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Exhibit 99.1


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

Targa Resources Partners LP Reports Third Quarter 2010 Financial Results and
Distribution Increase for Fourth Quarter 2010 to be Recommended by Management

HOUSTON — November 4, 2010 — Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) (NYSE: NGLS) today reported third quarter 2010 net income attributable to Targa Resources Partners of $13.8 million, or $0.14 per diluted limited partner unit, compared to a net loss of $4.2 million, or $0.23 per diluted limited partner unit, for the third quarter of 2009. Net income for the third quarters of 2010 and 2009 included $7.8 million and $17.1 million in non-cash charges related to derivative instruments, respectively. The third quarters of 2010 and 2009 also included $3.9 million and $29.4 million in affiliate interest expenses, respectively, for periods prior to the acquisition of the Downstream Business, the Permian, Straddle and Versado Systems and VESCO 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 $91.4 million for the third quarter of 2010 compared to $98.9 million for the third quarter of 2009.

Distributable cash flow for the third quarter of 2010 of $57.1 million corresponds to distribution coverage of over 1.2 times the $46.1 million in total distributions to be paid on November 12, 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).

“In addition to delivering strong third quarter financial results we are pleased to have completed a number of key growth initiatives during the quarter,” said Rene Joyce, Chief Executive Officer of the Partnership’s general partner and of Targa Resources, Inc (“Targa”). “During the quarter we closed two accretive acquisitions from Targa including interests in the Versado and VESCO gathering and processing systems; announced two growth projects in the Downstream Business; approved very attractive expansion projects associated with our operations in the Permian Basin of West Texas and approved management’s recommended distribution increase for the third quarter. We continue to see incremental growth opportunities for our Gathering and Processing and Downstream Businesses and we therefore plan to recommend to the Board of Directors a 4 cent increase in the annualized cash distribution rate to $2.19 per common unit for the fourth quarter of 2010 distribution.”

The fourth quarter recommended cash distribution of 54.75¢ per common unit, or $2.19 unit on an annualized basis, (if approved by the board) is currently expected to be declared in January 2011 and paid in February 2011.

On October 8, 2010, the Partnership announced a cash distribution of 53.75¢ per common unit, or $2.15 per unit on an annualized basis, for the third quarter of 2010. The cash distribution will be paid on November 12, 2010 to all outstanding common and general partner units to holders of record as of the close of business on October 18, 2010.

Capitalization, Liquidity and Financing Update

Total funded debt as of September 30, 2010 was approximately $1,433.2 million including $753.3 million outstanding under the Partnership’s $1.1 billion senior secured revolving credit facility, $209.1 million of 8.25% senior unsecured notes due 2016, $220.8 million of 11.25% senior unsecured notes due 2017 and $250 million of 7.875% senior unsecured notes due 2018.

On July 19, 2010, the Partnership entered into an amended and restated five-year $1.1 billion senior secured revolving credit facility due July 2015 that allows for increases in commitments up to an additional $300 million. The new senior secured credit facility amends and restates the former $977.5 million senior secured revolving credit facility due February 2012.

On August 13, 2010, the Partnership completed a public offering of 7,475,000 common units (6,500,000 common units plus an overallotment option of 975,000 common units) and the private offering of $250 million of 7.875% Senior Notes due 2018. The Partnership used the net proceeds from these offerings to reduce borrowings under the senior secured credit facility.

On August 25, 2010, the Partnership acquired Targa Resources, Inc.’s interests in the Versado System for $247.2 million. On September 28, 2010, the Partnership acquired Targa Resources, Inc.’s interests in VESCO for $175.6 million. The Partnership financed these acquisitions substantially through borrowings under its senior secured revolving credit facility.

As of September 30, 2010, the Partnership had $245.2 million in capacity available under its senior secured revolving credit facility after giving effect to the issuance of $101.5 million of letters of credit.

We estimate that total capital expenditures of the Partnership will be approximately $145 million for 2010. Maintenance capital expenditures account for approximately 35% of the total 2010 estimate.

Conference Call

Targa Resources Partners will host a conference call for investors and analysts at 12 p.m. Eastern Time (11 a.m. Central Time) on November 4, 2010 to discuss third 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 22737218. 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 Investor’s section of the Partnership’s website. Telephone replay access numbers are 800-642-1687 or 706-645-9291 with pass code 22737218 and will remain available, along with the Webcast, until November 18, 2010.

Consolidated Financial Results of Operations

With the closing of the acquisition of the Downstream Business in 2009, the Permian, Straddle and Versado Systems and VESCO 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, Permian, Straddle and Versado Systems and VESCO for all periods presented.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions, except
	operating and price data)
Revenues (1)	$	1,216.9		$	1,118.0		$	3,938.3		$	3,120.6
Product purchases		1,032.1			936.2			3,387.7			2,624.6

Gross margin (2)		184.8			181.8			550.6			496.0
Operating expenses		66.0			63.2			190.2			182.1

Operating margin (3)		118.8			118.6			360.4			313.9
Depreciation and amortization expense		43.3			43.1			128.3			125.0
General and administrative expense		26.7			22.6			80.0			81.9
Casualty loss adjustment		—			—			—			(3.8	)

Income from operations		48.8			52.9			152.1			110.8
Other income (expense):
Interest expense from affiliate		(2.5	)		(27.2	)		(23.8	)		(84.2	)
Interest expense allocated from Parent		(1.4	)		(2.2	)		(5.6	)		(6.9	)
Other interest expense, net		(23.3	)		(16.1	)		(56.4	)		(35.2	)
Other		(1.5	)		(6.2	)		29.0			(9.2	)
Income tax benefit (expense)		(1.7	)		0.2			(3.9	)		(0.9	)

Net income		18.4			1.4			91.4			(25.6	)
Less: Net income attributable to noncontrolling interest		4.6			5.6			18.2			11.9

Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)


Net loss attributable to predecessor operations	$	(1.3	)	$	(18.4	)	$	25.8		$	(53.4	)
Net income attributable to general partner		5.0			2.8			12.0			6.7
Net income allocable to limited partners		10.1			11.4			35.4			9.2

Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)


Basic and diluted net income (loss) per limited partner unit	$	0.14		$	0.23		$	0.51		$	0.19

Financial data:
Adjusted EBITDA (4)		91.4			98.9			278.7			278.6
Distributable cash flow (5)		57.1			78.8			198.8			216.8


(1)		Includes business interruption insurance revenues of $1.0 million and $6.0 million for the three and nine 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.”

Review of Consolidated Second Quarter Results

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

Revenue increased $98.9 million due to higher commodity prices ($183.1 million) offset by lower sales volumes ($83.8 million) and lower fee-based and other revenues ($0.4 million).

The $3.0 million increase in gross margin reflects higher revenue of $98.9 million offset by higher product purchase costs of $95.9 million.

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

The $2.8 million 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, as well as incremental depreciation on capital expenditures in 2010 of $36.5 million.

The increase in general and administrative expense reflects primarily higher compensation costs and 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.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Revenues increased $817.7 million due to higher commodity prices ($1,080.5 million) offset by lower sales volumes ($249.0 million), lower business interruption proceeds ($6.0 million) and lower fee-based and other revenues ($7.8 million).

The $54.6 million increase in gross margin reflects higher revenues of $817.7 million, offset by higher product purchase costs of $763.1 million.

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

The $8.1 million 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.

The decrease in interest expense was primarily due to lower interest rates on third party debt than on affiliate debt associated with predecessor operations.

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.

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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	($ in millions)
Gross margin	$	77.4		$	68.5		$	250.4		$	187.1
Operating expenses		(27.8	)		(22.6	)		(73.6	)		(63.7	)

Operating margin (1)	$	49.6		$	45.9		$	176.8		$	123.4


Operating statistics (2):
Plant natural gas inlet, MMcf/d
Permian System		127.3			114.6			127.0			117.8
SAOU System		102.6			92.0			97.3			92.1
North Texas System		182.7			172.7			177.2			176.2
Versado System		171.0			200.8			180.5			199.5

		583.6			580.1			582.0			585.6


Gross NGL production, MBbl/d
Permian System		14.9			12.8			14.5			13.2
SAOU System		15.6			14.0			15.0			14.2
North Texas System		20.9			20.5			20.3			20.5
Versado System		19.2			22.2			20.4			22.2

		70.6			69.5			70.2			70.1


Natural gas sales, BBtu/d		254.5			241.4			257.2			244.0
NGL sales, MBbl/d		54.9			55.3			55.6			55.4
Condensate sales, MBbl/d		3.1			3.3			3.0			3.5
Average realized prices:
Natural gas, $/MMBtu		4.00			2.95			4.30			3.12
NGL, $/gal		0.86			0.72			0.91			0.63
Condensate, $/Bbl		72.10			63.61			73.82			51.41


(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 September 30, 2010 Compared to Three Months Ended September 30, 2009

The $8.9 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($56.5 million) and an increase in natural gas sales volumes ($3.6 million) partially offset by a decrease NGL and condensate revenue ($2.1 million), fee-based and other revenues ($1.5 million) and increased commodity purchase costs ($47.6 million). The increased volumes were largely attributable to new well connects throughout our systems, partially offset by production declines at our Versado System, combined with planned and unplanned operational outages at our Eunice Plant.

The $5.2 million increase in operating expenses for 2010 was primarily due to increases in system maintenance expenses of $3.2 million, primarily attributable to the Eunice plant operational outages and higher compensation and benefits costs of $1.3 million.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $63.3 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($280.1 million), an increase in natural gas and NGL sales volumes ($12.4 million) and an increase in fee-based and other revenues ($2.4 million), offset by lower condensate sales volumes ($6.2 million) and increased commodity purchase costs ($225.4 million). The increased volumes were largely attributable to new well connects throughout our systems, partially offset at Versado by production declines in the high volume Morrow formation combined with operational outages.

The $9.9 million increase in operating expenses for 2010 was primarily due to increases in system maintenance expenses of $5.2 million and compensation and benefits costs of $2.5 million.

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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
				($ in millions)
Gross margin	$	34.2		$	34.2		$	106.3		$	87.7
Operating expenses		(10.7	)		(14.1	)		(31.4	)		(34.9	)

Operating margin (1)	$	23.5		$	20.1		$	74.9		$	52.8


Operating statistics (2):
Plant natural gas inlet, MMcf/d (3)
LOU System		163.7			199.4			190.6			174.2
Straddle System		1,041.3			1,149.0			1,100.6			983.2
VESCO System		427.7			345.8			423.3			354.7

		1,632.7			1,694.2			1,714.5			1,512.1


Gross NGL production, MBbl/d
LOU System		7.1			9.0			7.4			8.5
Straddle System		19.1			20.2			20.1			16.0
VESCO System		24.8			24.8			23.0			22.5

		51.0			54.0			50.5			47.0


Natural gas sales, BBtu/d		292.0			283.5			305.3			249.2
NGL sales, MBbl/d		42.4			44.2			44.0			39.5
Condensate sales, MBbl/d		0.2			1.5			0.6			1.6
Average realized prices:
Natural gas, $/MMBtu		4.41			3.42			4.64			3.88
NGL, $/gal		0.93			0.78			1.00			0.69
Condensate, $/Bbl		72.42			78.81			78.45			55.59


(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 September 30, 2010 Compared to Three Months Ended September 30, 2009

Gross margin for 2010 was flat when compared to 2009 due to an increase in commodity sales prices ($51.3 million), natural gas sales volumes ($2.7 million) and fee-based and other revenues ($0.2 million), offset by a decrease in NGL and condensate sales volumes ($14.5 million) and an increase in product purchase costs ($39.7 million). Natural gas sales volumes increased due to increased sales to affiliates for resale partially offset by a decrease in demand from our industrial customers. NGL sales volumes decreased primarily due to reduced plant inlet volumes resulting from a decline in traditional wellhead and offshore supply volumes.

The $3.4 million decrease in operating expenses for 2010 was primarily due to lower system maintenance expenses.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $18.6 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($224.0 million) and commodity sales volumes ($80.6 million), offset by a decrease in fee-based and other revenues ($5.7 million) and increased commodity purchase costs ($280.3 million). Natural gas sales volumes increased due to increased demand from our industrial customers and increased sales to affiliates for resale. NGL sales volumes increased primarily due to the straddle plants recovering operations in 1Q and 2Q 2009 after hurricanes Gustav and Ike in 2008.

The $3.5 million decrease in operating expenses for 2010 was primarily due to lower system maintenance expenses, reflecting hurricane related spending in 2009.

Logistics Assets Segment

The Logistics Assets segment is involved in gathering and storing mixed NGLs and fractionating and storing 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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	($ in millions)
Gross margin (1)	$	43.1		$	39.4		$	121.5		$	109.9
Operating expenses		(19.5	)		(18.0	)		(68.6	)		(62.4	)

Operating margin (2)	$	23.6		$	21.4		$	52.9		$	47.5


Operating statistics:
Fractionation volumes, MBbl/d		224.6			225.9			220.9			215.4
Treating volumes, MBbl/d (3)
		23.8			27.5			17.8			18.5


(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 September 30, 2010 Compared to Three Months Ended September 30, 2009

The $3.7 million improvement in gross margin was primarily due to fractionation fee improvement.

Operating expenses increased primarily due to higher fuel and electricity expenses of $2.5 million driven by higher gas prices, higher compensation costs of $0.9 million, partially offset by favorable system product gains of $1.6 million.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $11.6 million improvement in gross margin reflects higher fractionation fees of $15.1 million, offset by lower terminalling and storage revenues of $1.0 million. During 2009, we received $1.9 million in business interruption proceeds.

Operating expenses increased due to higher fuel and electricity expense of $5.8 million primarily driven by higher gas prices and higher compensation costs of $3.2 million, which were partially offset by favorable system product gains of $3.3 million.

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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	($ in millions)
Gross margin	$	26.4		$	26.5		$	82.3		$	89.5
Operating expenses		(11.4	)		(11.9	)		(33.5	)		(35.9	)

Operating margin (1)	$	15.0		$	14.6		$	48.8		$	53.6


Operating statistics:
Natural gas sales, BBtu/d		612.6			561.9			630.1			497.7
NGL sales, MBbl/d		242.9			266.6			241.3			281.4
Natural gas realized price, $/gal		4.22			3.17			4.50			3.46
NGL realized price, $/gal		0.95			0.81			1.06			0.72


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

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

Gross margin was flat for the quarter, reflecting the impact of higher commodity prices on revenues ($184.0 million) and increased natural gas volumes ($14.8 million), offset by lower NGL volumes ($74.4 million) and increased product purchases ($125.2 million).

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 were relatively flat versus the prior quarter.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $7.2 million decrease in gross margin reflects increased commodity prices ($1,127.8 million) and higher natural gas volumes ($124.9 million), more than offset by lower NGL volumes ($330.8), lower fee based and other revenues ($20.5 million), lower business interruption proceeds ($0.5 million) and increased product purchases ($893.7 million). Lower 2010 margins on sales at inventory locations were primarily attributable 2009 sales that were fixed at relatively high 2008 prices, along with higher spot

fractionation volumes and associated fees. These items were partially offset by higher marketing fees on higher on contract purchase volumes attributable to higher 2010 market prices. Margins on transportation activity decreased due to the expiration of a barge contract partially offset by increased truck activity.

The decrease in operating expenses was primarily due to lower outside services of $5.5 million, partially offset by higher maintenance and supplies expenses of $2.6 million and higher compensation costs of $0.5 million. Factors contributing to the decrease were the expiration of a barge contract, partially offset by increased truck utilization.

Other

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

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

During 2010 and 2009, the settlement of our commodity derivatives resulted in $7.1 million and $16.7 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.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

During 2010 and 2009, the settlement of our commodity derivatives resulted in $7.0 million and $36.6 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.

About Targa Resources Partners

Targa Resources Partners is engaged in the business of gathering, compressing, treating, processing and selling natural gas and storing, fractionating, treating, transporting and selling natural gas liquids, or NGLs, and NGL products. The Partnership owns an extensive network of integrated gathering pipelines and gas processing plants and currently operates along the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana, the Permian Basin in West Texas and Southeast New Mexico and the Fort Worth Basin in North Texas. 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.

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 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						Nine Months Ended
	September 30,						September 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	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)
Add:
Allocated and affiliate interest expense		3.9			29.4			29.4			91.1
Depreciation and amortization expense		43.3			43.1			128.3			125.0
Deferred income tax (expense) benefit		(0.1	)		0.1			0.3			0.9
Amortization of debt issue costs		0.9			2.5			3.6			3.8
Gain on debt repurchases		0.8			0.4			0.8			0.4
Non-cash (gain) loss related to mark-to-market derivative instruments		7.8			17.1			(5.4	)		71.2
Maintenance capital expenditures		(12.9	)		(8.0	)		(28.5	)		(33.4	)
Reimbursements		0.4			—			0.4			—
Other		(0.8	)		(1.6	)		(3.3	)		(4.7	)

Distributable cash flow	$	57.1		$	78.8		$	198.8		$	216.8

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 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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions)
Reconciliation of net cash provided by operating
activities to Adjusted EBITDA:
Net cash provided by operating activities	$	60.8		$	114.3		$	240.0		$	303.6
Net (income) loss attributable to noncontrolling interest		(4.6	)		(5.6	)		(18.2	)		(11.9	)
Other interest expense, net		22.4			13.5			52.8			31.4
Current income tax (expense) benefit		1.8			(0.3	)		3.6			—
Other		(6.0	)		(5.4	)		(11.7	)		(11.1	)
Changes in operating working capital which used (provided) cash:
Accounts receivable and other		26.6			(27.3	)		(40.3	)		(17.6	)
Accounts payable and other liabilities		(9.6	)		9.7			52.5			(15.8	)

Adjusted EBITDA	$	91.4		$	98.9		$	278.7		$	278.6


(1)		Net of amortization of debt issuance costs of $0.9 million and $3.6 for the three month and nine months ended 2010 and $2.5 million and $3.8 million for the three and nine months ended 2009. Excludes affiliate and allocated interest expense.


	Three Months Ended						Nine Months Ended
	September 30,						September 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	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)
Add:
Interest expense, net		27.2			45.5			85.8			126.3
Income tax (expense) benefit		1.7			(0.2	)		3.9			0.9
Depreciation and amortization expense		43.3			43.1			128.3			125.0
Non-cash activities related to derivative instruments		7.8			17.1			(5.4	)		71.2
Noncontrolling interest adjustment		(2.4	)		(2.4	)		(7.1	)		(7.3	)

Adjusted EBITDA	$	91.4		$	98.9		$	278.7		$	278.6

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					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009
	(In millions)
Reconciliation of net income (loss) attributable to
Targa Resources Partners LP to operating margin:
Net income (loss) attributable to Targa Resources Partners LP	$	13.8	$	(4.2	)	$	73.2		$	(37.5	)
Add:
Depreciation and amortization expense		43.3		43.1			128.3			125.0
General and administrative expense		26.7		22.6			80.0			81.9
Interest expense, net		27.2		45.5			85.8			126.3
Income tax benefit (expense)		1.7		(0.2	)		3.9			0.9
Other, net		6.1		11.8			(10.8	)		17.3

Operating margin	$	118.8	$	118.6		$	360.4		$	313.9

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

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED BALANCE SHEET DATA
(In millions)


	September 30,		December 31,
	2010		2009
ASSETS
Current assets:
Cash and cash equivalents	$	54.5	$	90.9
Trade receivables		351.0		405.5
Inventory		54.9		39.3
Assets from risk management activities		37.9		32.9
Other current assets		1.0		1.9

Total current assets		499.3		570.5

Property, plant and equipment, net		2,480.0		2,526.6
Long-term assets from risk management activities		27.5		13.9
Other assets		56.2		41.8

Total assets	$	3,063.0	$	3,152.8

LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	420.9	$	474.8
Liabilities from risk management activities		20.5		29.2

Total current liabilities		441.4		504.0

Long-term debt payable to third parties		1,433.2		908.4
Long-term debt allocated from Targa Resources, Inc.		—		151.8
Long-term debt payable to Targa Resources, Inc.		—		764.8
Long-term liabilities from risk management activities		29.0		43.9
Other long-term liabilities		56.5		51.6

Total liabilities		1,960.1		2,424.5
Owners’ equity:
Targa Resources Partners LP owners’ equity		978.7		604.9
Noncontrolling interest in subsidiary		124.2		123.4

Total owners’ equity		1,102.9		728.3

Total liabilities and owners’ equity	$	3,063.0	$	3,152.8

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
REVENUES	$	1,216.9		$	1,118.0		$	3,938.3		$	3,120.6
Product purchases		1,032.1			936.2			3,387.7			2,624.6
Operating expenses		66.0			63.2			190.2			182.1
Depreciation and amortization expense		43.3			43.1			128.3			125.0
General and administrative expense		26.7			22.6			80.0			81.9
Casualty loss adjustment		—			—			—			(3.8	)

INCOME FROM OPERATIONS		48.8			52.9			152.1			110.8
Other income (expense):
Interest expense from affiliate		(2.5	)		(27.2	)		(23.8	)		(84.2	)
Interest expense allocated from Parent		(1.4	)		(2.2	)		(5.6	)		(6.9	)
Other interest expense, net		(23.3	)		(16.1	)		(56.4	)		(35.2	)
Equity in earnings of unconsolidated investment		1.1			1.4			3.8			3.2
Loss on mark-to-market derivative instruments		(1.9	)		(6.7	)		26.0			(12.1	)
Other		(0.7	)		(0.9	)		(0.8	)		(0.3	)

Income before income taxes		20.1			1.2			95.3			(24.7	)
Income tax (expense) benefit		(1.7	)		0.2			(3.9	)		(0.9	)

NET INCOME (LOSS)		18.4			1.4			91.4			(25.6	)
Less: Net income attributable to noncontrolling interest		4.6			5.6			18.2			11.9

NET INCOME (LOSS) ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)


Net loss attributable to predecessor operations	$	(1.3	)	$	(18.4	)	$	25.8		$	(53.4	)
Net income attributable to general partner		5.0			2.8			12.0			6.7
Net income allocable to limited partners		10.1			11.4			35.4			9.2

Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)


Net income per limited partner unit — basic and diluted	$	0.14		$	0.23		$	0.51		$	0.19

Weighted average limited partner units outstanding — basic and diluted		72.0			50.6			69.2			47.7

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED CASH FLOW STATEMENTS
(In millions)


	Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	91.4		$	(25.6	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization, and accretion		134.6			131.2
Deferred income tax expense		0.3			0.9
Interest expense on affiliated indebtedness		29.4			91.1
Risk management activities		(5.4	)		71.2
Equity in earnings of unconsolidated investment, net of distribution		1.1			0.7
Loss on debt repurchases		0.8			0.4
Loss on sale of assets		—			0.3
Changes in operating assets and liabilities		(12.2	)		33.4

Net cash provided by operating activities		240.0			303.6

CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment		(82.5	)		(72.0	)
Other, net		2.1			(2.0	)

Net cash used in investing activities		(80.4	)		(74.0	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility		1,178.1			397.6
Repayments of credit facility		(904.0	)		(374.9	)
Proceeds from issuance of senior notes		250.0			237.4
Repayment of affiliated indebtedness		(582.8	)		(397.4	)
Repayment of allocated indebtedness		(157.4	)		—
Repurchases of senior notes		—			(18.9	)
Parent distributions		(102.5	)		(137.5	)
Proceeds from equity offerings		317.8			103.5
Costs incurred in connection with financing arrangements		(20.2	)		(9.8	)
General partner contributions		6.8			2.2
Distribution to unitholders		(117.8	)		(79.0	)
Distributions under common control		(46.6	)		—
Distributions to noncontrolling interest		(17.4	)		(19.2	)

Net cash used in financing activities		(196.0	)		(296.0	)

Net change in cash and cash equivalents		(36.4	)		(66.4	)
Cash and cash equivalents, beginning of period		90.9			143.2

Cash and cash equivalents, end of period	$	54.5		$	76.8


Delaware	001-33303	65-1295427
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation or organization)	File Number)	Identification No.)


Exhibit
Number		Description
Exhibit 99.1		Targa Resources Partners LP Press Release dated November 4, 2010.


	TARGA RESOURCES PARTNERS LP
	By:	Targa Resources GP LLC,
		its general partner

Dated: November 4, 2010	By:	/s/ Jeffrey J. McParland
		Jeffrey J. McParland
		Executive Vice President and Chief Financial Officer


Exhibit
Number		Description
Exhibit 99.1		Targa Resources Partners LP Press Release dated November 4, 2010.