Exhibit 99.1

1000 Louisiana, Suite 4300
Houston, TX 77002
713.584.1000
www.targaresources.com

Targa Resources Partners LP Reports Second Quarter 2010 Financial Results

HOUSTON — August 5, 2010 — Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) (NYSE: NGLS) today reported second quarter 2010 net income attributable to Targa Resources Partners of $19.8 million, or $0.23 per diluted limited partner unit, compared to a net loss of $4.5 million, or $0.10 per diluted limited partner unit, for the second quarter of 2009. Net income for the second quarters of 2010 and 2009 included $7.5 million and $24.5 million in non-cash charges related to derivative instruments, respectively. The second quarter of 2009 also included $20.7 million in affiliate interest expense for periods prior to the acquisition of the Downstream, Permian and Coastal Straddle businesses by the Partnership. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments (“Adjusted EBITDA”) of $78.4 million for the second quarter of 2010 compared to $81.4 million for the second quarter of 2009.

Distributable cash flow for the second quarter of 2010 of $55.2 million corresponds to distribution coverage of approximately 1.4 times the $40.2 million in total distributions to be paid on August 13, 2010 (see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, operating margin and distributable cash flow, and reconciliations of such measures to the comparable GAAP measures).

“The Partnership reported strong operating and financial results for the second quarter, supported by healthy Gathering and Processing inlet volumes and solid performance in the Downstream Business,” said Rene Joyce, Chief Executive Officer of the Partnership’s general partner. “We have also recently completed a number of strategic initiatives. We closed the accretive acquisition of the Permian and Straddle businesses during the quarter; executed a new $1.1 billion senior secured revolving credit facility that boosts the Partnership’s liquidity and reflects the strength of our operations; announced a new growth project in the Downstream Business and implemented management’s recommended 2%, year-over-year distribution increase for the quarter.”

On July 21, 2010, the Partnership announced a cash distribution of 52.75¢ per common unit, or $2.11 per unit on an annualized basis, for the second quarter of 2010. The cash distribution will be paid on all outstanding common and general partner units to holders of record as of the close of business on August 6, 2010.

Capitalization and Liquidity Update

Total funded debt as of June 30, 2010 was approximately $1,159.4 million including $729.8 million outstanding under the Partnership’s former $977.5 million senior secured revolving credit facility, $209.1 million of 8.25% senior unsecured notes due 2016 and $220.5 million of 11.25% senior unsecured notes due 2017.

On April 27, 2010, the Partnership acquired Targa Resources, Inc.’s interests in its Permian and Straddle Systems for $420.0 million, effective April 1, 2010. The Partnership financed this acquisition substantially through borrowings under its senior secured revolving credit facility.

As of June 30, 2010, the Partnership had $113.1 million in capacity available under its senior secured revolving credit facility after giving effect to the Lehman default and the issuance of $115.6 million of letters of credit. As of June 30, 2010, the Partnership had $43.7 million of cash, bringing total liquidity to approximately $156.8 million.

On July 19, 2010, the Partnership executed a new, five year $1.1 billion senior secured revolving credit facility. The new credit facility, which matures July 2015, amends and restates the Partnership’s former $977.5 million senior secured revolving credit facility due February 2012. As of June 30, 2010 and pro forma for the closing of the new credit facility, the Partnership had available capacity under the new credit facility of $254.6.

We estimate that total capital expenditures of the Partnership will be approximately $145 million in 2010. Maintenance capital expenditures account for approximately 25% of the total 2010 estimate.

Conference Call

Targa Resources Partners will host a conference call for investors and analysts at 10 a.m. Eastern Time (9 a.m. Central Time) on August 5, 2010 to discuss second quarter 2010 financial results. The conference call can be accessed via Webcast through the Events and Presentations section of the Partnership’s website at www.targaresources.com, by going directly to http://ir.targaresources.com/events.cfm?company=LP or by dialing 877-881-2598. The pass code for the dial-in is 89607543. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following completion of the Webcast through the Events and Presentations section of the Partnership’s website and will remain available until August 19, 2010. Replay access numbers are 800-642-1687 or 706-645-9291 with pass code 89607543.

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Consolidated Financial Results of Operations

With the closing of the acquisition of the Downstream Business in 2009 and the Permian and Straddle Systems in 2010, and in accordance with the accounting treatment for entities under common control, the results of operations of the Partnership include the historical results of the Downstream Business and Permian and Straddle Systems for all periods presented.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In millions, except
	operating and price data)
Revenues (1)	$	1,204.0		$	979.2		$	2,649.0		$	1,964.7
Product purchases		1,062.1			839.1			2,361.8			1,703.9
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
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	)
Other		3.5			(7.5	)		13.8			(1.3	)
Income tax expense		(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 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	)
Basic and diluted net income (loss) per limited partner unit	$	0.23		$	0.10		$	0.37		$	0.01
Financial data:
Adjusted EBITDA (2)		78.4			81.4			159.0			150.9
Distributable cash flow (3)		55.2			42.8			110.1			75.0

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

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(2)	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.”
(3)	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.”

Review of Consolidated Second Quarter Results

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 insurance 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 “Review of Segment Performance.”

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 to lower interest rates on third party debt than on affiliate debt associated with predecessor operations.

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 related 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 insurance proceeds and lower hedge settlements.

For additional information regarding the period to period changes in our gross margins, see “Review of Segment Performance.”

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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 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 $37.9 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 driven by the timing of allocations under common control.

Review of Segment Performance

The following discussion of segment performance includes inter-segment revenues. The Partnership views segment operating margin as an important performance measure of the core profitability of its operations. This measure is a key component of internal financial reporting and is reviewed for consistency and trend analysis. Operating margin is revenues less product purchases and operating expenses. 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.

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.

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Field Gathering and Processing Segment

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	($ in millions)
Gross margin	$	58.7		$	45.0		$	121.6		$	84.1
Operating expenses		(15.1	)		(13.1	)		(29.6	)		(27.8	)
Operating margin (1)	$	43.6		$	31.9		$	92.0		$	56.3
Operating statistics (2):
Plant natural gas inlet, MMcf/d
Permian System		129.0			118.6			126.8			119.5
SAOU System		97.6			93.0			94.6			92.2
North Texas System		175.0			179.8			174.5			178.0
		401.6			391.4			395.9			389.7
Gross NGL production, MBbl/d
Permian System		14.6			13.4			14.4			13.5
SAOU System		15.2			14.3			14.7			14.3
North Texas System		20.2			20.9			20.0			20.3
		50.0			48.6			49.1			48.1
Natural gas sales, BBtu/d		193.7			165.8			189.7			169.4
NGL sales, MBbl/d		41.9			39.6			41.0			39.4
Condensate sales, MBbl/d		2.7			2.8			2.3			2.8
Average realized prices:
Natural gas, $/MMBtu		3.78			2.76			4.43			3.22
NGL, $/gal		0.86			0.62			0.93			0.58
Condensate, $/Bbl		73.90			55.62			74.90			45.92

(1)	Operating margin is revenues less product purchases and operating expenses and excludes impact of hedges
(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.

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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

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 expirations in our North Texas System.

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.

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Coastal Gathering and Processing Segment

The Coastal Gas Gathering and Processing segment consists of 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. Coastal Gathering and Processing segment assets are located in the onshore region of the Louisiana Gulf Coast and Gulf of Mexico.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	($ in millions)
Gross margin	$	21.1		$	19.7		$	45.3		$	37.7
Operating expenses		(6.9	)		(6.5	)		(12.9	)		(14.4	)
Operating margin (1)	$	14.2		$	13.2		$	32.4		$	23.3
Operating statistics (2):
Plant natural gas inlet, MMcf/d (3)
LOU System		195.4			182.0			204.3			161.4
Straddle System		1,126.5			998.2			1,130.8			898.9
		1,321.9			1,180.2			1,335.1			1,060.3
Gross NGL production, MBbl/d
LOU System		7.2			9.0			7.6			8.3
Straddle System		21.3			15.7			20.7			13.8
		28.5			24.7			28.3			22.1
Natural gas sales, BBtu/d		310.3			248.1			312.1			231.7
NGL sales, MBbl/d		32.4			25.4			31.6			23.0
Condensate sales, MBbl/d		0.4			1.3			0.8			1.4
Average realized prices:
Natural gas, $/MMBtu		4.25			3.68			4.76			4.23
NGL, $/gal		0.99			0.70			1.04			0.66
Condensate, $/Bbl		81.16			53.22			77.98			44.66

(1)	Operating margin is revenues less product purchases and operating expenses and excludes impact of hedges.
(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.

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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 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.

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.

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.

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Logistics Assets Segment

The Logistics Assets segment is involved in gathering 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 following table provides summary data regarding results of operations of this segment for the periods indicated:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	($ in millions)
Gross margin (1)	$	40.8		$	40.3		$	78.4		$	70.4
Operating expenses		(22.8	)		(20.2	)		(49.1	)		(44.2	)
Operating margin (2)	$	18.0		$	20.1		$	29.3		$	26.2
Operating statistics:
Fractionation volumes, MBbl/d		228.4			230.0			219.0			210.0
Treating volumes, MBbl/d (3)		21.8			19.5			14.7			14.0

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

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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.

Marketing and Distribution Segment

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids. 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.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	($ in millions)
Gross margin	$	24.9		$	29.5		$	55.9		$	63.0
Operating expenses		(10.8	)		(12.8	)		(22.0	)		(24.0	)
Operating margin (1)	$	14.1		$	16.7		$	33.9		$	39.0
Operating statistics:
Natural gas sales, BBtu/d		668.3			479.0			639.0			465.1
NGL sales, MBbl/d		234.8			283.3			240.6			288.9
Natural gas realized price, $/gal		4.10			3.25			4.64			3.63
NGL realized price, $/gal		1.03			0.69			1.11			0.68

(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

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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 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.

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

Other

Other includes the impact on operating margin of the Partnership’s derivatives hedging activities.

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 $12.0 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 $17.5 million in additional revenue from our hedge counterparties, which were recorded as an increase to gross margin from hedge settlements. Cash

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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.

About Targa Resources Partners

Targa Resources Partners was formed by Targa Resources, Inc. (“Targa” or the “Company”) to engage in the business of gathering, compressing, treating, processing and selling natural gas and fractionating, treating and selling natural gas liquids and natural gas liquids products. Targa Resources Partners owns an extensive network of integrated gathering pipelines and natural gas processing plants and currently operates in the Permian Basin in West Texas, the Fort Worth Basin in North Texas and the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana. Additionally, our natural gas liquids logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana with terminals and transportation assets across the United States. A subsidiary of Targa is the general partner of Targa Resources Partners.

Targa Resources Partners’ principal executive offices are located at 1000 Louisiana, Suite 4300, Houston, Texas 77002 and its telephone number is 713-584-1000. For more information, visit www.targaresources.com.

Non-GAAP Financial Measures

This press release and accompanying schedules include the non-GAAP financial measures Adjusted EBITDA, operating margin and distributable cash flow. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”). Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of liquidity or financial performance.

Distributable Cash Flow— We define distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses/(gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures. Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by the board of directors of our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flow sufficient to make distributions to our investors. The GAAP measure most directly comparable to distributable cash flow is

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net income. Distributable cash flow should not be considered as an alternative to GAAP net income. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be compatible to similarly titled measures of other companies, thereby diminishing its utility. We compensate for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision making processes.

The following table presents a reconciliation of net income to distributable cash flow for the periods indicated:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In millions)
Reconciliation of net income (loss) attributable to 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

Adjusted EBITDA—The Partnership defines Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by management and by external users of the Partnership’s financial statements such as investors, commercial banks and others, to assess: (1) the financial performance of the Partnership’s assets without regard to financing methods, capital structure or historical cost basis; (2) the Partnership’s operating performance and return on capital compared to other companies in the midstream energy sector, without regard to financing or capital structure; and (3) the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

The economic substance behind management’s use of Adjusted EBITDA is to measure the ability of the Partnership’s assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to unitholders. The GAAP measure most directly comparable to Adjusted EBITDA is net income. The Partnership’s non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies, the Partnership’s definition of Adjusted EBITDA may not be comparable to

14

similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into its decision-making processes.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In millions)
Reconciliation of net cash provided by operating 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

(1) Net of amortization of debt issuance costs of $1.4 million and $0.7 million and amortization of interest swaps premiums of $0.3 million and $0.3 million for the three month and sixth months ended 2010. Net of amortization of debt issuance costs of $2.7 million and $1.3 million and amortization of interest swaps premium 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
	(In millions)
Reconciliation of net income (loss) attributable to 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 derivatives		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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Gross Margin. With respect to our Natural Gas Gathering and Processing segments, 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 segment we define operating margin as total revenue, which consists primarily of service fee revenues. With respect to our Marketing and Distribution segments, we define operating 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 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 Partnership’s non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of the Partnership’s results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies, the Partnership’s definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into its decision-making processes.

	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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Forward-Looking Statements

Certain statements in this release are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside Targa Resources Partners’ control, which could cause results to differ materially from those expected by management of Targa Resources Partners. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including declines in the production of natural gas or in the price and market demand for natural gas and natural gas liquids, the timing and success of business development efforts, the credit risk of customers and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Partnership’s reports and other filings with the Securities and Exchange Commission. Targa Resources Partners undertakes no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Investor contact info:

Phone: 713-584-1133

Anthony Riley
Senior Manager — Finance/Investor Relations

Matt Meloy
Vice President — Finance and Treasurer

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TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED BALANCE SHEET DATA
(In millions)

	June 30,		December 31,
	2010		2009
ASSETS
Current assets:
Cash and cash equivalents	$	43.7	$	60.4
Trade receivables		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, net		1,957.3		1,983.6
Long-term assets from risk management activities		20.7		10.9
Other assets		37.9		39.1
Total assets	$	2,462.5	$	2,550.7
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	393.5	$	448.8
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
Other long-term liabilities		23.0		24.2
Total liabilities		1,606.6		1,766.0
Owners’ equity:
Targa Resources Partners LP owners’ equity		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

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TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
REVENUES	$	1,204.0		$	979.2		$	2,649.0		$	1,964.7
Product purchases		1,062.1			839.1			2,361.8			1,703.9
Operating expenses		49.4			46.9			100.4			99.2
Depreciation and amortization expense		32.7			30.6			64.3			60.8
General and administrative expense		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
Income (loss) before income taxes		21.6			(3.5	)		52.2			(10.3	)
Income tax (expense) benefit		(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 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

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TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED CASH FLOW STATEMENTS
(In millions)

	Six Months Ended
	June 30,
	2010			2009
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:
Depreciation, amortization, and accretion		67.9			62.9
Deferred income tax expense		0.6			0.8
Interest expense on affiliated indebtedness		5.7			41.3
Risk management activities		5.7			41.7
Equity in earnings of unconsolidated investment, net of distribution		(0.7	)		(1.0	)
Loss on debt repurchases		—			—
Loss (gain) on sale of assets		(0.1	)		0.2
Changes in operating assets and liabilities		1.0			38.3
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 on credit facility		(385.2	)		(40.0	)
Repayment of affiliated indebtedness		(332.8	)		—
Proceeds from equity offerings		139.7			—
Distributions to unitholders		(77.6	)		(52.7	)
General partner contributions		3.0			—
Distributions to noncontrolling interest		(0.5	)		(0.9	)
Distributions under common control		(4.5	)		(79.1	)
Parent distributions		(87.2	)		—
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

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