TRI Resources (NGLS) 10-Q 2008 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

Or

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

For the transition period from                     to                     

Commission File Number 001-33303

TARGA RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	74-3117058
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1000 Louisiana, Suite 4300, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:

(713) 584-1000

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  þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  þ        Smaller reporting company  ¨

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes    ¨  No    þ  

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	5
	Consolidated Balance Sheets at March 31, 2008 and December 31, 2007	5
	Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007	6
	Consolidated Statements of Comprehensive Loss for the three months ended March 31, 2008 and 2007	7
	Consolidated Statement of Changes in Stockholder’s Equity for the three months ended March 31, 2008	8
	Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and 2007	9
	Notes to Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	44
Item 4T.	Controls and Procedures	47
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	48
Item 3.	Defaults Upon Senior Securities	48
Item 4.	Submission of Matters to a Vote of Security Holders	48
Item 5.	Other Information	48
Item 6.	Exhibits	49
SIGNATURES		50

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As generally used in the energy industry and in this Quarterly Report on Form 10-Q, the identified terms have the following meanings:

Bbl	Barrels
BBtu	Billion British thermal units, a measure of heating value
/d	Per day
gal	Gallons
MBbl	Thousand barrels
MMBtu	Million British thermal units, a measure of heating value
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
Price Index Definitions
GD-HH	Henry Hub Gas Daily average
IF-HH	Inside FERC Gas Market Report, Henry Hub
IF-HSC	Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha	Inside FERC Gas Market Report, West Texas Waha
NY-HH	NYMEX, Henry Hub Natural Gas
NY-WTI	NYMEX, West Texas Intermediate Crude Oil
OPIS-MB	Oil Price Information Service, Mont Belvieu, Texas

As used in this Quarterly Report, unless the context otherwise requires, “Targa,” “our,” “we,” “us” and similar terms refer to Targa Resources, Inc., together with its consolidated subsidiaries, including our publicly traded master limited partnership, Targa Resources Partners LP, which we refer to in this Quarterly Report as the “Partnership.”

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

This Quarterly Report contains “forward-looking statements” as defined in Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this Quarterly Report are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our future financial position, business strategy, future capital and other expenditures, plans and objectives of management for future operations. You can typically identify forward-looking statements by the use of forward-looking words such as “may,” “potential,” “project,” “plan,” “believe,” “expect,” “anticipate,” “intend,” “estimate” or similar expressions or variations on such expressions. Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors, known and unknown, which could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties, many of which are beyond our control, include, but are not limited to:

• our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations;

• our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks;

• the level of creditworthiness of counterparties to transactions;

• the amount of collateral required to be posted from time to time in our transactions;

• changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the gathering and processing industry;

• the timing and extent of changes in natural gas, NGL and commodity prices, interest rates and demand for our services;

• weather and other natural phenomena;

• industry changes, including the impact of consolidations and changes in competition;

• our ability to obtain necessary licenses, permits and other approvals;

• our ability to grow through acquisitions or internal growth projects, and the successful integration and future performance of such assets;

• the level and success of natural gas drilling around our assets, and our success in connecting natural gas supplies to our gathering and processing systems;

• general economic, market and business conditions; and

• the risks described in our Annual Report on Form 10-K for the year ended December 31, 2007.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

Forward-looking statements contained in this Quarterly Report and all subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this cautionary statement.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TARGA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	March 31, 2008			December 31, 2007
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	278,748		$	177,949
Trade receivables, net of allowances of $1,861 and $1,115		657,686			836,044
Inventory		80,022			143,185
Deferred income taxes		45,721			25,071
Assets from risk management activities		1,232			9,487
Other current assets		30,732			70,640
Total current assets		1,094,141			1,262,376
Property, plant and equipment, at cost		2,793,942			2,764,230
Accumulated depreciation		(372,167	)		(334,160	)
Property, plant and equipment, net		2,421,775			2,430,070
Unconsolidated investments		50,689			48,005
Long-term assets from risk management activities		193			4,279
Other assets		43,970			45,235
Total assets	$	3,610,768		$	3,789,965
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	347,293		$	470,860
Accrued liabilities		382,582			379,245
Current maturities of debt		12,500			12,500
Liabilities from risk management activities		106,103			75,568
Total current liabilities		848,478			938,173
Long-term debt, less current maturities		1,345,350			1,398,475
Long-term liabilities from risk management activities		122,976			81,019
Deferred income taxes		44,207			29,501
Other long-term obligations		37,652			35,267
Minority interest		106,903			100,826
Non-controlling interest in Targa Resources Partners LP		679,464			714,300
Commitments and contingencies (see Note 10)
Stockholder’s equity:
Common stock ($0.001 par value, 1,000 shares authorized, issued, and outstanding at March 31, 2008 and December 31, 2007, collateral for Targa Resources Investments Inc. debt)		—			—
Additional paid-in capital		421,445			473,784
Retained earnings		93,152			74,736
Accumulated other comprehensive loss		(88,859	)		(56,116	)
Total stockholder’s equity		425,738			492,404
Total liabilities and stockholder’s equity	$	3,610,768		$	3,789,965

See notes to unaudited consolidated financial statements

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TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands)
Revenues	$	2,202,393		$	1,449,012
Costs and expenses:
Product purchases		2,001,441			1,270,279
Operating expenses		63,578			57,923
Depreciation and amortization		38,192			36,732
General and administrative		24,093			18,691
Loss (gain) on sale of assets		(4,443	)		180
		2,122,861			1,383,805
Income from operations		79,532			65,207
Other income (expense):
Interest expense, net		(25,585	)		(43,982	)
Equity in earnings of unconsolidated investments		3,459			2,484
Minority interest		(10,147	)		(5,611	)
Non-controlling interest in Targa Resources Partners LP		(16,971	)		(1,369	)
Income before income taxes		30,288			16,729
Income tax expense
Current		(962	)		—
Deferred		(10,910	)		(7,189	)
		(11,872	)		(7,189	)
Net income	$	18,416		$	9,540

See notes to unaudited consolidated financial statements

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TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands)
Net income	$	18,416		$	9,540
Other comprehensive loss:
Commodity hedging contracts:
Change in non-controlling partners’ share of other comprehensive income of Targa Resources Partners LP		30,737			(422	)
Change in fair value		(93,388	)		(69,406	)
Reclassification adjustment for settled periods		16,044			(13,187	)
Related income taxes		15,689			33,927
Interest rate swaps:
Change in non-controlling partners’ share of other comprehensive income of Targa Resources Partners LP		7,109			—
Change in fair value		(9,435	)		270
Reclassification adjustment for settled periods		(233	)		(524	)
Related income taxes		925			95
Foreign currency items:
Foreign currency translation adjustment		(342	)		(15	)
Related income taxes		151			2
Other comprehensive loss		(32,743	)		(49,260	)
Comprehensive loss	$	(14,327	)	$	(39,720	)

See notes to unaudited consolidated financial statements

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TARGA RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER’S EQUITY

	Common Stock		Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Loss			Total
	Shares	Amount
	(Unaudited)
	(In thousands)
Balance, December 31, 2007	1	$—	$	473,784		$	74,736	$	(56,116	)	$	492,404
Distribution to parent	—	—		(52,891	)		—		—			(52,891	)
Amortization of equity awards	—	—		418			—		—			418
Tax benefit on vesting of common stock	—	—		134			—		—			134
Other comprehensive loss	—	—		—			—		(32,743	)		(32,743	)
Net income	—	—		—			18,416		—			18,416
Balance, March 31, 2008	1	$—	$	421,445		$	93,152	$	(88,859	)	$	425,738

See notes to unaudited consolidated financial statements

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TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
	2008			2007
	(Unaudited)
	(In thousands)
Cash flows from operating activities
Net income	$	18,416		$	9,540
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		38,161			36,701
Amortization		2,521			7,746
Accretion of asset retirement obligations		299			247
Deferred income tax expense		10,910			7,189
Equity in earnings of unconsolidated investments		(3,459	)		(2,484	)
Distributions from unconsolidated investments		775			1,550
Minority interest		10,147			5,611
Minority interest distributions		(4,070	)		(6,660	)
Non-controlling interest in Targa Resources Partners LP		16,971			1,369
Distributions to non-controlling interest in Targa Resources Partners LP		(13,768	)		—
Risk management activities		(2,180	)		(6,677	)
Loss (gain) on sale of assets		(4,443	)		180
Changes in operating assets and liabilities:
Accounts receivable and other assets		209,716			42,084
Inventory		63,163			53,212
Accounts payable and other liabilities		(121,177	)		(28,594	)
Net cash provided by operating activities		221,982			121,014
Cash flows from investing activities
Purchases of property, plant and equipment		(19,102	)		(38,877	)
Proceeds from property insurance		7,753			7,935
Investment in unconsolidated affiliate		—			(4,648	)
Other		(3,818	)		1,483
Net cash used in investing activities		(15,167	)		(34,107	)
Cash flows from financing activities
Senior secured credit facilities:
Borrowings		—			342,500
Repayments		(53,125	)		(748,000	)
Contribution from non-controlling interest in Targa Resources Partners LP		—			377,058
Distribution to parent		(52,891	)		(71	)
Costs incurred in connection with financing arrangements		—			(4,082	)
Net cash used in financing activities		(106,016	)		(32,595	)
Net increase in cash and cash equivalents		100,799			54,312
Cash and cash equivalents, beginning of period		177,949			142,739
Cash and cash equivalents, end of period	$	278,748		$	197,051

See notes to unaudited consolidated financial statements

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations

Organization and Operations

Targa Resources, Inc. is a Delaware corporation formed on February 26, 2004. Unless the context requires otherwise, references to “we”, “us”, “our”, “the Company” or “Targa” are intended to mean the consolidated business and operations of Targa Resources, Inc.

We are a second-tier, wholly owned subsidiary of our parent holding company, Targa Resources Investments Inc. (“Targa Investments”). The only significant asset of Targa Investments is its ownership of 100% of the outstanding capital stock of an intermediate holding company, whose sole asset is its ownership of 100% of our outstanding capital stock, which consists of one thousand shares of common stock.

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of NGLs. See Note 12—Segment Information for a description of our segments and segment operations.

Basis of Presentation

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. The unaudited consolidated financial statements for the three month periods ended March 31, 2008 and 2007 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair presentation of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Our financial results for the three months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2008. These unaudited consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

We currently own approximately 26.5% of Targa Resources Partners LP (the “Partnership”), including our 2% general partner interest. Targa Resources GP LLC, the general partner of the Partnership, is wholly owned by us. The Partnership is consolidated within our Gas Gathering and Processing segment in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights .”

The non-controlling interest in the Partnership on our consolidated balance sheets represents the investment by partners other than Targa Resources, Inc., plus those partners’ share of the net income, less those partners’ share of distributions of the Partnership. Non-controlling interest in net income of the Partnership on our consolidated statements of operations represents those partners’ share of the net income of the Partnership.

Note 2—Accounting Pronouncements

Accounting Pronouncements Recently Adopted

In September 2006 the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements.” SFAS 157 establishes a framework for

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measuring fair value, and expands disclosures about fair value measurements. The FASB partially deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We adopted SFAS 157 with respect to financial assets and liabilities that are recognized on a recurring basis on January 1, 2008. Although the adoption of SFAS 157 did not materially impact our financial condition, results of operations, or cash flows, the Company is now required to provide additional disclosures as part of its financial statements.

SFAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are either readily available in public markets or are quoted by counterparties to these contracts. In situations where we obtain inputs via quotes from our counterparties, we verify the reasonableness of these quotes via similar quotes from another source for each date for which financial statements are presented. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3. The price quotes for the Level 3 inputs are provided by a counterparty with whom we regularly transact business.

The fair value of our financial instruments as of March 31, 2008 was:

	Total		Level 1		Level 2		Level 3
	(In thousands)
Assets from commodity derivative contracts	$	1,425	$	—	$	1,425	$	—
Total assets	$	1,425	$	—	$	1,425	$	—
Liabilities from commodity derivative contracts	$	218,179	$	—	$	67,240	$	150,939
Liabilities from interest rate swaps		10,900		—		10,900		—
Total Liabilities	$	229,079	$	—	$	78,140	$	150,939

The following table sets forth a reconciliation of changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:

	Commodity Derivative Contracts
	(In thousands)
Balance, January 1, 2008	$	(124,282	)
Losses included in OCI		(25,115	)
Losses included in non-controlling interest in the Partnership		(22,605	)
Settlements		21,063
Transfers in/out of Level 3		—
Balance, March 31, 2008	$	(150,939	)

In February 2007, the FASB issued SFAS 159,“The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115.”SFAS 159 expands opportunities to use fair

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value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. Our adoption of SFAS 159 on January 1, 2008 did not have a material impact on our consolidated financial statements.

Recent Accounting Pronouncements

In March 2008 the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.” SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early adoption is encouraged. Our adoption of SFAS 161 will not impact our consolidated financial position, results of operations or cash flows.

Note 3—Partnership Units and Related Matters

A distribution for the fourth quarter of 2007 of $0.3975 per common and subordinated unit (approximately $18.8 million) was paid on February 14, 2008. Of this amount, $13.8 million was distributed to third parties. Please see also Note 13—Subsequent Events.

Note 4—Inventory

Inventory consisted of the following at the dates indicated:

	March 31, 2008		December 31, 2007
	(In thousands)
Natural gas and natural gas liquids	$	79,125	$	142,650
Materials and supplies		897		535
	$	80,022	$	143,185

Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceed their net realizable values. These non-cash adjustments are charged to product purchases within operating costs and expenses in the period they are recognized, with the related cash impact in the subsequent period. For the three month periods ended March 31, 2008 and 2007, lower of cost or market adjustments were $1.9 million and $32,000, respectively.

Note 5—Unconsolidated Investments

At March 31, 2008, our unconsolidated investments included a 22.8959% ownership interest in Venice Energy Services Company, LLC (“VESCO”), a venture that operates a natural gas liquids processing and extraction facility and a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids.

The following table shows our unconsolidated investments at the dates indicated:

	March 31, 2008		December 31, 2007
	(In thousands)
Natural Gas Gathering and Processing
VESCO	$	31,142	$	28,767
Logistics Assets
GCF		19,547		19,238
	$	50,689	$	48,005

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The following table shows our equity earnings, cash contributions and cash distributions with respect to our unconsolidated investments for the periods indicated:

	Three Months Ended March 31,
	2008		2007
	(In thousands)
Equity in earnings of:
VESCO	$	2,375	$	1,204
GCF		1,084		1,280
	$	3,459	$	2,484
Cash contributions:
VESCO	$	—	$	4,648
Cash distributions:
GCF	$	775	$	1,550

Our equity in earnings of VESCO for the three months ended March 31, 2007 includes $0.9 million for partially settled business interruption insurance claims.

The following tables show summarized financial information of our unconsolidated investments:

	Three Months Ended March 31,
	2008				2007
	GCF		VESCO		GCF		VESCO
	(In thousands)
Revenues	$	12,770	$	52,386	$	11,254	$	34,809
Cost of sales and operations		9,714		48,305		8,224		32,694
Income from operations		3,056		4,081		3,030		2,115
Net income		3,154		4,214		3,157		2,115
	As of March 31, 2008				As of December 31, 2007
	GCF		VESCO		GCF		VESCO
	(In thousands)
Current assets	$	13,974	$	50,504	$	15,497	$	54,311
Property, plant and equipment, net		49,139		176,730		50,034		139,893
Other assets		—		598		—		328
Total assets	$	63,113	$	227,832	$	65,531	$	194,532
Current liabilities	$	617	$	36,186	$	4,189	$	25,533
Long-term liabilities		—		22,388		—		8,805
Owners’ equity		62,496		169,258		61,342		160,194
Total liabilities and owners’ equity	$	63,113	$	227,832	$	65,531	$	194,532

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Note 6—Debt Obligations

Our consolidated debt obligations consisted of the following at the dates indicated:

	March 31, 2008			December 31, 2007
	(In thousands)
Long-term debt:
Obligations of Targa:
Senior secured term loan facility, variable rate, due October 2012	$	531,550		$	534,675
Senior unsecured notes, 8 1/2% fixed rate, due November 2013		250,000			250,000
Senior secured revolving credit facility, variable rate, due October 2011 (1)		—			—
Obligations of the Partnership:
Senior secured revolving credit facility, variable rate, due February 2012		576,300			626,300
Total debt		1,357,850			1,410,975
Current maturities of debt		(12,500	)		(12,500	)
Long-term debt	$	1,345,350		$	1,398,475
Irrevocable standby letters of credit:
Letters of credit outstanding under synthetic letter of credit facility (2)	$	284,331		$	272,409
Letters of credit outstanding under senior secured revolving credit facility of the Partnership		38,450			25,900
	$	322,781		$	298,309

(1) The entire $250 million available under our senior secured revolving credit facility may also be utilized for letters of credit.

(2) Our $300 million senior secured synthetic letter of credit facility terminates in October 2012. At March 31, 2008 we had approximately $15.7 million available under this facility.

Information Regarding Variable Interest Rates Paid

The following table shows the range of interest rates paid and weighted-average interest rates paid on our significant consolidated variable-rate debt obligations during the three months ended March 31, 2008:

	Range of interest rates paid	Weighted average interest rate paid
Senior secured term loan facility	4.7% to 6.9%	6.9	%
Senior secured revolving credit facility of the Partnership	4.0% to 6.4%	5.6	%

Holdco Loan Facility of Targa Investments

On March 7, 2008, we made a cash distribution of $50.0 million to Targa Investments. Targa Investments used the proceeds to retire $62.5 million of its outstanding borrowings under this facility.

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Note 7—Asset Retirement Obligations

The changes in our aggregate asset retirement obligations are as follows:

	Three Months Ended March 31, 2008
	(In thousands)
Beginning of period	$	12,608
Change in cash flow estimate (1)		2,732
Accretion expense		299
Liabilities settled		(229	)
End of period	$	15,410

(1) The change in cash flow estimate is primarily from a reassessment of abandonment cost estimates for our offshore gathering systems.

Note 8—Stock and Other Compensation Plans

Stock Option Plans

Share-based compensation cost related to stock options included in general and administrative expense for each of the three months ended March 31, 2008 and 2007 was $15,000. As of March 31, 2008, our remaining unamortized compensation cost related to stock options was approximately $0.1 million, which is expected to be recognized over a weighted-average period of approximately one year.

Non-vested (Restricted) Common Stock

Share-based compensation cost related to restricted stock included in general and administrative expense for the three months ended March 31, 2008 and 2007 was $0.4 million and $0.5 million, respectively. As of March 31, 2008, our remaining unamortized compensation cost related to restricted stock was approximately $0.9 million, which is expected to be recognized over a weighted-average period of approximately one year.

Non-Employee Director Grants and Incentive Plan related to the Partnership’s Common Units

Targa Investments has adopted a long-term incentive plan for employees, consultants and directors who perform services for Targa Investments or its affiliates.

At March 31, 2008, the aggregate fair value of performance units expected to vest was $8.4 million. For the three months ended March 31, 2008 and 2007, we recognized compensation expense of $0.1 million and $0.3 million related to the performance units. The total recognition period for the remaining unrecognized compensation cost is approximately two years.

On March 25, 2008, the Partnership’s general partner awarded 2,000 restricted common units to each of the Partnership’s and Targa Investments’ non-management and independent directors (16,000 units in total). The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date. For the three months ended March 31, 2008 and 2007, we recognized compensation expense related to equity-based awards of $41,000 and $16,000, respectively. We estimate that the remaining fair value of $0.5 million will be recognized in expense over the next 23-36 months.

Note 9—Derivative Instruments and Hedging Activities

At March 31, 2008, accumulated other comprehensive income (loss) (“OCI”) included $138.3 million ($88.1 million, net of tax) of unrealized net losses on commodity hedges, and $2.9 million ($1.8 million, net of tax) of unrealized net losses on interest rate hedges.

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During the three months ending March 31, 2008 and 2007, deferred net gains / (losses) on commodity hedges of $(16.0) million and $13.2 million, respectively, were reclassified from OCI to revenues, and deferred net gains / (losses) on interest rate hedges of $0.2 million and $0.5 million, respectively, were reclassified from OCI to interest expense.

As of March 31, 2008, $63.8 million ($40.6 million, net of tax) of deferred net losses on commodity hedges and $1.3 million ($0.8 million, net of tax) of deferred net losses on interest rate hedges recorded in OCI are expected to be reclassified to earnings during the next twelve months.

As of March 31, 2008, we had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from April 1, 2008 through December 31, 2008.):

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Natural Gas Sales
Swap	IF-Waha	6.96	21,918	—	—	—	—	$	(15,585	)
Swap	IF-Waha	6.62	—	21,918	—	—	—		(18,096	)
Swap	IF-Waha	7.40	—	—	9,300	—	—		(3,202	)
Swap	IF-Waha	7.36	—	—	—	5,500	—		(1,436	)
Swap	IF-Waha	7.18	—	—	—	—	5,500		(1,651	)
			21,918	21,918	9,300	5,500	5,500	$	(39,970	)

NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	0.80	3,547	—	—	—	—	$	(22,078	)
Swap	OPIS-MB	0.79	—	3,347	—	—	—		(21,218	)
Swap	OPIS-MB	0.87	—	—	2,750	—	—		(9,597	)
Swap	OPIS-MB	0.91	—	—	—	1,550	—		(4,312	)
Swap	OPIS-MB	0.92	—	—	—	—	1,250		(3,169	)
			3,547	3,347	2,750	1,550	1,250	$	(60,374	)

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As of March 31, 2008, the Partnership had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from April 1, 2008 through December 31, 2008):

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Natural Gas Purchases
Swap	NY-HH	8.42	1,552	—	—	—	—	$	775
Total Swaps			1,552	—	—	—	—		775
Natural Gas Sales
Swap	IF-HSC	8.09	2,328	—	—	—	—		(1,235	)
Swap	IF-HSC	7.39	—	1,966	—	—	—		(1,420	)
			2,328	1,966	—	—	—		(2,655	)
Swap	IF-NGPL MC	8.43	6,964	—	—	—	—		(1,182	)
Swap	IF-NGPL MC	8.02	—	6,256	—	—	—		(1,352	)
Swap	IF-NGPL MC	7.43	—	—	5,685	—	—		(1,538	)
Swap	IF-NGPL MC	7.34	—	—	—	2,750	—		(713	)
Swap	IF-NGPL MC	7.18	—	—	—	—	2,750		(820	)
			6,964	6,256	5,685	2,750	2,750		(5,605	)
Swap	IF-Waha	8.20	7,389	—	—	—	—		(2,754	)
Swap	IF-Waha	7.61	—	6,936	—	—	—		(3,339	)
Swap	IF-Waha	7.38	—	—	5,709	—	—		(2,017	)
Swap	IF-Waha	7.36	—	—	—	3,250	—		(848	)
Swap	IF-Waha	7.36	—	—	—	—	3,250		(976	)
			7,389	6,936	5,709	3,250	3,250		(9,934	)
Total Swaps			16,681	15,158	11,394	6,000	6,000		(18,194	)
Floor	IF-NGPL MC	6.55	1,000	—	—	—	—		115
Floor	IF-NGPL MC	6.55	—	850	—	—	—		25
			1,000	850	—	—	—		140
Floor	IF-Waha	6.85	670	—	—	—	—		75
Floor	IF-Waha	6.55	—	565	—	—	—		7
			670	565	—	—	—		82
Total Floors			1,670	1,415	—	—	—		222
Basis Swap Apr 2008 receive GD-HH, pay IF-HH, 120,000 MMBtu									—
								$	(17,197	)

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NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	1.02	7,110	—	—	—	—	$	(29,293	)
Swap	OPIS-MB	0.96	—	6,248	—	—	—		(27,281	)
Swap	OPIS-MB	0.91	—	—	4,809	—	—		(15,978	)
Swap	OPIS-MB	0.92	—	—	—	3,400	—		(10,417	)
Swap	OPIS-MB	0.92	—	—	—	—	2,700		(7,596	)
			7,110	6,248	4,809	3,400	2,700	$	(90,565	)

Condensate

Instrument Type	Index	Avg. Price $/Bbl	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Condensate Sales
Swap	NY-WTI	68.34	384	—	—	—	—	$	(3,016	)
Swap	NY-WTI	69.00	—	322	—	—	—		(3,002	)
Swap	NY-WTI	68.10	—	—	301	—	—		(2,641	)
Total Swaps			384	322	301	—	—		(8,659	)
Floor	NY-WTI	60.50	55	—	—	—	—		21
Floor	NY-WTI	60.00	—	50	—	—	—		(10	)
Total Floors			55	50	—	—	—		11
			439	372	301	—	—	$	(8,648	)

These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us with protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices which we have hedged, we will receive less revenue on the hedge volumes than we would in the absence of hedges.

Customer Hedges

As of March 31, 2008, the Partnership had the following commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market through earnings:

Period	Commodity	Instrument Type	Daily Volume		Average Price			Index	(In thousands) Fair Value
Purchases
Apr 2008 - June 2008	Natural gas	Swap	14,176	MMBtu	$	9.22	per MMBtu	NY-HH	$	545
Sales
Apr 2008 - June 2008	Natural gas	Fixed price sale	14,176	MMBtu	$	9.22	per MMBtu	NY-HH		(545	)
									$	—

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those underlying markets.

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Interest Rate Swaps

As of March 31, 2008, the Partnership had the following interest rate swaps:

Effective Date	Expiration Date	Notional Amount		Index	Fixed Rate
12/13/07	1/24/2011	$	50,000,000	3 Month USD LIBOR	4.0775	%
12/18/07	1/24/2011		50,000,000	3 Month USD LIBOR	4.2100	%
12/21/07	1/24/2012		50,000,000	3 Month USD LIBOR	4.0750	%
12/21/07	1/24/2012		50,000,000	3 Month USD LIBOR	4.0750	%
01/09/08	1/24/2012		50,000,000	3 Month USD LIBOR	3.6990	%
01/11/08	1/24/2012		50,000,000	3 Month USD LIBOR	3.6400	%

Each of these interest rate swaps has been designated as a cash flow hedge of variable rate interest payments on $50 million in borrowings under the Partnership’s revolving credit facility. At March 31, 2008, the fair value of these interest rate swaps was a liability of $10.9 million.

Note 10—Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated in accordance with the American Institute of Certified Public Accountants (“AICPA”) Statement of Position No. 96-1, “Environmental Remediation Liabilities.” Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

In August 2005, prior to Targa’s acquisition of Versado Gas Processors, L.L.C. (“Versado”), the State of New Mexico’s Environment Department (“NMED”) inspected Versado’s Eunice Gas Processing Plant and its books and records. Targa Midstream Services Limited Partnership (“TMS”) is the operator of Versado. In May 2007, the NMED sent Versado a draft compliance order relating to the 2005 inspection, alleging that Versado violated certain emissions standards and permit, monitoring and recordkeeping requirements. After TMS provided certain responses and information concerning the alleged violations, the NMED provided a revised draft compliance order and a settlement offer containing a proposed penalty of approximately $2.1 million to resolve the remaining alleged violations. More recently, however, we have discussed with the NMED an expansion of the proposed compliance order to include the resolution of other alleged violations associated with the operation of flares at the Eunice, Monument and Saunders plants. We may be required to incur capital expenditures, including flare upgrades at the Eunice, Monument and Saunders plants and additional facility enhancements, and additional operating costs to implement various leak detection and monitoring programs in order to resolve these alleged violations, the amount of which currently is not reasonably estimable. It is also possible that the NMED may assess a penalty for the alleged violations associated with the operation of the flares at the Eunice, Monument and Saunders plants as part of an overall settlement, although no such penalty has yet been proposed by the agency. At this time, we can not estimate the effect, if any, that this matter will have on our results of operations.

Our environmental liability at March 31, 2008 was $4.5 million, consisting of $0.6 million for gathering system leaks, $1.8 million for ground water assessment and remediation, and $2.1 million for the gas processing plant environmental violations.

Legal Proceedings

We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. We believe all

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such matters are without merit or involve amounts, which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows, except for the items more fully described below.

In May 2002, Apache Corporation (“Apache”) filed suit in Texas state court against Versado Gas Processors, LLC (“Versado”), as purchaser and processor of Apache’s gas, and Dynegy Midstream Services, Limited Partnership (now known as Targa Midstream Services Limited Partnership, a wholly-owned subsidiary of ours (“TMSLP”)), as operator of the Versado assets in New Mexico (“Versado Defendants”) alleging (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that the Versado Defendants engaged in certain transactions with affiliates, resulting in the Versado Defendants not receiving fair market value when it sold gas and liquids, and (iii) that the formula for calculating the amount the Versado Defendants received from its buyers of gas and liquids is flawed since it is based on gas price indices that were allegedly manipulated. At trial, the jury found in favor of Apache on the lost gas claim, awarding approximately $1.6 million in damages. Apache’s claims with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the trial court and abated for a future trial. The parties settled the severed lawsuit in May 2007.

In May 2004, the trial court granted the Versado Defendants’ motion to set aside the jury verdict on the lost gas claim and vacated the jury award to Apache. Apache filed its notice of appeal with the 14th Court of Appeals of Houston in October 2004. In 2006, the Court of Appeals reinstated the jury verdict in Apache’s favor on the issue of lost gas and also awarded Apache legal fees and interest, bringing the total award against the Versado Defendants to approximately $2.7 million. After rehearing, the Court of Appeals affirmed its decision reinstating the original jury verdict in Apache’s favor. With interest and attorneys fees that verdict stands at approximately $2.9 million.

In January 2007, the Versado Defendants filed their petition for review with the Supreme Court of Texas and in March 2007, Apache filed its conditional petition for review with the Supreme Court of Texas. On April 4, 2008, the Supreme Court of Texas granted review of the petitions, and the appeal is currently pending before the Supreme Court of Texas.

As a result of damage caused by Hurricane Rita, TMSLP’s West Cameron 229A platform sank in late September 2005. On November 12, 2005, the submerged wreckage was struck by an integrated tug-barge, the M/T Rebel, owned by K-Sea Transportation (“K-Sea”). As much as 25,000 barrels of No. 6 fuel oil may have entered Gulf of Mexico waters as the barge dragged part of the platform debris approximately three (3) miles from the sunken platform location. After receiving a letter from K-Sea threatening to hold TMSLP liable for all damages, TMSLP filed suit in federal district court in Galveston, Texas on November 21, 2005, seeking to hold K-Sea responsible for damage to the platform. In June 2007, the case was transferred to the federal district court in Houston, Texas.

In January 2006, Rios Energy (“Rios”), owner of the oil being transported in the barge, intervened in the existing suit and filed a new suit in the same federal court against both TMSLP and K-Sea alleging their negligence caused the loss of and damage to Rios’ oil. On March 8, 2006, K-Sea filed a counterclaim against TMSLP seeking to recover its alleged damages in excess of $90 million. In order to resolve K-Sea’s concerns over security for its claims, we agreed to provide a guarantee to K-Sea pursuant to which we would satisfy any final, non-appealable judgment or settlement against TMSLP if TMSLP is unable to pay any judgment against it.

On December 10, 2007, after a trial on the merits, the court concluded that K-Sea’s negligence caused 60% of the damages suffered by K-Sea and TMSLP. The court assessed 40% fault against TMSLP. Final judgment was entered on December 14, 2007. During trial, TMSLP and Rios settled their dispute. For purposes of the trial, K-Sea and TMSLP stipulated to the amount of damages for K-Sea in the amount of $62.3 million and for TMSLP in the amount of $400,000. The parties also agreed that prejudgment interest, if any, would accrue at the rate of 4.45% simple interest per annum commencing May 1, 2006. TMSLP and K-Sea entered into an

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agreement regarding the judgment, pursuant to which (i) TMSLP paid K-Sea $26.5 million on January 16, 2008, (ii) K-Sea acknowledged that the judgment has been satisfied, (iii) K-Sea released TMSLP and us from the guaranty, and (iv) TMSLP and K-Sea agreed not to appeal the judgment. TMSLP’s entire liability for K-Sea’s claims was covered by insurance, except for a self-insured retention amount.

Prior to trial, K-Sea submitted a claim under the Oil Pollution Act of 1990 seeking reimbursement of removal costs and cleanup damages from the Oil Spill Liability Trust Fund (“Trust Fund”). K-Sea included the same removal costs and cleanup damages as a portion of its request for relief at the trial before the federal district court. K-Sea has indicated that it will adjust its request for reimbursement from the Trust Fund to reflect any recovery of removal and cleanup damages from TMSLP but has not yet done so. In the event K-Sea receives a reimbursement from the Trust Fund, the Trust Fund may seek to recover from TMSLP some or all of any reimbursement to K-Sea. TMSLP anticipates that liability to the Trust Fund, if any, would be covered by insurance. TMSLP intends to contest liability in any action or proceeding to recover amounts reimbursed to K-Sea, but we can give no assurances regarding the outcome of any such action or proceeding.

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including us, three other Targa entities and private equity funds affiliated with Warburg Pincus, seeking damages from the defendants. The suit alleges that we and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from our competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal, and on May 6, 2008 filed its appellant’s brief with the 14^th Court of Appeals in Houston, Texas. We will contest the appeal, but can give no assurances regarding the outcome of the proceeding.

Note 11—Related-Party Transactions

Hedging Arrangements

An affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”) is an equity investor in Targa Investments. We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas, NGL, and condensate over periods ending in 2010, and we have agreed to pay MLCI floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with MLCI as of March 31, 2008:

Period	Commodity	Instrument Type	Daily Volumes		Average Price			Index
Apr 2008—Dec 2008	Natural gas	Swap	21,918	MMBtu	$	6.96	per MMBtu	IF-Waha
Jan 2009—Dec 2009	Natural gas	Swap	21,918	MMBtu	$	6.62	per MMBtu	IF-Waha
Apr 2008—Dec 2008	NGL	Swap	3,047	Bbl	$	0.76	per gallon	OPIS-MB
Jan 2009—Dec 2009	NGL	Swap	2,847	Bbl	$	0.74	per gallon	OPIS-MB

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The following table shows the Partnership’s open commodity derivatives with MLCI as of March 31, 2008:

Period	Commodity	Instrument Type	Daily Volumes		Average Price			Index
Apr 2008—Dec 2008	Natural gas	Swap	3,847	MMBtu	$	8.76	per MMBtu	IF-Waha
Jan 2009—Dec 2009	Natural gas	Swap	3,556	MMBtu	$	8.07	per MMBtu	IF-Waha
Jan 2010—Dec 2010	Natural gas	Swap	3,289	MMBtu	$	7.39	per MMBtu	IF-Waha
Apr 2008—Dec 2008	NGL	Swap	3,175	Bbl	$	1.06	per gallon	OPIS-MB
Jan 2009—Dec 2009	NGL	Swap	3,000	Bbl	$	0.98	per gallon	OPIS-MB
Apr 2008—Dec 2008	Condensate	Swap	264	Bbl	$	72.66	per barrel	NY-WTI
Jan 2009—Dec 2009	Condensate	Swap	202	Bbl	$	70.60	per barrel	NY-WTI
Jan 2010—Dec 2010	Condensate	Swap	181	Bbl	$	69.28	per barrel	NY-WTI

As of March 31, 2008, the fair value of these open positions is a liability of $103.9 million. For the three months ended March 31, 2008 and 2007, we paid MLCI $12.2 million and MLCI paid us $2.1 million, respectively, for amounts due under settled commodity derivative transactions.

Commodity Transactions

For the periods indicated, we completed natural gas and NGL purchases and sales transactions with related parties as follows:

Purchases
	Three Months Ended March 31,
	2008		2007
	(In thousands)
VESCO	$	46,795	$	31,437
MLCI		1,574		3,246
	$	48,369	$	34,683
Sales
	Three Months Ended March 31,
	2008		2007
	(In thousands)
VESCO	$	664	$	4,546
MLCI		28,029		13,642
	$	28,693	$	18,188

Note 12—Segment Information

We categorize the midstream natural gas industry into, and describe our business in, two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing.

Our Natural Gas Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas and Southeast New Mexico. We are also party to natural gas processing agreements with third party plants.

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Our Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating, storing, and transporting of finished NGLs. These assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing segment and are predominantly located in Mont Belvieu, Texas and Western Louisiana.

Our NGL Distribution and Marketing segment markets our own natural gas liquids production and also purchased natural gas liquids products in selected United States markets.

Our Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations. In our refinery services business, we provide LPG (liquefied petroleum gas) balancing services, purchasing natural gas liquids products from refinery customers and selling natural gas liquids products to various customers. Our wholesale propane marketing operations include the sale of propane and related logistics services to multi-state retailers, independent retailers and other end-users. Wholesale Marketing operates principally in the United States, and has a small marketing presence in Canada.

The “Eliminations and Other” column in the table below includes amounts related to general and administrative expenses not allocated to segment operations, corporate development, interest expense, income tax expense, and the depreciation and cost of equipment used in our headquarters office. “Eliminations and Other” also includes the elimination of intersegment revenues and expenses.

Our reportable segment information is shown in the following tables:

	Three Months Ended March 31, 2008
	Gas Gathering and Processing		Logistics Assets		NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
	(In thousands)
Revenues	$	439,201	$	20,818	$	1,219,113	$	523,261	$	—		$	2,202,393
Intersegment revenues		434,033		30,336		200,504		20,086		(684,959	)		—
Revenues		873,234		51,154		1,419,617		543,347		(684,959	)		2,202,393
Product purchases		724,045		—		944,386		333,010		—			2,001,441
Intersegment product purchases		6,419		—		466,429		200,732		(673,580	)		—
Product purchases		730,464		—		1,410,815		533,742		(673,580	)		2,001,441
Operating expenses		30,020		33,048		499		11		—			63,578
Intersegment operating expenses		148		11,231		—		—		(11,379	)		—
Operating expenses		30,168		44,279		499		11		(11,379	)		63,578
Operating margin	$	112,602	$	6,875	$	8,303	$	9,594	$	—		$	137,374
General and administrative	$	11,899	$	5,033	$	2,780	$	4,191	$	190		$	24,093
Equity in earnings of unconsolidated investments	$	2,375	$	1,084	$	—	$	—	$	—		$	3,459
Unconsolidated investments	$	31,142	$	19,547	$	—	$	—	$	—		$	50,689
Capital expenditures	$	12,123	$	5,920	$	—	$	—	$	1,059		$	19,102

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	Three Months Ended March 31, 2007
	Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing			Wholesale Marketing		Eliminations and Other			Total
	(In thousands)
Revenues	$	357,946	$	16,852		$	740,860		$	333,354	$	—		$	1,449,012
Intersegment revenues		264,895		25,905			141,438			8,737		(440,975	)		—
Revenues		622,841		42,757			882,298			342,091		(440,975	)		1,449,012
Product purchases		502,555		1			585,924			181,799		—			1,270,279
Intersegment product purchases		8		(1	)		284,042			153,778		(437,827	)		—
Product purchases		502,563		—			869,966			335,577		(437,827	)		1,270,279
Operating expenses		29,054		28,247			621			1		—			57,923
Intersegment operating expenses		46		3,125			(23	)		—		(3,148	)		—
Operating expenses		29,100		31,372			598			1		(3,148	)		57,923
Operating margin	$	91,178	$	11,385		$	11,734		$	6,513	$	—		$	120,810
General and administrative	$	9,379	$	3,426		$	1,840		$	3,121	$	925		$	18,691
Equity in earnings of unconsolidated investments	$	1,204	$	1,280		$	—		$	—	$	—		$	2,484
Unconsolidated investments	$	25,577	$	19,332		$	—		$	—	$	—		$	44,909
Capital expenditures	$	22,938	$	13,453		$	—		$	—	$	690		$	37,081

The following table is a reconciliation of operating margin to net income for each of the periods presented:

	Three Months Ended March 31,
	2008			2007
	(in thousands)
Operating margin	$	137,374		$	120,810
Adjustments to reconcile operating margin to net income:
Depreciation and amortization		(38,192	)		(36,732	)
Gain (loss) on sales of assets		4,443			(180	)
General and administrative		(24,093	)		(18,691	)
Interest expense, net		(25,585	)		(43,982	)
Equity in earnings of unconsolidated investments		3,459			2,484
Minority interest		(10,147	)		(5,611	)
Non-controlling interest in net income of the Partnership		(16,971	)		(1,369	)
Income tax expense		(11,872	)		(7,189	)
Net income	$	18,416		$	9,540

Note 13—Subsequent Events

On April 22, 2008, the general partner of the Partnership approved a quarterly distribution of available cash of $0.4175 per common and subordinated unit for the quarter ended March 31, 2008. The cash distribution of approximately $19.9 million (including distributions to us as the general partner and the holder of the incentive distribution rights) is to be paid on May 15, 2008 to all unitholders of record as of the close of business on May 5, 2008.

24

During April 2008, we received approximately $40 million and $22 million related to property damage and business interruption insurance claims, respectively. Our initial purchase price allocation for the DMS acquisition in October 2005 included an $81.1 million receivable for insurance claims related to expenditures to repair pre-acquisition property damage caused by hurricanes Katrina and Rita. We will recognize a gain of approximately $19 million related to the property damage payment, because cumulative receipts have exceeded the amount of the receivable recorded as part of the DMS acquisition purchase price allocation.

Note 14—Consolidating Financial Statements

We are the issuer of the notes discussed in Note 7 to the financial statements of our Annual Report on Form 10-K for the year ended December 31, 2007. . The notes are jointly and severally, irrevocably and unconditionally guaranteed by our wholly-owned subsidiaries (referred to as “Guarantor Subsidiaries”).

The following financial information presents condensed consolidating financial statements, which include:

• The parent company only (“Parent”);

• The Guarantor Subsidiaries on a consolidated basis;

• Non-wholly-owned and foreign subsidiaries (referred to as “Non-Guarantor Subsidiaries);

• Elimination entries necessary to consolidate the Parent, the Guarantor Subsidiaries, and the Non-Guarantor Subsidiaries; and

• The Company on a consolidated basis.

25

Targa Resources, Inc.

Condensed Consolidating Balance Sheet

March 31, 2008

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—		$	221,001		$	57,747		$	—		$	278,748
Accounts receivable and other current assets		45,810			653,229			116,354			—			815,393
Total current assets		45,810			874,230			174,101			—			1,094,141
Property, plant, and equipment, at cost		—			757,788			2,036,154			—			2,793,942
Accumulated depreciation		—			81,708			(453,875	)		—			(372,167	)
Property, plant, and equipment, net		—			839,496			1,582,279			—			2,421,775
Unconsolidated investments		—			50,689			—			—			50,689
Investment in subsidiaries		922,819			24,113			—			(946,932	)		—
Advances to (from) subsidiaries		163,638			(271,215	)		107,577			—			—
Other assets		132,583			(98,041	)		9,621			—			44,163
Total assets	$	1,264,850		$	1,419,272		$	1,873,578		$	(946,932	)	$	3,610,768
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and other liabilities	$	17,505		$	543,139		$	275,334		$	—		$	835,978
Current maturities of debt		12,500			—			—			—			12,500
Total current liabilities		30,005			543,139			275,334			—			848,478
Long-term liabilities:
Long-term debt, net of current maturities		769,050			—			576,300			—			1,345,350
Other long-term obligations		40,057			83,961			80,817			—			204,835
Total long-term liabilities		809,107			83,961			657,117			—			1,550,185
Minority interest		—			—			—			106,903			106,903
Noncontrolling interest in the Partnership		—			—			—			679,464			679,464
Stockholder’s equity:
Stockholder’s equity		514,597			899,834			1,066,174			(1,966,008	)		514,597
Accumulated other comprehensive loss		(88,859	)		(107,662	)		(125,047	)		232,709			(88,859	)
Total stockholder’s equity		425,738			792,172			941,127			(1,733,299	)		425,738
Total liabilities and stockholders’ equity	$	1,264,850		$	1,419,272		$	1,873,578		$	(946,932	)	$	3,610,768

26

Targa Resources, Inc.

Condensed Consolidating Balance Sheet

December 31, 2007

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—		$	88,303		$	89,646		$	—		$	177,949
Accounts receivable and other current assets		25,130			954,910			104,387			—			1,084,427
Total current assets		25,130			1,043,213			194,033			—			1,262,376
Property, plant, and equipment, at cost		—			743,652			2,020,578			—			2,764,230
Accumulated depreciation		—			94,265			(428,425	)		—			(334,160	)
Property, plant, and equipment, net		—			837,917			1,592,153			—			2,430,070
Unconsolidated investments		—			48,005			—			—			48,005
Investment in subsidiaries		1,087,322			109,411			—			(1,196,733	)		—
Advances to (from) subsidiaries		66,953			(172,735	)		105,782			—			—
Other assets		134,215			(97,599	)		12,898			—			49,514
Total assets	$	1,313,620		$	1,768,212		$	1,904,866		$	(1,196,733	)	$	3,789,965
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and other liabilities	$	11,043		$	657,736		$	256,894		$	—		$	925,673
Current maturities of debt		12,500			—			—			—			12,500
Total current liabilities		23,543			657,736			256,894			—			938,173
Long-term liabilities:
Long-term debt, net of current maturities		772,175			—			626,300			—			1,398,475
Other long-term obligations		25,498			100,516			19,773			—			145,787
Total long-term liabilities		797,673			100,516			646,073			—			1,544,262
Minority interest		—			—			—			100,826			100,826
Noncontrolling interest in the Partnership		—			—			—			714,300			714,300
Stockholder’s equity:
Stockholder’s equity		548,520			1,082,065			1,075,149			(2,157,214	)		548,520
Accumulated other comprehensive loss		(56,116	)		(72,105	)		(73,250	)		145,355			(56,116	)
Total stockholder’s equity		492,404			1,009,960			1,001,899			(2,011,859	)		492,404
Total liabilities and stockholders’ equity	$	1,313,620		$	1,768,212		$	1,904,866		$	(1,196,733	)	$	3,789,965

27

Targa Resources, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2008

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues:	$	—		$	2,018,510	$	704,761		$	(520,878	)	$	2,202,393
Operating costs and expenses:
Product purchases		—			1,936,502		571,893			(506,954	)		2,001,441
Operating expenses		—			34,962		42,540			(13,924	)		63,578
Depreciation and amortization		—			12,558		25,634			—			38,192
General and administrative and other		—			14,762		4,888			—			19,650
		—			1,998,784		644,955			(520,878	)		2,122,861
Income from operations		—			19,726		59,806			—			79,532
Other income (expense):
Interest expense, net		(17,113	)		—		(8,472	)		—			(25,585	)
Equity in earnings of unconsolidated investments		—			3,459		—			—			3,459
Equity in earnings of subsidiaries		47,488			24,113		—			(71,601	)		—
Minority interest/Non-controlling interest		—			—		—			(27,118	)		(27,118	)
Income before income taxes		30,375			47,298		51,334			(98,719	)		30,288
Income tax (expense) benefit		(11,959	)		190		(337	)		234			(11,872	)
Net income	$	18,416		$	47,488	$	50,997		$	(98,485	)	$	18,416

Targa Resources, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended March 31, 2007

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiary			Intercompany Eliminations			Consolidated
Revenues:	$	—		$	1,309,130	$	478,190		$	(338,308	)	$	1,449,012
Operating costs and expenses:
Product purchases		—			1,222,855		380,883			(333,459	)		1,270,279
Operating expenses		—			31,105		31,667			(4,849	)		57,923
Depreciation and amortization		—			11,651		25,081			—			36,732
General and administrative and other		16			15,448		3,407			—			18,871
		16			1,281,059		441,038			(338,308	)		1,383,805
Income from operations		(16	)		28,071		37,152			—			65,207
Other income (expense):
Interest expense, net		(41,497	)		—		(2,485	)		—			(43,982	)
Equity in earnings of unconsolidated investments		—			2,484		—			—			2,484
Equity in earnings of subsidiaries		58,111			27,535		—			(85,646	)		—
Minority interest/Non-controlling interest		—			—		—			(6,980	)		(6,980	)
Income before income taxes		16,598			58,090		34,667			(92,626	)		16,729
Income tax (expense) benefit		(7,058	)		21		(152	)		—			(7,189	)
Net income	$	9,540		$	58,111	$	34,515		$	(92,626	)	$	9,540

28

Targa Resources, Inc.

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2008

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income	$	18,416		$	47,488		$	50,997		$	(98,485	)	$	18,416
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion		2,047			12,697			26,237			—			40,981
Deferred income taxes		10,807			—			337			(234	)		10,910
Earnings from unconsolidated investments		—			(3,459	)		—			—			(3,459	)
Equity in earnings of subsidiaries		(47,488	)		(24,113	)		—			71,601			—
Other		—			(13,344	)		(10,342	)		27,118			3,432
Changes in operating assets and liabilities:
Accounts receivable and other assets		(27	)		227,943			(18,200	)		—			209,716
Inventory		—			64,396			(1,233	)		—			63,163
Accounts payable and other liabilities		6,463			(164,635	)		36,995			—			(121,177	)
Net cash provided by (used in) operating activities		(9,782	)		146,973			84,791			—			221,982
Cash flows from investing activities
Purchases of property and equipment		—			(7,316	)		(11,786	)		—			(19,102	)
Other		—			7,760			(3,825	)		—			3,935
Net cash provided by (used in) investing activities		—			444			(15,611	)		—			(15,167	)
Cash flows from financing activities
Repayments under senior secured credit facility		(3,125	)		—			(50,000	)		—			(53,125	)
Other		(52,891	)		—			—			—			(52,891	)
Receipts from (payments to) subsidiaries		65,798			(14,719	)		(51,079	)		—			—
Net cash provided by (used in) financing activities		9,782			(14,719	)		(101,079	)		—			(106,016	)
Net increase (decrease) in cash and cash equivalents		—			132,698			(31,899	)		—			100,799
Cash and cash equivalents, beginning of period		—			88,303			89,646			—			177,949
Cash and cash equivalents, end of period	$	—		$	221,001		$	57,747		$	—		$	278,748

29

Targa Resources, Inc.

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2007

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income	$	9,540		$	58,111		$	34,515		$	(92,626	)	$	9,540
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion		7,596			11,705			25,393			—			44,694
Deferred income taxes		7,058			(21	)		152			—			7,189
Earnings from unconsolidated investments		—			(2,484	)		—			—			(2,484	)
Equity in earnings of subsidiaries		(58,111	)		(27,535	)		—			85,646			—
Other		—			(20,120	)		8,513			6,980			(4,627	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		—			33,990			8,094			—			42,084
Inventory		—			53,313			(101	)		—			53,212
Accounts payable and other liabilities		16			(12,793	)		(15,817	)		—			(28,594	)
Net cash provided by (used in) operating activities		(33,901	)		94,166			60,749			—			121,014
Cash flows from investing activities
Purchases of property and equipment		—			(20,193	)		(18,684	)		—			(38,877	)
Other		—			4,769			1			—			4,770
Net cash used in investing activities		—			(15,424	)		(18,683	)		—			(34,107	)
Cash flows from financing activities
Senior secured credit facility:
Borrowings		—			—			342,500			—			342,500
Repayments		(700,000	)		—			(48,000	)		—			(748,000	)
Non-controlling interest in the Partnership		—			—			377,058			—			377,058
Other		(71	)		—			(4,082	)		—			(4,153	)
Receipts from (payments to) subsidiaries		733,972			(40,380	)		(693,592	)		—			—
Net cash provided by (used in) financing activities		33,901			(40,380	)		(26,116	)		—			(32,595	)
Net increase in cash and cash equivalents		—			38,362			15,950			—			54,312
Cash and cash equivalents, beginning of period		—			117,661			25,078			—			142,739
Cash and cash equivalents, end of period	$	—		$	156,023		$	41,028		$	—		$	197,051

30

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

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Form 10-Q and in our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Overview

We are a Delaware corporation formed in 2004 by our management team and Warburg Pincus LLC to acquire, own and operate assets in the midstream natural gas business.

Our gathering and processing assets are located primarily in the Permian Basin in West Texas and Southeast New Mexico, the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana, and, through the Partnership, the Fort Worth Basin in North Texas, the Permian Basin in West Texas and the onshore region of the Louisiana Gulf Coast. Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the United States.

We conduct our business operations through two divisions and report our results of operations under four segments: Our Natural Gas Gathering and Processing division, which includes the Partnership, is a single segment consisting of our natural gas gathering and processing facilities, as well as certain fractionation capability integrated within those facilities; and the NGL Logistics and Marketing division, which consists of three segments: Logistics Assets, NGL Distribution and Marketing and Wholesale Marketing.

Critical Accounting Policies

There have been no significant changes to our critical accounting policies since December 31, 2007. For a more complete description of our critical accounting polices and estimates, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Accounting Pronouncements

On January 1, 2008, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 157. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 2 of the Notes to Unaudited Consolidated Financial Statements for information regarding fair value disclosures pertaining to our financial assets and liabilities.

The accounting standard-setting bodies have recently issued the following accounting standard that have the potential to affect our future financial statements:

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

31

For additional information regarding this recent accounting development and others that may affect our future financial statements, see Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Results of Operations

The following table and discussion relate to the three months ended March 31, 2008 and 2007 and is a summary of our results of operations for the periods then ended:

	Three Months Ended March 31,
	2008			2007
	(In millions, except operating and price data)
Revenue	$	2,202.4		$	1,449.0
Product purchases		2,001.4			1,270.3
Operating expenses		63.6			57.9
Depreciation and amortization		38.2			36.7
General and administrative		24.1			18.7
Loss (gain) on sales of assets		(4.4	)		0.2
Income from operations		79.5			65.2
Interest expense, net		(25.6	)		(44.0	)
Equity in earnings of unconsolidated investments		3.5			2.5
Minority interest / non-controlling interest		(27.1	)		(7.0	)
Income tax expense		(11.9	)		(7.2	)
Net income	$	18.4		$	9.5
Financial data:
Operating margin (1)	$	137.4		$	120.8
Adjusted EBITDA (2)		91.9			90.7
Operating data:
Gathering throughput MMcf/d (3)		2,175.2			1,976.7
Plant natural gas inlet, MMcf/d (4) (5)		2,143.1			1,937.8
Gross NGL production, MBbl/d		103.9			104.1
Natural gas sales, BBtu/d (5)		533.0			507.5
NGLs sales, MBbl/d		317.5			300.9
Condensate sales, MBbl/d		3.6			3.3
Average realized prices:
Natural Gas, $/MMBtu
Average realized sales price		7.79			6.58
Impact of hedging		0.12			0.16
Average realized price		7.91			6.74
NGL, $/gal
Average realized sales price		1.47			0.97
Impact of hedging		(0.02	)		—
Average realized price		1.45			0.97
Condensate, $/Bbl
Average realized sales price		95.25			55.25
Impact of hedging		(1.89	)		1.91
Average realized price		93.36			57.16

32

(1) Operating margin is total operating revenues less product purchases and operating expense. Please see “Non-GAAP Financial Measures”.

(2) Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. Please see “Non-GAAP Financial Measures”.

(3) Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points.

(4) Plant natural gas inlet represented the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(5) Plant inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Revenues increased by $753.4 million, or 52%, to $2,202.4 million for the three months ended March 31, 2008 compared to $1,449.0 million for the three months ended March 31, 2007.

Revenues from the sale of natural gas increased by $75.7 million, consisting of an $56.6 million increase due to higher realized prices, and a $19.1 million increase due to higher sales volumes. Revenues from the sale of NGLs increased by $655.5 million, consisting of increases of $581.7 million due to higher realized prices and $73.8 million due to higher sales volumes. Revenues from the sale of condensate increased by $13.8 million, consisting of increases of $12.0 million due to higher realized prices and $1.8 million due to higher sales volumes. Non-commodity sales revenues, which are principally derived from fee-based services, increased by $8.4 million.

Average realized prices for natural gas increased by $1.17 per MMBtu (net of a $0.04 decrease due to hedging) , or 17%, to $7.91 per MMBtu for the three months ended March 31, 2008 compared to $6.74 per MMBtu for the three months ended March 31, 2007. The average realized price for NGLs increased by $0.48 per gallon (net of a $0.02 decrease due to hedging), or 49%, to $1.45 per gallon for the three months ended March 31, 2008 compared to $0.97 per gallon for the three months ended March 31, 2007. The average realized price for condensate increased by $36.20 per barrel (net of a $3.80 decrease due to hedging), or 63%, to $93.36 per barrel for the three months ended March 31, 2008 compared to $57.16 per barrel for the three months ended March 31, 2007.

Natural gas sales volumes increased by 25.5 BBtu/d, or 5%, to 533.0 BBtu/d for the three months ended March 31, 2008 compared to 507.5 BBtu/d for the three months ended March 31, 2007. NGL sales volumes increased by 16.6 MBbl/d, or 6%, to 317.5 MBbl/d for the three months ended March 31, 2008 compared to 300.9 MBbl/d for the three months ended March 31, 2007. Condensate sales volumes increased by 0.3 MBbl/d, or 9%, to 3.6 MBbl/d for the three months ended March 31, 2008 compared to 3.3 MBbl per day for the three months ended March 31, 2007. For information regarding the period to period changes in our commodity sales volumes, see “Results of Operations—By Segment.”

Product purchases increased by $731.1 million, or 58%, to $2,001.4 million for the three months ended March 31, 2008 compared to $1,270.3 million for the three months ended March 31, 2007. The increase is primarily due to higher product purchases and prices in the Natural Gas Gathering and Processing, NGL Distribution and Marketing, and Wholesale Marketing segments.

Operating expenses increased by $5.7 million, or 10%, to $63.6 million for the three months ended March 31, 2008 compared to $57.9 million for the three months ended March 31, 2007. See “Results of Operations—By Segment” for a more detailed explanation of the components of the increase.

33

Depreciation and amortization expense increased by $1.5 million, or 4%, to $38.2 million for the three months ended March 31, 2008 compared to $36.7 million for the three months ended March 31, 2007. The increase is due to the addition of property, plant and equipment.

General and administrative expense increased by $5.4 million, or 29%, to $24.1 million for the three months ended March 31, 2008 compared to $18.7 million for the three months ended March 31, 2007. The increase primarily consisted of increases of $2.8 million in compensation related expenses and $3.2 million in professional services fees, partially offset by a decrease of $0.6 million in miscellaneous expenses.

Interest expense decreased by $18.4 million, or 42%, to $25.6 million for the three months ended March 31, 2008 compared to $44.0 million for the three months ended March 31, 2007. The decrease is primarily from lower company debt resulting from the retirement of the $700 million senior secured asset sale bridge loan facility in February 2007 and the retirement of $687.2 million of the variable rate senior secured term loan facility in October 2007, offset by $281.8 million in net borrowings under the Partnership’s revolving credit facility.

34

Results of Operations—By Segment

Natural Gas Gathering and Processing Segment

The following table provides summary financial data regarding results of operations in our Natural Gas Gathering and Processing segment for the periods presented:

	Three Months Ended March 31,
	2008			2007
	(In millions, except operating and price data)
Operating statistics: (1)
Gathering throughput, MMcf/d		2,175.2			1,976.7
Plant natural gas inlet, MMcf/d		2,143.1			1,937.8
Gross NGL production, MBbl/d		103.9			104.1
Natural gas sales, BBtu/d		550.2			521.4
NGL sales, MBbl/d		89.6			89.2
Condensate sales, MBbl/d		5.0			4.7
Natural gas, $/MMBtu
Average realized sales price		7.80			6.59
Impact of hedging		0.11			0.15
Average realized price		7.91			6.74
NGLs, $/gal
Average realized sales price		1.32			0.82
Impact of hedging		(0.06	)		0.02
Average realized price		1.26			0.84
Condensate, $/Bbl
Average realized sales price		87.28			51.30
Impact of hedging		(1.39	)		1.35
Average realized price		85.89			52.65
Revenues	$	873.2		$	622.8
Product purchases		(730.4	)		(502.5	)
Operating expenses		(30.2	)		(29.1	)
Operating margin (2)	$	112.6		$	91.2
General and administrative	$	11.9		$	9.4
Equity in earnings of unconsolidated investments (3)	$	2.4		$	1.2

(1) Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

(2) Please see “Non-GAAP Financial Measures”.

(3) Consists of earnings from our investment in VESCO.

Revenues increased $250.4 million, or 40%, to $873.2 million for the three months ended March 31, 2008 compared to $622.8 million for the three months ended March 31, 2007. This increase is primarily due to:

• an increase in realized commodity prices that increased revenues by $218.5 million, consisting of increases in natural gas, NGL and condensate revenues of $58.7 million, $144.9 million and $14.9 million, respectively;

• an increase attributable to volumes of $27.0 million, consisting of increases in natural gas, NGL and condensate volumes of $21.2 million, $4.4 million and $1.4 million, respectively; and

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• an increase in compression and gathering, processing and other services, which increased revenues by $4.9 million.

Our average realized price for natural gas increased $1.17 per MMBtu (net of a $0.04 decrease due to hedging), or 17%, to $7.91 per MMBtu for the three months ended March 31, 2008 compared to $6.74 per MMBtu for the three months ended March 31, 2007. Our average realized price for NGLs increased $0.42 per gallon (net of an $0.08 decrease due to hedging), or 50%, to $1.26 per gallon for the first three months of 2008 compared to $0.84 per gallon for the first three months of 2007. Our average realized price for condensate increased $33.24 per barrel (net of a $2.74 decrease due to hedging), or 63%, to $85.89 per barrel for the three months ended March 31, 2008 compared to $52.65 per barrel for the three months ended March 31, 2007.

Our natural gas sales volumes increased 28.8 BBtu/d, or 6%, to 550.2 BBtu/d for the three months ended March 31, 2008 compared to 521.4 BBtu/d for the three months ended March 31, 2007. The net increase is primarily due to increased demand by our industrial customers and reduced producers’ take-in-kind volumes.

Our NGL sales volumes increased 0.4 MBbl/d, or less than 1%, to 89.6 MBbl/d for the three months ended March 31, 2008 compared to 89.2 MBbl/d for the three months ended March 31, 2007. While we experienced increase volumes from field plant inlets, NGL volumes were relatively flat due to leaner liquids content from the incremental production delivered to our gas plants.

Our condensate sales volumes increased 0.3 MBbl/d, or 6%, to 5.0 MBbl/d for the three months ended March 31, 2008 compared to 4.7 MBbl/d for the three months ended March 31, 2007.

Product purchases increased $227.9 million, or 45%, to $730.4 million for the three months ended March 31, 2008 compared to $502.5 million for the three months ended March 31, 2007. The increase in product purchases for the three months ended March 31, 2008 was due primarily to increased purchases to meet industrial market demands, with a corresponding increase in plant natural gas inlet volumes and higher realized sales prices on which producer settlements are based.

Operating expenses increased $1.1 million, or 4%, to $30.2 million for the three months ended March 31, 2008 compared to $29.1 million for the three months ended March 31, 2007. This increase is primarily related to the increased compensation costs of field personnel.

General and administrative expense increased by $2.5 million, or 27%, to $11.9 million for three months ended March 31, 2008 compared to $9.4 million for the three months ended March 31, 2007. General and administrative expense for this segment is an allocation of corporate-level expenses, which were higher for the three months ended March 31, 2008.

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Logistics Assets Segment

The following table provides summary financial data regarding results of operations of our Logistics Assets segment for the periods presented:

	Three Months Ended March 31,
	2008			2007
	(In millions, except operating data)
Fractionation volumes, MBbl/d		215.9			162.8
Treating volumes, MBbl/d (1)		15.1			—
Revenues from services (2)	$	50.8		$	42.4
Other revenues		0.4			0.4
		51.2			42.8
Operating expenses		(44.3	)		(31.4	)
Operating margin (3)	$	6.9		$	11.4
General and administrative	$	5.0		$	3.4
Equity in earnings of unconsolidated investments (4)	$	1.1		$	1.3

(1) Consists of the gas volume treated in our low sulfur natural gasoline unit, which commenced commercial operations in June 2007 .

(2) Excludes intrasegment revenue earned from barge day-rates and pipeline transport fees.

(3) Please see “Non-GAAP Financial Measures”.

(4) Consists of earnings from our investment in GCF.

Our operating margin decreased $4.5 million due primarily to nonrecurring items which reduced revenues and increased operating expenses as discussed below.

Revenues from services (fractionation, terminalling and storage, transportation and treating) increased $8.4 million, or 20%, to $50.8 million for the three months ended March 31, 2008 compared to $42.4 million for the three months ended March 31, 2007. Revenues were increased by higher fractionation volumes, higher fractionation rates, and treating revenue from our low-sulfur natural gasoline unit which commenced commercial operations in June 2007, partially offset by a planned maintenance outage at our Cedar Bayou fractionator and lower overall transportation revenue. Our fractionation facilities operated at 76% of design capacity for the three months ended March 31, 2008 and 59% during the same period in 2007.

Operating expenses increased $12.9 million, or 41%, to $44.3 million for the three months ended March 31, 2008 compared to $31.4 million for the three months ended March 31, 2007. This increase is primarily due to well emptying gains that lowered prior year expenses, increased fuel expense due to higher fuel prices and higher fractionation volumes, increased planned maintenance costs including the Cedar Bayou turnaround; and the operating costs of our low-sulfur natural gasoline unit.

General and administrative expense increased by $1.6 million, or 47%, to $5.0 million for the three months ended March 31, 2008 compared to $3.4 million for the three months ended March 31, 2007. General and administrative expense for this segment is an allocation of corporate-level expenses, which were higher for the three months ended March 31, 2008.

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NGL Distribution and Marketing Services Segment

The following table provides summary financial data regarding results of operations of our NGL Distribution and Marketing Services segment for the periods presented:

	Three Months Ended March 31,
	2008			2007
	(In millions, except operating and price data)
NGL sales, MBbl/d		262.2			252.3
NGL realized price, $/gal		1.42			0.92
NGL sales revenues	$	1,418.8		$	881.3
Other revenues		0.8			1.0
		1,419.6			882.3
Product purchases		(1,410.8	)		(870.0	)
Operating expenses		(0.5	)		(0.6	)
Operating margin (1)	$	8.3		$	11.7
General and administrative	$	2.8		$	1.8

(1) Please see “Non-GAAP Financial Measures”.

Our operating margin decreased by $3.4 million, or 29%, to $8.3 million for the three months ended March 31, 2008 compared to $11.7 million for the three months ended March 31, 2007. The decrease in operating margin was due to falling prices during the three months ended March 31, 2008, which reduced margins. We also had a inventory lower of cost or market adjustment of $1.7 million.

Revenues increased $537.3 million, or 61%, to $1,419.6 million for the three months ended March 31, 2008 compared to $882.3 million for the three months ended March 31, 2007. The net increase primarily comprised a $492.8 million increase due to higher commodity compared to the prior period prices and a $44.8 million increase as a result of higher sales volumes.

NGL sales volumes increased 9.9 MBbl/d, or 4%, to 262.2 MBbl/d for the three months ended March 31, 2008 compared to 252.3 MBbl/d for the three months ended March 31, 2007. The increase in sales volumes was primarily attributable to new and existing term contracts for NGL production from gas plants.

Our average realized price for NGLs increased $0.50 per gallon, or 54%, to $1.42 per gallon for the three months ended March 31, 2008 compared to $0.92 per gallon for the three months ended March 31, 2007, as a result of higher commodity prices for three months ended March 31, 2008.

General and administrative expense increased by $1.0 million, or 56%, to $2.8 million for the three months ended March 31, 2008 compared to $1.8 million for the three months ended March 31, 2007. General and administrative expense for this segment is an allocation of corporate-level expenses, which were higher for the three months ended March 31, 2008.

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Wholesale Marketing Segment

The following table provides summary financial data regarding results of operations of our Wholesale Marketing segment for the periods presented:

	Three Months Ended March 31,
	2008			2007
	(In millions, except operating and price data)
NGL sales, MBbl/d		86.9			80.5
NGL realized price, $/gal		1.64			1.12
NGL sales revenues	$	543.3		$	341.9
Other revenues		—			0.2
		543.3			342.1
Product purchases		(533.7	)		(335.6	)
Operating expenses		—			—
Operating margin (1)	$	9.6		$	6.5
General and administrative	$	4.2		$	3.1

(1) Please see “Non-GAAP Financial Measures”.

Our operating margin increased by $3.1 million, or 48%, to $9.6 million for the three months ended March 31, 2008 compared to $6.5 million for the three months ended March 31, 2007. The increase is primarily due to higher market prices realized on the sale of seasonal inventory.

Revenues increased $201.2 million, or 59%, to $543.3 million for the three months ended March 31, 2008 compared to $342.1 million for the three months ended March 31, 2007. The increase in revenues consists of increases of $31.3 million due to higher sales volumes and $170.1 million due to higher realized commodity prices, partially offset by a decrease of $0.2 million in non-commodity, fee-based service revenue.

The increase in average realized prices is primarily attributable to higher market prices for the three months ended March 31, 2008, combined with a different mix of products sold that had higher value.”

NGL sales volumes increased by 6.4 MBbl/d, or 8%, to 86.9 MBbl/d for the three months ended March 31, 2008 compared to 80.5 MBbl/d for the three months ended March 31, 2007. The volume increase for the three months ended March 31, 2008 is primarily due to third party refineries undergoing major maintenance during the three months ended March 31, 2007 and new supply contracts that began during the second quarter of 2007.

General and administrative expense increased by $1.1 million, or 35%, to $4.2 million for the three months ended March 31, 2008 compared to $3.1 million for the three months ended March 31, 2007. General and administrative expense for this segment is an allocation of corporate-level expenses, which were higher for the three months ended March 31, 2008.

Hurricane Update

Certain of our Louisiana and Texas facilities sustained damage during the 2005 hurricane season from two Gulf Coast hurricanes—Katrina and Rita. Repairs at all of our plant facilities other than VESCO which will be completed in the third quarter of 2008, have been completed.

We have submitted and continue to submit business interruption insurance claims for our estimated losses caused by the hurricanes. We recognize income from business interruption insurance claims in our consolidated statements of operations and comprehensive income in the period that a proof of loss is executed and submitted to the insurers for payment. This income recognition criterion has resulted in and will likely continue to result in business interruption insurance recoveries being recorded in periods subsequent to the periods that we experience

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lost income from the affected property, resulting in fluctuations in our net income that may reduce the comparability of reported quarterly and annual results for some periods into the future.

Our property damages insurance recoveries were $7.8 million for the three months ended March 31, 2008.

During April 2008, we received approximately $40 million and $22 million related to property damage and business interruption insurance claims, respectively, most of which was in connection with the final settlement of our claims related to Katrina under the onshore property insurance program. Our initial purchase price allocation for the DMS acquisition in October 2005 included an $81.1 million receivable for insurance claims related to expenditures to repair pre-acquisition property damage caused by hurricanes Katrina and Rita. We will recognize a gain of approximately $19 million related to property damage payments, because cumulative receipts have exceeded the amount of the receivable recorded as part of the DMS acquisition purchase price allocation.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. See “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Historically, our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow and borrowings available under our senior secured credit facilities should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, hurricane-related repair expenditures, long-term indebtedness obligations and collateral requirements for at least the next twelve months.

A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of March 31, 2008, total outstanding letter of credit postings by us and the Partnership were $284.3 million and $38.5 million, respectively.

Cash Flow

Net cash provided by or used in operating activities, investing activities and financing activities for the periods presented were as follows:

	Three Months Ended March 31,
	2008			2007
	(In millions)
Net cash provided by (used in):
Operating activities	$	222.0		$	121.0
Investing activities		(15.2	)		(34.1	)
Financing activities		(106.0	)		(32.6	)

Operating Activities

Net cash provided by operating activities was $222.0 million for the three months ended March 31, 2008 compared to $121.0 million for the three months ended March 31, 2007. Changes in operating assets and

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liabilities provided $151.7 million in cash during the three months ended March 31, 2008, compared to providing $66.7 million in cash during the three months ended March 31, 2007. The difference resulted primarily from the increase in accounts receivable due to higher commodity prices in the three months ended March 31, 2008 and a decrease of accounts payable as inventory volumes were liquidated.

Investing Activities

Net cash used in investing activities was $15.2 million for the three months ended March 31, 2008 compared to $34.1 million for the three months ended March 31, 2007. The $18.9 million decrease is primarily due to the timing of gathering system expansion projects and nonrecurring capital projects during 2007, primarily related to our low sulfur natural gasoline project and hurricane-related repair.

Financing Activities

Net cash used in financing activities was $106.0 million for the three months ended March 31, 2008 compared to $32.6 million for the three months ended March 31, 2007. During the three months ended March 31, 2008, we paid $53.1 million to retire debt and made cash distributions of $52.9 million to Targa Investments.

As of March 31, 2008, the Partnership had approximately $135.2 million in capacity available under its revolving credit facility, after giving effect to outstanding borrowings of $576.3 million and the issuance of $38.5 million of letters of credit.

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Non-GAAP Financial Measures

For a complete discussion of the measures that management uses to evaluate our operations, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate our Operations” in our Annual Report on Form 10-K for the year ended December 31, 2007. The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the three months ended March 31, 2008 and 2007:

Our operating margin by segment and in total is as follows for the periods indicated:

	Three Months Ended March 31,
	2008		2007
	(In millions)
Natural Gas Gathering and Processing	$	112.6	$	91.2
Logistics Assets		6.9		11.4
NGL Distribution and Marketing Services		8.3		11.7
Wholesale Marketing		9.6		6.5
	$	137.4	$	120.8

	Three Months Ended March 31,
	2008		2007
	(In millions)
Reconciliation of Operating Margin to net income:
Net income	$	18.4	$	9.5
Add:
Depreciation and amortization		38.2		36.7
Income tax expense		11.9		7.2
Other, net		19.2		4.7
Interest expense, net		25.6		44.0
General and administrative		24.1		18.7
Operating Margin	$	137.4	$	120.8

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	Three Months Ended March 31,
	2008			2007
	(In millions)
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	222.0		$	121.0
Interest expense, net		25.6			44.0
Amortization of debt issue costs		2.0			7.2
Current income tax expense		1.0			—
Changes in operating working capital which used (provided) cash:
Accounts receivable and other assets		(209.7	)		(42.1	)
Inventory		(63.2	)		(53.2	)
Accounts payable and other liabilities		121.2			28.6
Non-cash gain related to derivative instruments		(2.2	)		(6.7	)
Other, net		(4.8	)		(8.1	)
Adjusted EBITDA	$	91.9		$	90.7
Reconciliation of Adjusted EBITDA to net income:
Net income	$	18.4		$	9.5
Add:
Interest expense, net		25.6			44.0
Income tax expense		11.9			7.2
Depreciation and amortization		38.2			36.7
Non-cash gain related to derivative instruments		(2.2	)		(6.7	)
Adjusted EBITDA	$	91.9		$	90.7

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, changes in interest rates, as well as nonperformance by our customers. We do not use risk sensitive instruments for trading purposes.

Commodity Price Risk

A significant portion of our revenues is derived from percent-of-proceeds contracts under which we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. For an in-depth discussion of our hedging strategies, see Item “7A. Quantitative and Qualitative Disclosure about Market Risk—Commodity Price Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.

For the three months ended March 31, 2008, net hedging activities decreased our operating revenues by $16.2 million. At March 31, 2008, we had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from April 1, 2008 through December 31, 2008):

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Natural Gas Sales
Swap	IF-Waha	6.96	21,918	—	—	—	—	$	(15,585	)
Swap	IF-Waha	6.62	—	21,918	—	—	—		(18,096	)
Swap	IF-Waha	7.40	—	—	9,300	—	—		(3,202	)
Swap	IF-Waha	7.36	—	—	—	5,500	—		(1,436	)
Swap	IF-Waha	7.18	—	—	—	—	5,500		(1,651	)
			21,918	21,918	9,300	5,500	5,500	$	(39,970	)

NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	0.80	3,547	—	—	—	—	$	(22,078	)
Swap	OPIS-MB	0.79	—	3,347	—	—	—		(21,218	)
Swap	OPIS-MB	0.87	—	—	2,750	—	—		(9,597	)
Swap	OPIS-MB	0.91	—	—	—	1,550	—		(4,312	)
Swap	OPIS-MB	0.92	—	—	—	—	1,250		(3,169	)
			3,547	3,347	2,750	1,550	1,250	$	(60,374	)

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As of March 31, 2008, the Partnership had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from April 1, 2008 through December 31, 2008.):

Natural Gas

	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
Instrument Type			2008	2009	2010	2011	2012
Natural Gas Purchases
Swap	NY-HH	8.42	1,552	—	—	—	—	$	775
Total Swaps			1,552	—	—	—	—		775
Natural Gas Sales
Swap	IF-HSC	8.09	2,328	—	—	—	—		(1,235	)
Swap	IF-HSC	7.39	—	1,966	—	—	—		(1,420	)
			2,328	1,966	—	—	—		(2,655	)
Swap	IF-NGPL MC	8.43	6,964	—	—	—	—		(1,182	)
Swap	IF-NGPL MC	8.02	—	6,256	—	—	—		(1,352	)
Swap	IF-NGPL MC	7.43	—	—	5,685	—	—		(1,538	)
Swap	IF-NGPL MC	7.34	—	—	—	2,750	—		(713	)
Swap	IF-NGPL MC	7.18	—	—	—	—	2,750		(820	)
			6,964	6,256	5,685	2,750	2,750		(5,605	)
Swap	IF-Waha	8.20	7,389	—	—	—	—		(2,754	)
Swap	IF-Waha	7.61	—	6,936	—	—	—		(3,339	)
Swap	IF-Waha	7.38	—	—	5,709	—	—		(2,017	)
Swap	IF-Waha	7.36	—	—	—	3,250	—		(848	)
Swap	IF-Waha	7.36	—	—	—	—	3,250		(976	)
			7,389	6,936	5,709	3,250	3,250		(9,934	)
Total Swaps			16,681	15,158	11,394	6,000	6,000		(18,194	)
Floor	IF-NGPL MC	6.55	1,000	—	—	—	—		115
Floor	IF-NGPL MC	6.55	—	850	—	—	—		25
			1,000	850	—	—	—		140
Floor	IF-Waha	6.85	670	—	—	—	—		75
Floor	IF-Waha	6.55	—	565	—	—	—		7
			670	565	—	—	—		82
Total Floors			1,670	1,415	—	—	—		222
Basis Swap Apr 2008 receive GD-HH, pay IF-HH, 120,000 MMBtu									—
								$	(17,197	)

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NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	1.02	7,110	—	—	—	—	$	(29,293	)
Swap	OPIS-MB	0.96	—	6,248	—	—	—		(27,281	)
Swap	OPIS-MB	0.91	—	—	4,809	—	—		(15,978	)
Swap	OPIS-MB	0.92	—	—	—	3,400	—		(10,417	)
Swap	OPIS-MB	0.92	—	—	—	—	2,700		(7,596	)
			7,110	6,248	4,809	3,400	2,700	$	(90,565	)

Condensate

Instrument Type	Index	Avg. Price $/Bbl	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Condensate Sales
Swap	NY-WTI	68.34	384	—	—	—	—	$	(3,016	)
Swap	NY-WTI	69.00	—	322	—	—	—		(3,002	)
Swap	NY-WTI	68.10	—	—	301	—	—		(2,641	)
Total Swaps			384	322	301	—	—		(8,659	)
Floor	NY-WTI	60.50	55	—	—	—	—		21
Floor	NY-WTI	60.00	—	50	—	—	—		(10	)
Total Floors			55	50	—	—	—		11
			439	372	301	—	—	$	(8,648	)

These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

Interest Rate Risk

We are exposed to changes in interest rates primarily as a result of variable rate debt under our credit facilities. To the extent that interest rates increase, interest expense on our revolving debt will also increase. As of March 31, 2008, we had approximately $1,358 million of indebtedness, of which $250 million was at fixed interest rates and $1,108 million was at variable interest rates. Because of the interest rate risk, in addition to the $200 million in interest rate swaps that the Partnership had at December 31, 2007, the Partnership entered into an additional $100 million in interest rate swaps during the three months ended March 31, 2008 to reduce this risk, as shown below:

Trade Date	Term	From	To	Fixed Rate		Notional Amount
						(In thousands)
01/07/08	4 years	01/09/08	1/24/12	3.70	%	$	50,000
01/09/08	4 years	01/11/08	1/24/12	3.64	%		50,000

Each swap fixes the three month LIBOR rate, at the indicated rates for the specified amounts of related debt outstanding over the term of each swap agreement. We have designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in OCI until the

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interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account the rate swaps, would increase our annual interest expense by $8.1 million.

Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.

Item 4T. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective at a reasonable assurance level to provide reasonable assurance that all material information relating to us required to be included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. There has been no change in our internal control over financial reporting during the three months ended March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The information required for this item is provided in Note 10, Commitments and Contingencies included in the notes to the consolidated financial statements included under Part I, Item 1, which is incorporated by reference into this item.

Item 1A. Risk Factors

For an in-depth discussion of our risk factors, see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. There have been no material changes to the risk factors included in “Item 1A.” of our Annual Report on Form 10-K for the year ended December 31, 2007.

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

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

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

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibit Number		Description
3.1	—	Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.2	—	Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.3	—	Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.4	—	Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.5	—	Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
31.1*	—	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

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SIGNATURES

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

Targa Resources, Inc. (Registrant)
By:	/s/    JOHN ROBERT SPARGER
	John Robert Sparger
	Senior Vice President
	and Chief Accounting Officer
	(Authorized signatory and Principal Accounting Officer)

Date: May 14, 2008

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Exhibit Index

Exhibit Number		Description
3.1	—	Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.2	—	Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.3	—	Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.4	—	Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.5	—	Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
31.1*	—	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	—	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

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