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 March 31, 2008

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

For the transition period from to .

Commission file number 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 April 30, 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 Months Ended March 31, 2008 and 2007	5

	Consolidated Balance Sheets - March 31, 2008 and December 31, 2007	6

	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2008 and 2007	7

	Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income - Three Months Ended March 31, 2008	8-9

	Notes to Consolidated Financial Statements	10-18

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19-34

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	34-35

Item 4.	Controls and Procedures	35

Part II.	Other Information

Item 1.	Legal Proceedings	36

Item 1A.	Risk Factors	36

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	36

Item 3.	Defaults Upon Senior Securities	36

Item 4.	Submission of Matters to a Vote of Security Holders	36

Item 5.	Other Information	36

Item 6.	Exhibits	36

Signature		37

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” 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 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
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
MBbl		Thousand barrels
MBbl/d		Thousand barrels per day
Mcf		Thousand cubic feet
Midwestern Gas Transmission		Midwestern Gas Transmission Company
MMBtu		Million British thermal units
MMBtu/d		Million British thermal units per day
MMcf		Million cubic feet
MMcf/d		Million cubic feet per day
Moody’s		Moody’s Investors Service, Inc.
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
Overland Pass Pipeline Company		Overland Pass Pipeline Company LLC
Partnership Agreement		Third Amended and Restated Agreement of Limited Partnership of ONEOK Partners, L.P.
S&P		Standard & Poor’s Rating Group
SEC		Securities and Exchange Commission
Statement		Statement of Financial Accounting Standards

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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 March 31,
(Unaudited)	2008			2007
(Thousands of dollars, except per unit amounts)
Revenues
Operating revenue	$	2,059,035		$	1,168,674
Cost of sales and fuel		1,790,510			963,304
Net Margin		268,525			205,370
Operating Expenses
Operations and maintenance		76,941			66,676
Depreciation and amortization		29,942			27,513
General taxes		11,141			9,008
Total Operating Expenses		118,024			103,197
Gain on Sale of Assets		31			2,203
Operating Income		150,532			104,376
Equity earnings from investments (Note I)		27,783			24,055
Allowance for equity funds used during construction		8,496			1,337
Other income		2,058			1,463
Other expense		(2,131	)		(213	)
Interest expense		(38,529	)		(32,300	)
Income before Minority Interests and Income Taxes		148,209			98,718
Minority interests in income of consolidated subsidiaries		(123	)		(85	)
Income taxes		(3,068	)		(2,877	)
Net Income	$	145,018		$	95,756

Limited partners’ interest in net income:
Net income	$	145,018		$	95,756
General partners’ interest in net income		(19,705	)		(13,278	)
Limited Partners’ Interest in Net Income	$	125,313		$	82,478

Limited partners’ per unit net income:
Net income per unit (Note J)	$	1.48		$	1.00

Number of Units Used in Computation (Thousands)		84,454			82,891

See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


(Unaudited)	March 31, 2008			December 31, 2007
Assets	(Thousands of dollars)
Current Assets
Cash and cash equivalents	$	232,805		$	3,213
Accounts receivable, net		491,467			577,989
Affiliate receivables		63,756			52,479
Gas and natural gas liquids in storage		183,682			251,219
Commodity exchanges and imbalances		72,456			82,037
Other current assets		20,096			19,961
Total Current Assets		1,064,262			986,898

Property, Plant and Equipment
Property, plant and equipment		4,768,804			4,436,371
Accumulated depreciation and amortization		803,691			776,185
Net Property, Plant and Equipment (Note A)		3,965,113			3,660,186

Investments and Other Assets
Investment in unconsolidated affiliates (Note I)		754,304			756,260
Goodwill and intangible assets		680,168			682,084
Other assets		32,108			26,637
Total Investments and Other Assets		1,466,580			1,464,981
Total Assets	$	6,495,955		$	6,112,065


Liabilities and Partners’ Equity

Current Liabilities
Current maturities of long-term debt	$	11,931		$	11,930
Notes payable		—			100,000
Accounts payable		736,596			742,903
Affiliate payables		30,153			18,298
Commodity exchanges and imbalances		215,476			252,095
Accrued interest		72,752			38,435
Other current liabilities		82,002			98,229
Total Current Liabilities		1,148,910			1,261,890

Long-term Debt, excluding current maturities		2,601,425			2,605,396

Deferred Credits and Other Liabilities		46,025			43,799

Commitments and Contingencies (Note G)

Minority Interests in Consolidated Subsidiaries		5,851			5,802

Partners’ Equity
General partner		71,304			58,415
Common units: 54,297,214 units and 46,397,214 units issued and outstanding at March 31, 2008, and December 31, 2007, respectively		1,281,044			814,266
Class B units: 36,494,126 units issued and outstanding at
March 31, 2008, and December 31, 2007		1,357,788			1,340,638
Accumulated other comprehensive income (loss)		(16,392	)		(18,141	)
Total Partners’ Equity		2,693,744			2,195,178
Total Liabilities and Partners’ Equity	$	6,495,955		$	6,112,065

See accompanying Notes to Consolidated Financial Statements.

ONEOK Partners, L.P. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
(Unaudited)	2008			2007
Operating Activities		(Thousands of dollars)
Net income	$	145,018		$	95,756
Depreciation and amortization		29,942			27,513
Allowance for equity funds used during construction		(8,496	)		(1,337	)
Gain on sale of assets		(31	)		(2,203	)
Minority interests in income of consolidated subsidiaries		123			85
Equity earnings from investments		(27,783	)		(24,055	)
Distributions received from unconsolidated affiliates		24,040			26,455
Changes in assets and liabilities (net of acquisition and disposition effects):
Accounts receivable		81,852			(13,697	)
Affiliate receivables		(11,277	)		25,745
Gas and natural gas liquids in storage		43,696			15,592
Accounts payable		(34,232	)		85,139
Affiliate payables		11,855			(18,369	)
Commodity exchanges and imbalances, net		(27,038	)		(7,104	)
Accrued interest		34,317			25,950
Other assets and liabilities		(19,913	)		7,151
Cash Provided by Operating Activities		242,073			242,621
Investing Activities
Changes in investments in unconsolidated affiliates		3,311			(141	)
Capital expenditures (less allowance for equity funds used during construction)		(267,058	)		(74,564	)
Proceeds from sale of assets		72			3,707
Other		2,450			—
Cash Used in Investing Activities		(261,225	)		(70,998	)
Financing Activities
Cash distributions to:
General and limited partners		(101,135	)		(93,675	)
Minority interests		(74	)		—
Borrowing (repayment) of notes payable, net		(100,000	)		(6,000	)
Issuance of common units, net of discounts		443,579			—
Contributions from general partner		9,355			—
Payment of long-term debt		(2,981	)		—
Other		—			(30	)
Cash Provided by (Used in) Financing Activities		248,744			(99,705	)
Change in Cash and Cash Equivalents		229,592			71,918
Cash and Cash Equivalents at Beginning of Period		3,213			21,102
Cash and Cash Equivalents at End of Period	$	232,805		$	93,020

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)
Partners’ equity at December 31, 2007	46,397,214	36,494,126	$	58,415		$	814,266
Net income	-	-		19,705			70,756
Other comprehensive income (loss)	-	-		-			-
Total comprehensive income
Issuance of common units (Note E)	7,900,000	-		-			443,579
Contribution from general partner (Note E)	-	-		9,355			-
Distributions paid	-	-		(16,171	)		(47,557	)
Partners’ equity at March 31, 2008	54,297,214	36,494,126	$	71,304		$	1,281,044

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)
Partners’ equity at December 31, 2007	$	1,340,638		$	(18,141	)	$	2,195,178
Net income		54,557			-			145,018
Other comprehensive income (loss)		-			1,749			1,749

Total comprehensive income								146,767

Issuance of common units (Note E)		-			-			443,579
Contribution from general partner (Note E)		-			-			9,355
Distributions paid		(37,407	)		-			(101,135	)
Partners’ equity at March 31, 2008	$	1,357,788		$	(16,392	)	$	2,693,744

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.

Significant Accounting Policies

Property - The following table sets forth our property, by segment, for the periods presented.


	March 31, 2008		December 31, 2007
	(Thousands of dollars)
Non-Regulated
Natural Gas Gathering and Processing	$	1,254,567	$	1,227,475
Natural Gas Pipelines		163,345		162,390
Natural Gas Liquids Gathering and Fractionation		727,908		672,047
Other		50,534		50,482
Regulated
Natural Gas Pipelines		1,207,210		1,184,112
Natural Gas Liquids Pipelines		1,365,240		1,139,865
Property, plant and equipment		4,768,804		4,436,371
Accumulated depreciation and amortization		803,691		776,185
Net property, plant and equipment	$	3,965,113	$	3,660,186

At March 31, 2008, property, plant and equipment on our Consolidated Balance Sheets included construction work in process of $1,061.5 million 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, 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 have 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 applicability 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.

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.

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. We are currently reviewing the applicability of Statement 141R to our operations and its potential impact on our consolidated financial statements.

Noncontrolling Interests - In December 2007, the FASB issued Statement 160, “Noncontrolling Interest in Consolidated Financial Statements - an amendment to 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. We are currently reviewing the applicability of Statement 160 to our operations and its potential impact on our consolidated financial statements.

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. We are currently reviewing the applicability of Statement 161 to our consolidated financial statement disclosures.

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 applicability 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

Acquisition of NGL Pipeline - 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 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 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 London Interbank Offered Rate (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, 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. As interpretations of Statement 157 evolve, our classification of certain instruments within the hierarchy may be revised.

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


	March 31, 2008
	Level 1			Level 2		Level 3			Total
	(Thousands of dollars)
Derivatives, Non-Trading
Assets	$	2		$	—	$	68		$	70
Liabilities		(3,463	)		—		(10,454	)		(13,917	)
Total net liabilities	$	(3,461	)	$	—	$	(10,386	)	$	(13,847	)

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. We utilize a 10 percent threshold to weigh the significance of an input to the total fair value measurement.

Our Level 1 fair value measurements are primarily based on NYMEX-settled prices for natural gas and crude oil. For our Level 3 inputs, we utilize modeling techniques using NYMEX-settled pricing data and historical correlations of NGL product prices to crude oil. All of our derivatives are part of a hedge relationship.

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


	Derivatives, Non-Trading
	(Thousands of dollars)
Net liabilities at January 1, 2008	$	(16,400	)
Total realized/unrealized gains (losses):
Included in earnings (a)		980
Included in other comprehensive income (loss)		5,034
Transfers in and/or out of Level 3		-
Net liabilities at March 31, 2008	$	(10,386	)

Total gains (losses) for the period included in earnings attributable to the change in unrealized gain (loss) relating to assets and liabilities still held as of March 31, 2008	$	-



(a)	-	Reported in operating revenue in our Consolidated Statement 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 and the gross processing spread. At March 31, 2008, the accompanying Consolidated Balance Sheet reflected an unrealized loss of $13.1 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 nine months. Net gains and losses related to the ineffective portion of our hedges are reclassified out of accumulated other comprehensive income (loss) to operating revenues in the period the ineffectiveness occurs. Ineffectiveness related to these cash flow hedges was not material for the three months ended March 31, 2008 and 2007. There were no material gains or losses during the three months ended March 31, 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 three months ended March 31, 2008, from amortization of terminated swaps was $0.9 million, and the remaining amortization of terminated swaps will be recognized over the following periods.



	(Millions of dollars)
Remainder of 2008	$	2.8
2009		3.7
2010		3.7
2011		0.9
2012		-
Thereafter		-

At March 31, 2008, none of the interest on our fixed-rate debt was swapped to floating using interest rate swaps.

E.	PARTNERS’ EQUITY

At March 31, 2008, we had 54,297,214 common units and 36,494,126 Class B units issued and outstanding. 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. The Class B units, common units and the general partner interest held by ONEOK and its affiliates together constituted a 47.8 percent interest in us at March 31, 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 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 contributed $0.2 million in order to maintain its 2 percent general partner interest in us. As a result, ONEOK now holds an aggregate 47.7 percent 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 (2007 Partnership Credit Agreement).

In April 2008, we declared a cash distribution of $1.04 per unit ($4.16 per unit on an annualized basis) for the first quarter of 2008. The distribution will be paid on May 15, 2008, to unitholders of record as of April 30, 2008.

F.	CREDIT FACILITIES

Our 2007 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 March 31, 2008, we were in compliance with all covenants.

At March 31, 2008, we had no borrowings outstanding and $1.0 billion of credit available under the 2007 Partnership Credit Agreement.

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.

G.	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 action 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.

H.	SEGMENTS

Segment Descriptions - In July 2007, we announced a series of organizational changes that led to the realignment of our previous business segments. Our financial results are now reported in these four segments: (i) Natural Gas Gathering and Processing, which remains unchanged; (ii) Natural Gas Pipelines, which is comprised of our former interstate natural gas pipelines segment and the natural gas assets of our former pipelines and storage segment; (iii) Natural Gas Liquids Gathering and Fractionation, which remains unchanged; and (iv) Natural Gas Liquids Pipelines, which is comprised of the natural gas liquids assets of our former pipelines and storage segment. Prior periods have been restated to reflect these segment changes.

Our operations are divided into these 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 raw 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 subsidiaries of ONEOK. 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. Our equity method investments do not represent operating segments.

Customers - We had no single external customer from which we received 10 percent or more of our consolidated operating 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 March 31, 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	$	96,581	$	61,864	$	1,700,070	$	17,183	$	2		$	1,875,700
Sales to affiliated customers		155,294		28,041		—		—		—			183,335
Intersegment sales		184,695		267		6,450		21,500		(212,912	)		—
Operating revenue	$	436,570	$	90,172	$	1,706,520	$	38,683	$	(212,910	)	$	2,059,035
Gain on sale of assets	$	1	$	17	$	12	$	1	$	—		$	31
Operating income	$	59,053	$	31,714	$	45,287	$	13,813	$	665		$	150,532
Equity earnings from investments	$	7,044	$	20,061	$	—	$	678	$	—		$	27,783
EBITDA	$	77,022	$	59,633	$	50,176	$	18,209	$	3,144		$	208,184
Investment in unconsolidated affiliates	$	300,788	$	422,169	$	—	$	31,347	$	—		$	754,304
Total assets	$	1,606,980	$	1,170,655	$	1,834,531	$	1,428,156	$	455,633		$	6,495,955
Capital expenditures	$	26,487	$	22,222	$	29,571	$	188,726	$	52		$	267,058



(a)	-	Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $77.1 million and operating income of $23.8 million for the three months ended March 31, 2008.
(b)	-	All of our Natural Gas Liquids Pipelines segment’s operations are regulated.


Three Months Ended March 31, 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	$	103,575	$	50,778	$	857,963	$	—	$	22		$	1,012,338
Sales to affiliated customers		130,428		25,908		—		—		—			156,336
Intersegment sales		88,878		327		2,969		17,659		(109,833	)		—
Operating revenue	$	322,881	$	77,013	$	860,932	$	17,659	$	(109,811	)	$	1,168,674
Gain on sale of assets	$	2,197	$	3	$	2	$	1	$	—		$	2,203
Operating income	$	30,452	$	32,361	$	31,999	$	8,635	$	929		$	104,376
Equity earnings from investments	$	5,608	$	18,168	$	—	$	279	$	—		$	24,055
EBITDA	$	47,425	$	58,796	$	37,222	$	12,094	$	1,657		$	157,194
Investment in unconsolidated affiliates	$	295,892	$	440,981	$	—	$	9,511	$	—		$	746,384
Total assets	$	1,677,969	$	1,261,713	$	1,579,493	$	556,417	$	(57,594	)	$	5,017,998
Capital expenditures	$	16,316	$	17,650	$	7,475	$	33,117	$	6		$	74,564


(a)	-	Our Natural Gas Pipelines segment has regulated and non-regulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $65.7 million and operating income of $25.4 million for the three months ended March 31, 2007.
(b)	-	All of our Natural Gas Liquids Pipelines segment’s operations are regulated.

We evaluate our performance based on EBITDA, which we define as earnings before interest, income taxes, depreciation and amortization less the cost of the equity component of AFUDC. Management uses EBITDA to compare the financial performance of its segments and to internally manage those business segments. Management believes that EBITDA provides useful information to investors as a measure of comparison with peer companies. EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. EBITDA calculations may vary from company to company, so our computation of EBITDA may not be comparable with a similarly titled measure of another company.

The following tables set forth the reconciliation of net income to EBITDA by operating segment for the periods indicated.

Three Months Ended

March 31, 2008

Natural Gas
Gathering and
Processing

Natural Gas
Pipelines

Natural Gas
Liquids
Gathering and
Fractionation

Natural Gas
Liquids
Pipelines

Other and
Eliminations

Total

(Thousands of dollars)

Net income

53,420

43,979

36,236

12,911

(1,528

)

145,018

Minority interests

—

123

Interest expense, net

11,836

7,183

8,321

7,546

3,643

38,529

Depreciation and amortization

11,757

8,418

5,619

4,142

29,942

Income taxes

2,036

—

1,023

3,068

Allowance for equity funds used during construction

—

(2,079

)

—

(6,417

)

—

(8,496

)

EBITDA

77,022

59,633

50,176

18,209

3,144

208,184


Three Months Ended March 31, 2007	Natural Gas Gathering and Processing			Natural Gas Pipelines			Natural Gas Liquids Gathering and Fractionation			Natural Gas Liquids Pipelines			Other and Eliminations			Total
	(Thousands of dollars)
Net income	$	38,461		$	45,570		$	33,154		$	10,993		$	(32,422	)	$	95,756
Minority interests		—			85			—			—			—			85
Interest expense, net		(2,158	)		3,395			(1,264	)		(1,007	)		33,334			32,300
Depreciation and amortization		11,122			8,020			5,332			3,012			27			27,513
Income taxes		—			2,159			—			—			718			2,877
Allowance for equity funds used during construction		—			(433	)		—			(904	)		—			(1,337	)
EBITDA	$	47,425		$	58,796		$	37,222		$	12,094		$	1,657		$	157,194

I.	UNCONSOLIDATED AFFILIATES

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


	Three Months Ended March 31,
	2008		2007
	(Thousands of dollars)
Northern Border Pipeline	$	19,782	$	18,040
Bighorn Gas Gathering, L.L.C.		2,318		1,691
Fort Union Gas Gathering		2,295		2,587
Lost Creek Gathering Company, L.L.C.		1,285		1,329
Other		2,103		408
Equity earnings from investments	$	27,783	$	24,055

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


	Three Months Ended March 31,
	2008		2007
	(Thousands of dollars)
Income Statement
Operating revenue	$	111,395	$	98,713
Operating expenses		43,344		38,357
Net income		55,821		49,157
Distributions paid to us	$	27,413	$	26,455

J.	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 $16.8 million for the three months ended March 31, 2008. The $16.2 million distribution paid to our general partner shown on our Consolidated Statement of Changes in Partners’ Equity and Comprehensive Income included $14.1 million in incentive distributions paid to our general partner during the first three 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 on sale of assets for the three months ended March 31, 2008 and 2007 had no impact on the incentive distribution rights.

K.	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 continues to operate 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 C 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 March 31,
	2008		2007
	(Thousands of dollars)
Revenues	$	183,335	$	156,336
Administrative and general expenses	$	46,901	$	44,130

In addition, we sold 5.4 million common units to ONEOK in March 2008 in a private placement, generating proceeds of approximately $303.2 million. ONEOK also made additional general partner contributions to us in March and April 2008. See Note E 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 “Financial and Operating Results” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements for additional information.

In July 2007, we announced a series of organizational changes that led to the realignment of our previous business segments. Our financial results are now reported in these four segments: (i) Natural Gas Gathering and Processing, which remains unchanged; (ii) Natural Gas Pipelines, which is comprised of our former interstate natural gas pipelines segment and the natural gas assets of our former pipelines and storage segment; (iii) Natural Gas Liquids Gathering and Fractionation, which remains unchanged; and (iv) Natural Gas Liquids Pipelines, which is comprised of the natural gas liquids assets of our former pipelines and storage segment. Prior periods have been restated to reflect these segment changes. The change reflects the increasing scale of our natural gas liquids business, which has grown significantly since 2005 and will expand further as we continue to integrate the assets from 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. (Kinder Morgan) into our Natural Gas Liquids Pipelines segment and complete our other internal growth projects.

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 (2007 Partnership Credit Agreement).

In April 2008, we declared an increase in our cash distribution to $1.04 per unit ($4.16 per unit on an annualized basis), an increase of approximately 5 percent over the $0.99 declared in April 2007.

Net income per unit increased to $1.48 for the three months ended March 31, 2008, compared with $1.00 in 2007. The increase in net income per unit for the three-month period is primarily due to higher realized commodity prices in our Natural Gas Gathering and Processing segment and wider regional product price spreads in our Natural Gas Liquids Gathering and Fractionation segment. In addition, our Natural Gas Liquids Pipeline segment benefited from the assets acquired from Kinder Morgan in October 2007.

In January 2008, Midwestern Gas Transmission, our subsidiary, placed its eastern extension pipeline into service.

SIGNIFICANT ACQUISITION

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 - In February 2008, we announced plans to construct a 78-mile natural gas liquids gathering pipeline to connect two natural gas processing plants, operated by Devon Energy Corporation and Antero Resources Corporation, respectively, in the Woodford Shale area in southeast Oklahoma at a cost of approximately $25 million, excluding AFUDC. The project is currently scheduled for completion in the second quarter of 2008. Upon completion, these two plants are expected to have the capacity to produce approximately 25 MBbl/d of unfractionated NGLs. The natural gas liquids production will be transported by our existing Mid-Continent natural gas liquids 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 more than 220 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 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. This project has received the required approvals of various state and federal regulatory authorities, and we are constructing the pipeline with start-up currently expected during the third 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 are nearing agreements with other producers for supply commitments which are expected to add an additional 50 MBbl/d to this pipeline. The pipeline project is currently estimated to cost approximately $535 million, excluding AFUDC. Since our initial estimate in early 2006, there has been a significant increase in the demand for pipeline construction-related services, which has led to higher rates, particularly for construction labor and equipment. Additionally, winter construction, due to the extended permitting process, has contributed to added construction costs and further delays and federal restrictions on construction in wildlife sensitive areas are expected to further impact our estimated costs and construction schedule. We are also investing approximately $216 million, excluding AFUDC, to expand our existing fractionation and storage capabilities and the capacity of our natural gas liquids distribution pipelines. 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 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. This project requires the approval of various state and federal regulatory authorities. Assuming Overland Pass Pipeline Company obtains the required state and federal regulatory approvals, construction of this lateral pipeline is currently expected to begin in late 2008 and be completed during the second quarter of 2009, at a current cost estimate of approximately $120 million, excluding AFUDC. 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, at a current estimated cost of approximately $260 million, excluding AFUDC. The Arbuckle Pipeline will have the capacity to transport 160 MBbl/d of unfractionated natural gas liquids and will connect our existing Mid-Continent infrastructure with

our fractionation facility in Mont Belvieu, Texas, and other Gulf Coast region fractionators. We have commitments from producers for 65 MBbl/d and continue to negotiate with other producers for additional supply commitments. Construction of the pipeline will require permits from various federal, state and local regulatory bodies. Construction is currently expected to begin in mid-2008 and be completed by early 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 at a cost of approximately $30 million, excluding AFUDC. 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 come on-line in phases, with the final phase currently expected to be on-line in the second half 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 that it will 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 is expected to cost approximately $110 million, excluding AFUDC, which will be financed within the Fort Union Gas Gathering partnership and will occur in two phases. Phase 1, with more than 200 MMcf/d capacity, was placed in service during the fourth quarter of 2007. Phase 2, with approximately 450 MMcf/d capacity, is currently expected to be in service during the second quarter of 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 cost of the project is currently estimated to be $277 million, excluding AFUDC. 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,”

•

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

•

Statement 141R, “Business Combinations,”

•

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

•

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

FINANCIAL AND OPERATING RESULTS

Consolidated Operations

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


	Three Months Ended March 31,
Financial Results	2008			2007
	(Thousands of dollars)
Operating revenue	$	2,059,035		$	1,168,674
Cost of sales and fuel		1,790,510			963,304
Net margin		268,525			205,370
Operating costs		88,082			75,684
Depreciation and amortization		29,942			27,513
Gain on sale of assets		31			2,203
Operating income	$	150,532		$	104,376

Equity earnings from investments	$	27,783		$	24,055
Allowance for equity funds used during construction	$	8,496		$	1,337
Interest expense	$	(38,529	)	$	(32,300	)
Minority interests in income of consolidated subsidiaries	$	(123	)	$	(85	)

Operating Results - Net margin increased for the three months ended March 31, 2008, compared with the same period last year, primarily due to higher realized commodity prices in our Natural Gas Gathering and Processing segment and wider regional product price spreads in our Natural Gas Liquids Gathering and Fractionation segment. In addition, net margin increased in our Natural Gas Liquids Pipelines segment primarily due to the assets acquired from Kinder Morgan in October 2007.

Operating costs increased for the three months ended March 31, 2008, compared with the same period last year, primarily due to incremental operating expenses associated with the assets acquired from Kinder Morgan, increased costs incurred to comply with regulations and higher employee-related costs.

Depreciation and amortization increased for the three months ended March 31, 2008, compared with the same period last year, primarily due to the assets acquired from Kinder Morgan.

Equity earnings from investments increased for the three months ended March 31, 2008, compared with the same period last year, primarily due to increased throughput on Northern Border Pipeline, of which we own a 50 percent interest.

Allowance for equity funds used during construction increased for the three months ended March 31, 2008, compared with the same period last year, due to our capital projects, which are discussed beginning on page 20.

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 operations include gathering of natural gas production from crude oil and natural gas wells. We gather raw 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 raw natural gas in three producing basins in the Rocky Mountain region: (i) the Williston Basin, which spans portions of Montana, North Dakota and the Canadian province of Saskatchewan, (ii) the Powder River Basin of Wyoming and (iii) the Wind River Basin of Wyoming.

Through gathering systems, raw 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 liquids are separated from the raw natural gas at the processing plants, the liquids are 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). These NGL products are marketed to a diverse customer base.

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


	Three Months Ended March 31,
Financial Results	2008			2007
	(Thousands of dollars)
Natural gas liquids and condensate sales	$	211,646		$	130,076
Gas sales		186,679			158,700
Gathering, compression, dehydration and processing fees and other revenue		38,245			34,105
Cost of sales and fuel		332,664			249,514
Net margin		103,906			73,367
Operating costs		33,097			33,990
Depreciation and amortization		11,757			11,122
Gain on sale of assets		1			2,197
Operating income	$	59,053		$	30,452

Equity earnings from investments	$	7,044		$	5,608

	Three Months Ended March 31,
Operating Information	2008			2007
Natural gas gathered (BBtu/d)		1,192			1,168
Natural gas processed (BBtu/d)		624			609
Natural gas liquids sales (MBbl/d)		38			37
Natural gas sales (BBtu/d)		277			268
Capital expenditures (Thousands of dollars)	$	26,487		$	16,316
Realized composite NGL sales price ($/gallon)	$	1.33		$	0.82
Realized condensate sales price ($/Bbl)	$	87.51		$	56.53
Realized natural gas sales price ($/MMBtu)	$	7.40		$	6.58
Realized gross processing spread ($/MMBtu)	$	7.43		$	3.59

	Three Months Ended March 31,
	2008			2007
Percent of proceeds
Wellhead purchases (MMBtu/d)		70,594			90,636
NGL sales (Bbl/d)		5,723			6,095
Residue sales (MMBtu/d)		36,607			30,294
Condensate sales (Bbl/d)		1,127			1,122
Percentage of total net margin		58	%		61	%
Fee-based
Wellhead volumes (MMBtu/d)		1,191,801			1,167,714
Average rate ($/MMBtu)	$	0.26		$	0.24
Percentage of total net margin		24	%		33	%
Keep-whole
NGL shrink (MMBtu/d)		23,515			22,018
Plant fuel (MMBtu/d)		2,488			2,689
Condensate shrink (MMBtu/d)		2,011			2,215
Condensate sales (Bbl/d)		407			448
Percentage of total net margin		18	%		6	%

Operating Results - Net margin increased $30.5 million for the three months ended March 31, 2008, compared with the same period last year, primarily due to the following:

•

an increase of $24.5 million in higher realized commodity prices,

•

an increase of $3.1 million due to higher volumes processed, and

•

an increase of $2.1 million due to improved contract terms.

The increase in equity earnings from investments for the three-month period is driven primarily by the earnings related to our investment in Venice Energy Services Co., LLC, which operated on a limited basis in the first quarter of 2007 due to Hurricane Katrina damage.

The increase in capital expenditures for the three months ended March 31, 2008, compared with the same period last year, is driven primarily by our capital projects, which are discussed beginning on page 20.

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 34 under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk.

Natural Gas Pipelines

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


	Three Months Ended March 31,
Financial Results	2008			2007
	(Thousands of dollars)
Transportation revenue	$	62,633		$	61,431
Storage revenue		14,358			12,493
Gas sales and other revenue		13,181			3,089
Cost of sales		26,477			15,521
Net margin		63,695			61,492
Operating costs		23,580			21,114
Depreciation and amortization		8,418			8,020
Gain on sale of assets		17			3
Operating income	$	31,714		$	32,361

Equity earnings from investments	$	20,061		$	18,168
Allowance for equity funds used during construction	$	2,079		$	433
Minority interest in income of consolidated subsidiaries	$	(96	)	$	(85	)

	Three Months Ended March 31,
Operating Information (a)	2008			2007
Natural gas transported (MMcf/d)		3,956			3,948
Average natural gas price Mid-Continent region ($/MMBtu )	$	7.18		$	6.29
Capital expenditures (Thousands of dollars)	$	22,222		$	17,650


(a) - Includes volumes for consolidated entities only.

Operating Results - Net margin increased $2.2 million for the three months ended March 31, 2008, compared with the same period last year, due to new and renegotiated natural gas storage contracts and increased operational natural gas inventory sales.

Operating costs increased $2.5 million for the three months ended March 31, 2008, compared with the same period last year, primarily due to increased general operating costs, including general taxes and employee-related costs.

Equity earnings from investments increased $1.9 million for the three months ended March 31, 2008, compared with the same period last year, primarily due to increased throughput on Northern Border Pipeline, of which we own a 50 percent interest.

The increase in allowance for equity funds used during construction and capital expenditures for the three months ended March 31, 2008, compared with the same period last year, is driven primarily by our capital projects, which are discussed beginning on page 20.

Other - In April 2008, Northern Border Pipeline announced that its wholly-owned subsidiary, Bison Pipeline LLC, is conducting a binding open season for potential shippers to request firm pipeline capacity on a proposed pipeline system. The Bison Pipeline would extend from natural gas gathering facilities at Deadhorse, Wyoming, a coalbed methane hub located in the Powder River Basin supply area, to a point of interconnection with Northern Border Pipeline in Morton County, North Dakota. The Bison Pipeline is anticipated to be approximately 289 miles with initial capacity of approximately 400 MMcf/d and a maximum capacity of approximately 660 MMcf/d. However, the ultimate capacity of the Bison Pipeline will be determined by the level of binding shipper commitments. The projected in-service date for the Bison Pipeline is currently November 2010. An affiliate of TransCanada Corporation will operate the Bison Pipeline. We own 50 percent of Northern Border Pipeline, and we account for this investment under the equity method of accounting.

Natural Gas Liquids Gathering and Fractionation

Overview - This 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 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 motor gasoline manufacturers.

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


	Three Months Ended March 31,
Financial Results	2008		2007
	(Thousands of dollars)
Natural gas liquids and condensate sales	$	1,626,103	$	800,165
Storage and fractionation revenue		80,417		60,767
Cost of sales and fuel		1,636,995		808,877
Net margin		69,525		52,055
Operating costs		18,631		14,726
Depreciation and amortization		5,619		5,332
Gain on sale of assets		12		2
Operating income	$	45,287	$	31,999


	Three Months Ended March 31,
Operating Information	2008		2007
Natural gas liquids gathered (MBbl/d)		251		210
Natural gas liquids sales (MBbl/d)		286		220
Natural gas liquids fractionated (MBbl/d)		391		319
Conway-to-Mont Belvieu OPIS average spread Ethane/Propane mixture ($/gallon)	$	0.09	$	0.06
Capital expenditures (Thousands of dollars)	$	29,571	$	7,475

Operating Results - Net margin increased $17.5 million for the three months ended March 31, 2008, compared with the same period last year, primarily due to the following:

•

an increase of $10.6 million due to wider regional product price spreads,

•

an increase of $5.6 million due to higher exchange net margin primarily driven by increased volumes due to new supply connections and increased fractionation volumes, and

•

an increase of $1.2 million due to higher storage margins in our Mid-Continent storage business.

Operating costs increased $3.9 million for the three months ended March 31, 2008, compared with the same period last year, primarily due to increased costs incurred to comply with regulations at our storage facilities, higher employee-related costs and increased lease costs.

The increase in capital expenditures for the three months ended March 31, 2008, compared with the same period last year, is driven primarily by our growth activities for new supply connections. See discussion of our capital projects beginning on page 20.

Natural Gas Liquids Pipelines

Overview - This segment 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 and the Texas panhandle to our Natural Gas Liquids Gathering and Fractionation segment’s Mid-Continent fractionation facilities in Medford, Oklahoma. 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 and Texas. We have terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois.

Operating revenue for this segment is 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.

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


	Three Months Ended March 31,
Financial Results	2008			2007
	(Thousands of dollars)
Transportation and gathering revenue	$	34,066		$	17,647
Storage revenue		2,592			—
Gas sales and other revenue		2,025			12
Cost of sales and fuel		7,326			651
Net margin		31,357			17,008
Operating costs		13,403			5,362
Depreciation and amortization		4,142			3,012
Gain on sale of assets		1			1
Operating income	$	13,813		$	8,635

Equity earnings from investments	$	678		$	279
Allowance for equity funds used during construction	$	6,417		$	904
Minority interest in income of consolidated subsidiaries	$	(27	)	$	—

	Three Months Ended March 31,
Operating Information	2008			2007
Natural gas liquids transported (MBbl/d)		303			205
Natural gas liquids gathered (MBbl/d)		92			71
Capital expenditures (Thousands of dollars)	$	188,726		$	33,117

Operating Results - Net margin increased $14.3 million for the three months ended March 31, 2008, compared with the same period last year, primarily as a result of the following:

•

an increase of $12.6 million due to incremental margin from the assets acquired from Kinder Morgan in October 2007 and

•

an increase of $1.7 million due to increased throughput from new supply connections and increased production volumes from existing supply connections to our natural gas liquids gathering pipelines.

Operating costs increased $8.0 million for the three months ended March 31, 2008, compared with the same period last year, primarily due to $6.8 million in incremental operating expenses associated with the assets acquired from Kinder Morgan as well as higher employee-related costs.

Depreciation and amortization increased $1.1 million for the three months ended March 31, 2008, primarily due to the assets acquired from Kinder Morgan.

The increase in allowance for equity funds used during construction and capital expenditures for the three months ended March 31, 2008, compared with the same period last year, is driven primarily by our growth activities. See discussion of our capital projects beginning on page 20.

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.

Other - 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 action 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.

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 2007 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 foreseeable future. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

During the three months ended March 31, 2008 and 2007, our capital expenditures were financed through operating cash flows and short- and long-term debt. For the three months ended March 31, 2008, our capital expenditures were also financed through the issuance of common units. Capital expenditures for the first three months of 2008 were $267.1 million, compared with $74.6 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 20.

Financing - Financing is provided through available cash, our 2007 Partnership Credit Agreement, the issuance of common units and long-term debt. Other options to obtain financing include, but are not limited to issuance of hybrid securities such as any trust preferred security or deferrable interest subordinated debt issued by us or any business trusts 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 March 31, 2008, we had no borrowings outstanding and $1.0 billion available under our 2007 Partnership Credit Agreement and available cash and cash equivalents of approximately $232.8 million. As of March 31, 2008, we could have issued $1.4 billion of additional debt under the most restrictive provisions contained in our various borrowing agreements.

million letter of credit was issued. Both agreements are used to support various permits required by the KDHE for our ongoing business in Kansas.

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 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 2007 Partnership Credit Agreement.

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


	March 31, 2008		December 31, 2007
Long-term Debt	49	%	54	%
Equity	51	%	46	%
Debt (including notes payable)	49	%	55	%
Equity	51	%	45	%

Credit Ratings - Our investment grade credit ratings as of March 31, 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 ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, the interest rates on our 2007 Partnership Credit Agreement borrowings would increase, resulting in an increase in our cost to borrow funds. An adverse rating change is not a default under our 2007 Partnership Credit Agreement.

Our $250 million and $225 million long-term 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.

Capital Expenditures - We classify expenditures that are expected to generate additional revenue 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	$	80	$	26	$	106
Natural Gas Pipelines		217		24		241
Natural Gas Liquids Gathering and Fractionation		126		29		155
Natural Gas Liquids Pipelines		574		12		586
Total projected capital expenditures	$	997	$	91	$	1,088

Additional information about these projects is included under “Capital Projects” beginning on page 20. Financing for these projects may include any, or a combination of, the following: cash from operations, borrowings under our 2007 Partnership Credit Agreement, and debt or equity offerings.

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 and incentive distribution interests for the periods indicated.


	Three Months Ended March 31,
	2008		2007
	(Thousands of dollars)
Common unitholders	$	47,557	$	45,470
Class B unitholder		37,407		35,764
General Partner		16,171		12,441

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 ($4.16 per unit on an annualized basis) for the first quarter of 2008. The distribution will be paid on May 15, 2008, to unitholders of record as of April 30, 2008.

Commodity Prices - We are subject to commodity price volatility. Significant fluctuations in commodity prices in our contracts may impact our overall liquidity due to the impact the commodity price change has on items such as the cost of NGLs and gas held in storage, increased margin requirements, the cost of transportation to various market locations, collectibility of certain energy-related receivables and working capital. We believe that our current lines of credit are adequate to meet liquidity requirements associated with commodity price volatility. See discussion beginning on page 34 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 and wildlife preservation laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid wastes and hazardous materials, and substance management. These laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to 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 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 three months ended March 31, 2008 or 2007, related to compliance with environmental regulations.

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

Air and Water Emissions - The federal Clean Air Act and 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 federal 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 in United States water. To our knowledge, we are substantially 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 receiving these reports, Homeland Security will identify which sites are required to implement security measures. Homeland Security is in the initial stages of implementing this rule, and the 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) 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 gathering and processing sector and the transmission sector of the United States Environmental Protection Agency’s Natural Gas STAR Program to voluntarily reduce methane emissions. In addition, we continue to focus on reducing methane loss through expanded implementation of best practices across our operations and analyzing options for additional emission reductions, including (i) closing older facilities and routing products to more efficient facilities, (ii) self-imposing permit limits at facilities where operationally feasible, (iii) utilizing electric motors on select compressor applications, and (iv) utilizing methods to limit the release of methane gas during pipeline maintenance and operations.

CASH FLOW ANALYSIS

Operating Cash Flows - Operating cash flows for the three months ended March 31, 2008, were comparable with the same period in 2007. Our net income increased to $145.0 million for the three months ended March 31, 2008, compared with $95.8 million for the three months ended March 31, 2007. This increase was primarily the result of higher realized commodity prices in our Natural Gas Gathering and Processing segment and wider regional product price spreads in our Natural Gas Liquids Gathering and Fractionation segment. In addition, our Natural Gas Liquids Pipeline segment benefited from the assets acquired from Kinder Morgan in October 2007. These increases were offset by a reduction from changes in working capital.

Investing Cash Flows - Cash used in investing activities was $261.2 million for the three months ended March 31, 2008, compared with $71.0 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 $248.7 million for the three months ended March 31, 2008, compared with cash used in financing activities of $99.7 million for the same period in 2007.

Cash distributions to our general and limited partners for the first quarter of 2008 were $101.1 million, compared with $93.7 million in the same period in 2007, an increase of $7.4 million, due to cash distributions of $1.025 per unit during the first quarter of 2008, compared with $0.98 per unit in the first quarter of 2007.

In the first quarter of 2008, our common unit offering and private placement of common units generated proceeds of $443.6 million. In addition, ONEOK contributed $9.4 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 short-term borrowings. Total repayments of short-term borrowings were $100.0 million during the first quarter of 2008.

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, authorized rates or recovery of gas and gas transportation costs;

•

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 or changes in governmental policies and regulations due to climate change initiatives;

•

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

•

actions by rating agencies concerning the credit ratings of 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 which 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 affects 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;

availability of additional storage capacity;

weather conditions; and

competitive developments by Canadian and U.S. natural gas transmission peers;

•

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 pipelines 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;

•

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;

•

our ability to promptly obtain all necessary materials and supplies required for construction of gathering, processing, storage, fractionation and transportation facilities;

•

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. Fixed-rate swaps are used to reduce our risk of increased interest costs during periods of rising interest rates. Floating-rate swaps are used to convert the fixed rates of long-term borrowings into short-term variable rates. At March 31, 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

Our Natural Gas Gathering and Processing segment is 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. Based on current market conditions, the gross processing spread for the remainder of 2008 is expected to be above the five-year average. 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 table sets forth our Natural Gas Gathering and Processing segment’s hedging information for the remainder of 2008.


	Volumes Hedged	Average Price	Percentage Hedged
Natural gas liquids (Bbl/d) (a)	8,421	$ 1.31 /gallon	72	%
Condensate (Bbl/d) (a)	799	$ 2.15 gallon	73	%
Total liquid sales (Bbl/d)	9,220	$ 1.39 gallon	72	%

Natural gas (MMBtu/d) (a)	5,665	$ 9.23 / MMBtu	78	%
(a) - Hedged with fixed-priced swaps.

Our commodity price risk is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at March 31, 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 $1.6 million,

•

a $1.00 per barrel increase in the price of crude oil would increase annual net margin by approximately $0.7 million, and

•

a $0.10 per MMBtu increase in the price of natural gas would increase annual net margin by approximately $0.3 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.

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.

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 March 31, 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 first quarter ended March 31, 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

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.

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. 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.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

See Form 8-K filed on March 12, 2008.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not Applicable.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not Applicable.

ITEM 5.

OTHER INFORMATION

Not Applicable.

ITEM 6.

EXHIBITS

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


Exhibit No.		Exhibit Description
10.1		Underwriting Agreement dated March 11, 2008, among ONEOK Partners, L.P. and the underwriters named therein (incorporated by reference to Exhibit 1.1 to ONEOK Partners, L.P.’s report on Form 8-K filed on March 12, 2008).

10.2		Common Unit Purchase Agreement dated March 11, 2008, between ONEOK Partners, L.P. and ONEOK, Inc. (incorporated by reference to Exhibit 1.2 to ONEOK Partners, L.P.’s report on Form 8-K filed on March 12, 2008).

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: May 2, 2008		By:	/s/ Curtis L. Dinan
			Curtis L. Dinan
			Senior Vice President,
			Chief Financial Officer and Treasurer
			(Signing on behalf of the Registrant and as Principal Financial Officer)

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