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form10q.htm

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 June 30, 2010

¨ 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 PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	65-1295427 (I.R.S. Employer Identification No.)
1000 Louisiana, Suite 4300, Houston, Texas (Address of principal executive offices)	77002 (Zip Code)

(713) 584-1000

(Registrant’s telephone number, including area code)

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.

þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

¨ Yes ¨ 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.

Large accelerated filer	¨	Accelerated filer	þ
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	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 þ No

As of August 1, 2010, there were 67,980,596 Common Units and 1,387,360 General Partner Units outstanding.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements.	4

	Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	4

	Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009	5

	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2010 and 2009	7

	Consolidated Statement of Changes in Owners' Equity for the six months ended June 30, 2010	7

	Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009	8

	Notes to Consolidated Financial Statements	9

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations.	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	41

Item 4.	Controls and Procedures.	45

PART II—OTHER INFORMATION

Item 1.	Legal Proceedings.	47

Item 1A.	Risk Factors.	47

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	48

Item 3.	Defaults Upon Senior Securities.	48

Item 4.	(Removed and Reserved).	48

Item 5.	Other Information.	48

Item 6.	Exhibits.	49

SIGNATURES

Signatures		51

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

Bbl			Barrels
BBtu			Billion British thermal units
Btu			British thermal units, a measure of heating value
/d			Per day
gal			Gallons
MBbl			Thousand barrels
Mcf			Thousand cubic feet
MMBbl			Million barrels
MMBtu			Million British thermal units
MMcf			Million cubic feet
NGL(s)			Natural gas liquid(s)

Price Index Definitions

IF-NGPL MC			Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha			Inside FERC Gas Market Report, West Texas Waha
IF-PB			Inside FERC Gas Market Report, Permian Basin
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, “we,” “us,” “our,” the “Partnership” and similar terms refer to Targa Resources Partners LP, together with its consolidated subsidiaries.

Cautionary Statement About Forward-Looking Statements

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” as well as the following:

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

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

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

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the level of creditworthiness of counterparties to transactions;

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

the timing and extent of changes in natural gas, natural gas liquids and other 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;

the level and success of crude oil and natural gas drilling around our assets and our success in connecting natural gas supplies to our gathering and processing systems and NGL supplies to our logistics and marketing facilities;

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

general economic, market and business conditions; and

the risks described in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2009 (the “Annual Report”).

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 in “Item 1A. Risk Factors” in this Quarterly Report and our Annual Report. 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.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
	June 30,			December 31,
	2010			2009
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	43.7		$	60.4
Trade receivables, net of allowances of $7.6 million and $7.9 million		317.6			387.8
Inventory		48.7			39.1
Assets from risk management activities		35.8			28.2
Other current assets		0.8			1.6
Total current assets		446.6			517.1
Property, plant and equipment, at cost		2,526.4			2,488.5
Accumulated depreciation		(569.1	)		(504.9	)
Property, plant and equipment, net		1,957.3			1,983.6
Long-term assets from risk management activities		20.7			10.9
Investment in unconsolidated affiliate		19.2			18.5
Other long-term assets		18.7			20.6
Total assets	$	2,462.5		$	2,550.7

LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable to third parties	$	129.5		$	173.5
Accounts payable to affiliates		33.7			57.9
Accrued liabilities		230.3			217.4
Liabilities from risk management activities		12.0			22.1
Total current liabilities		405.5			470.9
Long-term debt payable to third parties		1,159.4			908.4
Long-term debt payable to Targa Resources, Inc.		-			327.0
Long-term liabilities from risk management activities		18.7			35.5
Deferred income taxes		4.8			5.8
Other long-term liabilities		18.2			18.4

Commitments and contingencies (see Note 10)

Owners' equity:
Common unitholders (67,922,853 and 61,597,853 units issued and
outstanding as of June 30, 2010 and December 31, 2009)		821.0			850.5
General partner (1,387,360 and 1,257,957 units issued and
outstanding as of June 30, 2010 and December 31, 2009)		10.3			10.1
Net parent investment		-			(51.5	)
Accumulated other comprehensive income (loss)		10.5			(37.8	)
		841.8			771.3
Noncontrolling interest in subsidiary		14.1			13.4
Total owners' equity		855.9			784.7
Total liabilities and owners' equity	$	2,462.5		$	2,550.7

See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(Unaudited)
	(In millions)
Revenues from third parties	$	1,204.0		$	978.7		$	2,648.9		$	1,948.8
Revenues from affiliates		-			0.5			0.1			15.9
Total operating revenues		1,204.0			979.2			2,649.0			1,964.7
Product purchases from third parties		963.3			774.2			2,154.8			1,563.6
Product purchases from affiliates		98.8			64.9			207.0			140.3
Operating expenses		49.4			46.9			100.4			99.2
Depreciation and amortization expenses		32.7			30.6			64.3			60.8
General and administrative expenses		24.0			28.9			45.3			50.0
Casualty loss adjustment		-			(0.7	)		-			(0.7	)
Income from operations		35.8			34.4			77.2			51.5
Other income (expense):
Interest expense from affiliate		-			(20.7	)		(5.7	)		(41.3	)
Other interest expense, net		(17.7	)		(9.7	)		(33.1	)		(19.2	)
Equity in earnings of unconsolidated investment		2.4			1.7			2.7			1.8
Gain (loss) on mark-to-market derivative instruments		1.1			(9.2	)		11.1			(3.8	)
Other		-			-			-			0.7
		(14.2	)		(37.9	)		(25.0	)		(61.8	)
Income (loss) before income taxes		21.6			(3.5	)		52.2			(10.3	)
Income tax (expense) benefit:
Current		(1.0	)		(0.2	)		(1.8	)		(0.3	)
Deferred		0.1			(0.4	)		(0.6	)		(0.8	)
		(0.9	)		(0.6	)		(2.4	)		(1.1	)
Net income (loss)		20.7			(4.1	)		49.8			(11.4	)
Less: Net income attributable to noncontrolling interest		0.9			0.4			1.2			0.3
Net income (loss) attributable to Targa Resources Partners LP	$	19.8		$	(4.5	)	$	48.6		$	(11.7	)

Net income (loss) attributable to predecessor operations	$	-		$	(11.0	)	$	16.3		$	(16.1	)
Net income attributable to general partner		3.9			2.0			7.0			3.9
Net income allocable to limited partners		15.9			4.5			25.3			0.5
Net income (loss) attributable to Targa Resources Partners LP	$	19.8		$	(4.5	)	$	48.6		$	(11.7	)

Net income per limited partner unit - basic and diluted	$	0.23		$	0.10		$	0.37		$	0.01
Weighted average limited partner units outstanding - basic and diluted		68.0			46.2			67.7			46.2

See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(Unaudited)
	(In millions)

Net income (loss)	$	20.7		$	(4.1	)	$	49.8		$	(11.4	)
Other comprehensive income (loss):
Commodity hedges:
Change in fair value		26.3			(35.2	)		60.0			(20.9	)
Reclassification adjustment for settled periods		(2.9	)		(13.3	)		0.1			(19.9	)
Interest rate hedges:
Change in fair value		(10.1	)		8.2			(16.8	)		4.5
Reclassification adjustment for settled periods		3.4			2.6			5.0			5.1
Foreign currency translation adjustment		-			0.7			-			0.5
Other comprehensive income (loss)		16.7			(37.0	)		48.3			(30.7	)
Comprehensive income (loss)		37.4			(41.1	)		98.1			(42.1	)
Less: Comprehensive income attributable to noncontrolling interest		0.9			0.4			1.2			0.3
Comprehensive income (loss) attributable to Targa Resources Partners LP	$	36.5		$	(41.5	)	$	96.9		$	(42.4	)

See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY

							Accumulated
							Other			Net
	Limited			General			Comprehensive			Parent			Noncontrolling
	Partners			Partner			Income			Investment			Interest			Total
	(Unaudited)
	(In millions)
Balance, December 31, 2009	$	850.5		$	10.1		$	(37.8	)	$	(51.5	)	$	13.4		$	784.7
Issuance of common units:
Equity offering		139.7			3.0			-			-			-			142.7
Distribution to Parent		-			-			-			(87.2	)		-			(87.2	)
Distributions under common control		(124.3	)		(2.6	)		-			122.4			-			(4.5	)
Distributions to noncontrolling interest		-			-			-			-			(0.5	)		(0.5	)
Amortization of equity awards		0.2			-			-			-			-			0.2
Other comprehensive income		-			-			48.3			-			-			48.3
Net income		25.3			7.0			-			16.3			1.2			49.8
Distributions to unitholders		(70.4	)		(7.2	)		-			-			-			(77.6	)
Balance, June 30, 2010	$	821.0		$	10.3		$	10.5		$	-		$	14.1		$	855.9

See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended
	June 30,
	2010			2009
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income (loss)	$	49.8		$	(11.4	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Amortization in interest expense		2.7			1.3
Amortization in general and administrative expense		0.2			0.2
Depreciation and amortization expenses		64.3			60.8
Interest expense on affiliate indebtedness		5.7			41.3
Accretion of asset retirement obligations		0.7			0.6
Deferred income tax expense		0.6			0.8
Equity in earnings of unconsolidated investment, net of distributions		(0.7	)		(1.0	)
Risk management activities		5.7			41.7
Loss (gain) on sale of assets		(0.1	)		0.2
Changes in operating assets and liabilities:
Receivables and other assets		68.9			(17.5	)
Inventory		(10.1	)		28.7
Accounts payable and other liabilities		(57.8	)		27.1
Net cash provided by operating activities		129.9			172.8
Cash flows from investing activities
Outlays for property, plant and equipment		(37.9	)		(46.0	)
Other, net		0.6			-
Net cash used in investing activities		(37.3	)		(46.0	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		635.8			-
Repayments of credit facility		(385.2	)		(40.0	)
Repayment of affiliated indebtedness		(332.8	)		-
Parent distribution		(87.2	)		-
Proceeds from equity offerings		139.7			-
General partner contributions		3.0			-
Distributions to unitholders		(77.6	)		(52.7	)
Distributions under common control		(4.5	)		(79.1	)
Distributions to noncontrolling interest		(0.5	)		(0.9	)
Net cash used in financing activities		(109.3	)		(172.7	)
Net change in cash and cash equivalents		(16.7	)		(45.9	)
Cash and cash equivalents, beginning of period		60.4			95.3
Cash and cash equivalents, end of period	$	43.7		$	49.4

See notes to consolidated financial statements

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Targa Resources Partners LP

Notes to Consolidated Financial Statements

(Unaudited)

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1—Organization and Operations

Targa Resources Partners LP, is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis.

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”). We report our results of operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two segments – (a) Logistics Assets and (b) Marketing and Distribution.

Our gathering and processing assets are located in the Fort Worth Basin/Bend Arch in North Texas, the Permian Basin in West Texas and the onshore and offshore coastal regions of Louisiana.

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 U.S. See Note 13.

Targa Resources GP LLC is a Delaware single-member limited liability company formed in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa. As of June 30, 2010, Targa and its subsidiaries own an 18.7% interest in the Partnership in the form of 1,387,360 general partner units and 11,555,846 common units.

We acquired from Targa its ownership interests in the following assets, liabilities and operations on the dates indicated:

February 14, 2007 – North Texas System

October 24, 2007 – San Angelo (“SAOU”) System and Louisiana (“LOU”) System

September 24, 2009 – Downstream Business

April 27, 2010 – Permian and Straddle Systems (See Note 4)

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions collectively as our “predecessors.”

Note 2—Basis of Presentation

We have prepared these unaudited consolidated financial statements 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. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for

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annual periods. The unaudited consolidated financial statements for the three and six months ended June 30, 2010 and 2009 include all adjustments and disclosures which we believe are necessary for a fair presentation of the results for the interim periods.

We are required by GAAP to record the acquisitions described in Note 1 based on Targa historical amounts, assuming that the acquisitions occurred at the date they qualified as entities under common control (October 31, 2005) following the acquisition of the SAOU and LOU System. We recognize the difference between our acquisition cost and the Targa basis in the net assets as an adjustment to owners’ equity. We have retrospectively adjusted the financial statements, footnotes and other financial information presented for any period affected by common control accounting to reflect the results of the combined entities.

We have prepared the separate financial results of our predecessors from the records maintained by Targa and eliminated all significant intercompany transactions. We have included allocations of corporate general and administrative expense, interest expense and the financial effects of certain commodity derivative contracts. Transactions among us and other Targa operations have been identified in the consolidated financial statements as transactions among affiliates. The consolidated financial results of our predecessors may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as unaffiliated entities.

Our financial results for the six months ended June 30, 2010 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2010. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.

Note 3—Accounting Policies and Related Matters

Accounting Policy Updates/Revisions

The accounting policies followed by the us are set forth in Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2009, and are supplemented by the notes to these consolidated financial statements. There have been no significant changes to these policies.

Accounting Pronouncements Recently Adopted

In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures About Fair Value Measurements,” which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. We adopted the revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, on January 1, 2010. The amendments to Level 3 disclosures were delayed until periods beginning after December 15, 2010 and are not anticipated to have a material impact on our financial statements upon adoption.

Note 4—Acquisitions

On April 27, 2010, we acquired Targa’s interests in its Permian and Straddle Systems for $420.0 million, effective April 1, 2010. We financed this acquisition substantially through borrowings under our senior secured revolving credit facility. The total consideration was used to repay $332.8 million of outstanding affiliated indebtedness, with the remaining $87.2 million reported as a distribution to our parent.

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This acquisition is reflected in these financial statements as a transfer of assets under common control. The following tables present the impact of combining the Permian and Straddle Systems on our consolidated financial position and consolidated results of operations for the dates and periods indicated:

	December 31, 2009
	Historical		Permian
	Targa		and						Targa
	Resources		Straddle						Resources
	Partners LP		Systems			Eliminations			Partners LP
Current assets	$	455.0	$	112.0		$	(49.9	)	$	517.1
Property, plant and equipment, net		1,678.5		305.1			-			1,983.6
Other assets		47.4		2.6			-			50.0
Total assets	$	2,180.9	$	419.7		$	(49.9	)	$	2,550.7

Current liabilities	$	395.9	$	124.9		$	(49.9	)	$	470.9
Long-term debt		908.4		327.0			-			1,235.4
Other long-term liabilities		40.4		19.3			-			59.7

Owners of Targa Resources Partners LP		822.8		-			-			822.8
Net parent investment		-		(51.5	)		-			(51.5	)
Noncontrolling interest in subsidiary		13.4		-			-			13.4
Total owners' equity		836.2		(51.5	)		-			784.7
Total liabilities and owners' equity	$	2,180.9	$	419.7		$	(49.9	)	$	2,550.7

	Three Months Ended June 30, 2009
	Historical			Permian
	Targa			and						Targa
	Resources			Straddle						Resources
	Partners LP			Systems			Eliminations			Partners LP
Revenues	$	916.3		$	216.5		$	(153.6	)	$	979.2
Costs and expenses:
Product purchases		791.3			195.0			(147.2	)		839.1
Operating expenses		45.6			7.7			(6.4	)		46.9
Depreciation and amortization expense		25.1			5.5			-			30.6
General and administrative expense and other		21.6			6.6			-			28.2
		883.6			214.8			(153.6	)		944.8
Income from operations		32.7			1.7			-			34.4
Other income (expense):
Interest expense		(24.5	)		(5.9	)		-			(30.4	)
Other income (expense)		1.6			(9.1	)		-			(7.5	)
Income tax expense		(0.5	)		(0.1	)		-			(0.6	)
Net income (loss)		9.3			(13.4	)		-			(4.1	)
Less: Net income attributable to noncontrolling interest		0.4			-			-			0.4
Net income (loss) attributable to Targa Resources Partners LP	$	8.9		$	(13.4	)	$	-		$	(4.5	)

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	Six Months Ended June 30, 2009
	Historical			Permian
	Targa			and						Targa
	Resources			Straddle						Resources
	Partners LP			Systems			Eliminations			Partners LP
Revenues	$	1,832.3		$	431.2		$	(298.8	)	$	1,964.7
Costs and expenses:
Product purchases		1,598.9			391.0			(286.0	)		1,703.9
Operating expenses		94.6			17.4			(12.8	)		99.2
Depreciation and amortization expense		49.9			10.9			-			60.8
General and administrative expense and other		37.5			11.8			-			49.3
		1,780.9			431.1			(298.8	)		1,913.2
Income from operations		51.4			0.1			-			51.5
Other income (expense):
Interest expense		(49.0	)		(11.5	)		-			(60.5	)
Other income (expense)		2.5			(3.8	)		-			(1.3	)
Income tax expense		(1.0	)		(0.1	)		-			(1.1	)
Net income (loss)		3.9			(15.3	)		-			(11.4	)
Less: Net income attributable to noncontrolling interest		0.3			-			-			0.3
Net income (loss) attributable to Targa Resources Partners LP	$	3.6		$	(15.3	)	$	-		$	(11.7	)

Note 5—Property, Plant and Equipment

Property, plant and equipment, at cost, were as follows as of the dates indicated:

	June 30,		December 31,		Estimated useful lives
	2010		2009		(In years)
Natural gas gathering systems	$	1,457.5	$	1,437.2	5 to 20
Processing and fractionation facilities		558.4		555.7	5 to 25
Terminalling and natural gas liquids storage facilities		239.6		238.5	5 to 25
Transportation assets		166.6		165.5	10 to 25
Other property, plant and equipment		26.8		26.4	3 to 25
Land		50.2		50.0		-
Construction in progress		27.3		15.2		-
	$	2,526.4	$	2,488.5

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Note 6—Debt Obligations

Consolidated debt obligations consisted of the following as of the dates indicated:

	June 30,			December 31,
	2010			2009
Senior secured revolving credit facility, variable rate, due February 2012	$	729.8		$	479.2
Senior unsecured notes, 8¼% fixed rate, due July 2016		209.1			209.1
Senior unsecured notes, 11¼% fixed rate, due July 2017		231.3			231.3
Unamortized discounts, net of premiums		(10.8	)		(11.2	)
Targa Permian LP:
Note payable to Parent, 10% fixed rate		-			170.2
Targa Straddle LP:
Note payable to Parent, 10% fixed rate		-			156.8
	$	1,159.4		$	1,235.4

Letters of credit issued	$	115.6		$	108.4

As of June 30, 2010, availability under our senior secured revolving credit facility was $113.1 million, after giving effect to $115.6 million in outstanding letters of credit and an unfunded commitment of $19.0 million due to a default by Lehman Bank in 2008. We have an additional $22.5 million of uncommitted borrowing capacity under our senior secured revolving credit facility.

The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations during the six months ended June 30, 2010:

	Range of interest	Weighted average
	rates paid	interest rate paid
Senior secured revolving credit facility	1.2% to 3.5%		1.4%

Compliance with Debt Covenants

As of June 30, 2010, we are in compliance with the covenants contained in our various debt agreements.

Affiliated Indebtedness

On January 1, 2007, Targa contributed to the Permian and Straddle predecessor businesses affiliated indebtedness applicable to each of these businesses. Our acquisition of the Permian and Straddle Systems has been treated as a transfer between entities under common control and periods prior to the transfer have been adjusted to present comparative information.

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The following table summarizes the financial effects of this affiliated indebtedness related to our acquisition of the Permian and Straddle Systems:

	Permian and
	Straddle
	Systems
Original principal December 1, 2005	$	232.2
Interest accrued during 2005 and 2006		25.1
Parent debt contributed January 1, 2007		257.3
Interest accrued prior to Targa conveyance:
For the year ended December 31, 2007		23.2
For the year ended December 31, 2008		23.3
For the year ended December 31, 2009		23.3
For the period ended March 31, 2010		5.7
		75.5
Outstanding affiliate debt at conveyance date		332.8
Cash payment		(332.8	)
Affiliate debt liquidated at conveyance date	$	-

Subsequent event. On July 19, 2010, we entered into an Amended and Restated Credit Agreement that replaced our existing variable rate Senior Secured Credit Facility with a new variable rate Senior Secured Credit Facility due July 2015. The new Senior Secured Credit Facility increases available commitments to $1.1 billion, with an option to increase the Senior Secured Credit Facility by an additional $300 million. The Amended and Restated Credit Agreement increased our availability by $141.5 million.

The new credit facility bears interest at LIBOR plus an applicable margin ranging from 2.25% to 3.5% dependent on our consolidated funded indebtedness to consolidated adjusted EBITDA ratio. Our new credit facility is secured by substantially all of our assets.

Note 7—Partner Equity and Distributions

On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under our existing shelf registration statement on Form S-3 at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of $121.4 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units at $23.14 per common unit, providing net proceeds of $18.3 million. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.

On April 14, 2010, we completed a secondary public offering of 8,500,000 common units owned by Targa. The Partnership did not receive any of the proceeds from this offering and the number of outstanding common units of the Partnership remained unchanged.

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Distributions declared and paid during the six months ended June 30, 2010 and 2009 were as follows:

		Distributions Paid										Distributions
	For the Three	Limited Partners				General Partner						per limited
Date Paid	Months Ended	Common		Subordinated		Incentive			2%	Total		partner unit
		(In millions, except per unit amounts)
2010
May 14, 2010	March 31, 2010	$	35.2	$	-	$	2.8	$	0.8	$	38.8	$	0.5175
February 12, 2010	December 31, 2009		35.2		-		2.8		0.8		38.8		0.5175

2009
May 15, 2009	March 31, 2009		18.0		5.9		1.9		0.5		26.3		0.5175
February 13, 2009	December 31, 2008		18.0		6.0		1.9		0.5		26.4		0.5175

Subsequent Event. On July 21, 2010, we announced a cash distribution of $0.5275 per unit on our outstanding common units for the three months ended June 30, 2010. The distribution, which totals $40.2 million, will be paid on August 13, 2010.

Note 8—Derivative Instruments and Hedging Activities

Commodity Hedges

We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover baskets of ethane, propane, normal butane, iso-butane and natural gasoline based upon our expected equity NGL composition, as well as specific NGL hedges of ethane and propane. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Mid-Continent, Waha and Permian Basin (El Paso), which closely approximate our actual NGL and natural gas delivery points.

We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying West Texas condensate equity volumes.

At June 30, 2010, the notional volumes of our commodity hedges were:

Commodity	Instrument	Unit	2010		2011		2012		2013
Natural Gas	Swaps	MMBtu/d		24,416		20,530		16,830		5,360
NGL	Swaps	Bbl/d		7,328		5,824		3,950		-
NGL	Floors	Bbl/d		-		223		259		-
Condensate	Swaps	Bbl/d		690		566		308		308

Interest Rate Swaps

As of June 30, 2010, we had $729.8 million outstanding under our credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market

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interest rates we have entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

Period	Fixed Rate		Notional Amount			Fair Value
Remainder of 2010		3.67%	$	300	million	$	(5.0	)
2011		3.52%		300	million		(6.5	)
2012		3.40%		300	million		(5.8	)
2013		3.39%		300	million		(3.0	)
1/1 - 4/24/2014		3.39%		300	million		(0.7	)
						$	(21.0	)

All interest rate swaps and interest rate basis swaps have been designated as cash flow hedges of variable rate interest payments on borrowings under our credit facility.

The following schedules reflect the fair values of derivative instruments in our financial statements:

	Asset Derivatives					Liability Derivatives
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	June 30,		December 31,		Sheet	June 30,		December 31,
	Location	2010		2009		Location	2010		2009
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	34.9	$	24.5	Current liabilities	$	4.0	$	7.8
	Long-term assets		20.7		7.0	Long-term liabilities		5.3		24.2

Interest rate contracts	Current assets		-		0.2	Current liabilities		7.6		8.0
	Long-term assets		-		1.9	Long-term liabilities		13.4		4.7
Total derivatives designated
as hedging instruments			55.6		33.6			30.3		44.7

Derivatives not designated as hedging instruments
Commodity contracts	Current assets		0.9		1.1	Current liabilities		0.4		0.6
	Long-term assets		-		0.3	Long-term liabilities		-		-

Allocated commodity contracts	Current assets		-		2.4	Current liabilities		-		5.7
	Long-term assets		-		1.7	Long-term liabilities		-		6.6

Total derivatives not designated
as hedging instruments			0.9		5.5			0.4		12.9

Total derivatives		$	56.5	$	39.1		$	30.7	$	57.6

Targa allocated to us a portion of our predecessor’s derivatives under its corporate wide hedging program. All of these derivatives are recorded on the balance sheets at fair value. As we were not a direct party to those hedge transactions, we did not apply hedge accounting. Therefore, changes in the unrealized fair value of these allocated hedges were recognized on a mark-to-market basis in earnings as a component of other income and expense. Upon our acquisition of the predecessor business, we became a legal party to the hedge transactions and applied hedge accounting.

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The following table reflects amounts reclassified from AOCI to revenue and expense:

	Amount of Gain (Loss)
	Reclassified from AOCI into
Location of Gain (Loss)	Income (Effective Portion)
Reclassified from	Three Months Ended June 30,						Six Months Ended June 30,
AOCI into Income	2010			2009			2010			2009
Interest expense, net	$	(3.4	)	$	(2.6	)	$	(5.0	)	$	(5.1	)
Revenues		2.9			13.3			(0.1	)		19.9
	$	(0.5	)	$	10.7		$	(5.1	)	$	14.8

The following tables reflect the gain (loss) recognized in OCI and income:

	Amount of Gain (Loss)
	Recognized in OCI on
Derivatives in	Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended June 30,						Six Months Ended June 30,
Relationships	2010			2009			2010			2009
Interest rate contracts	$	(10.1	)	$	8.2		$	(16.8	)	$	4.5
Commodity contracts		26.3			(35.2	)		60.0			(20.9	)
	$	16.2		$	(27.0	)	$	43.2		$	(16.4	)

	Amount of Gain (Loss)
Location of Gain (Loss)	Recognized in Income (Ineffective Portion)
Reclassified from	Three Months Ended June 30,						Six Months Ended June 30,
AOCI into Income	2010			2009			2010			2009
Revenues	$	(0.3	)	$	(0.4	)	$	(0.3	)	$	-

Our earnings are also affected by the use of the mark-to-market method of accounting for our derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheets and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.

		Amount of Gain (Loss) Recognized
Derivatives	Location of Gain (Loss)	in Income on Derivatives
Not Designated as	Recognized in Income	Three Months Ended June 30,						Six Months Ended June 30,
Hedging Instruments	on Derivatives	2010			2009			2010			2009
Realized gain (loss) on allocated commodity contracts	Revenue	$	(0.3	)	$	(2.0	)	$	(0.7	)	$	(3.0	)
Realized gain (loss) on allocated commodity contracts	Other income (expense)		1.1			(12.2	)		1.1			(9.8	)
Unrealized gain (loss) on allocated commodity contracts	Other income (expense)		-			3.0			10.0			6.0
		$	0.8		$	(11.2	)	$	10.4		$	(6.8	)

The following table shows the unrealized gain (loss) included in OCI:

	June 30,			December 31,
	2010			2009
Unrealized net gain (loss) on commodity hedges	$	31.4		$	(28.7	)
Unrealized net losses on interest rate hedges	$	(21.0	)	$	(9.2	)

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Deferred net gains of $17.3 million on commodity hedges and deferred net losses of $7.6 million on interest rate hedges recorded in AOCI are expected to be reclassified to revenues from third parties and interest expense during the next twelve months.

During the three and six months ended June 30, 2010, we reclassified deferred losses of $7.1 million and $14.0 million from AOCI as a non-cash reduction of revenue. During the three and six months ended June 30, 2009, deferred losses of $10.8 million and $29.5 million were reclassified from AOCI as a non-cash reduction of revenue. These deferred losses are primarily related to the 2008 termination of certain out-of-the-money natural gas and NGL commodity swaps.

See Note 9, Note 12 and Note 15 for additional disclosures related to derivative instruments and hedging activities.

Note 9—Related Party Transactions

Relationship with Targa

We are a party to various agreements with Targa, our general partner, Targa affiliates and others that address (i) the reimbursement of costs incurred on our behalf by our general partner, (ii) allocation of general administrative costs, (iii) distribution support to us under certain circumstances, (iv) intercompany purchases and sales of natural gas and NGLs, (v) cash distributions and (vi) acquisition transactions. See the Consolidated Statement of Changes in Owners’ Equity and Note 4, which summarize the transactional activity related to our acquisition of the Permian and Straddle systems.

The following table summarizes transactions with Targa and its affiliates:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010			2009		2010			2009
Sales to affiliates	$	-		$	0.5	$	0.1		$	15.9
Purchases from affiliates
Included in product purchases		98.8			64.9		207.0			140.3
Payroll and related costs included in operating expense		14.8			13.1		30.6			27.0
Parent allocation of general & administrative expense		19.6			22.7		37.2			40.9
Net change in affiliate receivable (payable)		(13.1	)		21.7		(24.2	)		27.2
Cash distributions to Targa based on unit ownership		5.2			8.4		14.7			16.8
Cash distribution to Targa from Permian/Straddle acquisition		87.2			-		87.2			-
Distributions (contributions) under common control		-			26.4		4.5			79.1

Relationship with Warburg Pincus LLC

Two of the directors of our general partner, who are also directors of Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. During the three and six months ended June 30, 2010, we purchased $9.6 million and $16.1 million of product from Broad Oak. During the three and six months ended June 30, 2009, we purchased $1.7 million and $3.1 million of product from Broad Oak.

Relationship with Bank of America

An affiliate of Bank of America (“BofA”) is a equity investor in Targa Resources Investments Inc., which indirectly owns our general partner.

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Financial Services. BofA is a lender and the administrative agent under our senior secured revolving credit facility.

Commodity hedges. We have entered into various commodity derivative transactions with BofA. The following table shows our open commodity derivatives with BofA as of June 30, 2010:

Period

Commodity

Daily Volumes

Average Price

Index

Jul 2010 - Dec 2010

Natural Gas

3,289

MMBtu

7.39

per MMBtu

IF_WAHA

Jul 2010 - Dec 2010

Condensate

181

Bbl

69.28

per Bbl

WTI

As of June 30, 2010, the aggregate fair value of these open positions was $1.4 million. For the three and six months ended June 30, 2010, we received $0.5 million and $1.3 million from BofA to settle payments due under hedge transactions. For the three and six months ended June 30, 2009, we received $7.5 million and $16.0 million from BofA to settle payments due under hedge transactions.

Commercial Relationships. Our product sales and product purchases with BofA were:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Included in revenues	$	6.9	$	7.8	$	15.4	$	22.7
Included in costs and expenses		2.0		-		2.2		1.0

Note 10—Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of any 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.

Our environmental liability was not material as of June 30, 2010.

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 that have been filed or are pending against us. We believe all 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.

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa 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 Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October&# 160;2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. On February 23, 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. On April 16, 2010, WTG filed a petition for review with the Texas Supreme Court, and defendants filed

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their responses on June 11, 2010. If the petition for review is granted, Targa intends to contest the appeal, but can give no assurances regarding the outcome of the proceeding. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

Note 11—Fair Value of Financial Instruments

We have determined the estimated fair values of our assets and liabilities classified as financial instruments using available market information and valuation methodologies described below. We apply considerable judgment when interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.

The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The carrying value of the notes payable to Parent at December 31, 2009 approximates their fair value as they were settled at their stated amount at the time of acquisition of the affected assets. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:

	June 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior unsecured notes, 8¼% fixed rate	$	209.1	$	204.7	$	209.1	$	206.5
Senior unsecured notes, 11¼% fixed rate		231.3		250.9		231.3		253.5

Note 12—Fair Value Measurements

We categorize the inputs to the fair value of our financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

·	Level 1 – observable inputs such as quoted prices in active markets;

·	Level 2 – inputs other than quoted prices in active markets that are either directly or indirectly observable; and

·	Level 3 – 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 readily available in public markets. 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.

The following tables present the fair value of our financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

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	June 30, 2010
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	56.5	$	-	$	51.9	$	4.6
Assets from interest rate derivatives		-		-		-		-
Total assets	$	56.5	$	-	$	51.9	$	4.6
Liabilities from commodity derivative contracts	$	9.7	$	-	$	8.8	$	0.9
Liabilities from interest rate derivatives		21.0		-		21.0		-
Total liabilities	$	30.7	$	-	$	29.8	$	0.9

	December 31, 2009
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	37.0	$	-	$	37.0	$	-
Assets from interest rate derivatives		2.1		-		2.1		-
Total assets	$	39.1	$	-	$	39.1	$	-
Liabilities from commodity derivative contracts	$	44.9	$	-	$	34.8	$	10.1
Liabilities from interest rate derivatives		12.7		-		12.7		-
Total liabilities	$	57.6	$	-	$	47.5	$	10.1

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

	Commodity Derivative Contracts
Balance, December 31, 2009	$	(10.1	)
Unrealized gains included in OCI		13.0
Transfer of hedges		1.1
Settlements		(0.3	)
Balance, June 30, 2010	$	3.7

Note 13—Segment Information

In connection with the April 2010 acquisition of Targa’s interest in the Permian and Straddle Systems and its impact on our structure used for internal management purposes, an updated evaluation of our reportable segments was performed during the second quarter of 2010. As a result, our operations are now presented under four reportable segments: (1) Field Gathering and Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and (4) Marketing and Distribution. Prior period information in this report has been revised to conform to the 2010 reported segment presentation.

Prior to the second quarter of 2010, we reported our results under four segments: (1) Natural Gas Gathering and Processing, (2) Logistics Assets, (3) NGL Distribution and Marketing and (4) Wholesale Marketing. The increase in our Coastal Gathering and Processing businesses as a result of our acquisition of the Permian and Straddle Systems, and consideration of underlying operational and economic differences between Field and Coastal gathering and processing systems led to more granular analysis of the Natural Gas Gathering and Processing results. Also, we have aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant operational interrelationships among the Marketing an d Distribution activities apparent in our current business model.

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The Natural Gas Gathering and Processing division 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. The Field Gathering and Processing segment assets are located in North Texas and the Permian Basin and the Coastal Gathering and Processing segment assets are located in the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico.

The NGL Logistics and Marketing division is also referred to as our Downstream Business. It includes all the activities necessary to convert raw natural gas liquids into NGL products, market the finished products and provide certain value added services.

The Logistics Assets segment is involved in transporting and storing mixed NGLs and fractionating, storing, and transporting finished NGLs. These assets are generally connected to and supplied, in part, by our gathering and processing segments and are predominantly located in Mont Belvieu, Texas and Western Louisiana.

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to us from our Gathering and Processing segments and the purchase and resale of natural gas in selected United States markets.

Our reportable segment information is shown in the following tables:

	Three Months Ended June 30, 2010
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Third party revenues	$	25.7	$	101.4	$	19.9	$	1,054.4	$	2.6	$	-		$	1,204.0
Intersegment revenues		201.1		147.0		20.9		128.1		-		(497.1	)		-
Total revenues	$	226.8	$	248.4	$	40.8	$	1,182.5	$	2.6	$	(497.1	)	$	1,204.0
Operating margin	$	43.6	$	14.2	$	18.0	$	14.1	$	2.6	$	-		$	92.5
Other financial information:
Capital expenditures	$	10.5	$	1.0	$	10.7	$	0.7	$	-	$	-		$	22.9

	Three Months Ended June 30, 2009
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Third party revenues	$	17.4	$	79.8	$	19.1	$	851.3	$	11.3	$	(0.2	)	$	978.7
Revenues from affiliates		-		-		-		0.4		-		0.1			0.5
Intersegment revenues		134.9		81.7		21.2		60.2		-		(298.0	)		-
Total revenues	$	152.3	$	161.5	$	40.3	$	911.9	$	11.3	$	(298.1	)	$	979.2
Operating margin	$	31.9	$	13.2	$	20.1	$	16.7	$	11.3	$	-		$	93.2
Other financial information:
Capital expenditures	$	9.7	$	3.6	$	4.5	$	1.2	$	-	$	-		$	19.0

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	Six Months Ended June 30, 2010
	Field		Coastal
	Gathering		Gathering				Marketing					Corporate
	and		and		Logistics		and					and
	Processing		Processing		Assets		Distribution		Other			Eliminations			Total
Third party revenues	$	42.9	$	234.4	$	36.5	$	2,335.9	$	(0.8	)	$	-		$	2,648.9
Revenues from affiliates		-		-		-		0.2		-			(0.1	)		0.1
Intersegment revenues		437.2		299.6		41.9		266.6		-			(1,045.3	)		-
Total revenues	$	480.1	$	534.0	$	78.4	$	2,602.7	$	(0.8	)	$	(1,045.4	)	$	2,649.0
Operating margin	$	92.0	$	32.4	$	29.3	$	33.9	$	(0.8	)	$	-		$	186.8
Other financial information:
Total assets	$	1,275.9	$	250.9	$	422.1	$	392.9	$	56.5		$	64.2		$	2,462.5
Capital expenditures	$	21.6	$	2.0	$	13.7	$	0.6	$	-		$	-		$	37.9

	Six Months Ended June 30, 2009
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Third party revenues	$	32.2	$	175.8	$	32.8	$	1,691.1	$	16.8	$	0.1		$	1,948.8
Revenues from affiliates		-		-		-		15.9		-		-			15.9
Intersegment revenues		268.0		138.2		37.6		128.7		-		(572.5	)		-
Total revenues	$	300.2	$	314.0	$	70.4	$	1,835.7	$	16.8	$	(572.4	)	$	1,964.7
Operating margin	$	56.3	$	23.3	$	26.2	$	39.0	$	16.8	$	-		$	161.6
Other financial information:
Total assets	$	1,313.9	$	256.1	$	413.6	$	357.7	$	110.9	$	115.2		$	2,567.4
Capital expenditures	$	18.7	$	8.2	$	7.6	$	12.9	$	-	$	-		$	47.4

The following table shows our revenues by product and services for each period presented:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Natural gas sales	$	249.3	$	167.7	$	551.0	$	367.6
NGL sales		892.7		724.5		1,982.2		1,455.8
Condensate sales		20.9		20.6		42.1		32.6
Fractionation & Treating fees		12.5		15.3		24.6		23.3
Storage & Terminalling fees		9.3		10.9		18.8		20.3
Transportation fees		7.7		16.2		15.1		25.1
Gas processing fees		6.0		4.6		11.6		8.8
Hedge Settlements		2.9		13.3		0.1		19.9
Business interruption insurance		-		3.3		-		5.0
Other		2.7		2.8		3.5		6.3
	$	1,204.0	$	979.2	$	2,649.0	$	1,964.7

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The following table is a reconciliation of operating margin to net income (loss):

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2010		2009		2010		2009
Reconciliation of operating margin to net income (loss):
Operating margin	$	92.5	$	93.2	$	186.8	$	161.6
Depreciation and amortization expense		(32.7)		(30.6)		(64.3)		(60.8)
General and administrative expense		(24.0)		(28.9)		(45.3)		(50.0)
Interest expense, net		(17.7)		(30.4)		(38.8)		(60.5)
Income tax expense		(0.9)		(0.6)		(2.4)		(1.1)
Other, net		3.5		(6.8)		13.8		(0.6)
Net income (loss)	$	20.7	$	(4.1)	$	49.8	$	(11.4)

Note 14—Supplemental Cash Flow Information

The following table provides supplemental cash flow information for each period presented:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
Cash:
Interest paid	$	2.3	$	3.0		$	29.0	$	14.7
Non-cash:
Inventory line-fill transferred to property, plant and equipment		0.5		(0.3	)		0.5		9.8

Note 15—Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry. Our business activities include gathering, transporting, processing, fractionating and storage of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities.

A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, as well as changes in interest rates. The fair value of our commodity and interest rate derivative

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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 observed in underlying markets. 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.

Commodity Price Risk. A majority of the revenues from our natural gas gathering and processing business are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to market 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 commodity derivative 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.

In an effort to reduce the variability of our cash flows we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in adv ance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market 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 our variable rate borrowings under our credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement.

Counterparty Risk – Credit and Concentration

Derivative Counterparty Risk. Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.

We have master agreements with all of our hedge counterparties that allow us to net settle asset and liability positions with the same counterparty. As of June 30, 2010, we had $7.9 million in liabilities to offset the default risk of counterparties with which we also had asset positions of $56.2 million as of that date.

Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

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As of June 30, 2010, affiliates of Goldman Sachs, Barclays and Credit Suisse accounted for 48%, 33% and 7% of our net counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Barclays and Credit Suisse are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

Customer Credit Risk. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.

Significant Commercial Relationships. We are exposed to concentration risk when a significant customer or supplier accounts for a significant portion of our business activity. We have not had a material change in the make-up of our customers or suppliers during the six months ended June 30, 2010.

Casualty or Other Risks

Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. A portion of the cost of these insurance programs described above is allocated to us pursuant to the Omnibus Agreement.

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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 Quarterly Report and in our consolidated financial statements and notes thereto included in our Annual Report. We intend to file supplemental financial statements to our Annual Report to reflect our acquisition of the Permian and Straddle on a common control basis.

Overview

Targa Resources GP LLC is a Delaware limited liability company, formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa.

We acquired from Targa its ownership interests in the following assets, liabilities and operations on the dates indicated:

February 14, 2007 – North Texas System

October 24, 2007 – San Angelo (“SAOU”) System and Louisiana (“LOU”) System

September 24, 2009 – Downstream Business

April 27, 2010 – Permian and Straddle Systems

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions collectively as our “predecessors.”

Our Operations

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”).

We report our operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two segments – (a) Logistics Assets and (b) Marketing and Distribution. Other includes the impact on operating income of our derivatives hedging activities. Prior period information in this report has been revised to conform to the 2010 reported segment presentation.

Prior to the second quarter of 2010, we reported our results under four segments: (1) Natural Gas Gathering and Processing, (2) Logistics Assets, (3) NGL Distribution and Marketing and (4) Wholesale Marketing. The increased amount of Coastal Gathering & Processing assets owned by us as a result of our acquisition of the Permian and Straddle Systems, and consideration of underlying operational and economic differences between Field and Coastal gathering and processing systems led to more granular analysis of the Natural Gas Gathering and Processing results. Also, we have aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant operational interrelationships among th e Marketing and Distribution activities apparent in our current business model.

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The Natural Gas Gathering and Processing division 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. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin and the Coastal Gathering and Processing segment’s assets are located in the onshore region of the Louisiana Gulf Coast and the Gulf of Mexico.

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; and (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users.

Recent Developments

On April 14, 2010, we completed a secondary public offering of 8,500,000 common units owned by Targa LP Inc., a wholly-owned subsidiary of Targa. The Partnership did not receive any of the proceeds from this offering and the number of outstanding common units of the Partnership remained unchanged.

On April 27, 1010, we completed our acquisition of Targa’s interests in its Permian and Straddle Systems, which consists of natural gas gathering and processing businesses located in West Texas and the Gulf Coast region of Louisiana, for $420.0 million, effective April 1, 2010. We financed this acquisition substantially through borrowings under our senior secured revolving credit facility. The total consideration was used to repay outstanding affiliated indebtedness of $332.8 million, with the remaining $87.2 million reported as a parent distribution. This acquisition is reflected in our financial statements as a transfer of assets under common control.

As part of the purchase of the Permian and Straddle assets, our Omnibus Agreement with Targa was amended and extended through April 2013 for Targa to provide general and administrative and other services to us associated with (1) these assets, (2) any additional assets, operations or businesses that may be sold to us by Targa, and (3) subject to mutual consent additional assets, operations or businesses that we may acquire from third parties.

On July 21, 2010, we announced a cash distribution of $0.5275 per unit on our outstanding common units for the three months ended June 30, 2010. The aggregate distribution to be paid on August 13, 2010 is $40.2 million.

Recently Issued Pronouncements

See Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

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Results of Operations

The following table and discussion relate to the three and six months ended June 30, 2010 and 2009 and is a summary of our results of operations for the periods then ended:

	Three Months Ended June 30,												Six Months Ended June 30,
	2010			2009			$ Change			% Change			2010			2009			$ Change			% Change
	(In millions, except												(In millions, except
	operating and price data)												operating and price data)
Revenues (1)	$	1,204.0		$	979.2		$	224.8			23	%	$	2,649.0		$	1,964.7		$	684.3			35	%
Product purchases		1,062.1			839.1			223.0			27	%		2,361.8			1,703.9			657.9			39	%
Gross margin (2)		141.9			140.1			1.8			1	%		287.2			260.8			26.4			10	%
Operating expenses		49.4			46.9			2.5			5	%		100.4			99.2			1.2			1	%
Operating margin (3)		92.5			93.2			(0.7	)		(1	%)		186.8			161.6			25.2			16	%
Depreciation and amortization expense		32.7			30.6			2.1			7	%		64.3			60.8			3.5			6	%
General and administrative expense		24.0			28.9			(4.9	)		(17	%)		45.3			50.0			(4.7	)		(9	%)
Casualty loss adjustment		-			(0.7	)		0.7			100	%		-			(0.7	)		0.7			100	%
Income from operations		35.8			34.4			1.4			4	%		77.2			51.5			25.7			50	%
Interest expense, net		(17.7	)		(30.4	)		(12.7	)		(42	%)		(38.8	)		(60.5	)		(21.7	)		(36	%)
Other income (expense)		3.5			(7.5	)		11.0			147	%		13.8			(1.3	)		15.1			1,162	%
Income tax expense		(0.9	)		(0.6	)		0.3			50	%		(2.4	)		(1.1	)		1.3			118	%
Net income (loss)		20.7			(4.1	)		24.8			605	%		49.8			(11.4	)		61.2			537	%
Less: Net income attributable to
noncontrolling interest		0.9			0.4			0.5			125	%		1.2			0.3			0.9			300	%
Net income (loss) attributable to
Targa Resources Partners LP	$	19.8		$	(4.5	)		24.3			540	%	$	48.6		$	(11.7	)		60.3			515	%

Financial and operating data:
Financial data:
Adjusted EBITDA (4)		78.4			81.4			(3.0	)		(4	%)		159.0			150.9			8.1			5	%
Distributable cash flow (5)		55.2			42.8			12.4			29	%		110.1			75.0			35.1			47	%
Operating data:
Plant natural gas inlet, MMcf/d (6) (7)		1,723.5			1,571.6			151.9			10	%		1,731.0			1,450.0			281.0			19	%
Gross NGL production, MBbl/d		78.6			73.2			5.4			7	%		77.4			70.2			7.2			10	%
Natural gas sales, BBtu/d (7)		666.4			561.1			105.3			19	%		653.5			543.1			110.4			20	%
NGL sales, MBbl/d		235.7			281.6			(45.9	)		(16	%)		241.2			287.0			(45.8	)		(16	%)
Condensate sales, MBbl/d		3.1			4.1			(1.0	)		(24	%)		3.1			3.8			(0.7	)		(18	%)
Average realized prices (8):
Natural Gas, $/MMBtu		4.21			3.45			0.76			22	%		4.72			3.89			0.83			21	%
NGL, $/gal		0.99			0.68			0.31			46	%		1.08			0.67			0.41			61	%
Condensate, $/Bbl		72.67			54.58			18.09			33	%		73.92			48.38			25.54			53	%

_______

(1)	Includes business interruption insurance revenues of $3.3 million and $5.0 million for the three and six months of 2009.

(2)	Gross margin is revenues less product purchases. See “Non-GAAP Financial Measures.”

(3)	Operating margin is gross margin less operating expenses. See “Non-GAAP Financial Measures.”

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

(5)	Distributable cash flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses on mark to market derivative contracts, less maintenance capital expenditures. See “Non-GAAP Financial Measures.”

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

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

(8)	Average realized prices include the impact of hedging activities.

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Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include gross margin, operating margin, operating expenses, plant inlet, gross NGL production, adjusted EBITDA and distributable cash flow, among others.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Revenue increased $330.6 million due to higher commodity prices offset by $90.9 million in lower sales volumes and $14.9 million in lower revenues that are primarily fee based.

The increase in gross margin reflects higher throughput and NGL production, increased natural gas sales volumes and higher commodity prices, offset by lower NGL and condensate sales volumes, lower fee revenues, lower business interruption proceeds, lower hedge settlements and a lower of cost or market adjustment.

For additional information regarding the period to period changes in our gross margins, see “Results of Operations—By Segment.”

The increase in operating expenses was primarily due to increased compensation and benefit costs and increased non-capitalized maintenance costs, offset by decreased costs associated with outside contract services and lower professional fees.

The increase in depreciation and amortization expense is primarily attributable to assets acquired in 2009 that now have a full period of depreciation and capital expenditures during 2010 of $22.0 million.

The decrease in general and administrative expense was primarily driven by the timing of allocations under common control.

The decrease in interest expense was primarily due lower interest rates on third party debt than on affiliate debt associated with predecessor operations. See “Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Revenues increased $861.2 million due to higher commodity prices offset by $161.8 million in lower sales volumes and $15.1 million in lower revenues that are primarily fee based.

The increase in gross margin reflects higher throughputs and NGL production, increased natural gas sales volumes, higher commodity prices and a favorable change in lower of cost or market adjustment offset by lower NGL and condensate sales volumes, lower fee revenues, lower business interruption proceeds and lower hedge settlements.

For additional information regarding the period to period changes in our gross margins, see “Results of Operations—By Segment.”

The increase in operating expenses was primarily due to increased compensation and benefits costs, increased non-capitalized maintenance costs and increased environmental spending, offset by decreased costs associated with outside contract services and lower professional fees.

The decrease in general and administrative expense was primarily driven by the timing of allocations under common control.

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Results of Operations—By Segment

Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volume or sales for the period and the denominator is the number of calendar days for the period.

Field Gathering and Processing Segment

The following table provides summary financial data regarding results of operations of our Field Gathering and Processing segment for the periods indicated:

	Three Months Ended June 30,												Six Months Ended June 30,
	2010			2009			$ Change			% Change			2010			2009			$ Change			% Change
	($ in millions)												($ in millions)
Gross margin	$	58.7		$	45.0		$	13.7			30	%	$	121.6		$	84.1		$	37.5			45	%
Operating expenses		(15.1	)		(13.1	)		2.0			15	%		(29.6	)		(27.8	)		1.8			6	%
Operating margin (1)	$	43.6		$	31.9			11.7			37	%	$	92.0		$	56.3			35.7			63	%
Operating statistics (2):
Plant natural gas inlet, MMcf/d		401.6			391.4			10.2			3	%		395.9			389.7			6.2			2	%
Gross NGL production, MBbl/d		50.0			48.6			1.4			3	%		49.1			48.1			1.0			2	%
Natural gas sales, BBtu/d		193.7			165.8			27.9			17	%		189.7			169.4			20.3			12	%
NGL sales, MBbl/d		41.9			39.6			2.3			6	%		41.0			39.4			1.6			4	%
Condensate sales, MBbl/d		2.7			2.8			(0.1	)		(4	%)		2.3			2.8			(0.5	)		(18	%)
Average realized prices:
Natural gas, $/MMBtu		3.78			2.76			1.02			37	%		4.43			3.22			1.21			38	%
NGL, $/gal		0.86			0.62			0.24			39	%		0.93			0.58			0.35			60	%
Condensate, $/Bbl		73.90			55.62			18.28			33	%		74.90			45.92			28.98			63	%

_______

(1)	Operating margin is revenues less product purchases and operating expenses.

(2)	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.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

The increase in gross margin for 2010 is primarily due to an increase in commodity sales prices and an increase in natural gas inlet and gross NGL production. The increased volumes were largely attributable to new well connects throughout our systems, partially offset by a contract expiration in our North Texas System.

The increase in operating expenses for 2010 was primarily due to increases in system maintenance and repairs.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

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The increase in operating expenses for 2010 was primarily due to increases in system maintenance and repairs compensation and benefits costs and environmental expenses, partially offset by decreases in chemicals and lubricants and utilities expenses.

Coastal Gathering and Processing Segment

The following table provides summary financial data regarding results of operations of our Coastal Gathering and Processing segment for the periods indicated:

	Three Months Ended June 30,												Six Months Ended June 30,
	2010			2009			$ Change			% Change			2010			2009			$ Change			% Change
	($ in millions)												($ in millions)
Gross margin	$	21.1		$	19.7		$	1.4			7	%	$	45.3		$	37.7		$	7.6			20	%
Operating expenses		(6.9	)		(6.5	)		0.4			6	%		(12.9	)		(14.4	)		(1.5	)		(10	%)
Operating margin (1)	$	14.2		$	13.2			1.0			8	%	$	32.4		$	23.3			9.1			39	%
Operating statistics (2):
Plant natural gas inlet, MMcf/d (3)		1,321.9			1,180.2			141.7			12	%		1,335.1			1,060.3			274.8			26	%
Gross NGL production, MBbl/d		28.5			24.7			3.8			15	%		28.3			22.1			6.2			28	%
Natural gas sales, BBtu/d		310.3			248.1			62.2			25	%		312.1			231.7			80.4			35	%
NGL sales, MBbl/d		32.4			25.4			7.0			28	%		31.6			23.0			8.6			37	%
Condensate sales, MBbl/d		0.4			1.3			(0.9	)		(69	%)		0.8			1.4			(0.6	)		(43	%)
Average realized prices:
Natural gas, $/MMBtu		4.25			3.68			0.57			15	%		4.76			4.23			0.53			13	%
NGL, $/gal		0.99			0.70			0.29			41	%		1.04			0.66			0.38			58	%
Condensate, $/Bbl		81.16			53.22			27.94			52	%		77.98			44.66			33.32			75	%

_______

(1)	Operating margin is revenues less product purchases and operating expenses.

(2)	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.

(3)	The majority of Straddle System volumes are gathered on third party offshore pipeline systems and delivered to the plant inlets.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

The increase in gross margin for 2010 is primarily due to an increase in NGL sales prices, higher plant inlet and NGL production and return to normal processing settlement from special processing arrangements during 2009 hurricane recovery, partially offset by lower volumes of LOU wellhead gas supply. Natural gas sales volumes increased due to increased demand from our industrial customers and increased NGL sales to affiliates for resale. NGL sales volumes increased primarily due to the straddle plants, third party pipeline gathering systems and producers recovering operations in 2009 after hurricanes Gustav and Ike.

The increase in operating expenses for 2010 was primarily due to an increase in compensation and benefit costs, chemicals and lubricants and utilities expenses associated with return to normal operations as compared to hurricane impacted operations in 2009.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

The increase in gross margin for 2010 is primarily due to an increase in NGL sales prices, higher plant inlet and NGL production and return to normal processing settlement related to special processing arrangements during 2009 hurricane recovery, partially offset by lower volumes of LOU wellhead gas supply. Natural gas sales volumes increased due to increased demand from our industrial customers and increased NGL sales to affiliates for resale. NGL sales volumes increased primarily due to the straddle plants, third party pipeline gathering systems and producers recovering operations in 2009 after hurricanes Gustav and Ike.

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Logistics Assets Segment

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

	Three Months Ended June 30,												Six Months Ended June 30,
	2010			2009			$ Change			% Change			2010			2009			$ Change		% Change
	($ in millions)												($ in millions)
Gross margin (1)	$	40.8		$	40.3		$	0.5			1	%	$	78.4		$	70.4		$	8.0		11	%
Operating expenses		(22.8	)		(20.2	)		2.6			13	%		(49.1	)		(44.2	)		4.9		11	%
Operating margin (2)	$	18.0		$	20.1			(2.1	)		(10	%)	$	29.3		$	26.2			3.1		12	%
Operating statistics:
Fractionation volumes, MBbl/d		228.4			230.0			(1.6	)		(1	%)		219.0			210.0			9.0		4	%
Treating volumes, MBbl/d (3)		21.8			19.5			2.3			12	%		14.7			14.0			0.7		5	%

_______

(1)	Gross margin consists of fee revenue and business interruption proceeds.

(2)	Operating margin is revenues less product purchases and operating expenses.

(3)	Consists of the volumes treated in our low sulfur natural gasoline unit.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Gross margin increased by $0.5 million for 2010. During 2009, we received $1.9 million in business interruption proceeds.

Excluding the impact of business interruption proceeds in 2009, the increase in gross margin was primarily due to increased fractionating fees due to fee improvement and higher gas prices, which were partially offset by decreases in other services revenue as 2009 benefited from higher Ike related terminalling activity. Fractionation volumes were within 1% of comparable volumes from the prior year.

Operating expenses increased primarily due to higher general maintenance costs, higher fuel and electricity expenses driven by higher gas prices along with commencement of operations of a cogeneration unit at our Mt. Belvieu plant, which did not become operational until the third quarter of 2009. We also had higher outside fractionation expenses and well workover expenses, which were partially offset by favorable system product gains in 2010.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Gross margin increased by $8.0 million for 2010. During 2009, we received $1.9 million in business interruption proceeds.

Excluding the impact of business interruption proceeds in 2009, the increase in gross margin is primarily due to fee improvement, higher gas prices and increased volumes due to the impact of Hurricane Ike on 2009 operations. These increases were partially offset by decreases in other services revenue as 2009 benefited from higher Ike related terminalling activity.

Operating expenses increased primarily due to higher general maintenance costs, higher fuel and electricity expense driven by higher gas prices along with commencement of operations of a cogeneration unit at our Mt. Belvieu plant, which did not become operational until the third quarter of 2009. We also had higher outside fractionation expenses and well workover expenses, which were partially offset by favorable system product gains in 2010.

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Marketing and Distribution Segment

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

	Three Months Ended June 30,												Six Months Ended June 30,
	2010			2009			$ Change			% Change			2010			2009			$ Change			% Change
	($ in millions)												($ in millions)
Gross margin	$	24.9		$	29.5		$	(4.6	)		(16	%)	$	55.9		$	63.0		$	(7.1	)		(11	%)
Operating expenses		(10.8	)		(12.8	)		(2.0	)		(16	%)		(22.0	)		(24.0	)		(2.0	)		(8	%)
Operating margin (1)	$	14.1		$	16.7			(2.6	)		(16	%)	$	33.9		$	39.0			(5.1	)		(13	%)
Operating statistics:
Natural gas sales, BBtu/d		668.3			479.0			189.3			40	%		639.0			465.1			173.9			37	%
NGL sales, MBbl/d		234.8			283.3			(48.5	)		(17	%)		240.6			288.9			(48.3	)		(17	%)
Natural gas realized price, $/gal		4.10			3.25			0.85			26	%		4.64			3.63			1.01			28	%
NGL realized price, $/gal		1.03			0.69			0.34			49	%		1.11			0.68			0.43			63	%

_______

(1)	Operating margin is revenues less product purchases and operating expenses.

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

Gross margin decreased in 2010 on sales at hub and staged inventory locations primarily due to the 2009 impact of higher margins on forward sales agreements that were fixed at relatively high prices during 2008 and less spot fractionation volumes and associated fees. These items were partially offset by higher marketing fees on contract purchase volumes due to overall higher market prices. Margin on transportation activity decreased due to expiration of a large barge contract partially offset by increased truck activity.

Natural gas sales volumes are higher due to increased purchases for resale. NGL sales volumes are lower due to a change in contract terms with a petrochemical supplier that has a minimal impact to gross margin.

Operating expenses decreased due to lower barge expenses associated with the expiration of a large barge contract partially offset by increased truck transportation costs.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Gross margin decreased primarily due to lower margins on inventory sales at our hub and staged inventory locations, and decreased margins related to our transportation activity, partially offset by increased margins on marketing fees for equity production and refinery service activity. The margins on NGL sales in 2010 are lower in comparison to the prior year due to the impact of higher margin forward sales agreements that were fixed at relatively high prices during 2008 and delivered in 2009. The reduction of margins related to transportation activity was primarily due to the expiration of a large barge contract. Margins associated with marketing fees increased due to higher market prices and increased equity volumes in 2010.

Operating expenses decreased primarily due to lower barge expenses associated with the expiration of a large barge contract partially offset by increased truck transportation costs incurred.

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Other

Three Months Ended June 30, 2010 Compared to Three Months Ended June 30, 2009

During 2010 and 2009, the settlement of our commodity derivatives resulted in $2.6 million and $11.3 million in additional revenue (cash and non-cash) from our hedge counterparties, which were recorded as an increase to gross margin from hedge settlements during the quarters. Cash receipts or payments on our hedge settlements are due to the contracted price of our hedge contracts falling above or below the market prices of the commodity settled.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

During 2010, the settlement of our commodity derivatives resulted in a reduction of revenue of $0.8 million, which was recorded as a reduction of gross margin from hedge settlements. During 2009, the settlement of our commodity derivatives resulted in $16.8 million in additional revenue from our hedge counterparties, which were recorded as an increase to gross margin from hedge settlements. Cash receipts or payments on our hedge settlements are due to the contracted price of our hedge contracts falling above or below the market prices of the commodity settled.

Liquidity and Capital Resources

The ability to finance our operations, including funding capital expenditures and acquisitions, to meet indebtedness obligations, to refinance indebtedness or to meet collateral requirements depends on our ability to generate cash in the future. The 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 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 this Quarterly Report and our Annual Report.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our credit facility, the issuance of additional equity and access to debt markets. The capital markets continue to experience volatility. Many financial institutions have or have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit conditions includes our credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operation. We sell our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil and natural gas prices are also volatile. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2013 (see Note 8 of the Notes to Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report). Market conditions may also impact our ability to enter into future commodity derivative contracts. In the event of a continuing global recession, commodity prices may stay depressed or fall further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

As of June 30, 2010, our liquidity of $156.8 million consisted of $43.7 million of available cash and $113.1 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the lenders in our credit facility. To date, other than a default by Lehman Bank, we have experienced no disruptions in our ability to access funds committed under our credit facility. However, we cannot predict with any certainty the impact to us of any further disruptions in the credit environment. On July 15, 2010, we entered into an amended and restated credit

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agreement that replaced our existing variable rate senior secured credit facility with a new variable rate senior secured credit facility due July 2015. The new senior secured credit facility increases available commitments to $1.1 billion, with an option to increase the senior secured credit facility by an additional $300 million. The amended and restated credit agreement increased our availability by $141.5 million.

Our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures, with remaining amounts being distributed in accordance with our distribution policy. 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 facility should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, long-term indebtedness obligations, collateral requirements and minimum quarterly cash distributions 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 June 30, 2010, our total outstanding letter of credit postings were $115.6 million.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). As of June 30, 2010, such annual minimum amounts payable to non-Targa unitholders total approximately $76.2 million. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 6 and Note 7 of the Notes to Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we set tle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

As of June 30, 2010, we had a positive working capital balance of $41.1 million.

Contractual Obligations. As of June 30, 2010, except for changes in the ordinary course of our business, our contractual obligations have not changed materially from those reported in our Annual Report.

Cash Flow. Net cash provided by or used in operating activities, investing activities and financing activities for the three months ended June 30, 2010 and 2009 were as follows:

	Six Months Ended June 30,
	2010			2009			$ Change			% Change
	($ in millions)
Net cash provided by (used in):
Operating activities	$	129.9		$	172.8		$	(42.9	)		(25	%)
Investing activities		(37.3	)		(46.0	)		(8.7	)		(19	%)
Financing activities		(109.3	)		(172.7	)		(63.4	)		(37	%)

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Net cash provided by operating activities decreased primarily due to a decrease in our payables related to accrued interest on affiliate indebtedness and trade payables.

Net cash used in investing activities decreased due primarily to lower capital additions during 2010 compared to 2009.

The following table lists gross additions to property, plant and equipment, cash flows used in property, plant and equipment additions and the difference, which is primarily settled accruals:

	Three Months Ended June 30,					Six Months Ended June 30,
	2010			2009		2010			2009
	(In millions)
Gross additions to property, plant and equipment	$	22.9		$	19.0	$	37.9		$	47.4
Non-cash additions to property, plant and equipment		(0.5	)		0.3		(0.5	)		(9.8	)
Change in accruals		(0.4	)		1.1		0.5			8.4
Cash expenditures	$	22.0		$	20.4	$	37.9		$	46.0

Net cash used in financing activities decreased primarily due to intercompany transactions associated with the Downstream and Permian/Straddle predecessor operations.

Capital Requirements. The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A portion of the cost of constructing new gathering lines to connect to our gathering system is paid for by the natural gas producer. However, we expect to continue to incur significant expenditures through the remainder of 2010 related to the expansion of our natural gas gathering and processing infrastructure and our logistics assets.

We categorize our capital expenditures as either: (i) expansion expenditures or (ii) maintenance expenditures. Expansion expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues. Maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations.

The following table shows the breakout of our capital expenditures between expansion expenditures and maintenance expenditures:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(In millions)
Capital expenditures:
Expansion	$	17.0	$	10.3	$	26.7	$	30.9
Maintenance		5.9		8.7		11.2		16.5
	$	22.9	$	19.0	$	37.9	$	47.4

Our planned capital expenditures for 2010 are approximately $145 million with maintenance capital expenditures accounting for approximately 25%. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that over time we will invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

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We expect to fund future capital expenditures with funds generated from our operations, borrowings under our senior secured revolving credit facility, the issuance of additional partnership units and debt offerings.

Non-GAAP Financial Measures

For a complete discussion of the measures that management uses to evaluate our operations, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations” in our Annual Report.

Gross Margin. With respect to our Natural Gas Gathering and Processing segment, we define gross margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. With respect to our Logistics Assets segment we define gross margin as total revenue, which consists primarily of service fee revenue. With respect to our Marketing and Distribution segments, we define gross margin as total revenue, which consists primarily of service fee revenues and NGL sales, less cost of sales, which consists primarily of NGL purchases and changes in inventory valuation.

Operating Margin. With respect to our Natural Gas Gathering and Processing segments, our Logistics Assets segment and our Marketing and Distribution segment, we define operating margin as gross margin less operating expense.

The GAAP measure most directly comparable to gross margin and operating margin is net income. The non-GAAP financial measures of gross margin and operating margin should not be considered as an alternative to GAAP net income. Gross margin and operating margin are not presentations made in accordance with GAAP and have important limitations as analytical tools. You should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into its decision-making processes. Management reviews gross margin and operating margin monthly for consistency and trend analysis. Based on this monthly analysis, management takes appropriate action to maintain positive trends or to reverse negative trends. Management uses gross margin and operating margin as important performance measures of the core profitability of our operations

The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the three and six months ended June 30, 2010 and 2009:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Reconciliation of gross margin and operating margin to net income (loss):
Gross margin	$	141.9		$	140.1		$	287.2		$	260.8
Operating expenses		49.4			46.9			100.4			99.2
Operating margin		92.5			93.2			186.8			161.6
Depreciation and amortization expense		(32.7	)		(30.6	)		(64.3	)		(60.8	)
General and administrative expense		(24.0	)		(28.9	)		(45.3	)		(50.0	)
Interest expense, net		(17.7	)		(30.4	)		(38.8	)		(60.5	)
Income tax expense		(0.9	)		(0.6	)		(2.4	)		(1.1	)
Other, net		3.5			(6.8	)		13.8			(0.6	)
Net income (loss)	$	20.7		$	(4.1	)	$	49.8		$	(11.4	)

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Reconciliation of net cash provided by operating	(In millions)
activities to Adjusted EBITDA:
Net cash provided by operating activities	$	24.8		$	80.3		$	129.9		$	172.8
Net income attributable to noncontrolling interest		(0.9	)		(0.4	)		(1.2	)		(0.3	)
Interest expense, net (1)		16.1			8.0			30.1			16.9
Current income tax expense		1.0			0.2			1.8			0.3
Other		0.6			0.1			(0.6	)		(0.5	)
Changes in operating working capital which used (provided) cash:
Accounts receivable and other		77.0			109.4			(58.8	)		(11.2	)
Accounts payable and other liabilities		(40.2	)		(116.2	)		57.8			(27.1	)
Adjusted EBITDA	$	78.4		$	81.4		$	159.0		$	150.9

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(1)

Net of amortization of debt issuance costs of $1.4 million and $2.7 million and amortization of interest swaps premiums of $0.3 million and $0.3 million for the three and six months ended 2010. Net of amortization of debt issuance costs of $0.7 million and $1.3 million and amortization of interest swaps premiums of $1.1 million and $1.1 million for the three and six months ended 2009.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Reconciliation of net income (loss) attributable to	(In millions)
Targa Resources Partners LP to Adjusted EBITDA:
Net income (loss) attributable to Targa Resources Partners LP	$	19.8		$	(4.5	)	$	48.6		$	(11.7	)
Add:
Interest expense, net		17.7			30.4			38.8			60.5
Income tax expense		0.9			0.6			2.4			1.1
Depreciation and amortization expense		32.7			30.6			64.3			60.8
Non-cash loss related to derivative instruments		7.5			24.5			5.4			40.6
Noncontrolling interest adjustment		(0.2	)		(0.2	)		(0.5	)		(0.4	)
Adjusted EBITDA	$	78.4		$	81.4		$	159.0		$	150.9

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Reconciliation of net income (loss) attributable to	(In millions)
Targa Resources Partners LP to distributable cash flow:
Net income (loss) attributable to Targa Resources Partners LP	$	19.8		$	(4.5	)	$	48.6		$	(11.7	)
Add:
Depreciation and amortization expense		32.7			30.6			64.3			60.8
Deferred income tax (expense) benefit		(0.1	)		0.4			0.6			0.8
Amortization of debt issue costs		1.4			0.7			2.7			1.3
Non-cash loss related to derivative instruments		7.5			24.5			5.4			40.6
Maintenance capital expenditures		(5.9	)		(8.7	)		(11.2	)		(16.5	)
Other		(0.2	)		(0.2	)		(0.3	)		(0.3	)
Distributable cash flow	$	55.2		$	42.8		$	110.1		$	75.0

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. Please see the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change depreciation amounts prospectively. Examples of such circumstances include:

changes in energy prices;

changes in competition;

changes in laws and regulations that limit the estimated economic life of an asset;

changes in technology that render an asset obsolete;

changes in expected salvage values; or

changes in the forecast life of applicable resource basins, if any.

As of June 30, 2010, the net book value of property, plant and equipment was $1,957.3 million and we recorded $32.7 million and $64.3 million in depreciation and amortization expense for the three and six months ended June 30, 2010. The weighted-average life of long-lived assets is approximately 20 years. If the useful lives of these assets were found to be shorter than originally estimated, depreciation and amortization expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result. For example, if the depreciable lives of assets were reduced by 10%, we estimate

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that depreciation and amortization expense would increase by $7.1 million, which would result in a corresponding reduction in operating income. In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, operating income would decrease by $19.6 million. There have been no material changes impacting estimated useful lives of the assets.

Revenue Recognition. Revenues for a period reflect collections to the report date, plus any uncollected revenues reported for the period, which are reflected as accounts receivable in the balance sheet. As of June 30, 2010, the balance sheet reflects total accounts receivable of $325.2 million, which is due from third-parties. The allowance for doubtful accounts as of June 30, 2010 was $7.6 million.

Exposure to uncollectible accounts receivable relates to the financial health of our counterparties. We and our indirect parent, Targa, have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectibility resulted in a 1% reduction of third-party accounts receivable, operating income would decrease by $3.2 million. There have been no material changes impacting accounts receivable.

Price Risk Management (Hedging). Net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of cash flows, we have entered into (i) derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities and (ii) interest rate financial instruments to fix the interest rate on a portion of our variable debt. We are exposed to the credit risk of our counterparties in these derivative financial instruments.

Our cash flow is affected by the derivative financial instruments we enter into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.

One of the primary factors that can affect our financial position each period is the price assumptions we use to value derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.

The estimated fair value of our commodity derivative financial instruments was $46.8 million as of June 30, 2010, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities, by year, for each counterparty’s traded credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to $0.7 million as of June 30, 2010. If a financial instrument counterparty were to declare bankruptcy, we would be exposed to the loss of fair value of the financial instrument transaction with that counterparty. Ignoring our adjustment for credit risk, if a bankruptcy by a financial instrument counterparty impacted 10% of the fair value of commodity-b ased financial instruments, we estimate that operating income would decrease by $4.7 million per year.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report.

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

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Our commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. Our principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations, in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges, are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secu re these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.

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As of June 30, 2010, we had the following hedge arrangements which will settle during the years ending December 31, 2010 through 2013 (except as indicated otherwise, the 2010 volumes reflect daily volumes for the period from July 1, 2010 through December 31, 2010):

Natural Gas

Instrument		Price		MMBtu per day
Type	Index	$/MMBtu		2010		2011		2012		2013		Fair Value
												(In millions)
Derivatives designated as hedging instruments
Swap	IF-NGPL MC		8.83		5,745		-		-		-	$	4.6
Swap	IF-NGPL MC		6.87		-		4,350		-		-		2.9
Swap	IF-NGPL MC		6.82		-		-		4,250		-		2.2
					5,745		4,350		4,250		-


Swap	IF-Waha		6.55		17,991		-		-		-		6.7
Swap	IF-Waha		6.20		-		15,500		-		-		6.1
Swap	IF-Waha		6.43		-		-		11,220		-		3.8
Swap	IF-Waha		5.59		-		-		-		4,000		-
					17,991		15,500		11,220		4,000


Swap	IF-PB		5.42		680		-		-		-		0.1
Swap	IF-PB		5.42		-		680		-		-		0.1
Swap	IF-PB		5.54		-		-		1,360		-		0.1
Swap	IF-PB		5.54		-		-		-		1,360		-
					680		680		1,360		1,360


Total Sales					24,416		20,530		16,830		5,360

Derivatives not designated as hedging instruments
Basis Swaps	Various Indexes, Maturities July 2010 - May 2011												0.6
Swaps	Various Indexes, Maturities July 2010 - May 2012												(0.1	)
												$	27.1

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NGLs

Instrument		Price		Barrels per day
Type	Index	$/gal		2010		2011		2012		2013		Fair Value
												(In millions)
Derivatives designated as hedging instruments
Swap	OPIS-MB		1.11		7,328		-		-		-	$	13.1
Swap	OPIS-MB		0.85		-		5,824		-		-		3.3
Swap	OPIS-MB		0.89		-		-		3,950		-		2.9
Total Swaps					7,328		5,824		3,950		-


Floor	OPIS-MB		1.44		-		223		-		-		1.6
Floor	OPIS-MB		1.43		-		-		259		-		1.9
Total Floors					-		223		259		-

Total Sales					7,328		6,047		4,209		-
												$	22.8

Condensate

Instrument		Price		Barrels per day
Type	Index	$/Bbl		2010		2011		2012		2013		Fair Value
												(In millions)
Derivatives designated as hedging instruments
Swap	NY-WTI		71.38		690		-		-		-	$	(0.7	)
Swap	NY-WTI		76.87		-		566		-		-		(0.6	)
Swap	NY-WTI		72.60		-		-		308		-		(0.9	)
Swap	NY-WTI		73.93		-		-		-		308		(0.9	)
					690		566		308		308

Total Sales					690		566		308		308
												$	(3.1	)

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant 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. We determine the value of our NGL 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.

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As of June 30, 2010 we had the following open interest rate swaps:

Period	Fixed Rate		Notional Amount			Fair Value
						(In millions)
Remainder of 2010		3.67%	$	300	million	$	(5.0	)
2011		3.52%		300	million		(6.5	)
2012		3.40%		300	million		(5.8	)
2013		3.39%		300	million		(3.0	)
1/1 - 4/24/2014		3.39%		300	million		(0.7	)
						$	(21.0	)

We have designated all interest rate swaps and interest rate basis swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the swaps are deferred in OCI until 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 interest rate swaps and interest rate basis swaps, would increase annual interest expense by $4.3 million.

Counterparty Risk – Credit and Concentration

We have master agreements with most of our hedge counterparties. These netting agreements allow us to net settle asset and liability positions with the same counterparty As of June 30, 2010, we had $7.9 million in liabilities to offset the default risk of counterparties with which we also had asset positions of $56.2 million as of that date.

As of June 30, 2010, affiliates of Goldman Sachs, Barclays and Credit Suisse accounted for 48%, 33% and 7% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Barclays and Credit Suisse are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

Item 4. 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

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Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures provide reasonable assurance that information required to be disclosed 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.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the six months ended June 30, 2010 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, under the heading “Legal Proceeding” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, 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, 2009. These risks and uncertainties are not the only ones facing us, and there may be additional matters of which we are unaware, or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations, as could the following:

Recent events in the Gulf of Mexico may result in facility shut-downs and in increased governmental regulation.

On April 20, 2010, the Transocean Deepwater Horizon drilling rig exploded and subsequently sank 130 miles south of New Orleans, Louisiana, and the resulting release of crude oil into the Gulf of Mexico has been declared a Spill of National Significance by the United States Department of Homeland Security. We cannot predict with any certainty the impact of this oil spill, the extent of cleanup activities associated with this spill, or possible changes in regulations that may be enacted in response to this spill, but this event and its aftermath could adversely affect our operations as follows:

Although our operations have not been impacted as of the date of this report, the ultimate result of the oil spill may result in oil reaching our coastal facilities and may require us to shut down the facilities until any impact on our operations can be safely corrected. This may reduce the volume of natural gas that our facilities process, and result in lower mixed NGL volumes for our fractionation business and lower NGL volumes for our NGL logistics and marketing business.

Third party offshore natural gas and NGL production might be temporarily reduced as a result of the oil spill and associated cleanup activities which could temporarily reduce the supply of natural gas to our processing facilities and result in lower mixed NGL volumes for our fractionation business and lower NGL volumes for our NGL logistics and marketing business.

Longer term in the aftermath of this oil spill, any additional governmental regulation of the offshore exploration and production industry may negatively impact volumes being gathered and processed by our facilities, and may potentially reduce volumes in our downstream logistics and marketing business.

The shutdown of our facilities or other curtailment of our operations could materially impact our business, financial condition and results of operations.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to hedge risks associated with our business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements in connection with our derivative activities, although the application

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of those provisions to us is uncertain at this time. The financial reform legislation also requires many counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including those requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulatio ns, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

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

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. (Removed and Reserved).

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit Index

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
3.2	Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
3.3	Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
3.4	First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
3.5	Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
3.6	Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
4.1	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.2	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.3	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.4	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.5	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.6	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.6 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.7	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).

4.8	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.9	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.9 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.10	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.10 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.11	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.11 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
4.12	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.12 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 6, 2010 (File No. 001-33303)).
10.1	Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (file No. 001-33303)).
10.2	First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (file No. 001-33303)).
10.3	Amended and Restated Credit Agreement, dated July 19, 2010, by and among Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 21, 2010 (file No. 001-33303)).
31.1**	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2**	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	Certification of the 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 the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Filed herewith

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 Partners LP

(Registrant)

By: Targa Resources GP LLC,

its general partner

By: /s/ John Robert Sparger

John Robert Sparger

Senior Vice President and Chief Accounting Officer

(Authorized signatory and Principal Accounting Officer)

Date: August 5, 2010

ex31-1.htm

Exhibit 31.1

CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A)/15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934

I, Rene R. Joyce, certify that:

I have reviewed this Quarterly Report on Form 10-Q for the period ended June 30, 2010 of Targa Resources Partners LP;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 5, 2010

By: /s/ RENE R. JOYCE

Name: Rene R. Joyce

Title: Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

ex31-2.htm

Exhibit 31.2

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A)/15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934

I, Jeffrey J. McParland, certify that:

I have reviewed this Quarterly Report on Form 10-Q for the period ended June 30, 2010 of Targa Resources Partners LP;

(a)

(b)

(c)

(d)

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 5, 2010

By: /s/ JEFFREY J. MCPARLAND

Name: Jeffrey J. McParland

Title: Executive Vice President and Chief Financial Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Financial Officer)

ex32-1.htm

Exhibit 32.1

CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended June 30, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Rene R. Joyce, as Chief Executive Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By: /s/ RENE R. JOYCE

Name: Rene R. Joyce

Title: Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

Date: August 5, 2010

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request

ex32-2.htm

Exhibit 32.2

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended June 30, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Jeffrey J. McParland, as Chief Financial Officer of Targa Resources GP LLC, the general partner of the Partnership, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

By: /s/ JEFFREY J. MCPARLAND

Name: Jeffrey J. McParland

Title: Executive Vice President and Chief Financial Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Financial Officer)

Date: August 5, 2010