Targa Resources Partners (NGLS-PA) 8-K Targa Resources Partners LP Reports Third Quarter 2009 Financial Results

Exhibit 99.1

Targa Resources Partners LP Reports Third Quarter 2009 Financial Results

HOUSTON – November 4, 2009 -Targa Resources Partners LP ("Targa Resources Partners" or the "Partnership") (NASDAQ: NGLS) today reported third quarter 2009 net income attributable to Targa Resources Partners of $10.0 million or $0.23 per diluted limited partner unit. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments ("Adjusted EBITDA") of $69.1 million for the third quarter of 2009.

Distributable cash flow for the quarter was $51.5 million which corresponds to distribution coverage of approximately 1.46 times for the 62.9 million total units outstanding on September 30, 2009 (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).

“We are excited to have closed the acquisition of the Downstream Business during the third quarter, and are pleased with the Partnership’s very solid third quarter results. We currently expect the Downstream Business to generate 2009 Adjusted EBITDA that exceeds our guidance range of $80 to $85 million. Furthermore, our total gathering and processing volumes continue to perform above last year’s levels,” said Rene Joyce, Chief Executive Officer of the Partnership's general partner and of Targa Resources, Inc. ("Targa").

On October 19, 2009, the Partnership announced a cash distribution of 51.75¢ per common unit, or $2.07 per unit on an annualized basis, for the third quarter of 2009. The cash distribution will be paid November 13, 2009 on all outstanding common units to holders of record as of the close of business on November 4, 2009.

Acquisition of the Downstream Business

On September 24, 2009 the Partnership acquired Targa’s natural gas liquids business (the “Downstream Business”) for aggregate consideration of $530 million, subject to certain adjustments. As part of the transaction, Targa agreed to provide distribution support to the Partnership in the form of a reduction in the reimbursement of allocated general and administrative expense if necessary for a 1.0 times distribution coverage ratio, calculated using the current distribution rate of $0.5175 per limited partner unit and subject to maximum support of $8 million in any quarter. The distribution support will be in effect for the nine quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011.

Consideration to Targa included 25% of the transaction value in newly issued common and general partner units of the Partnership. The remaining 75% of the transaction value, or approximately $397.5 million, was funded in cash through borrowings under the Partnership’s senior secured revolving credit facility.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions, except operating and price data)
Revenues	$	1,003.8		$	2,214.9		$	2,822.3		$	6,414.6
Product purchases		874.2			2,110.5			2,459.3			5,985.5
Operating expenses		47.5			68.3			142.1			197.7
Depreciation and amortization expense		25.6			24.4			75.5			72.8
General and administrative expense		17.1			19.1			55.5			57.4
Casualty loss adjustment		-			-			(0.8	)		-
Gain on sale of assets		-			-			-			(4.4	)
Income from operations		39.4			(7.4	)		90.7			105.6
Interest expense, net		(29.8	)		(25.4	)		(78.8	)		(71.6	)
Income tax (expense) benefit		0.2			(0.6	)		(0.8	)		(1.8	)
Other		1.0			(4.7	)		3.6			(2.5	)
Net income (loss)		10.8			(38.1	)		14.7			29.7
Less: Net income to noncontrolling interest		0.8			0.2			1.1			0.1
Net income (loss) to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Net loss attributable to predecessor operations	$	(4.2	)	$	(52.9	)	$	(2.4	)	$	(38.2	)
Net income attributable to general partner		2.8			0.3			6.8			5.5
Net income allocable to limited partners		11.4			14.4			9.2			62.3
Basic and diluted net income per limited partner unit	$	0.23		$	0.31		$	0.19		$	1.35
Financial data:
Operating margin	$	82.1		$	36.1		$	220.9		$	231.4
Adjusted EBITDA		69.1			22.5			201.8			186.7
Distributable cash flow		51.5			1.0			158.6			132.4
Operating data:
Gathering throughput, MMcf/d		490.2			438.3			465.2			455.0
Plant natural gas inlet, MMcf/d		464.1			415.8			442.5			430.8
Gross NGL production, MBbl/d		43.5			41.3			43.1			43.2
Natural gas sales, BBtu/d		414.9			404.4			383.0			410.9
NGL sales, MBbl/d		262.7			282.5			278.6			290.2
Condensate sales, MBbl/d		2.6			2.4			2.8			2.4
Average realized prices:
Natural gas, $/MMBtu		3.49			9.42			3.83			9.29
NGLs, $/gal		0.81			1.66			0.71			1.56
Condensate, $/ Bbl		71.25			103.87			55.84			103.75

Review of Third Quarter Results

Net income attributable to Targa Resources Partners for the third quarter of 2009 was $10.0 million, or $0.23 per diluted limited partner unit, compared to a loss of $38.3 million, or $0.31 per diluted limited partner unit for the third quarter of 2008. Income for the third quarter of 2008 was negatively impacted by inventory lower of cost or market adjustments, hurricane casualty losses and mark-to-market derivative losses of $31.6 million, $4.9 million and $1.0 million, respectively. Adjusted EBITDA was $69.1 million for the third quarter of 2009 compared to $22.6 million for the 2008 quarter.

Revenues decreased by $1,211.1 million, or 55%, to $1,003.8 million for 2009 compared to $2,214.9 million for 2008, driven primarily by lower commodity prices. Operating margin was $82.1 million for the third quarter of 2009 compared to $36.1 million for the third quarter of 2008.

The Partnership’s average realized prices for natural gas, NGL and condensate decreased by 63%, 51% and 31% for 2009 compared to 2008.

Natural gas sales volumes for 2009 increased by 10.5 BBtu/d, or 3% compared to 2008. The increase in natural gas sales was primarily the result of increased demand by the Partnership’s industrial customers and increased sales under third party contracts. NGL sales volumes decreased by 19.8 MBbl/d, or 7% and condensate sales volumes increased by 0.2 MBbl/d, or 8% for the same periods. For information regarding the period to period changes in the Partnership’s commodity sales volumes, see “Review of Segment Performance.”

General and administrative expenses decreased by $2.0 million, or 10% compared to 2008. The decrease was primarily due to a reduction in allocated general and administrative expenses, offset by the timing of and increases to compensation and benefit expenses as well as increases in property insurance and outside professional services.

Interest expense increased by $4.4 million, or 17%, for 2009 compared to 2008. The increase was primarily due to the issuance of the 11.25% senior unsecured notes, offset partially by lower overall interest rates.

Review of Nine Months Results

Net income attributable to Targa Resources Partners was $13.6 million for the first nine months of 2009 compared to $29.6 million for the first nine months of 2008. Adjusted EBITDA was $201.8 million for the first nine months of 2009 compared to $186.8 million for the 2008 period.

Revenues were $2,822.3 million for the first nine months of 2009, 56% lower than revenues of $6,414.6 million for the first nine months of 2008, driven primarily by lower prices for natural gas, NGL and condensate and lower natural gas and NGL sales volumes.

The Partnership’s average realized prices for natural gas, NGL and condensate decreased by 59%, 54%, and 46% for 2009 compared to 2008.

Natural gas sales volumes for the first nine months of 2009 decreased by 27.9 BBtu/d, or 7% compared to 2008. The decrease in natural gas sales was primarily the result of a decrease in purchases from

affiliates for resale and a decrease in demand by the Partnership’s industrial customers. NGL sales volumes decreased by 11.6 MBbl/d, or 4% and condensate sales volumes increased by 0.4 MBbl/d, or 17%, for the same periods. For information regarding the period to period changes in our commodity sales volumes, see “Review of Segment Performance.”

General and administrative expenses decreased by $1.9 million, or 3%, to $55.5 million for 2009 compared to $57.4 million for 2008. The decrease was primarily due to a decrease in allocated general and administrative expenses, offset by the timing of and increases to compensation and benefit expenses and increased outside professional services.

Interest expense increased by $7.2 million, or 10%, for 2009 compared to 2008.The increase was primarily due to the issuance of the 11.25% senior unsecured notes.

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. The generally accepted accounting principles ("GAAP") measure most directly comparable to segment operating margin is net income. Operating margin is a non-GAAP financial measure that is defined later in this release.

Natural Gas Gathering and Processing Segment

The Natural 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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	($ in millions)
Revenues	$	273.1		$	578.6		$	752.8		$	1,721.4
Product purchases		(212.6	)		(512.5	)		(592.8	)		(1,509.8	)
Operating expenses		(14.3	)		(15.5	)		(39.0	)		(42.7	)
Operating margin	$	46.2		$	50.6		$	121.0		$	168.9
Operating statistics:
Gathering throughput, MMcf/d
LOU System		213.4			178.1			183.1			189.4
SAOU System		98.5			99.0			99.9			98.7
North Texas System		178.3			161.2			182.2			166.9
		490.2			438.3			465.2			455.0
Plant natural gas inlet, MMcf/d
LOU System		199.4			168.5			174.2			178.8
SAOU System		92.0			91.3			92.1			91.2
North Texas System		172.7			156.0			176.2			160.8
		464.1			415.8			442.5			430.8
Gross NGL production, MBbl/d
LOU System		9.0			9.2			8.5			10.1
SAOU System		14.0			14.1			14.2			14.2
North Texas System		20.5			18.0			20.4			18.9
		43.5			41.3			43.1			43.2
Natural gas sales, BBtu/d		414.9			404.4			383.0			410.9
NGL sales, MBbl/d		40.6			37.4			39.2			38.2
Condensate sales, MBbl/d		2.6			3.3			3.0			3.6
Average realized prices:
Natural gas, $/MMBtu		3.49			9.42			3.83			9.29
NGLs, $/gal		0.73			1.46			0.64			1.40
Condensate, $/Bbl		71.25			95.58			54.00			92.72

Review of Third Quarter Results

Revenues decreased by $305.5 million, or 53%, to $273.1 million for the third quarter of 2009 compared to $578.6 million for the third quarter of 2008. The decrease was primarily due to:

· a decrease attributable to commodity prices of $325.2 million, comprising decreases in natural gas, NGL and condensate revenues of $226.4 million, $93.1 million and $5.7 million;

· an increase attributable to commodity sales volume of $20.9 million comprising increases in natural gas and condensate revenues of $9.1 million and $19.1 million, partially offset by a decrease in NGL revenues of $7.3 million; and

· a decrease in other revenues of $1.2 million, primarily from miscellaneous processing activities.

The average realized price for natural gas, NGL and condensate decreased by 63%, 50%, and 25%, for 2009 compared to 2008.

Natural gas sales volumes increased by 10.5 BBtu/d, or 3%, for 2009 compared to 2008. The increase in natural gas sales volumes was primarily the result of an increase in demand from the Partnership’s industrial customers and increased sales under third party contracts. NGL sales volumes increased by 3.2 MBbl/d, or 9% and condensate sales volumes decreased by 0.7 MBbl/d, or 21%, for the same periods.

Product purchases decreased by $299.9 million, or 59% compared to 2008. The decrease in product purchase cost reflects lower commodity pricing and purchases of wellhead volumes.

Operating expenses for 2009 decreased by $1.2 million, or 8% compared to 2008. The decrease in operating expenses was primarily the result of a decrease in compensation and benefit costs, system maintenance expenses, chemicals and lubricants expenses and utility expenses, partially offset by an increase in ad valorem taxes.

Review of Nine Month Results

Revenues decreased by $968.6 million, or 56%, for 2009 compared to 2008. The decrease was primarily due to:

· a decrease attributable to commodity prices of $893.1 million, comprising decreases in natural gas, NGL and condensate revenues of $570.0 million, $290.8 million and $32.2 million;

· a decrease attributable to commodity sales volume of $74.5 million comprising decreases in natural gas and condensate revenues of $74.6 million and $16.4 million, partially offset by an increase in NGL revenues of  $16.5 million; and

· a decrease in other revenues of $1.0 million, primarily from miscellaneous processing activities.

Average realized price for natural gas, NGL and condensate decreased by 59%, 54%, and 42%, for 2009 compared to 2008.

Natural gas sales volumes decreased by 27.9 BBtu/d, or 7%, for 2009 compared to 2008. The decrease in natural gas sales was primarily the result of a decrease in purchases from affiliates. NGL sales volumes increased by 1.0 MBbl/d, or 3%, for 2009 compared to 2008. Condensate sales volumes decreased by 0.6 MBbl/d, or 17%, for 2009 compared to 2008.

Product purchases for 2009 decreased by $917.0 million, or 61% compared to 2008. The decrease in product cost reflects lower commodity pricing and purchases of wellhead volumes.

Operating expenses for 2009 decreased $3.7 million, or 9% compared to 2008. The decrease was primarily the result of a decrease in compensation and benefit costs, system maintenance expenses, utility expenses, chemical and lubricant expenses and outside professional services costs.

Logistics Assets Segment

The Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating, storing, treating and transporting finished NGLs. These assets are predominantly located in Mont Belvieu and Galena Park, Texas and in western Louisiana. They are generally connected to and supplied in part by Targa’s natural gas processing plants.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	($ in millions)
Revenues from services	$	55.1		$	65.5		$	152.9		$	181.8
Other revenues		(0.1	)		0.1			2.0			0.6
		55.0			65.6			154.9			182.4
Operating expenses		(29.9	)		(49.8	)		(97.7	)		(147.9	)
Operating margin	$	25.1		$	15.8		$	57.2		$	34.5
Equity in earnings of GCF	$	1.4		$	1.1		$	3.2		$	3.0
Operating statistics:
Fractionation volumes, MBbl/d		225.9			207.1			215.4			219.3
Treating volumes, MBbl/d		27.5			20.4			18.5			19.0

Review of Third Quarter Results

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $10.4 million, or 16%, for 2009 compared to 2008. The decrease was primarily due to a lower fuel cost reimbursement component of fractionation fees, which has an equal impact on operating expenses.

Operating expenses decreased by $19.9 million, or 40% compared to 2008. The decrease was due to lower expenses for fuel, utilities, equipment rental and maintenance, and barge fees related to lower volumes and decreased fuel and utility rates.

Review of Nine Months Results

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $28.9 million, or 16%, for 2009 compared to 2008. The decrease was primarily due to decreased fractionation and terminalling and storage volumes as a result of damage to certain of our and third party

Gulf Coast processing, pipeline and production facilities from Hurricane Ike as well as a lower fuel reimbursement component of fractionation fees. In addition, truck and barge volumes were lower for 2009 due to decreased mixed butanes and wholesale activity.

Operating expenses decreased by $50.2 million, or 34%, for 2009 compared to 2008. The decrease was due to lower fuel, utility, equipment rental/maintenance, and barge fees related to lower volumes and decreased fuel and utility rates.

NGL Distribution and Marketing Services Segment

The NGL Distribution and Marketing Services segment markets the Partnership’s natural gas liquids production and also purchased natural gas liquids products in selected United States markets. The following table provides summary data regarding results of operations of this segment for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	762.4		$	1,654.0		$	2,011.2		$	4,564.4
Other revenues		1.4			0.8			3.6			10.9
		763.8			1,654.8			2,014.8			4,575.3
Product purchases		(755.7	)		(1,679.4	)		(1,982.2	)		(4,558.8	)
Operating expenses		-			(0.3	)		(0.6	)		(1.5	)
Operating margin	$	8.1		$	(24.9	)	$	32.0		$	15.0
Operating statistics:
NGL sales, MBbl/d		244.5			258.1			251.2			257.5
NGL realized price, $/gal		0.81			1.66			0.70			1.54

Review of Third Quarter Results

NGL sales revenues decreased by $891.6 million, or 54%, for 2009 compared to 2008. The decrease comprised a $736.1 million decrease from lower average sales prices, which were down 51% for 2009 compared to 2008 and a $155.5 million decrease from lower sales volumes, down 5% for 2009 compared to 2008. The decrease in sales volumes was primarily attributable to a change in contract terms with a large petrochemical customer partially offset by higher plant operational rates and spot sales. Other revenues, which consist primarily of non-commodity based service revenue, increased by $0.6 million.

Product purchases decreased by $923.7 million, or 55%, for 2009 compared to 2008. The net decrease comprised a $768.2 million decrease from lower average market prices and a $155.5 million decrease from lower purchased volumes.

Review of Nine Months Results

NGL sales revenues decreased by $2,553.2 million, or 56%, to $2,011.2 million for 2009 compared to $4,564.4 million for 2008. The decrease comprised a $2,272.3 million decrease from lower average sales prices during 2009, down 55% or $0.84 per gallon and a $280.9 million decrease from lower sales volumes during 2009, down 2% or 6.3 MBbl/d. The decrease in sales volumes was primarily due to reduced sales to petrochemical customers associated with their lower plant operational rates, partially offset by higher spot sales.

Other revenues decreased by $7.3 million, primarily due to $8.6 million in proceeds from business interruption claims received in 2008 partially offset by lower 2008 non-commodity based service revenue of $1.3 million.

Product purchases decreased by $2,576.6 million, or 57%, to $1,982.2 million for 2009 compared to $4,558.8 million for 2008. The decrease comprised a $2,297.3 million decrease due to lower commodity prices and a $279.3 million decrease from lower purchased volumes.

Wholesale Marketing Segment

The Wholesale Marketing segment includes the Partnership’s refinery services business and wholesale propane marketing business. In the refinery services business, the Partnership provides LPG (liquefied petroleum gas) balancing services, purchases natural gas liquids products from refinery customers and sells natural gas liquids products to various customers. The wholesale propane marketing business includes the sale of propane and related logistics services to multi-state retailers, independent retailers and other end-users. Wholesale Marketing operates principally in the United States and has a small marketing presence in Canada.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	141.7		$	320.6		$	559.4		$	1,175.3
Other revenues		0.3			-			1.2			5.9
		142.0			320.6			560.6			1,181.2
Product purchases		(138.7	)		(326.0	)		(549.9	)		(1,168.2	)
Operating margin	$	3.3		$	(5.4	)	$	10.7		$	13.0
Operating statistics:
NGL sales, MBbl/d		41.2			47.0			54.9			60.1
NGL realized price, $/gal		0.89			1.77			0.89			1.70

Review of Third Quarter Results

NGL sales revenues decreased by $178.9 million, or 56%, to $141.7 million for 2009 compared to $320.6 million for 2008. Lower NGL market prices decreased revenue by $139.2 million and lower sales volumes decreased revenue by an additional $39.6 million. The 5.8 MBbl/d decrease in volumes was primarily due to decreased sales of propane due to the expiration of refinery purchase agreements.

Product purchases decreased by $187.3 million, or 57%, to $138.7 million for 2009 compared to $326.0 million for 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $147.7 million and $39.7 million in 2009.

Review of Nine Months Results

NGL sales revenues decreased by $615.9 million, or 52%, for 2009 compared to 2008. Lower NGL market prices decreased revenue by $510.4 million and lower sales volumes decreased revenue by an additional $105.5 million. The 5.2 MBbl/d decrease in volumes was primarily due to reduced sales of propane as a result of the expiration of sales supply agreements as well as lower butane sales associated with the expiration of a refinery supply agreement.

Product purchases decreased by $618.3 million, or 53%, for 2009 compared to 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $528.1 million and $90.4 million in 2009.

Capitalization and Liquidity Update

Total funded debt as of September 30, 2009 was approximately $939 million including $510 million outstanding under the Partnership’s $978 million senior secured revolving credit facility, $209 million of 8.25% senior unsecured notes due 2016 and $220 million of 11.25% senior unsecured notes due 2017. During the third quarter the Partnership repurchased a face amount of $18.7 million of its 11.25 percent senior notes due 2017 in open market transactions at an aggregate purchase price of $19.2 million including $0.3 million of accrued interest. The purchased notes were retired and will not be eligible for re-issue at a later date.

On August 12, 2009, the Partnership completed a public offering of 6,900,000 common units representing limited partner interests resulting in net proceeds of $103.5 million.

As of September 30, 2009, the Partnership had $390 million in capacity available under its senior secured revolving credit facility after giving effect to the Lehman default and the issuance of $59 million of letters of credit. As of September 30, 2009, the Partnership had $58 million of cash, bringing total liquidity to approximately $448 million.

Including the Downstream Business, we estimate capital expenditures of the Partnership to be approximately $50 million in 2009. Maintenance capital expenditures account for approximately 40% of the 2009 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 November 4, 2009 to discuss third quarter 2009 financial results. The conference call can be accessed via Webcast through the Investor's section of the Partnership's website at http://www.targaresources.com or by dialing (800) 762-8908. The pass code is 4173122. 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 and will remain available until November 18, 2009. Replay access numbers are 303-590-3030 or 800-406-7325 with pass code 4173122.

About Targa Resources Partners

Targa Resources Partners was formed by Targa to engage in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling natural gas liquids and natural gas liquids products. Targa Resources Partners owns an extensive network of integrated gathering pipelines, seven natural gas processing plants and two fractionators and currently operates in Southwest Louisiana, the Permian Basin in West Texas and the Fort Worth Basin in North Texas. A subsidiary of Targa is the general partner of Targa Resources Partners. 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—Distributable cash flow is a significant performance metric used by the Partnership and by external users of its financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by the Partnership (prior to the establishment of any retained cash reserves by the general partner) to the cash distributions the Partnership expects to pay to 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 non-GAAP financial measure for the Partnership’s unitholders because it serves as an indicator of the Partnership’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Partnership is generating cash flow at a level that can sustain or support an increase in its 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 the Partnership’s use of distributable cash flow is to measure the ability of its assets to generate cash flows sufficient to make distributions to unitholders.

The GAAP measure most directly comparable to distributable cash flow is net income (loss). The Partnership’s non-GAAP measure of distributable cash flow should not be considered as an alternative to GAAP net income (loss). 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 the Partnership’s results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income (loss) and is defined differently by different publicly-traded partnerships and limited liability companies, the Partnership’s definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates 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 learnings into its decision-making processes.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions)
Reconciliation of net income (loss) to Targa Resources Partners LP
to distributable cash flow:
Net income (loss) to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Add:
Depreciation and amortization expense		25.6			24.4			75.5			72.8
Deferred income tax expense (benefit)		0.1			0.5			0.8			1.4
Noncash interest expense		15.0			15.4			45.9			45.9
Loss on debt repurchases		1.5			-			1.5			-
Non-cash loss related to derivatives		4.1			10.6			33.8			11.6
Maintenance capital expenditures		(4.7	)		(11.4	)		(12.1	)		(28.5	)
Other		(0.1	)		(0.2	)		(0.4	)		(0.4	)
Distributable cash flow	$	51.5		$	1.0		$	158.6		$	132.4

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 as 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.

Operating Margin—With respect to the Natural Gas Gathering and Processing division, the Partnership defines operating 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 less operating expense. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Our Natural Gas Gathering and Processing segment

operating margin is impacted by volumes and commodity prices as well as by our contract mix and hedging program, which are described in more detail in the Partnership’s reports and other filings with the Securities and Exchange Commission.

With respect to our NGL Logistics and Marketing division, the Partnership defines 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. Within this division, our management analyzes segment operating margin for each of the three segments per unit of NGL handled or sold as an indicator of operational and commercial performance.

The GAAP measure most directly comparable to 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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions)
Reconciliation of net cash provided by (used in)
operating activities to Adjusted EBITDA:
Net cash provided by (used in) operating activities	$	64.8		$	(168.2	)	$	219.9		$	128.6
Net income to noncontrolling interest		(0.8	)		(0.2	)		(1.1	)		(0.1	)
Termination of commodity derivatives		-			87.4			-			87.4
Interest expense, net		14.8			10.0			32.9			25.7
Other		(3.9	)		(1.2	)		(3.5	)		4.0
Changes in operating working capital which used (provided) cash:
Accounts receivable and other assets		22.3			(36.4	)		(5.5	)		(160.1	)
Accounts payable and other liabilities		(28.1	)		131.1			(40.9	)		101.2
Adjusted EBITDA	$	69.1		$	22.5		$	201.8		$	186.7

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions)
Reconciliation of net income (loss) to Targa Resources Partners LP to Adjusted EBITDA:
Net income (loss) to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Add:
Interest expense, net		29.8			25.4			78.8			71.6
Income tax expense (benefit)		(0.2	)		0.6			0.8			1.8
Depreciation and amortization expense		25.6			24.4			75.5			72.8
Non-cash loss related to derivatives		4.1			10.6			33.8			11.6
Noncontrolling interest adjustment		(0.2	)		(0.2	)		(0.7	)		(0.7	)
Adjusted EBITDA	$	69.1		$	22.5		$	201.8		$	186.7
	Three Months Ended September 30,						Nine Months Ended September 30,
		2009			2008			2009			2008
	(In millions)
Reconciliation of net income (loss) to Targa Resources Partners LP to operating margin:
Net income (loss) to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Add:
Depreciation and amortization expense		25.6			24.4			75.5			72.8
General and administrative expense		17.1			19.1			55.5			57.4
Interest expense, net		29.8			25.4			78.8			71.6
Income tax benefit (expense)		(0.2	)		0.6			0.8			1.8
Other, net		(0.2	)		4.9			(3.3	)		(1.8	)
Operating margin	$	82.1		$	36.1		$	220.9		$	231.4

Reconciliation of non-GAAP Measures for the Downstream Business
	Twelve Months Ended
	December 31, 2009
	(In millions)
	Low Range			High Range
Reconciliation of net income to Adjusted EBITDA
Net income	$	(5.6	)	$	(0.6	)
Depreciation and amortization		25.4			25.4
Interest expense		59.4			59.4
Income tax expense		0.8			0.8
Adjusted EBITDA	$	80.0		$	85.0

 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 STATEMENTS OF OPERATIONS
(In thousands)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
REVENUES	$	1,003,778		$	2,214,851		$	2,822,284		$	6,414,564
COSTS AND EXPENSES:
Product purchases		874,228			2,110,428			2,459,296			5,985,455
Operating expenses		47,474			68,255			142,096			197,690
Depreciation and amortization expense		25,597			24,431			75,490			72,785
General and administrative expense		17,078			19,116			55,474			57,433
Other		(1	)		(13	)		(852	)		(4,440	)
Total costs and expenses		964,376			2,222,217			2,731,504			6,308,923
INCOME FROM OPERATIONS		39,402			(7,366	)		90,780			105,641
Other income (expense):
Interest expense from affiliate indebtedness		(13,701	)		(14,832	)		(43,414	)		(44,400	)
Other interest expense, net		(16,097	)		(10,617	)		(35,344	)		(27,175	)
Equity in earnings of unconsolidated investments		1,417			1,102			3,221			3,028
Loss on debt repurchases		(1,483	)		-			(1,483	)		-
Other income (expense)		1,132			(5,700	)		1,831			(5,535	)
Income (loss) before income taxes		10,670			(37,413	)		15,591			31,559
Income tax (expense) benefit		220			(647	)		(800	)		(1,842	)
NET INCOME (LOSS)		10,890			(38,060	)		14,791			29,717
Less: Net income to noncontrolling interest		888			162			1,179			91
NET INCOME (LOSS) TO TARGA RESOURCES PARTNERS LP	$	10,002		$	(38,222	)	$	13,612		$	29,626
Net loss attributable to predecessor operations	$	(4,208	)	$	(52,914	)	$	(2,377	)	$	(38,207	)
Net income attributable to general partner		2,809			294			6,765			5,524
Net income allocable to limited partners		11,401			14,398			9,224			62,309
Basic and diluted net income per limited partner unit	$	0.23		$	0.31		$	0.19		$	1.35
Basic and diluted weighted average limited
partner units outstanding		50,611			46,180			47,692			46,175

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In thousands)
	Nine Months Ended September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	14,791		$	29,717
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization and accretion		78,534			74,739
Deferred income tax expense		800			1,406
Interest expense on affiliate indebtedness		43,414			44,400
Risk management activities		33,826			(75,747	)
Equity in earnings of unconsolidated investments, net of distributions		654			(316	)
Loss on debt repurchases		1,483			-
Gain on sale of assets		(7	)		(4,440	)
Changes in operating assets and liabilities		46,428			58,821
Net cash provided by operating activities		219,923			128,580
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant and equipment		(46,327	)		(55,335	)
Other, net		82			183
Net cash used in investing activities		(46,245	)		(55,152	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility		397,618			87,500
Repayments on credit facility		(374,900	)		(323,800	)
Proceeds from issuance of senior notes		237,433			250,000
Repurchases of senior notes		(18,882	)		-
Repayment of affiliated indebtedness		(397,500	)		-
Proceeds from equity offerings		103,470			-
Distributions to unitholders		(79,127	)		(64,574	)
General partner contributions		2,216			8
Costs incurred in connection with public offerings		(164	)		-
Costs incurred in connection with financing arrangements		(9,558	)		(7,079	)
Distributions to noncontrolling interest		(1,740	)		-
Deemed Parent distributions		(70,086	)		(36,183	)
Net cash used in financing activities		(211,220	)		(94,128	)
Net change in cash and cash equivalents		(37,542	)		(20,700	)
Cash and cash equivalents, beginning of period		95,308			64,342
Cash and cash equivalents, end of period	$	57,766		$	43,642