all costs associated with construction and operating the pipeline. Within two years of the pipeline becoming fully operational, Williams will have the option to increase its ownership up to 50 percent by reimbursing ONEOK Partners for certain costs 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. Partial operations began in October 2008, with Williams’ Echo Springs plant beginning to deliver 30 MBbl/d of unfractionated NGLs into the pipeline. The remaining portion of the pipeline from Opal, Wyoming, to Echo Springs, Wyoming, is substantially complete and scheduled for startup in the fourth quarter of 2008.

As part of a long-term agreement, Williams dedicated its NGL production of approximately 60 MBbl/d 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 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. The pipeline project is currently estimated to cost in the range of $575 million to $590 million, excluding AFUDC, which remains unchanged from the previous quarter. Since ONEOK Partners’ initial estimate of $433 million in early 2006, there has been a significant increase in the demand for pipeline construction-related services, which has led to higher construction labor and equipment rates. Additionally, compliance with federal restrictions on construction in wildlife sensitive areas increased costs and resulted in construction delays that further impacted costs due to winter construction.

ONEOK Partners is also investing in the range of $230 million to $240 million, excluding AFUDC, which remains unchanged from the previous quarter, to expand its existing fractionation and storage capabilities and the capacity of its natural gas liquids distribution pipelines. Since ONEOK Partners’ initial estimate of $216 million, these expansion projects have experienced cost increases related to further design enhancements adding 30 MBbl/d of fractionation capacity, increased construction labor rates, increased material costs and increased costs resulting from heavy spring rainfall. Part of this expansion will increase the fractionation capacity from 80 MBbl/d to 150 MBbl/d. Phase I of the fractionator upgrade was

completed in August 2008, placed in service and is capable of fractionating up to 80 MBbl/d. Phase II is expected to begin operation in the fourth quarter of 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 to be transported by the lateral pipeline, totaling approximately 30 MBbl/d. 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 to be completed during the third quarter of 2009. The completion date has been revised from the second quarter of 2009 to the third quarter of 2009 due to a delay in the approval of ONEOK Partners’ construction permit from the Bureau of Land Management. The project is currently estimated to cost in the range of $110 million to $140 million, excluding AFUDC, which remains unchanged from the previous quarter.

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 projected to be partially in service during the fourth quarter of 2008 and fully completed during the first quarter of 2009.

Arbuckle 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. Current estimated costs are in the range of $340 million to $360 million, excluding AFUDC, which remains unchanged from the previous quarter. Negotiations with pipeline contractors have recently been completed and the resulting construction labor rates have increased project costs from the original estimate of $260 million. ONEOK Partners has also experienced higher than originally expected acquisition costs for pipeline easements, particularly in the Barnett Shale area, along with increased costs for materials. 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 for 65 MBbl/d and indications of interest with other producers that could add an additional 145 MBbl/d of supply within the next three to five years. These additional supply commitments are in various stages of negotiation. Construction permits from various federal, state and local regulatory bodies have been received. Construction began in the third quarter of 2008 and is expected to be completed in the first quarter of 2009.

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, which remains unchanged from the previous quarter. 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 expansion project is expected to be online in the fourth quarter of 2008.

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 is currently expected to cost in the range of $120 million to $130 million, excluding AFUDC, which was primarily 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 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, which remains unchanged from the previous quarter. ONEOK Partners’ estimated project costs increased from the initial estimate of $241 million in 2006, which excluded AFUDC, primarily due to weather 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. The pipeline is currently projected to be in service in the fourth quarter of 2008.

REGULATORY

Several regulatory initiatives impacted the earnings and future earnings potential for our Distribution segment. See discussion of our Distribution segment’s regulatory initiatives on page 41.

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 Quarterly Report on Form 10-Q:

•

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

•

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,”

•

FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,”

•

Statement 141R, “Business Combinations,”

•

Statement 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51,” and

•

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

CRITICAL ACCOUNTING POLICIES AND 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 revenues and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.

Information about our critical accounting estimates is included below and under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and Estimates,” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Fair Value Measurements

General - In September 2006, the FASB issued Statement 157 which 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, which 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. Under FSP 157-2, we will be required to apply Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities beginning January 1, 2009. We are currently reviewing the impact of Statement 157 to our nonrecurring fair value measurements associated with our nonfinancial assets and liabilities, as well as the potential impact on our consolidated financial statements. 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 which 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.

•

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

•

Level 3 - Generally unobservable inputs, which are developed based on the best information available and may include our own internal data.

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

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 the changes occur. Commodity price volatility may have a significant impact on the gain or loss in a given period.

•

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 Quarterly Report on Form 10-Q for more discussion of derivatives and risk management activities.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

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


	Three Months Ended September 30,						Nine Months Ended September 30,
Financial Results	2008			2007			2008			2007
	(Thousands of dollars)
Revenues	$	4,239,246		$	2,809,997		$	13,314,188		$	9,492,446
Cost of sales and fuel		3,784,220			2,469,837			11,852,422			8,219,737
Net margin		455,026			340,160			1,461,766			1,272,709
Operating costs		203,908			181,085			585,342			539,328
Depreciation and amortization		60,249			56,364			179,429			168,458
Gain on sale of assets		1,310			59			1,319			1,893
Operating income	$	192,179		$	102,770		$	698,314		$	566,816

Equity earnings from investments	$	29,412		$	22,162		$	74,805		$	64,975
Allowance for equity funds used during construction	$	15,616		$	3,691		$	35,788		$	6,686
Other income (expense)	$	1,391		$	1,102		$	312		$	15,231
Interest expense	$	(61,180	)	$	(62,675	)	$	(183,100	)	$	(187,503	)
Minority interests in income of consolidated subsidiaries	$	(95,354	)	$	(44,998	)	$	(235,411	)	$	(135,013	)

Operating Results - Net margin increased for the three and nine months ended September 30, 2008, compared with the same periods last year, primarily due to wider NGL product price differentials, increased NGL gathering and fractionation volumes, certain operational measurement gains, higher realized commodity prices and incremental net margin associated with the assets acquired from Kinder Morgan, all in our ONEOK Partners segment. Additionally, net margin increased due to implementation of new rate schedules in our Distribution segment. These increases were partially offset by decreases in financial trading margins and a decrease for the nine-month period in storage and marketing margins, which occurred primarily in the first quarter of 2008, both in our Energy Services segment. In addition, the nine-month period was also impacted by decreases in transportation margins, net of hedging activities, in our Energy Services segment.

Operating costs increased for the three and nine months ended September 30, 2008, compared with the same periods last year, primarily due to incremental operating expenses associated with the assets acquired from Kinder Morgan by ONEOK Partners and higher employee-related costs in our ONEOK Partners and Distribution segments.

Depreciation and amortization increased for the three and nine months ended September 30, 2008, compared with the same periods last year, 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 for the three and nine months ended September 30, 2008, compared with the same periods last year, primarily due to ONEOK Partners’ 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 increased for the three and nine months ended September 30, 2008, compared with the same periods last year, due to increased spending for ONEOK Partners’ capital projects, which are discussed beginning on page 31.

Other income (expense) fluctuated for the nine months ended September 30, 2008, compared with the same period last year, primarily due to investment gains (losses), including realized and unrealized gains on available-for-sale securities sold and transferred to trading. The activity with our available-for-sale securities occurred 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.

Minority interest in income of consolidated subsidiaries for the three and nine months ended September 30, 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 for the three and nine months ended September 30, 2008, compared with the same periods last year, is due to the increase in income for our ONEOK Partners segment, partially offset by our increased equity ownership interest in ONEOK Partners.

Our effective tax rate decreased for the three and nine months ended September 30, 2008, compared to the same periods in 2007, primarily due to the utilization of state income tax credits.

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

ONEOK Partners

Overview - At September 30, 2008, we owned a 47.7 percent equity interest in ONEOK Partners. The remaining interest in ONEOK Partners is reflected as minority interests in income of consolidated subsidiaries on our Consolidated Statements of Income.

ONEOK Partners gathers and processes natural gas and fractionates NGLs, primarily in the Mid-Continent and Rocky Mountain regions. ONEOK Partners’ operations include the gathering of natural gas production from oil and natural gas wells. Through gathering systems, these volumes are aggregated and treated or processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. 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.

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. ONEOK Partners’ FERC-regulated natural gas liquids distribution pipelines deliver NGL products to the natural gas liquids market hubs 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 natural gas pipelines. ONEOK Partners’ regulated intrastate natural gas pipeline assets access the major natural gas producing areas and transport natural gas throughout Oklahoma, Kansas and Texas. ONEOK Partners owns or leases storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas.

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.


	Three Months Ended September 30,				Nine Months Ended September 30,
Financial Results	2008		2007		2008		2007
	(Thousands of dollars)
Revenues	$	2,241,107	$	1,410,257	$	6,444,034	$	3,954,245
Cost of sales and fuel		1,915,707		1,196,373		5,569,176		3,317,421
Net margin		325,400		213,884		874,858		636,824
Operating costs		97,488		80,079		272,728		237,383
Depreciation and amortization		30,408		28,800		90,383		84,326
Gain on sale of assets		22		111		50		1,935
Operating income	$	197,526	$	105,116	$	511,797	$	317,050

Equity earnings from investments	$	29,412	$	22,162	$	74,805	$	64,975
Allowance for equity funds used during construction	$	15,616	$	3,691	$	35,788	$	6,686
Minority interests in income of consolidated subsidiaries	$	111	$	125	$	368	$	302


	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2008		2007		2008		2007
Natural gas gathered (BBtu/d) (a)		1,146		1,170		1,174		1,168
Natural gas processed (BBtu/d) (a)		649		617		641		615
Natural gas transported (MMcf/d)		3,500		3,378		3,637		3,524
Residue gas sales (BBtu/d) (a)		281		289		280		279
NGLs gathered (MBbl/d)		243		232		249		222
NGL sales (MBbl/d)		273		223		275		221
NGLs fractionated (MBbl/d)		375		370		379		346
NGLs transported (MBbl/d)		331		225		314		219
Capital expenditures (Thousands of dollars)	$	335,580	$	201,962	$	860,167	$	408,353
Conway-to-Mont Belvieu OPIS average price differential Ethane ($/gallon)	$	0.24	$	0.05	$	0.15	$	0.05
Realized composite NGL sales prices ($/gallon) (a)	$	1.51	$	1.09	$	1.44	$	0.97
Realized condensate sales price ($/Bbl) (a)	$	99.61	$	69.05	$	96.91	$	61.25
Realized natural gas sales price ($/MMBtu) (a)	$	8.33	$	5.41	$	8.39	$	6.20
Realized gross processing spread ($/MMBtu) (a)	$	6.69	$	5.54	$	6.94	$	4.56
(a) - Statistics relate to ONEOK Partners’ natural gas gathering and processing business.

Operating Results - Net margin increased $111.5 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to the following:

•

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

^¡

an increase of $43.7 million in wider NGL product price differentials,

^¡

an increase of $13.3 million in certain operational measurement gains, primarily at NGL storage caverns, and

^¡

an increase of $12.5 million due to increased NGL gathering and fractionation volumes,

•

an increase of $18.3 million due to higher realized commodity prices in ONEOK Partners’ natural gas gathering and processing business, and

•

an increase of $12.0 million in incremental net margin in ONEOK Partners’ natural gas liquids pipelines business, due to the assets acquired from Kinder Morgan in October 2007.

Net margin increased $238.0 million for the nine months ended September 30, 2008 compared with the same period last year, primarily due to the following:

•

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

^¡

an increase of $59.3 million in wider NGL product price differentials,

^¡

an increase of $31.8 million due to increased NGL gathering and fractionation volumes, and

^¡

an increase of $11.4 million in certain operational measurement gains, primarily at NGL storage caverns,

•

an increase of $66.2 million due to higher realized commodity prices in ONEOK Partners’ natural gas gathering and processing business, and

•

an increase of $34.0 million in incremental net margin in ONEOK Partners’ natural gas liquids pipelines business, due to the assets acquired from Kinder Morgan in October 2007.

Operating costs increased $17.4 million and $35.3 million for the three and nine months ended September 30, 2008, respectively, compared with the same periods last year, primarily due to incremental operating expenses associated with the assets acquired from Kinder Morgan and higher employee-related costs. Operating costs also increased due to costs associated with the startup of ONEOK Partners’ newly expanded Bushton fractionator.

Depreciation and amortization increased $1.6 million and $6.1 million for the three and nine months ended September 30, 2008, respectively, compared with the same periods last year, primarily due to depreciation expense associated with ONEOK Partners’ completed capital projects and the assets acquired from Kinder Morgan.

Equity earnings from investments increased $7.3 million and $9.8 million for the three and nine months ended September 30, 2008, respectively, compared with the same periods last year, primarily due to an $8.3 million gain on the sale of Bison Pipeline LLC by Northern Border Pipeline and higher gathering revenues in ONEOK Partners’ 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 increased $11.9 million and $29.1 million for the three and nine months ended September 30, 2008, respectively, compared with the same periods last year. Capital expenditures increased $133.6 million and $451.8 million for the three and nine months ended September 30, 2008, respectively, compared with the same periods last year. These increases were due to increased spending for ONEOK Partners’ capital projects, which are discussed beginning on page 31.

As noted in the “Operating Information” table above, NGL product price differentials in ONEOK Partners’ natural gas liquids gathering and fractionation business were significantly higher in 2008 than 2007. This business began experiencing lower price differentials beginning in October 2008. However, the price differentials ONEOK Partners’ is currently experiencing have remained above the three-year average Conway-to-Mont Belvieu price differential for ethane of $0.05 per gallon.

Distribution

Overview - 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. 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.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
Financial Results	2008			2007			2008			2007
	(Thousands of dollars)
Gas sales	$	242,759		$	208,398		$	1,463,699		$	1,381,102
Transportation revenues		18,096			17,747			64,142			65,454
Cost of gas		146,792			117,056			1,067,891			997,753
Net margin, excluding other		114,063			109,089			459,950			448,803
Other revenues		9,866			7,921			30,660			25,803
Net margin		123,929			117,010			490,610			474,606
Operating costs		97,558			91,620			285,623			278,949
Depreciation and amortization		29,271			26,903			87,295			82,148
Loss on sale of assets		(3	)		(56	)		(21	)		(56	)
Operating income (loss)	$	(2,903	)	$	(1,569	)	$	117,671		$	113,453

Operating Results - Net margin increased $6.9 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to implementation of new rate mechanisms, which includes a $3.9 million increase in Oklahoma and a $1.0 million increase in Texas.

Net margin increased $16.0 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to implementation of new rate mechanisms, which includes a $10.0 million increase in Oklahoma and a $2.3 million increase in Texas, and an increase of $1.1 million in reimbursements for relocation projects in Oklahoma.

Operating costs increased $5.9 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to an increase of $3.2 million in employee-related costs and an increase of $1.2 million in fuel-related vehicle costs.

Operating costs increased $6.7 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to an increase of $2.1 million in employee-related costs, a non-recurring expense reimbursement of $3.3 million in 2007, and an increase of $1.5 million in fuel-related vehicle costs.

Depreciation and amortization increased $2.4 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to an increase of $1.3 million of regulatory amortization associated with revenue rider recoveries and an increase of $1.0 million in depreciation expense related to our investment in property, plant and equipment.

Depreciation and amortization increased $5.1 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to an increase of $3.0 million in depreciation expense related to our investment in property, plant and equipment and an increase of $2.0 million of regulatory amortization associated with revenue rider recoveries.

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

Three Months Ended

Nine Months Ended

September 30,

Operating Information

2008

2007

2008

2007

Average number of customers

2,038,929

2,022,615

2,063,022

2,049,021

Customers per employee

707

721

722

733

Capital expenditures (Thousands of dollars)

56,052

40,213

126,407

108,741

Three Months Ended

Nine Months Ended

September 30,

Volumes (MMcf)

2008

2007

2008

2007

Gas sales

Residential

7,688

7,900

83,027

80,903

Commercial

3,258

3,642

25,966

25,770

Industrial

260

226

1,233

1,296

Wholesale

2,521

4,810

5,080

10,494

Public Authority

288

264

1,623

1,640

Total volumes sold

14,015

16,842

116,929

120,103

Transportation

50,344

47,953

163,362

148,685

Total volumes delivered

64,359

64,795

280,291

268,788


		Three Months Ended				Nine Months Ended
		September 30,				September 30,
Margin		2008		2007		2008		2007
Gas sales		(Thousands of dollars)
Residential	$	77,835	$	74,578	$	317,331	$	314,084
Commercial		16,839		16,146		73,349		70,879
Industrial		534		422		2,192		1,861
Wholesale		188		359		454		941
Public Authority		571		482		2,482		2,240
Net margin on gas sales		95,967		91,987		395,808		390,005
Transportation		18,096		17,102		64,142		58,798
Net margin, excluding other	$	114,063	$	109,089	$	459,950	$	448,803

Residential volumes increased for the nine months ended September 30, 2008, compared with the same period last year, due to colder temperatures in our Oklahoma and Kansas service territories during the first half of 2008; however, margins were moderated by weather normalization mechanisms.

Wholesale sales represent contracted gas volumes that exceed the needs of our residential, commercial and industrial customer base and are available-for-sale to other parties. Wholesale volumes decreased for the three and nine months ended September 30, 2008, compared with the same periods in 2007, due to reduced volumes available-for-sale.

Transportation margins increased for the three and nine months ended September 30, 2008, compared with the same periods last year, primarily due to increased transportation volumes in Oklahoma and Kansas.

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 assure safe, reliable and efficient operations. Our capital expenditure program included $13.5 million and $13.1 million for new business development for the three months ended September 30, 2008 and 2007, respectively, and $35.4 million and $34.5 million for new business development for the nine months ended September 30, 2008 and 2007, respectively. Capital expenditures increased for the three and nine months ended September 30, 2008, compared with the same periods last year, due to the timing of system maintenance expenditures.

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 2004 rate case. The rates, which were effective in March 2008, are expected to generate margins of approximately $7.6 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. A final order is pending full approval by the OCC. If approved, Oklahoma Natural Gas expects this increase to be effective 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 an 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 2008 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. Oklahoma Natural Gas will continue to defer IMP costs as they are incurred and expects to file a new application each year for recovery of any additional 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. A final order is pending full approval by the OCC.

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 a more streamlined incentive based regulatory process. If approved, this will provide for more timely rate changes.

Kansas - In August 2008, Kansas Gas Service filed an application with the KCC to impose a surcharge designed to annually collect $2.9 million in costs associated with its Gas System Recovery Surcharge (GSRS) mechanism. The GSRS mechanism allows natural gas utilities to recover carrying charges 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 is expected to rule on the request in December 2008, with authorized GSRS collections expected to begin in the first quarter of 2009.

Texas - 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 Texas Railroad Commission 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 statute with the city of El Paso, Texas, and surrounding communities for approximately $1.1 million. This statute 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.

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

Overview - 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. At September 30, 2008, our total storage capacity under lease was 91 Bcf, with maximum withdrawal capability of 2.2 Bcf/d and maximum injection capability of 1.4 Bcf/d. Additionally, our transportation capacity was 1.8 Bcf/d at September 30, 2008. Our contracted storage and transportation capacity connects the 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.

Our Energy Services segment conducts business with ONEOK Partners, our affiliate, which comprises our ONEOK Partners segment. This segment also conducts business with our Distribution segment. These services are provided under agreements with market-based terms.

Due to seasonality of natural gas consumption, 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. During periods of high natural gas demand, we utilize storage capacity to supplement natural gas supply volumes to meet peak day demand obligations or market needs.

Numerous risk management opportunities and operational strategies are implemented through the use of storage 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 manage our contracted transportation and storage capacity by utilizing derivative instruments such as over-the-counter forward swap and option contracts and NYMEX futures and options contracts. 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 Quarterly Report on Form 10-Q 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.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Energy Services segment for the periods indicated.


		Three Months Ended						Nine Months Ended
		September 30,						September 30,
Financial Results		2008			2007			2008		2007
		(Thousands of dollars)
Revenues	$	2,038,447		$	1,399,154		$	6,407,914	$	4,928,330
Cost of sales and fuel		2,033,628			1,390,699			6,314,057		4,769,413
Net margin		4,819			8,455			93,857		158,917
Operating costs		9,465			8,599			27,987		27,683
Depreciation and amortization		178			537			754		1,612
Gain on sale of assets		1,288			-			1,288		-
Operating income (loss)	$	(3,536	)	$	(681	)	$	66,404	$	129,622


		Three Months Ended				Nine Months Ended
		September 30,				September 30,
Operating Information		2008		2007		2008		2007
Natural gas marketed (Bcf)		261		291		867		886
Natural gas gross margin ($/Mcf)	$	0.02	$	0.03	$	0.08	$	0.16
Physically settled volumes (Bcf)		560		605		1,756		1,794
Capital expenditures (Thousands of dollars)	$	-	$	-	$	15	$	-

Operating Results - Energy markets were affected by higher commodity prices during the first, second and third quarters of 2008, compared with the same periods in 2007. The increase in commodity prices had a direct impact on our revenues and the cost of sales and fuel.

Net margin decreased $3.6 million for the three months ended September 30, 2008, compared with the same period last year. This decrease was comprised of:

•

a decrease of $9.9 million in financial trading margins,

•

a decrease of $1.5 million in retail margins, due to lower sales volumes resulting from unfavorable weather and market conditions in our service territory, and an adjustment to lost and unaccounted for natural gas volumes, partially offset by

•

a net increase of $7.5 million in storage and marketing margins, primarily due to:

^¡

an increase of $9.8 million in marketing margins, primarily due to a more favorable price environment that allowed for better optimization of our contractual assets,

^¡

an increase of $5.9 million in storage margins, net of hedging activities, due to favorable unrealized fair value changes on non-qualified hedging activity and gains on storage hedges due to ineffectiveness, partially offset by

^¡

a net decrease of $9.7 million due to a lower of cost or market write-down on natural gas inventory, partially offset by the reclassification of deferred gains on our cash flow hedges into earnings.

Net margin decreased $65.1 million for the nine months ended September 30, 2008, compared with the same period last year. This decrease was comprised of:

•

a net decrease of $38.6 million in storage and marketing margins, primarily due to:

^¡

a decrease of $30.0 million from storage margins, net of hedging activities, related to a more favorable price environment in early 2007, which resulted in improved storage margins during that period,

^¡

a net decrease of $9.7 million due to a lower of cost or market write-down on natural gas inventory partially offset by the reclassification of deferred gains on our cash flow hedges into earnings during the third quarter of 2008,

^¡

a decrease of $1.7 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

^¡

an increase of $2.8 million from changes in the unrealized fair value of derivative instruments associated with storage and marketing activities, and

•

a decrease of $14.8 million in our financial trading margins, and

•

a net decrease of $11.7 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 the first six months of 2008, slightly offset by favorable unrealized fair value changes on non-qualifying hedge activity and gains on transportation hedges due to ineffectiveness.

Our natural gas in storage at September 30, 2008, was 74.7 Bcf, compared with 80.1 Bcf at September 30, 2007. At September 30, 2008 and 2007, our total natural gas storage capacity under lease was 91 Bcf and 96 Bcf, respectively.

Natural gas volumes marketed decreased for the three and nine months ended September 30, 2008, compared with the same periods in 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.

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 our 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.


		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2008			2007			2008			2007
		(Thousands of dollars)
Marketing, storage and transportation, gross	$	57,268		$	38,328		$	246,097		$	274,607
Less: Storage and transportation costs		(54,577	)		(43,390	)		(163,135	)		(141,409	)
Marketing, storage and transportation, net		2,691			(5,062	)		82,962			133,198
Retail marketing		1,715			3,204			9,332			9,377
Financial trading		413			10,313			1,563			16,342
Net margin	$	4,819		$	8,455		$	93,857		$	158,917

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 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.

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 credit agreements and commercial paper, 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.

Beginning in 2007 and continuing in 2008, the capital markets have been impacted by macroeconomic, liquidity, credit and other recessionary concerns. 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 ONEOK’s commercial paper program and ONEOK’s $1.2 billion credit agreement (ONEOK Credit Agreement), and ONEOK Partners has continued to have access to the ONEOK Partners Credit Agreement, which have 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 “Financing.” Also in 2008, ONEOK Partners issued common units and received additional contributions from ONEOK Partners GP. See discussion below under “ONEOK Partners Common Units.” ONEOK Partners also issued $600 million of long-term debt in September 2007. 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 existing capital resources, ability to obtain financing and cash flow generated from future operations will enable both to maintain current levels of operations and planned operations, including collateral requirements and capital expenditures, for the remainder of 2008 and into 2009.

During the three and nine months ended September 30, 2008 and 2007, ONEOK and ONEOK Partners’ capital expenditures were financed through operating cash flows and short- and long-term debt. For the nine months ended September 30, 2008, ONEOK Partners’ capital expenditures were also financed through the issuance of ONEOK Partners’ common units. Total capital expenditures for the first nine months of 2008 were $1.0 billion, compared with $527.5 million for the same period in 2007, exclusive of acquisitions. Of these amounts, ONEOK Partners’ capital expenditures for the first nine months of 2008 were $860.2 million, compared with $408.4 million for the same period in 2007, exclusive of acquisitions. The increase in capital expenditures for 2008, compared with 2007, is driven primarily by ONEOK Partners’ capital projects discussed beginning on page 31, and ONEOK’s purchase of ONEOK Plaza.

Financing - For ONEOK, financing is provided through available cash, credit agreements or long-term debt. ONEOK also has a commercial paper program which can be utilized for short-term liquidity needs. Other options for ONEOK to obtain financing include, but are not limited to, issuance of equity, issuance of convertible debt securities, asset securitization and sale/leaseback of facilities. ONEOK Partners’ operations are financed through available cash, the ONEOK Partners Credit Agreement, the issuance of common units or long-term debt. Other options for ONEOK Partners to obtain financing include, but are not limited to, issuance of convertible debt securities, asset securitization and sale/leaseback of facilities.

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 for working capital, capital expenditures and other general corporate purposes.

The total amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5 billion. At September 30, 2008, ONEOK had $292.2 million in commercial paper outstanding, $750 million in borrowings outstanding, $114.9 million in letters of credit issued, which includes $84.6 million under the ONEOK Credit Agreement and an additional $30.3 million in other letters of credit, and available cash and cash equivalents of approximately $57.1 million. Considering outstanding borrowings, commercial paper and letters of credit under the ONEOK Credit Agreement, ONEOK had $473.2 million of credit available at September 30, 2008, under the ONEOK Credit Agreement and the 364-Day Facility. As of September 30, 2008, ONEOK could have issued $1.6 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 September 30, 2008, ONEOK Partners had $280 million in borrowings outstanding and $720 million of credit available under the ONEOK Partners Credit Agreement and available cash and cash equivalents of approximately $15.8 million. ONEOK Partners 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. As of September 30, 2008, ONEOK Partners could have issued $1.4 billion of additional short- and long-term debt under the most restrictive provisions of its agreements.

The ONEOK Credit Agreement, the 364-Day Facility and the ONEOK Partners Credit Agreement contain typical covenants as discussed in Note H of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K, for the year ended December 31, 2007. At September 30, 2008, ONEOK and ONEOK Partners were in compliance with all covenants.

During the third and fourth quarters of 2008, the capital markets have been significantly impacted by a financial credit crisis, including the commercial paper market that experienced decreased liquidity and higher interest rates. Because of these market conditions and to ensure ONEOK and ONEOK Partners would have access to the capital required to fund their respective working capital needs, certain measures were taken. In September 2008, ONEOK began borrowing under the ONEOK Credit Agreement, instead of accessing the commercial paper market. In October, ONEOK borrowed an additional $350 million under the ONEOK Credit Agreement and $300 million under the 364-Day Facility to ensure access to the capital ONEOK anticipates needing to fund its working capital requirements through the winter heating season. With this borrowing, ONEOK had $1.4 billion outstanding and $115 million available under the ONEOK Credit Agreement and the 364-Day Facility at October 31, 2008. On that date, ONEOK also had approximately $335 million in cash and cash equivalents. ONEOK will utilize these funds and the remaining borrowing capacity, as well as operating cash flow, to fund working capital requirements for the remainder of the 2008/2009 heating season.

Additionally, ONEOK Partners borrowed $590 million under the ONEOK Partners Credit Agreement in October 2008. With this borrowing, ONEOK Partners had $870 million outstanding and $130 million available under the ONEOK Partners Credit Agreement at October 31, 2008. On that date, ONEOK Partners also had approximately $396 million in available cash and cash equivalents. ONEOK Partners will utilize these funds and the remaining borrowing capacity, as well as operating cash flow, to fund its growth projects and working capital requirements for the remainder of 2008 and into 2009.

The average interest rate on ONEOK and ONEOK Partners short-term debt outstanding at October 31, 2008, was 4.51 percent and 4.22 percent, respectively, compared with a weighted average rate of 3.10 percent and 3.24 percent, respectively, for the first nine months of 2008. Based on the forward LIBOR curve, we expect the interest rate on ONEOK and ONEOK Partners’ short-term borrowings to increase in 2009, compared with 2008.

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


	September 30,	December 31,
	2008	2007
Long-term debt	67%	70%
Equity	33%	30%
Debt (including Notes payable)	73%	71%
Equity	27%	29%

ONEOK does not guarantee the debt of ONEOK Partners. For purposes of determining compliance with financial covenants in the ONEOK Credit Agreement and the 364-Day Facility, the debt of ONEOK Partners is excluded. At September 30, 2008, ONEOK’s capitalization structure, excluding the debt of ONEOK Partners, was 56 percent debt and 44 percent equity, and at December 31, 2007, ONEOK’s capitalization structure, excluding the debt of ONEOK Partners, was 52 percent debt and 48 percent equity. In February 2008, ONEOK repaid $402.3 million of matured long-term debt with cash from operations and short-term borrowings.

Credit Ratings - Our investment grade credit ratings as of September 30, 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

ONEOK’s commercial paper is rated P2 by Moody’s and A2 by S&P. Credit ratings 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. 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. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to access the ONEOK Credit Agreement, which expires in July 2011, and the 364-Day Facility, which expires in August 2009, and ONEOK Partners would continue to access the ONEOK Partners Credit Agreement, which expires in March 2012. An adverse rating change alone is not a default under the ONEOK Credit Agreement, the 364-Day Facility or the ONEOK Partners Credit Agreement.

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 and 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. ONEOK Partners 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. A decline in ONEOK Partners’ credit rating below investment grade may also require ONEOK Partners to provide security to its counterparties in the form of cash, letters of credit or other negotiable instruments.

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 September 30, 2008, ONEOK could have been required to fund approximately $56 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 credit worthiness, ONEOK or ONEOK Partners could be asked to provide additional collateral.

Capital Projects - See the “Capital Projects” section beginning on page 31 for discussion of capital projects.

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

ONEOK Partners 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 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. We 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.

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

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices in either physical or financial energy contracts may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs and natural gas held in storage, margin requirements and certain energy-related receivables. We believe that ONEOK’s and ONEOK Partners’ available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 52 under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk for information on our hedging activities.

Pension and Postretirement Benefit Plans - Information about our pension and postretirement benefits plans is included in Note J of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007. See Note H of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for additional information.

The fair value of the assets held by our defined benefit plans have decreased significantly in 2008. However, based on current market conditions, the discount rate we anticipate using at December 31, 2008, to calculate our projected benefit obligation has increased, which has the effect of lowering our pension liability and would significantly offset the asset decline. We anticipate that our net periodic benefit cost and required contributions for 2009 will increase compared to 2008. The extent of the increases are dependent on a number of factors, including, but not limited to, actuarial assumptions for the

discount rate, expected long-term return on plan assets, and the actual return on plan assets through the end of 2008. We will determine our net periodic benefit cost and required contributions for 2009 when we complete our December 31, 2008, actuarial valuation. However, we do not expect that our funding requirements in 2009 will have a material impact on our liquidity.

ENVIRONMENTAL AND SAFETY MATTERS

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, storm water 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 an accidental 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.

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 the nine months ended September 30, 2008 or 2007, related to compliance with environmental regulations.

For more information regarding our environmental liabilities, refer to discussion in Note I of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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

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. After having received these reports, Homeland Security is identifying which sites are required to implement minimum security measures. Homeland Security is in the initial stages of implementing this rule, and the full extent to which the rule will require us to undertake additional expenditures for site security is uncertain at this point.

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, (ii) improving the efficiency of our various pipeline and gas processing 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, operating entities within ONEOK Partners participate in the Processing and Transmission sectors and LDCs in our Distribution segment participate in the Distribution sector of the United States Environmental Protection Agency’s Natural Gas STAR Program to voluntarily reduce methane emissions. In addition, we continue to focus on maintaining low rates of

lost and unaccounted for gas through expanded implementation of best practices to limit the release of methane during pipeline and facility maintenance and operations.

CASH FLOW ANALYSIS

Operating Cash Flows - 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 and allowance for doubtful accounts.

Operating cash flows decreased by $471.6 million for the nine months ended September 30, 2008, compared with the same period in 2007, primarily as a result of changes in the components of working capital. These changes decreased operating cash flows by $245.9 million for the nine months ended September 30, 2008, compared with an increase of $344.0 million for the same period in 2007. The decrease in working capital between periods was primarily due to increases in the cost of gas and natural gas liquids in storage, increases in the fair value of firm commitments and decreases in accounts payable, which were partially offset by decreases in trade accounts and notes receivable.

Investing Cash Flows - Cash used in investing activities was $1.0 billion for the nine months ended September 30, 2008, compared with $497.9 million for the same period in 2007. The increased use of cash was related to capital expenditures resulting from ONEOK Partners’ capital projects.

Financing Cash Flows - Cash provided by financing activities was $591.4 million for the nine months ended September 30, 2008, compared with $313.4 million for the same period in 2007.

Net short-term borrowings were $1.1 billion during the nine months ended September 30, 2008, compared with $359.0 million for the same period in 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 of increased working capital requirements 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.

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.

During the third quarter of 2007, ONEOK Partners completed an underwritten public offering of senior notes totaling $598.1 million in net proceeds, before offering expenses. This debt issuance, net of discounts, was used to repay borrowings under the ONEOK Partners Credit Agreement in the fourth quarter of 2007 and finance the $300 million acquisition of assets, before working capital adjustments, from a subsidiary of Kinder Morgan in October 2007.

FORWARD-LOOKING STATEMENTS

Some of the statements contained and incorporated in this Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q 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;

•

the capital intensive nature of our businesses;

•

the profitability of assets or businesses acquired by us;

•

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;

•

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

•

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 rights-of-way permits and consents in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;

•

the mechanical integrity of facilities operated;

•

demand for our services in the proximity of our facilities;

•

our ability to control operating costs;

•

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

•

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

•

the risk of a significant slowdown in growth or decline in the U.S. economy or the risk of delay in growth recovery in the U.S. economy, including increasing liquidity risks in U.S. 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 Part I, Item 1A, Risk Factors, in our Annual Report on Form 10-K for the year ended December 31, 2007. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our quantitative and qualitative disclosures about market risk are consistent with those discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures About Market Risk in our Annual Report on Form 10-K for the year ended December 31, 2007, except that, beginning January 1, 2008, we determine the fair value of our derivative instruments in accordance with Statement 157. See Notes A and C of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for further discussion of Statement 157.

COMMODITY PRICE RISK

ONEOK Partners

ONEOK Partners is exposed to commodity price risk, primarily 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. 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 tables set forth ONEOK Partners’ hedging information for the remainder of 2008 and for the year ending December 31, 2009.


	Three Months Ending December 31, 2008
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	8,496	$	1.30 / gallon	64	%
Condensate (Bbl/d) (a)	773	$	2.14 / gallon	53	%
Total liquid sales (Bbl/d)	9,269	$	1.37 / gallon	63	%
Natural gas (MMBtu/d) (a)	5,000	$	9.61 / MMBtu	56	%
(a) - Hedged with fixed-price swaps.

	Year Ending December 31, 2009
	Volumes Hedged	Average Price		Percentage Hedged
NGLs (Bbl/d) (a)	2,185	$	2.08 / gallon	19	%
Condensate (Bbl/d) (a)	666	$	3.23 / gallon	30	%
Total liquid sales (Bbl/d)	2,851	$	2.35 / gallon	21	%
(a) - Hedged with fixed-price swaps.

ONEOK Partners’ commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at September 30, 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 increase in the composite price of NGLs would increase annual net margin by approximately $1.5 million,

•

a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.9 million, and

•

a $0.10 per MMBtu increase in the price of natural gas would increase annual net margin by approximately $0.4 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 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 has not entered into any hedges 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 September 30, 2008, there were no hedges in place with respect to natural gas price risk from ONEOK Partners’ natural gas pipeline business.

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 Energy Marketing and Risk Management Assets and Liabilities–The following table sets forth the fair value component of our energy marketing and risk management assets and liabilities, excluding $219.7 million of net liabilities from derivative instruments declared as either fair value or cash flow hedges and $2.0 million of net assets from deferred option premiums.


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 realized or otherwise settled during the period		(10,525	)
Fair value of new derivatives when entered into during the period		142,365
Other changes in fair value		(627	)
Net fair value of derivatives outstanding at September 30, 2008 (a)	$	156,384

(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: $147.9 million matures through March 2009, $8.6 million matures through March 2012 and $(0.1) million matures through March 2014.

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. See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for further discussion of fair value measurements.

For further discussion of trading activities and assumptions used in our trading activities, see the “Critical Accounting Policies and Estimates” section of Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operation in this Quarterly Report on Form 10-Q. Also, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Value-at-Risk (VAR) Disclosure of Market Risk - The potential impact on our future earnings, as measured by VAR, was $12.5 million and $8.2 million at September 30, 2008 and 2007, respectively. The following table details the average, high and low daily VAR calculations for the periods indicated.


		Three Months Ended				Nine Months Ended
		September 30,				September 30,
Value-at-Risk		2008		2007		2008		2007
		(Millions of dollars)
Average	$	12.0	$	8.6	$	12.4	$	9.3
High	$	15.0	$	17.7	$	17.7	$	23.0
Low	$	7.7	$	3.4	$	6.5	$	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 the portfolios during the year. The increase in average VAR for the three months ended September 30, 2008, compared with the same period last year, was primarily due to higher natural gas prices, as well as higher market volatility as Mid-Continent and Rocky Mountain basis spreads widened to near record levels in the third quarter of 2008. The increase in average VAR for the nine months ended September 30, 2008, compared with the same period last year, 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. As a result of this change, the calculated high and low VAR was less extreme in 2008 than in 2007. 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.

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

INTEREST RATE RISK

General - We 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 September 30, 2008, the interest rate on 78.5 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 September 30, 2008, the interest rate on all of ONEOK Partners’ long-term debt was fixed.

At September 30, 2008, a 100 basis point move in the annual interest rate on our variable-rate long-term debt would have changed our annual interest expense by $3.4 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 Quarterly Report on Form 10-Q for discussion of interest-rate swaps and net interest expense savings from terminated swaps.

Total savings from the interest-rate swaps and amortization of terminated swaps was $12.7 million for the nine months ended September 30, 2008. The swaps are expected to net the following savings for the remainder of the year:

•

interest expense savings of $2.6 million related to the amortization of the terminated swaps, and

•

approximately $1.1 million in interest expense savings from the existing $340 million of swapped debt, based on LIBOR rates at September 30, 2008.

Total net swap savings for 2008 are expected to be $16.4 million, compared with $8.2 million for 2007.

CURRENCY RATE RISK

As a result of our Energy Services segment’s operations in Canada, we are subject to currency exposure from our commodity purchases and sales related to our firm transportation and storage contracts. Our objective with respect to currency risk is to reduce the exposure due 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 September 30, 2008, our exposure to risk from currency translation was not material. There were no material currency translation gains or losses recorded during the nine months ended September 30, 2008. We recognized currency translation gains of $3.8 million during the nine months ended September 30, 2007.

COUNTERPARTY CREDIT RISK

ONEOK and ONEOK Partners assess the credit worthiness of their counterparties on an on going basis and require security, including prepayments and other forms of cash collateral, when appropriate.

ITEM 4.

CONTROLS AND PROCEDURES

Quarterly Evaluation of Disclosure Controls and Procedures - As of the end of the period covered by this report, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. Based on their evaluation, they concluded that as of September 30, 2008, our disclosure controls and procedures were effective in ensuring that the information required to be disclosed by us in the reports 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.

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 third quarter ended September 30, 2008, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Additional information about our legal proceedings is included under Part I, Item 3, Legal Proceedings, in our Annual Report on Form 10-K for the year ended December 31, 2007.

Gas Index Pricing Litigation: As previously reported, we, ONEOK Energy Services Company, L.P. (“OESC”) and one other affiliate are defending, either individually or together, against several lawsuits that claim damages resulting from the alleged market manipulation or false reporting of prices to gas index publications by us and others. On May 14, 2008, the motion for summary judgment based upon federal preemption of the claims asserted by the plaintiffs that had been filed by us, OESC, and the other defendants in the J.P. Morgan and Learjet cases was denied. Pretrial discovery has commenced in the cases transferred to the MDL-1566 proceeding in the United States District Court for the District of Nevada.

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 Texas Commission on Environmental Quality (TCEQ) staff regarding air emissions from a heat exchanger at its Mont Belvieu fractionator, which may have exceeded the emissions allowed under its air permit. OHSL discovered the 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.

ITEM 1A.

RISK FACTORS

Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2007, that could affect us and our business. These risk factors have not materially changed, except as set forth below. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should carefully consider the discussion of risks and the other information included or incorporated by reference in this Quarterly Report on Form 10-Q, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

RISK FACTORS INHERENT IN OUR BUSINESS

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 the 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 recover all costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could 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 pipeline and gas processing facilities will potentially to

be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. We may not recover all costs related to complying with climate change regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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 Yet Be Purchased Under the Plans or Programs
July 1-31, 2008	18	(1	)	$	47.80	—	—
August 1-31, 2008	—				—	—	—
September 1-30, 2008	2,400	(2	)	$	34.80	—	—

Total	2,418			$	34.90	—


(1)	Includes shares repurchased directly from employees, pursuant to our Employee Stock Award Program, as follows:
		18 shares for the period July 1-31, 2008

(2)	Includes shares withheld pursuant to attestation of ownership and deemed tendered to us in connection with the exercise of stock options under the ONEOK, Inc. Long-Term Incentive Plan, as follows:
		2,400 shares for the period September 1-30, 2008

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable.

ITEM 5.

OTHER INFORMATION

Not Applicable.

ITEM 6.

EXHIBITS

The following exhibits are filed as part of this Quarterly Report on Form 10-Q:


Exhibit No.		Exhibit Description

10.1		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.

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)).

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	ONEOK, Inc.
	Registrant

Date: November 6, 2008	By:	/s/ Curtis L. Dinan
		Curtis L. Dinan
		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)