Form 10-Q

10-Q 1 d10q.htm FORM 10-Q 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 1-12202

ONEOK PARTNERS, L.P.

(Exact name of registrant as specified in its charter)


Delaware		93-1120873
(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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at October 31, 2008
Common units		54,426,087 units
Class B units		36,494,126 units

ONEOK PARTNERS, L.P.

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

	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2008 and 2007	7

	Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income - Nine Months Ended September 30, 2008	8-9

	Notes to Consolidated Financial Statements	10-19

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20-38

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38-40

Item 4.	Controls and Procedures	40

Part II.	Other Information

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40-41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 3.	Defaults Upon Senior Securities	41

Item 4.	Submission of Matters to a Vote of Security Holders	41

Item 5.	Other Information	41

Item 6.	Exhibits	41

Signature		42

As used in this Quarterly Report on Form 10-Q, “we,” “our,” “us” or the “Partnership” refers to ONEOK Partners, L.P. and its subsidiary, ONEOK Partners Intermediate Limited Partnership and its 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
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
LIBOR		London Interbank Offered Rate
MBbl		Thousand barrels
MBbl/d		Thousand barrels per day
Midwestern Gas Transmission		Midwestern Gas Transmission Company
MMBtu		Million British thermal units
MMBtu/d		Million British thermal units per day
MMcf/d		Million cubic feet per day
Moody’s		Moody’s Investors Service, Inc.
NBP Services		NBP Services, LLC, a subsidiary of ONEOK
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
OkTex Pipeline		OkTex Pipeline Company, L.L.C.
ONEOK		ONEOK, Inc.
ONEOK Partners GP		ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK, Inc. and our sole general partner
OPIS		Oil Price Information Service
Overland Pass Pipeline Company		Overland Pass Pipeline Company LLC
Partnership Agreement		Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P., as amended
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.oneokpartners.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 Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME


	Three Months Ended September 30,						Nine Months Ended September 30,
(Unaudited)	2008			2007			2008			2007
	(Thousands of dollars, except per unit amounts)
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 Expenses
Operations and maintenance		86,456			71,470			243,929			212,517
Depreciation and amortization		30,408			28,800			90,383			84,326
General taxes		11,032			8,609			28,799			24,866
Total Operating Expenses		127,896			108,879			363,111			321,709
Gain (Loss) on Sale of Assets		22			111			50			1,935
Operating Income		197,526			105,116			511,797			317,050
Equity earnings from investments (Note J)		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		990			905			3,724			4,870
Other expense		(5,784	)		(125	)		(7,951	)		(636	)
Interest expense		(34,447	)		(33,510	)		(107,681	)		(99,313	)
Income before Minority Interests and Income Taxes		203,313			98,239			510,482			293,632
Minority interests in income of consolidated subsidiaries		(111	)		(125	)		(368	)		(302	)
Income taxes		670			(2,198	)		(6,703	)		(7,039	)
Net Income	$	203,872		$	95,916		$	503,411		$	286,291

Limited partners’ interest in net income:
Net income	$	203,872		$	95,916		$	503,411		$	286,291
General partners’ interest in net income		(24,397	)		(14,872	)		(65,790	)		(42,203	)
Limited Partners’ Interest in Net Income	$	179,475		$	81,044		$	437,621		$	244,088

Limited partners’ per unit net income:
Net income per unit (Note K)	$	1.97		$	0.98		$	4.93		$	2.94

Number of Units Used in Computation (Thousands)		90,920			82,891			88,768			82,891

See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


(Unaudited)	September 30, 2008		December 31, 2007
Assets	(Thousands of dollars)
Current Assets
Cash and cash equivalents	$	15,803	$	3,213
Accounts receivable, net		475,105		577,989
Affiliate receivables		43,234		52,479
Gas and natural gas liquids in storage		265,824		251,219
Commodity exchanges and imbalances		79,345		82,037
Other current assets		49,691		19,961
Total Current Assets		929,002		986,898

Property, Plant and Equipment
Property, plant and equipment		5,444,041		4,436,371
Accumulated depreciation and amortization		849,699		776,185
Net Property, Plant and Equipment (Note A)		4,594,342		3,660,186

Investments and Other Assets
Investment in unconsolidated affiliates (Note J)		756,449		756,260
Goodwill and intangible assets		678,453		682,084
Other assets		34,049		26,637
Total Investments and Other Assets		1,468,951		1,464,981
Total Assets	$	6,992,295	$	6,112,065


Liabilities and Partners’ Equity

Current Liabilities
Current maturities of long-term debt	$	11,931	$	11,930
Notes payable		280,000		100,000
Accounts payable		759,785		742,903
Affiliate payables		29,699		18,298
Commodity exchanges and imbalances		245,882		252,095
Other current liabilities		151,058		136,664
Total Current Liabilities		1,478,355		1,261,890

Long-term Debt, excluding current maturities		2,593,481		2,605,396

Deferred Credits and Other Liabilities		43,744		43,799

Commitments and Contingencies (Note H)

Minority Interests in Consolidated Subsidiaries		5,947		5,802

Partners’ Equity
General partner		77,520		58,415
Common units: 54,426,087 units and 46,397,214 units issued and outstanding at September 30, 2008, and December 31, 2007, respectively		1,360,311		814,266
Class B units: 36,494,126 units issued and outstanding at September 30, 2008, and December 31, 2007		1,406,515		1,340,638
Accumulated other comprehensive income (loss) (Note E)		26,422		(18,141	)
Total Partners’ Equity		2,870,768		2,195,178
Total Liabilities and Partners’ Equity	$	6,992,295	$	6,112,065

See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
(Unaudited)	2008			2007
Operating Activities	(Thousands of dollars)
Net income	$	503,411		$	286,291
Depreciation and amortization		90,383			84,326
Allowance for equity funds used during construction		(35,788	)		(6,686	)
Gain on sale of assets		(50	)		(1,935	)
Minority interests in income of consolidated subsidiaries		368			302
Equity earnings from investments		(74,805	)		(64,975	)
Distributions received from unconsolidated affiliates		67,812			77,144
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts receivable		98,214			(83,065	)
Affiliate receivables		9,245			45,650
Gas and natural gas liquids in storage		(59,690	)		(29,357	)
Accounts payable		(52,516	)		146,880
Affiliate payables		11,401			1,734
Commodity exchanges and imbalances, net		(3,521	)		22,627
Accrued interest		32,117			23,086
Other assets and liabilities		(17,916	)		24,461
Cash Provided by Operating Activities		568,665			526,483
Investing Activities
Changes in investments in unconsolidated affiliates		3,063			(5,546	)
Capital expenditures (less allowance for equity funds used during construction)		(860,167	)		(408,353	)
Proceeds from sale of assets		133			3,959
Other		2,450			—
Cash Used in Investing Activities		(854,521	)		(409,940	)
Financing Activities
Cash distributions to:
General and limited partners		(332,090	)		(285,998	)
Minority interests		(223	)		(147	)
Borrowing (payment) of notes payable, net		180,000			359,000
Issuance of common units, net of discounts		450,198			—
Contributions from general partner		9,508			—
Issuance of long-term debt		—			598,146
Payment of long-term debt		(8,947	)		(8,948	)
Other		—			(5,280	)
Cash Provided by Financing Activities		298,446			656,773
Change in Cash and Cash Equivalents		12,590			773,316
Cash and Cash Equivalents at Beginning of Period		3,213			21,102
Cash and Cash Equivalents at End of Period	$	15,803		$	794,418

See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY AND COMPREHENSIVE INCOME


(Unaudited)	Common Units	Class B Units	General Partner			Common Units
	(Units)		(Thousands of dollars)
December 31, 2007	46,397,214	36,494,126	$	58,415		$	814,266
Net income	-	-		65,790			257,699
Other comprehensive income (loss) (Note E)	-	-		-			-
Total comprehensive income
Issuance of common units (Note F)	8,028,873	-		-			450,198
Contribution from general partner (Note F)	-	-		9,508			-
Distributions paid (Note K)	-	-		(56,193	)		(161,852	)
September 30, 2008	54,426,087	36,494,126	$	77,520		$	1,360,311

See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ EQUITY AND COMPREHENSIVE INCOME

(Continued)


	Class B Units			Accumulated Other Comprehensive Income (Loss)			Total Partners’ Equity
	(Thousands of dollars)
December 31, 2007	$	1,340,638		$	(18,141	)	$	2,195,178
Net income		179,922			-			503,411
Other comprehensive income (loss) (Note E)		-			44,563			44,563

Total comprehensive income								547,974

Issuance of common units (Note F)		-			-			450,198
Contribution from general partner (Note F)		-			-			9,508
Distributions paid (Note K)		(114,045	)		-			(332,090	)
September 30, 2008	$	1,406,515		$	26,422		$	2,870,768

ONEOK Partners, L.P. 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.

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

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, 2008		December 31, 2007
	(Thousands of dollars)
Non-Regulated
Natural Gas Gathering and Processing	$	1,328,693	$	1,227,475
Natural Gas Pipelines		166,889		162,390
Natural Gas Liquids Gathering and Fractionation		851,476		672,047
Other		50,401		50,482
Regulated
Natural Gas Pipelines		1,361,142		1,184,112
Natural Gas Liquids Pipelines		1,685,440		1,139,865
Property, plant and equipment		5,444,041		4,436,371
Accumulated depreciation and amortization		849,699		776,185
Net property, plant and equipment	$	4,594,342	$	3,660,186

At September 30, 2008, and December 31, 2007, property, plant and equipment on our Consolidated Balance Sheets included construction work in process of $1.4 billion and $0.9 billion, respectively, that had not yet been put in service and therefore was not being depreciated.

Other

Fair Value Measurements - 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. See Note C for disclosures of fair value measurements for our financial instruments. 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.

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 applied the provisions of FIN 39-1 to our consolidated financial statements beginning January 1, 2008, and the impact was not material. At September 30, 2008, we had no cash collateral held or posted under our master netting arrangement.

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.

Net Income Per Unit - The FASB ratified EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships,” in March 2008. EITF 07-4 results in the allocation of undistributed current-period earnings to the unitholders using the two-class method in periods in which earnings exceed distributions. When distributions to participating securities exceed current-period earnings, the excess distributions generate an undistributed loss that would be allocated back to the equity interests based on the contractual terms of the partnership agreement. EITF 07-4 is effective for our year beginning January 1, 2009, and requires retrospective application. We are currently reviewing the impact of EITF 07-4 to our net income per unit computations.

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 partners’ equity.

B.	ACQUISITION

In October 2007, we 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. Our investment in Heartland is accounted for under the equity method of accounting. Financing for this transaction came from a portion of the proceeds of our 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

As discussed in Note A, we applied the provisions of Statement 157 as of January 1, 2008, to our recurring fair value measurements.

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 income approach to determine the fair value of our derivative 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. For certain transactions, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil. 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. Finally, we consider the credit risk of our counterparties with whom our derivative assets and liabilities are executed. 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 significant.

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, as discussed below.

The following table sets forth our recurring fair value measurements for the period indicated.

September 30, 2008

Level 1

Level 2

Level 3

Total

(Thousands of dollars)

Derivatives

Assets

—

10,648

15,065

25,713

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.

When our fair value measurements that are based on NYMEX-settled prices are associated with exchange-traded instruments, we classify those derivatives as Level 1. These measurements may include futures for natural gas and crude oil which are valued based on unadjusted quoted prices in active markets. Our Level 2 fair value measurements 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. For our Level 3 inputs, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil.

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


	Derivative Assets (Liabilities)
	(Thousands of dollars)
Net liabilities at June 30, 2008	$	(37,704	)
Total realized/unrealized gains (losses):
Included in earnings (a)		(3,407	)
Included in other comprehensive income (loss)		56,176
Transfers in and/or out of Level 3		-
Net assets at September 30, 2008	$	15,065

Total gains (losses) for the three-month period included in earnings attributable to the change in unrealized gain (loss) relating to assets and liabilities still held as of September 30, 2008 (a)	$	(3,422	)



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


	Derivative Assets (Liabilities)
	(Thousands of dollars)
Net liabilities at January 1, 2008	$	(16,400	)
Total realized/unrealized gains (losses):
Included in earnings (a)		(2,434	)
Included in other comprehensive income (loss)		33,899
Transfers in and/or out of Level 3		-
Net assets at September 30, 2008	$	15,065

Total gains (losses) for the nine-month period included in earnings attributable to the change in unrealized gain (loss) relating to assets and liabilities still held as of September 30, 2008 (a)	$	(3,422	)



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

D.	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We utilize financial instruments to reduce our market risk exposure to interest rate and commodity price fluctuations and to achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our financial instrument activities. We do not use these instruments for trading purposes.

Cash Flow Hedges - Our Natural Gas Gathering and Processing segment primarily utilizes NYMEX-based futures, collars and over-the-counter swaps, which are designated as cash flow hedges, to hedge our exposure to volatility in the price of natural gas, NGLs and condensate. At September 30, 2008, our Consolidated Balance Sheet reflected an unrealized gain of $29.3 million in accumulated other comprehensive income (loss), with a corresponding offset in derivative financial instrument assets and liabilities, all of which will be recognized over the next 15 months. If prices remain at current levels, we will recognize $22.5 million in gains over the next 12 months, and we will recognize gains of $6.8 million thereafter. Net gains and losses related to the ineffective portion of our hedges are reclassified out of accumulated other comprehensive income (loss) to revenues in the period the ineffectiveness occurs. Ineffectiveness related to our cash flow hedges was not material for the three and nine months ended September 30, 2008 and 2007. 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.

Fair Value Hedges - In prior years, we terminated various interest-rate swap agreements. The net savings from the termination of these swaps is being recognized in interest expense over the terms of the debt instruments originally hedged. Interest expense savings for the nine months ended September 30, 2008, from amortization of terminated swaps was $2.8 million, and the remaining amortization of terminated swaps will be recognized over the following periods.



	(Millions of dollars)
Remainder of 2008	$	0.9
2009		3.7
2010		3.7
2011		0.9

At September 30, 2008, none of the interest on our fixed-rate debt was swapped to floating using interest rate swaps.

E.	OTHER COMPREHENSIVE INCOME (LOSS)

The table below shows other comprehensive income (loss) for the periods indicated.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(Thousands of dollars)
Unrealized gains (losses) on derivatives	$	66,661		$	(1,361	)	$	13,496		$	(8,089	)
Less: Realized losses recognized in net income		(14,202	)		-			(31,067	)		-
Other comprehensive income (loss)	$	80,863		$	(1,361	)	$	44,563		$	(8,089	)

The table below shows the balance in accumulated other comprehensive income (loss) for the period indicated.


	Unrealized Gains (Losses) on Derivatives
	(Thousands of dollars)
December 31, 2007	$	(18,141	)
Other comprehensive income (loss)		44,563
September 30, 2008	$	26,422

F.	PARTNERS’ EQUITY

ONEOK and its affiliates own all of the Class B units, 5,900,000 common units and the entire 2 percent general partner interest in us, which together constituted a 47.7 percent equity interest in us at September 30, 2008.

In March 2008, we completed a public offering of 2.5 million common units at $58.10 per common unit, generating net proceeds of approximately $140.4 million after deducting underwriting discounts but before offering expenses. In addition, we sold 5.4 million common units to ONEOK in a private placement, generating proceeds of approximately $303.2 million. In conjunction with the public offering of common units and the private placement, ONEOK Partners GP contributed $9.4 million in order to maintain its 2 percent general partner interest in us.

In April 2008, we 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. We received net proceeds of approximately $7.2 million from the sale of the 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 in order to maintain its 2 percent general partner interest in us.

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

The following summarizes our quarterly cash distribution activity for 2008.

•

In January 2008, we declared a cash distribution of $1.025 per unit for the fourth quarter of 2007. The distribution was paid on February 14, 2008, to unitholders of record on January 31, 2008.

•

In April 2008, we declared a cash distribution of $1.04 per unit for the first quarter of 2008. The distribution was paid on May 15, 2008, to unitholders of record as of April 30, 2008.

•

In July 2008, we declared a cash distribution of $1.06 per unit for the second quarter of 2008. The distribution was paid on August 14, 2008, to unitholders of record as of July 31, 2008.

•

In October 2008, we declared a cash distribution of $1.08 per unit ($4.32 per unit on an annualized basis) for the third quarter of 2008. The distribution will be paid on November 14, 2008, to unitholders of record as of October 31, 2008.

Our general partner’s percentage interest in quarterly distributions increases after certain specified target levels are met. For additional information, see “Cash Distribution Policy” under Part II, Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities, in our Annual Report on Form 10-K for the year ended December 31, 2007.

G.	CREDIT FACILITIES

Our Partnership Credit Agreement contains typical covenants as discussed in Note F 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, we were in compliance with all covenants.

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

In October 2008, we borrowed $590 million under our Partnership Credit Agreement. With this borrowing, we had $870 million outstanding and $130 million available under our Partnership Credit Agreement at October 31, 2008.

We have 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 our ongoing business in Kansas.

H.	COMMITMENTS AND CONTINGENCIES

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.

I.	SEGMENTS

Segment Descriptions - Our operations are divided into strategic business segments based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, as follows:

•

our Natural Gas Gathering and Processing segment primarily gathers and processes unprocessed natural gas;

•

our Natural Gas Pipelines segment primarily operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities;

•

our Natural Gas Liquids Gathering and Fractionation segment primarily gathers, treats and fractionates NGLs and stores and markets NGL products; and

•

our Natural Gas Liquids Pipelines segment primarily operates FERC-regulated interstate natural gas liquids gathering and distribution pipelines.

Accounting Policies - The accounting policies of the segments are the same as those described in Note A and Note J of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007. Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Our Natural Gas Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A portion of our Natural Gas Pipelines segment’s revenues are from subsidiaries of ONEOK that utilize transportation and storage services. Corporate overhead costs relating to a reportable segment have been allocated for the purpose of calculating operating income.

Customers - For the three months ended September 30, 2008 and 2007, we had no single external customer from which we received 10 percent or more of our consolidated revenues. We had one customer, Dow Hydrocarbons and Resources L.L.C., from which we received $686.3 million, or approximately 11 percent of our consolidated revenues, for the nine months ended September 30, 2008. All of these revenues were received by our Natural Gas Liquids Gathering and Fractionation segment. For the nine months ended September 30, 2007, 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. Amounts in prior periods have been restated to conform to our current presentation.


Three Months Ended September 30, 2008	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)		Natural Gas Liquids Gathering and Fractionation		Natural Gas Liquids Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	129,305	$	55,528	$	1,836,627	$	10,838	$	47		$	2,032,345
Sales to affiliated customers		178,167		30,595		—		—		—			208,762
Intersegment sales		190,403		567		6,695		23,708		(221,373	)		—
Total revenues	$	497,875	$	86,690	$	1,843,322	$	34,546	$	(221,326	)	$	2,241,107
Net margin	$	111,720	$	65,762	$	118,630	$	29,754	$	(466	)	$	325,400
Operating costs		35,651		23,852		22,954		14,986		45			97,488
Depreciation and amortization		12,533		8,607		5,901		3,361		6			30,408
Gain (loss) on sale of assets		2		—		13		7		—			22
Operating income	$	63,538	$	33,303	$	89,788	$	11,414	$	(517	)	$	197,526
Equity earnings from investments	$	8,819	$	20,207	$	—	$	386	$	—		$	29,412
Capital expenditures	$	35,769	$	107,822	$	52,558	$	139,431	$	—		$	335,580



(a)	-	Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $71.2 million, net margin of $52.8 million and operating income of $25.9 million for the three months ended September 30, 2008.
(b)	-	All of our Natural Gas Liquids Pipelines segment’s operations are regulated.


Three Months Ended September 30, 2007	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)		Natural Gas Liquids Gathering and Fractionation		Natural Gas Liquids Pipelines (b)			Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	81,660	$	44,550	$	1,113,467	$	—		$	4		$	1,239,681
Sales to affiliated customers		141,907		28,669		—		—			—			170,576
Intersegment sales		125,384		145		6,630		19,672			(151,831	)		—
Total revenues	$	348,951	$	73,364	$	1,120,097	$	19,672		$	(151,827	)	$	1,410,257
Net margin	$	87,625	$	60,247	$	48,827	$	17,981		$	(796	)	$	213,884
Operating costs		31,808		24,109		17,787		5,648			727			80,079
Depreciation and amortization		11,277		8,089		6,439		2,987			8			28,800
Gain (loss) on sale of assets		10		73		27		1			—			111
Operating income	$	44,550	$	28,122	$	24,628	$	9,347		$	(1,531	)	$	105,116
Equity earnings from investments	$	6,180	$	16,493	$	—	$	(511	)	$	—		$	22,162
Capital expenditures	$	32,307	$	44,561	$	20,645	$	104,428		$	21		$	201,962



(a)	-	Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $61.2 million, net margin of $48.1 million and operating income of $20.6 million for the three months ended September 30, 2007.
(b)	-	All of our Natural Gas Liquids Pipelines segment’s operations are regulated.


Nine Months Ended September 30, 2008	Natural Gas Gathering and Processing			Natural Gas Pipelines (a)			Natural Gas Liquids Gathering and Fractionation		Natural Gas Liquids Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	366,095		$	173,442		$	5,267,185	$	40,845	$	48		$	5,847,615
Sales to affiliated customers		504,541			91,878			—		—		—			596,419
Intersegment sales		602,542			1,338			21,761		67,160		(692,801	)		—
Total revenues	$	1,473,178		$	266,658		$	5,288,946	$	108,005	$	(692,753	)	$	6,444,034
Net margin	$	336,746		$	196,173		$	255,494	$	88,480	$	(2,035	)	$	874,858
Operating costs		101,538			67,900			61,575		42,171		(456	)		272,728
Depreciation and amortization		36,431			25,547			17,188		11,200		17			90,383
Gain (loss) on sale of assets		(3	)		(18	)		31		8		32			50
Operating income	$	198,774		$	102,708		$	176,762	$	35,117	$	(1,564	)	$	511,797
Equity earnings from investments	$	23,989		$	49,421		$	—	$	1,395	$	—		$	74,805
Investment in unconsolidated affiliates	$	323,537		$	403,373		$	—	$	29,539	$	—		$	756,449
Minority interests in consolidated subsidiaries	$	—		$	5,800		$	—	$	132	$	15		$	5,947
Total assets	$	1,593,872		$	1,371,178		$	1,982,549	$	1,702,542	$	342,154		$	6,992,295
Capital expenditures	$	98,604		$	159,810		$	137,177	$	464,511	$	65		$	860,167


(a)	-	Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $221.7 million, net margin of $155.0 million and operating income of $76.9 million for the nine months ended September 30, 2008.
(b)	-	All of our Natural Gas Liquids Pipelines segment’s operations are regulated.


Nine Months Ended September 30, 2007	Natural Gas Gathering and Processing		Natural Gas Pipelines (a)		Natural Gas Liquids Gathering and Fractionation		Natural Gas Liquids Pipelines (b)		Other and Eliminations			Total
	(Thousands of dollars)
Sales to unaffiliated customers	$	292,867	$	140,394	$	3,029,248	$	—	$	30		$	3,462,539
Sales to affiliated customers		413,027		78,679		—		—		—			491,706
Intersegment sales		328,695		652		19,416		56,194		(404,957	)		—
Total revenues	$	1,034,589	$	219,725	$	3,048,664	$	56,194	$	(404,927	)	$	3,954,245
Net margin	$	249,396	$	179,680	$	155,295	$	51,933	$	520		$	636,824
Operating costs		96,399		69,953		49,387		16,551		5,093			237,383
Depreciation and amortization		33,544		24,246		17,525		8,990		21			84,326
Gain (loss) on sale of assets		1,823		79		31		2		—			1,935
Operating income	$	121,276	$	85,560	$	88,414	$	26,394	$	(4,594	)	$	317,050
Equity earnings from investments	$	19,518	$	45,275	$	—	$	182	$	—		$	64,975
Investment in unconsolidated affiliates	$	297,581	$	434,827	$	—	$	8,902	$	—		$	741,310
Minority interests in consolidated subsidiaries	$	—	$	5,724	$	—	$	22	$	15		$	5,761
Total assets	$	1,442,511	$	1,181,898	$	1,582,772	$	700,995	$	1,156,744		$	6,064,920
Capital expenditures	$	72,235	$	90,635	$	43,234	$	202,222	$	27		$	408,353


(a)	-	Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $182.7 million, net margin of $143.1 million and operating income of $63.1 million for the nine months ended September 30, 2007.
(b)	-	All of our Natural Gas Liquids Pipelines segment’s operations are regulated.

J.	UNCONSOLIDATED AFFILIATES

Equity Earnings from Investments - The following table sets forth our equity earnings from investments for the periods indicated.


	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 us	$	30,466	$	20,078	$	91,093	$	77,144

K.	NET INCOME PER UNIT

Net income per unit is computed by dividing net income, after deducting the general partner’s allocation, by the weighted average number of outstanding limited partner units. The general partner owns the entire 2 percent interest in us and also owns incentive distribution rights that provide for an increasing proportion of cash distributions from the partnership as the distributions made to limited partners increase above specified levels. For purposes of our calculation of net income per unit, net income is generally allocated to the general partner as follows: (i) an amount based upon the 2 percent general partner interest in net income and (ii) the amount of the general partner’s incentive distribution rights based on the total cash distributions declared for the period. The amount of incentive distribution allocated to our general partner totaled $20.3 million and $55.7 million for the three and nine months ended September 30, 2008, respectively. Distributions paid to our general partner and shown on our Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income of $56.2 million included $49.5 million in incentive distributions paid to our general partner during the first nine months of 2008. Gains resulting from interim capital transactions, as defined in our Partnership Agreement, are generally not subject to distribution; however, our Partnership Agreement provides that if such distributions were made, the incentive distribution rights would not apply. Accordingly, the gain (loss) on sale of assets for the three and nine months ended September 30, 2008 and 2007 had no impact on the incentive distribution rights.

L.	RELATED-PARTY TRANSACTIONS

Intersegment and affiliate sales are recorded on the same basis as sales to unaffiliated customers. Our Natural Gas Gathering and Processing segment sells natural gas to ONEOK and its subsidiaries. A portion of our Natural Gas Pipelines segment’s revenues are from ONEOK and its subsidiaries that utilize natural gas transportation and storage services.

We have certain contractual rights to the Bushton Plant that is leased by OBPI. Our Processing and Services Agreement with ONEOK and OBPI sets out the terms by which OBPI provides services at the Bushton Plant through 2012. We have contracted for all of the capacity of the Bushton Plant from OBPI. In exchange, we pay OBPI for all direct costs and expenses of the Bushton Plant, including reimbursement of a portion of OBPI’s obligations under equipment leases covering the Bushton Plant.

Under the Services Agreement with ONEOK, ONEOK Partners GP and NBP Services, our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK provides to us at least the type and amount of services that it provides to its affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP operates our interstate natural gas pipeline assets according to each pipeline’s operating agreement. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. ONEOK Partners GP has no employees and utilizes the services of ONEOK and ONEOK Services Company to fulfill its responsibilities.

ONEOK and its affiliates provide a variety of services to us under the Services Agreement, including cash management and financial services, employee benefits provided through ONEOK’s benefit plans, administrative services, insurance and office space leased in ONEOK’s headquarters building and other field locations. Where costs are specifically incurred on behalf of one of our affiliates, the costs are billed directly to us by ONEOK. In other situations, the costs may be allocated to us through a variety of methods, depending upon the nature of the expense and activities. For example, a service that applies equally to all employees is allocated based upon the number of employees. However, an expense benefiting the consolidated company but having no direct basis for allocation is allocated by the modified Distrigas method, a method using a combination of ratios that include gross plant and investment, earnings before interest and taxes and payroll expense. All costs directly charged or allocated to us are included in our Consolidated Statements of Income.

An affiliate of ONEOK enters into some of the commodity derivative contracts at the direction of and on behalf of our Natural Gas Gathering and Processing segment. See Note D for a discussion of our derivative instruments and hedging activities.

The following table sets forth the transactions with related parties 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

In addition, concurrent with our sale of common units to the public, we sold 5.4 million common units to ONEOK in March 2008 in a private placement, generating proceeds of approximately $303.2 million. ONEOK Partners GP also made additional general partner contributions to us in March and April 2008. See Note F for additional information.

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.

EXECUTIVE SUMMARY

The following discussion highlights some of our achievements and significant issues affecting us for the periods presented. Please refer to the “Liquidity and Capital Resources,” “Capital Projects,” and “Financial Results and Operating Information” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements for additional information.

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

In October 2008, we declared an increase in our cash distribution to $1.08 per unit ($4.32 per unit on an annualized basis), 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, our subsidiary, placed its eastern extension pipeline into service.

Net income per unit increased to $1.97 for the three months ended September 30, 2008, compared with $0.98 for the same period in 2007. For the nine-month period, net income per unit increased to $4.93 from $2.94 for the same period last year. The increase in net income per unit for the three- and nine-month periods is primarily due to the following:

•

wider NGL product price differentials, increased NGL gathering and fractionation volumes and certain operational measurement gains, primarily at NGL storage caverns, in our Natural Gas Liquids Gathering and Fractionation segment,

•

higher realized commodity prices, higher volumes sold and processed, and improved contractual terms in our Natural Gas Gathering and Processing segment,

•

increased transportation and storage margins as a result of the impact of higher natural gas prices on retained fuel and new and renegotiated storage contracts in our Natural Gas Pipelines segment, and

•

incremental operating income in our Natural Gas Liquids Pipelines segment from the assets acquired from Kinder Morgan Energy Partners, LP (Kinder Morgan) in October 2007.

During September 2008, our Natural Gas Gathering and Processing segment, Natural Gas Liquids Gathering and Fractionation segment, and Natural Gas Liquids Pipelines segment experienced disruptions related to Hurricane Ike. Without these disruptions, we estimate net margin would have been approximately $7.8 million higher.

SIGNIFICANT ACQUISITION

In October 2007, we 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. Our investment in Heartland is accounted for under the equity method of accounting. Financing for this transaction came from a portion of the proceeds of our 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. These assets are included in our Natural Gas Liquids Pipelines segment.

CAPITAL PROJECTS

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 our 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 our Mont Belvieu, Texas, fractionation facility. This project is in our Natural Gas Liquids Gathering and Fractionation segment.

Overland Pass Pipeline Company - In May 2006, we 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, we paid $11.6 million to Williams for the acquisition of our interest in the joint venture and for reimbursement of initial capital expenditures. As the 99 percent owner of the joint venture, we are 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 us 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. We will provide downstream fractionation, storage and transportation services to Williams. We have also reached agreements with certain producers for supply commitments of up to an additional 80 MBbl/d, and we are 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 our 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.

We are also investing in the range of $230 million to $240 million, excluding AFUDC, which remains unchanged from the previous quarter, to expand our existing fractionation and storage capabilities and the capacity of our natural gas liquids distribution pipelines. Since our 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 our natural gas liquids distribution pipeline upgrades were completed in the second

and third quarters of 2008. Overland Pass Pipeline Company is included in our Natural Gas Liquids Pipelines segment, while the associated expansions are included in our Natural Gas Liquids Gathering and Fractionation segment and our Natural Gas Liquids Pipelines segment.

Piceance Lateral Pipeline - In March 2007, we 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. We continue to negotiate with other producers for supply commitments. In October 2008, this project received the 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 our construction permit from the federal 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. This project is in our Natural Gas Liquids Pipelines segment.

D-J Basin Lateral Pipeline - In September 2008, we 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. We have 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. This project is in our Natural Gas Liquids Pipelines segment.

Arbuckle Natural Gas Liquids Pipeline - In March 2007, we 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 our project costs from our original estimate of $260 million. We have 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 our existing Mid-Continent infrastructure with our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. We have 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. This project is in our Natural Gas Liquids Pipelines segment.

Williston Basin Gas Processing Plant Expansion - In March 2007, we announced the expansion of our 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. Our estimated project costs increased from $30 million primarily as a result of higher contract labor and equipment costs. The Grasslands facility is our 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. This project is in our Natural Gas Gathering and Processing segment.

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. We own approximately 37 percent of Fort Union Gas Gathering. This investment is in our Natural Gas Gathering and Processing segment and is accounted for 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 us 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 to $305 million, excluding AFUDC, which remains unchanged from the previous quarter. Our estimated project costs increased from our 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. We 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. This project is in our Natural Gas Pipelines segment.

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 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,”

•

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

•

EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships.”

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.

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.

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	$	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 (loss) 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
Other income (expense)	$	(4,794	)	$	780		$	(4,227	)	$	4,234
Interest expense	$	(34,447	)	$	(33,510	)	$	(107,681	)	$	(99,313	)

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 the following:

•

higher realized commodity prices, higher volumes sold and processed, and improved contractual terms in our Natural Gas Gathering and Processing segment,

•

incremental net margin in our Natural Gas Liquids Pipelines segment from the assets acquired from Kinder Morgan in October 2007, and

•

increased transportation and storage margins as a result of the impact of higher natural gas prices on retained fuel and new and renegotiated storage contracts in our Natural Gas Pipelines 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 and higher employee-related costs. Operating costs also increased due to costs associated with the startup of our newly expanded Bushton fractionator.

Depreciation and amortization increased for the three and nine months ended September 30, 2008, compared with the same periods last year, primarily due to depreciation expense associated with our completed capital projects and the assets acquired from Kinder Morgan.

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 a gain on the sale of Bison Pipeline LLC by Northern Border Pipeline and higher gathering revenues in our various investments, partially offset by reduced throughput on Northern Border Pipeline. We own 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 our capital projects, which are discussed beginning on page 21.

Other income (expense) fluctuated for the three and nine months ended September 30, 2008, compared with the same periods last year, primarily due to investment gains (losses).

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

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment’s operations include gathering of natural gas production from crude oil and natural gas wells. We gather unprocessed natural gas in the Mid-Continent region, which includes the Anadarko Basin of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas. We also gather unprocessed natural gas in two producing basins in the Rocky Mountain region: the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, and the Powder River Basin of Wyoming.

Through gathering systems, unprocessed natural gas volumes are aggregated for removal of water vapor, solids and other contaminants and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas. When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are generally in the form of a mixed, unfractionated NGL stream. This unfractionated NGL stream is generally shipped to fractionators, where by applying heat and pressure, the unfractionated NGL stream is separated into marketable purity products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). Revenues for this segment are primarily derived from percent-of-proceeds (POP), fee and keep-whole contracts. Under a POP contract, we retain a portion of sales proceeds from the commodity sales for our services. With a fee-based contract, we charge a fee for our services, and with the keep-whole contract, we retain the NGLs as our fee for service and return to the producer an equivalent quantity of residue gas containing the same amount of Btus as the unprocessed natural gas that was delivered to us. Our natural gas and NGL products are sold to affiliates and a diverse customer base.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
Financial Results	2008		2007		2008			2007
	(Thousands of dollars)
NGL and condensate sales	$	249,246	$	168,668	$	720,185		$	455,122
Residue gas sales		209,734		143,956		636,980			472,340
Gathering, compression, dehydration and processing fees and other revenues		38,895		36,327		116,013			107,127
Cost of sales and fuel		386,155		261,326		1,136,432			785,193
Net margin		111,720		87,625		336,746			249,396
Operating costs		35,651		31,808		101,538			96,399
Depreciation and amortization		12,533		11,277		36,431			33,544
Gain (loss) on sale of assets		2		10		(3	)		1,823
Operating income	$	63,538	$	44,550	$	198,774		$	121,276

Equity earnings from investments	$	8,819	$	6,180	$	23,989		$	19,518

	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2008		2007		2008			2007
Natural gas gathered (BBtu/d)		1,146		1,170		1,174			1,168
Natural gas processed (BBtu/d)		649		617		641			615
NGL sales (MBbl/d)		39		37		39			37
Residue gas sales (BBtu/d)		281		289		280			279
Capital expenditures (Thousands of dollars)	$	35,769	$	32,307	$	98,604		$	72,235
Realized composite NGL sales price ($/gallon)	$	1.51	$	1.09	$	1.44		$	0.97
Realized condensate sales price ($/Bbl)	$	99.61	$	69.05	$	96.91		$	61.25
Realized residue gas sales price ($/MMBtu)	$	8.33	$	5.41	$	8.39		$	6.20
Realized gross processing spread ($/MMBtu)	$	6.69	$	5.54	$	6.94		$	4.56



	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Percent of proceeds
Wellhead purchases (MMBtu/d)		65,804			76,841			68,564			86,361
NGL sales (Bbl/d)		5,948			5,680			6,053			5,911
Residue gas sales (MMBtu/d)		42,119			34,691			38,570			32,252
Condensate sales (Bbl/d)		709			681			964			695
Percentage of total net margin		64	%		53	%		62	%		56	%
Fee-based
Wellhead volumes (MMBtu/d)		1,145,656			1,170,030			1,173,894			1,168,360
Average rate ($/MMBtu)	$	0.27		$	0.26		$	0.26		$	0.26
Percentage of total net margin		22	%		32	%		23	%		32	%
Keep-whole
NGL shrink (MMBtu/d)		20,016			22,056			21,978			23,555
Plant fuel (MMBtu/d)		2,106			2,605			2,301			2,785
Condensate shrink (MMBtu/d)		1,574			1,733			1,941			2,299
Condensate sales (Bbl/d)		318			351			393			465
Percentage of total net margin		14	%		15	%		15	%		12	%

Operating Results - Net margin increased $24.1 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to the following:

•

an increase of $18.3 million due to higher realized commodity prices,

•

an increase of $3.4 million due to improved contractual terms, and

•

an increase of $2.3 million due to higher volumes sold and processed.

Net margin increased $87.4 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to the following:

•

an increase of $66.2 million due to higher realized commodity prices,

•

an increase of $11.5 million due to higher volumes sold and processed, and

•

an increase of $9.7 million due to improved contractual terms.

During September 2008, the disruption in the Gulf Coast area related to Hurricane Ike limited our ability to process and deliver natural gas and NGL volumes from our Mid-Continent processing plants. Without this volume reduction, we estimate net margin would have been approximately $1.8 million higher.

Operating costs increased $3.8 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to increased employee-related costs and increased costs for chemicals and maintenance parts, partially offset by decreased equipment lease costs associated with the Bushton Plant.

Operating costs increased $5.1 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to increased employee-related costs, increased costs for chemicals and maintenance parts, and a favorable legal settlement received in June 2007, which reduced legal costs for the nine months ended September 30, 2007. These increases were partially offset by decreased equipment lease costs in 2008 associated with the Bushton Plant.

Depreciation and amortization increased $1.3 million and $2.9 million for the three- and nine-month periods in 2008, respectively, primarily as a result of depreciation expense associated with our completed capital projects.

The increase in equity earnings from investments for the three- and nine-month periods is driven primarily by higher gathering revenues in our various investments.

The increase in capital expenditures for the three and nine months ended September 30, 2008, compared with the same periods last year, is driven primarily by our increased growth activities, primarily in the Rocky Mountain region.

Our Natural Gas Gathering and Processing segment is exposed to commodity price risk, primarily from NGLs, as a result of our contractual obligations for services provided. A small percentage of our services, based on volume, is provided through keep-whole arrangements. See discussion regarding our commodity price risk beginning on page 38 under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment primarily operates regulated natural gas transmission pipelines, natural gas storage facilities, and non-processable natural gas gathering facilities. We also provide interstate natural gas transportation and storage service in accordance with Section 311(a) of the Natural Gas Policy Act.

Our interstate natural gas pipeline assets transport natural gas through FERC-regulated interstate natural gas pipelines in Montana, North Dakota, South Dakota, Minnesota, Wisconsin, Iowa, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipelines include Midwestern Gas Transmission, Guardian Pipeline, Viking Gas Transmission Company, OkTex Pipeline and a 50 percent equity interest in Northern Border Pipeline.

Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas and transport natural gas throughout the state. We also have access to the major natural gas producing area in south central Kansas. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas panhandle and the Permian Basin, and transport natural gas to the Waha Hub, where other pipelines may be accessed for transportation east to the Houston Ship Channel market, north into the Mid-Continent market and west to the California market.

We own or lease storage capacity in underground natural gas storage facilities in Oklahoma, Kansas and Texas.

Our transportation contracts for our regulated natural gas activities are based upon rates stated in our tariffs. Tariffs specify the maximum rates customers can be charged, which can be discounted to meet competition if necessary, and the general terms and conditions for pipeline transportation service, which are established at FERC or appropriate state jurisdictional agency proceedings known as rate cases. In Texas and Kansas, natural gas storage service is a fee business that may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas gathering and natural gas storage operations are not subject to rate regulation and have market-based rate authority from the FERC for certain types of services.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
Financial Results	2008		2007		2008			2007
	(Thousands of dollars)
Transportation revenues	$	59,190	$	54,845	$	184,454		$	169,426
Storage revenues		17,054		13,579		49,324			40,984
Gas sales and other revenues		10,446		4,940		32,880			9,315
Cost of sales		20,928		13,117		70,485			40,045
Net margin		65,762		60,247		196,173			179,680
Operating costs		23,852		24,109		67,900			69,953
Depreciation and amortization		8,607		8,089		25,547			24,246
Gain (loss) on sale of assets		—		73		(18	)		79
Operating income	$	33,303	$	28,122	$	102,708		$	85,560

Equity earnings from investments	$	20,207	$	16,493	$	49,421		$	45,275
Allowance for equity funds used during construction	$	3,822	$	1,005	$	8,304		$	2,110

	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information (a)	2008		2007		2008			2007
Natural gas transported (MMcf/d)		3,500		3,378		3,637			3,524
Average natural gas price Mid-Continent region ($/MMBtu)	$	8.44	$	5.42	$	8.27		$	6.08
Capital expenditures (Thousands of dollars)	$	107,822	$	44,561	$	159,810		$	90,635

(a) - Includes volumes for consolidated entities only.

Operating Results - Net margin increased $5.5 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to:

•

an increase of $3.4 million due to higher natural gas transportation margins, primarily as a result of the impact of higher natural gas prices on retained fuel, and

•

an increase of $1.1 million due to increased operational natural gas inventory sales.

Net margin increased $16.5 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to:

•

an increase of $8.5 million due to higher natural gas transportation margins, primarily as a result of the impact of higher natural gas prices on retained fuel,

•

an increase of $4.7 million due to higher natural gas storage margins, primarily related to new and renegotiated natural gas storage contracts and the higher natural gas price impact on retained fuel, and

•

an increase of $3.0 million due to increased operational natural gas inventory sales.

Operating costs decreased $2.1 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to decreased general taxes and lower general operating costs.

Depreciation and amortization increased for the three- and nine-month periods, primarily as a result of depreciation expense associated with our completed capital projects.

Equity earnings from investments increased $3.7 million and $4.1 million for the three- and nine-month periods in 2008, respectively, primarily due to an $8.3 million gain on the sale of Bison Pipeline LLC by Northern Border Pipeline, partially offset by reduced throughput on Northern Border Pipeline. We own a 50 percent equity interest in Northern Border Pipeline.

The increase in allowance for equity funds used during construction and capital expenditures for the three and nine months ended September 30, 2008, compared with the same periods last year, is driven primarily by increased spending for our capital projects, which are discussed beginning on page 21.

Natural Gas Liquids Gathering and Fractionation

Overview - Our Natural Gas Liquids Gathering and Fractionation segment primarily gathers, treats and fractionates NGLs produced by natural gas processing plants located in Oklahoma, Kansas, the Texas panhandle and the Texas Gulf Coast, and stores and markets NGL products. We purchase NGLs and condensate from third parties as well as our Natural Gas Gathering and Processing segment. We connect the NGL production basins in Oklahoma, Kansas and the Texas panhandle with the key natural gas liquids market centers in Conway, Kansas, and Mont Belvieu, Texas.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline. Natural gas processing plants remove the NGLs from the natural gas stream to realize the higher economic value of the NGLs and to meet natural gas pipeline quality specifications, which limit NGLs in the natural gas stream due to liquid and Btu content. The NGLs that are separated from the natural gas stream at the natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to our fractionators. A fractionator, by applying heat and pressure, separates the unfractionated NGL stream into marketable purity products, such as ethane/propane mix, propane, iso-butane, normal butane and natural gasoline (collectively, NGL products). These NGL products are then stored and/or distributed to our customers, such as petrochemical plants, heating fuel users and refineries.

Revenues for this segment are primarily derived from exchange services, optimization, isomerization and storage.

•

Our exchange services business collects fees to gather, fractionate and treat unfractionated NGLs, thereby converting them into NGL products that are stored and shipped to a market center or customer-designated location.

•

Our optimization business utilizes our assets, contract portfolio and market knowledge to capture locational and seasonal price differentials. We move NGL products between Conway, Kansas, and Mont Belvieu, Texas, in order to capture the locational price differentials between the two market centers. Our NGL storage facilities are also utilized to capture seasonal price variances.

•

Our isomerization business captures the price differential when normal butane is converted into the more valuable iso-butane at an isomerization unit in Conway, Kansas. Iso-butane is used in the refining industry to upgrade the octane of motor gasoline.

•

Our storage business collects fees to store NGLs at our Mid-Continent and Mont Belvieu, Texas, facilities.

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids Gathering and Fractionation segment for the periods indicated.


	Three Months Ended September 30,				Nine Months Ended September 30,
Financial Results	2008		2007		2008		2007
	(Thousands of dollars)
NGL and condensate sales	$	1,759,141	$	1,054,759	$	5,037,563	$	2,851,363
Storage and fractionation revenues		84,181		65,338		251,383		197,301
Cost of sales and fuel		1,724,692		1,071,270		5,033,452		2,893,369
Net margin		118,630		48,827		255,494		155,295
Operating costs		22,954		17,787		61,575		49,387
Depreciation and amortization		5,901		6,439		17,188		17,525
Gain (loss) on sale of assets		13		27		31		31
Operating income	$	89,788	$	24,628	$	176,762	$	88,414


	Three Months Ended September 30,				Nine Months Ended September 30,
Operating Information	2008		2007		2008		2007
NGLs gathered (MBbl/d)		243		232		249		222
NGL sales (MBbl/d)		273		223		275		221
NGLs fractionated (MBbl/d)		375		370		379		346
Conway-to-Mont Belvieu OPIS average price differential Ethane ($/gallon)	$	0.24	$	0.05	$	0.15	$	0.05
Capital expenditures (Thousands of dollars)	$	52,558	$	20,645	$	137,177	$	43,234

Operating Results - Net margin increased $69.8 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to the following:

•

an increase of $43.7 million due to significantly wider product price differentials between Conway, Kansas, and Mont Belvieu, Texas,

•

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

•

an increase of $12.5 million due to higher exchange margins, primarily driven by increased gathering and fractionation volumes, and

•

an increase of $3.3 million due to higher isomerization volumes and wider iso-butane-to-normal butane price differentials.

Net margin increased $100.2 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to the following:

•

an increase of $59.3 million due to wider product price differentials between Conway, Kansas, and Mont Belvieu, Texas,

•

an increase of $31.8 million due to higher exchange margins, primarily driven by increased gathering and fractionation volumes,

•

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

•

an increase of $2.5 million due to higher storage margins in our Mid-Continent storage business.

During September 2008, Hurricane Ike caused disruptions to our gathering and fractionation operations in the Mid-Continent and Gulf Coast regions. Without this disruption, we estimate net margin would have been approximately $3.8 million higher.

Operating costs increased $5.2 million and $12.2 million, respectively, for the three- and nine-month periods, primarily due to increased lease costs for the Bushton facility, increased costs associated with the startup of our newly expanded Bushton fractionator, increased employee-related costs and increased operating expenses at our fractionators due to increased utilization.

As noted in the “Operating Information” table above, product price differentials were significantly higher in 2008 than 2007. We began experiencing lower price differentials beginning in October 2008. However, the price differentials we are currently experiencing have remained above the three-year average Conway-to-Mont Belvieu price differential for ethane of $0.05 per gallon.

The increase in capital expenditures for the three and nine months ended September 30, 2008, compared with the same periods last year, is driven primarily by our capital projects, which are discussed beginning on page 21.

Natural Gas Liquids Pipelines

Overview - Our Natural Gas Liquids Pipelines segment primarily operates FERC-regulated natural gas liquids gathering and distribution pipelines and associated above- and below-ground storage facilities. Our natural gas liquids gathering pipelines deliver unfractionated NGLs gathered in Oklahoma, Kansas, the Texas panhandle and the Rocky Mountain region to our Natural Gas Liquids Gathering and Fractionation segment’s Mid-Continent fractionation facilities. Our natural gas liquids distribution pipelines deliver NGL products to the natural gas liquids market hubs in Conway, Kansas, and Mont Belvieu, Texas. Through our acquisition of the natural gas liquids assets from Kinder Morgan, we acquired terminal and storage facilities, as well as natural gas liquids and refined petroleum products pipelines that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. Our natural gas liquids gathering and distribution pipelines operate in Oklahoma, Kansas, Nebraska, Missouri, Iowa, Illinois, Indiana, Texas, Wyoming and Colorado. We have terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois.

Revenues for this segment are primarily derived from transporting product under our FERC-regulated tariffs. Tariffs specify the rates we can charge our customers and the general terms and conditions for NGL transportation service on our pipelines. Our tariffs include specifications regarding the receipt and delivery of NGLs at points along the pipeline systems. We generally charge tariff rates under a FERC-approved indexing methodology, which allows charging rates up to a prescribed ceiling that changes annually based on the year-to-year change in the Producer Price Index for finished goods. The FERC also permits interstate natural gas liquids pipelines to support rates by using a cost-of-service methodology, competitive market price or an agreement with a pipeline’s non-affiliated shipper.


	Three Months Ended September 30,					Nine Months Ended September 30,
Financial Results	2008		2007			2008		2007
	(Thousands of dollars)
Transportation and gathering revenues	$	33,282	$	19,671		$	101,284	$	56,181
Storage revenues		914		—			3,943		—
NGL sales and other revenues		350		1			2,778		13
Cost of sales and fuel		4,792		1,691			19,525		4,261
Net margin		29,754		17,981			88,480		51,933
Operating costs		14,986		5,648			42,171		16,551
Depreciation and amortization		3,361		2,987			11,200		8,990
Gain (loss) on sale of assets		7		1			8		2
Operating income	$	11,414	$	9,347		$	35,117	$	26,394

Equity earnings from investments	$	386	$	(511	)	$	1,395	$	182
Allowance for equity funds used during construction	$	11,794	$	2,686		$	27,484	$	4,576

	Three Months Ended September 30,					Nine Months Ended September 30,
Operating Information	2008		2007			2008		2007
NGLs transported (MBbl/d)		331		225			314		219
NGLs gathered (MBbl/d)		88		84			92		78
Capital expenditures (Thousands of dollars)	$	139,431	$	104,428		$	464,511	$	202,222

Operating Results - Net margin increased $11.8 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to an increase of $12.0 million in incremental margin from the assets acquired from Kinder Morgan in October 2007.

Net margin increased $36.5 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to the following:

•

an increase of $34.0 million in incremental margin from the assets acquired from Kinder Morgan in October 2007 and

•

an increase of $2.5 million due to increased throughput from new supply connections and increased production volumes from existing supply connections to our natural gas liquids gathering pipelines.

During September 2008, the disruption in the Gulf Coast area related to Hurricane Ike reduced transportation and gathering volumes on our pipeline assets between the Mid-Continent fractionation facilities and the natural gas liquids market hubs of Conway, Kansas, and Mont Belvieu, Texas. Without this volume reduction, we estimate net margin would have been approximately $2.2 million higher.

Operating costs increased $9.3 million for the three months ended September 30, 2008, compared with the same period last year, primarily due to $7.3 million in incremental operating expenses associated with the assets acquired from Kinder Morgan, as well as higher employee-related costs and costs associated with the startup of Overland Pass Pipeline operations.

Operating costs increased $25.6 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to $20.6 million in incremental operating expenses associated with the assets acquired from Kinder Morgan, as well as higher employee-related costs, outside services, and costs associated with the startup of Overland Pass Pipeline operations.

Depreciation and amortization increased $2.2 million for the nine months ended September 30, 2008, primarily due to the assets acquired from Kinder Morgan.

Equity earnings from investments increased $1.2 million for the nine months ended September 30, 2008, compared with the same period last year, primarily due to equity earnings from our investment in Heartland, which we acquired from Kinder Morgan in October 2007.

The increase in allowance for equity funds used during construction and capital expenditures for the three and nine months ended September 30, 2008, compared with the same periods last year, is driven primarily by our growth activities. See discussion of our capital projects beginning on page 21.

Other

In the second quarter of 2008, we started the decommissioning of the Black Mesa Pipeline, Inc. The affected land owners have been informed of this decision. We do not expect the decommissioning to have a material impact on our consolidated financial statements.

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.

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.

LIQUIDITY AND CAPITAL RESOURCES

General - Our principal sources of liquidity include cash generated from operating activities, bank credit facilities, debt issuances and the sale of common units. We fund our operating expenses, debt service and cash distributions to our limited partners and general partner primarily with operating cash flow. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

Part of our growth strategy is to expand our existing businesses and strategically acquire related businesses that strengthen and complement our existing assets. Capital resources for acquisitions and maintenance and growth expenditures may be funded by a variety of sources, including those listed above as our principal sources of liquidity. Beginning in 2007 and continuing in 2008, the capital markets have been impacted by macroeconomic, liquidity, credit and other recessionary concerns. During this period, we have continued to have access to our Partnership Credit Agreement to fund our short-term liquidity needs. In 2008, we issued common units and received additional contributions from our general partner. See discussion below under “Equity Issuance.” We also issued $600 million of long-term debt in September 2007. Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions. We anticipate that our existing capital resources, ability to obtain financing and cash flow generated from future operations will enable us to maintain our current level of operations and our planned operations, including capital expenditures, for the remainder of 2008 and into 2009.

During the nine months ended September 30, 2008 and 2007, our capital expenditures were financed through operating cash flows and short- and long-term debt. For the nine months ended September 30, 2008, our capital expenditures were also financed through the issuance of common units. 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 our capital projects, which are discussed beginning on page 21.

Financing - Financing is provided through available cash, our Partnership Credit Agreement, the issuance of common units or long-term debt. Other options to obtain financing include, but are not limited to, issuance of convertible debt securities, asset securitization and sale/leaseback of facilities.

The total amount of short-term borrowings authorized by our general partner’s Board of Directors is $1.5 billion. At September 30, 2008, we had $280 million of borrowings outstanding and $720 million available under our Partnership Credit Agreement and available cash and cash equivalents of approximately $15.8 million. As of September 30, 2008, we could have issued $1.4 billion of additional short- and long-term debt under the most restrictive provisions contained in our Partnership Credit Agreement.

During the third and fourth quarters of 2008, the capital markets have been significantly impacted by a financial credit crisis. Because of these market conditions and to ensure we would have access to the capital required to fund our growth projects and working capital needs, we borrowed $590 million under our Partnership Credit Agreement in October 2008. With this borrowing, we had $870 million outstanding and $130 million available under our Partnership Credit Agreement at October 31, 2008. On that date, we also had approximately $396 million in available cash and cash equivalents. We will utilize these funds and remaining borrowing capacity, as well as operating cash flow, to fund our growth projects and working capital requirements for the remainder of 2008 and into 2009. The average interest rate on our short-term debt outstanding at October 31, 2008, was 4.22 percent, compared with a weighted average of 3.24 percent for the first nine months of 2008. Based on the forward LIBOR curve, we expect the interest rate on our short-term borrowings to increase in 2009, compared with 2008.

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

We used a portion of the proceeds from the sale of common units and the general partner contributions to repay borrowings under our Partnership Credit Agreement.

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


	September 30, 2008		December 31, 2007
Long-term Debt	48	%	54	%
Equity	52	%	46	%
Debt (including notes payable)	50	%	55	%
Equity	50	%	45	%

Credit Ratings - Our investment grade credit ratings as of September 30, 2008, are shown in the table below.


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

Our credit ratings may be affected by a material change in our financial ratios or a material event affecting our business. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA (earnings before interest, taxes, depreciation and amortization) ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, the interest rates on our Partnership Credit Agreement borrowings would increase, resulting in an increase in our cost to borrow funds. An adverse rating change alone is not a default under our Partnership Credit Agreement.

Our $250 million and $225 million senior notes, due 2010 and 2011, respectively, contain provisions that require us to offer to repurchase the senior notes at par value if our Moody’s or S&P credit rating falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the investment grade rating is not reinstated within a period of 40 days. Further, the indentures governing our 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 our 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. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow money under our credit facilities or seek alternative financing sources to finance the repurchases and repayment. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations. A decline in our credit rating below investment grade may also require us to provide security to our counterparties in the form of cash, letters of credit or other negotiable instruments.

Other than the note repurchase obligations described above, we have determined that we do not have significant exposure to rating triggers in various other contracts and equipment leases. 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, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit rating or a significant change in our counterparties’ evaluation of our credit worthiness, we could be asked to provide additional collateral.

Capital Expenditures - We classify expenditures that are expected to generate additional revenues or significant operating efficiencies as growth capital expenditures. Any remaining capital expenditures are classified as maintenance capital expenditures.

The following table summarizes our 2008 projected growth and maintenance capital expenditures, excluding AFUDC.


2008 Projected Capital Expenditures	Growth		Maintenance		Total
	(Millions of dollars)
Natural Gas Gathering and Processing	$	128	$	22	$	150
Natural Gas Pipelines		224		21		245
Natural Gas Liquids Gathering and Fractionation		143		29		172
Natural Gas Liquids Pipelines		735		12		747
Total projected capital expenditures	$	1,230	$	84	$	1,314

Additional information about our growth capital expenditures is included under “Capital Projects” beginning on page 21. Financing for our capital expenditures may include any, or a combination, of the following: cash from operations, borrowings under our Partnership Credit Agreement, and debt or equity offerings.

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 our share will be approximately $43 million for our 50 percent equity interest.

Cash Distributions - We distribute 100 percent of our available cash, which generally consists of all cash receipts less adjustments for cash disbursements and net change to reserves, to our general and limited partners. Our income is allocated to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. The effect of any incremental income allocations for incentive distributions to our 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 sets forth the distribution payments, including our general partner’s incentive distribution interests, for the periods indicated.


	Nine Months Ended September 30,
	2008		2007
	(Thousands of dollars)
Common unitholders	$	161,852	$	137,801
Class B unitholder		114,045		108,387
General Partner		56,193		39,810

The following summarizes our quarterly cash distribution activity for 2008.

•

In January 2008, we increased our cash distribution to $1.025 per unit for the fourth quarter of 2007. The distribution was paid on February 14, 2008, to unitholders of record on January 31, 2008.

•

In April 2008, we increased our cash distribution to $1.04 per unit for the first quarter of 2008. The distribution was paid on May 15, 2008, to unitholders of record as of April 30, 2008.

•

In July 2008, we increased our cash distribution to $1.06 per unit for the second quarter of 2008. The distribution was paid on August 14, 2008, to unitholders of record as of July 31, 2008.

•

In October 2008, we increased our cash distribution to $1.08 per unit ($4.32 per unit on an annualized basis) for the third quarter of 2008. The distribution will be paid on November 14, 2008, to unitholders of record as of October 31, 2008.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices may impact our overall liquidity due to the impact commodity price changes have on our cash flows from operating activities, including the impact on working capital for NGLs held in storage, margin requirements and certain energy-related receivables. We believe that our available credit and cash and cash equivalents are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 38 under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk, for information on our hedging activities.

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.

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 our Partnership participate in the Processing and Transmission sectors 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 subsidiaries, and undistributed earnings from equity investments in excess of distributions received.

Operating cash flows increased by $42.2 million for the nine months ended September 30, 2008, compared with the same period in 2007. The increase in our operating cash flow is primarily attributable to higher net income, adjusted for the non-cash items as discussed above. This increase was offset by a reduction in cash from changes in working capital. For more information on our results of operations, see “Financial Results and Operating Information” within Item 2.

Investing Cash Flows - Cash used in investing activities was $854.5 million for the nine months ended September 30, 2008, compared with $409.9 million for the same period in 2007. The increased use of cash was primarily due to increased capital expenditures related to our capital projects.

Financing Cash Flows - Cash provided by financing activities was $298.4 million for the nine months ended September 30, 2008, compared with $656.8 million for the same period in 2007.

During 2008, our concurrent public offering and private placement of common units generated proceeds of $450.2 million. In addition, ONEOK Partners GP contributed $9.5 million in order to maintain its 2 percent general partner interest in us. We used a portion of the proceeds and general partner contributions to repay borrowings under our revolving credit agreement.

Net borrowings totaled $180.0 million for the nine months ended September 30, 2008, compared with $359.0 million for the same period in 2007. Borrowings for both periods were primarily used to fund our ongoing capital projects. Net borrowings in 2008 include repayments, which were made with a portion of the proceeds provided by the public offering and private placement discussed above.

Cash distributions to our general and limited partners for 2008 were $332.1 million, compared with $286.0 million in the same period in 2007, an increase of $46.1 million. This increase was primarily due to the additional units outstanding during 2008, as a result of the concurrent public offering and private placement in March and April 2008, as well as cash distributions of $3.125 per unit for the nine months ended September 30, 2008, compared with $2.97 per unit paid in the same period in 2007.

During the third quarter of 2007, we completed an underwritten public offering of senior notes totaling $598 million in net proceeds, before offering expenses. This debt issuance, net of discounts, was used to repay borrowings under our revolving 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, 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, 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;

•

actions by rating agencies concerning the credit ratings of us or our general partner;

•

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 control 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 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.

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. At September 30, 2008, the interest rate on all of our long-term debt was fixed.

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 interest expense savings from terminated swaps.

Total interest expense savings from amortization of terminated swaps for 2008 will be $3.7 million, compared with total net swap savings of $2.5 million in 2007.

COMMODITY PRICE RISK

In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk, primarily NGLs, as a result of receiving commodities in exchange for our services. To a lesser extent, exposures arise from the relative price differential between NGLs and natural gas, or the gross processing spread, with respect to our keep-whole processing contracts. We are also exposed to the risk of price fluctuations and the cost of intervening transportation at various market locations. We use commodity fixed-price physical forwards and derivative contracts, including NYMEX-based futures and over-the-counter swaps, to minimize earnings volatility related to natural gas, NGL and condensate price fluctuations.

We reduce our gross processing spread exposure through a combination of physical and financial hedges. We utilize a portion of our percent-of-proceeds equity natural gas as an offset, or natural hedge, to an equivalent portion of our

keep-whole shrink requirements. This has the effect of converting our gross processing spread risk to NGL commodity price risk, and we then use financial instruments to hedge the sale of NGLs.

The following tables set forth our Natural Gas Gathering and Processing segment’s 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.

Our 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. Our condensate sales are based on the price of crude oil. We estimate 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 our 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.

In our Natural Gas Liquids Gathering and Fractionation segment, we are 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. We have not entered into any hedges with respect to our NGL marketing activities.

In our Natural Gas Pipelines segment, we are exposed to commodity price risk because our intrastate and interstate natural gas pipelines collect natural gas from our customers for operations or as part of our fee for services provided. When the amount of natural gas consumed in operations by these pipelines differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas from inventory, which exposes us to commodity price risk. At September 30, 2008, there were no hedges in place with respect to natural gas price risk from our intrastate and interstate pipeline operations.

See Note D of the Notes to Consolidated Financial Statements in this Quarterly Report on Form 10-Q for more information on our hedging activities.

COUNTERPARTY CREDIT RISK

We assess the credit worthiness of our 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, the Chief Executive Officer (Principal Executive Officer) and the Chief Financial Officer (Principal Financial Officer) of ONEOK Partners GP, our general partner, 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 of ONEOK Partners GP, including the officers of ONEOK Partners GP who are the equivalent of 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 Control Over Financial Reporting - We have made no changes in our internal control 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.

Mont Belvieu Emissions, Texas Commission on Environmental Quality - We are in discussions with Texas Commission on Environmental Quality (TCEQ) staff regarding air emissions from a heat exchanger at our Mont Belvieu fractionator, which may have exceeded the emissions allowed under our air permit. We 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, we do not believe that any penalties associated with any alleged violations will have a material adverse effect on our 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 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

Not Applicable.

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
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 hereunto duly authorized.


	ONEOK PARTNERS, L.P.
	By:	ONEOK Partners GP, L.L.C., its General Partner
Date: November 6, 2008
		By:	/s/ Curtis L. Dinan
			Curtis L. Dinan
			Executive Vice President,
			Chief Financial Officer and Treasurer
			(Signing on behalf of the Registrant
			and as Principal Financial Officer)