Targa Resources Corp. - FORM 8-K - EX-99.1

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8-K - FORM 8-K - Targa Resources Corp.	form8-k.htm

Exhibit 99.1

Targa Resources Partners LP and Targa Resources Corp. Report

Third Quarter 2011 Financial Results

HOUSTON – November 7, 2011 - Targa Resources Partners LP (NYSE: NGLS) ("Targa Resources Partners" or the "Partnership") and Targa Resources Corp. (NYSE: TRGP) (“TRC” or the “Company”) today reported third quarter 2011 results. Third quarter 2011 net income attributable to Targa Resources Partners was $35.9 million compared to $13.8 million for the third quarter of 2010. The income per basic and diluted limited partner unit was $0.31 in the third quarter of 2011 compared to $0.14 for the third quarter of 2010. Net income for the third quarters of 2011 and 2010 included non-cash losses of $2.0 million and $6.1 million related to derivative instruments, respectively. The Partnership’s third quarter of 2010 also included $3.9 million in affiliate and allocated interest expense for periods prior to the acquisitions of TRC businesses by the Partnership. The Partnership reported Adjusted EBITDA of $107.3 million for the third quarter of 2011 compared to $90.5 million for the third quarter of 2010. The Partnership’s distributable cash flow for the third quarter 2011 of $65.4 million corresponds to distribution coverage of approximately 1.1 times the $59.4 million in total distributions to be paid on November 14, 2011 (see the section of this release entitled “Targa Resources Partners - Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, gross margin, operating margin and distributable cash flow, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”)).

“We are pleased to report operating margin increases for each of our segments compared to last year on both a year-to-date and a third quarter basis. These results clearly illustrate the growth we are seeing across all areas of our operations,” said Rene Joyce, Chief Executive Officer of the Partnership’s general partner and of Targa Recourses Corp. “We have over $300 million of growth investments that are coming on line this year. We have also announced over $860 million of approved projects targeted for start up during 2013, as we continue to expand our diverse operations in response to strong industry fundamentals. These projects provide the Partnership with good visibility on incremental contributions to EBITDA through the 2014 timeframe. And we are continuing the development of additional projects to serve our customers’ needs.”

On October 11, 2011, the Partnership announced a cash distribution for the third quarter 2011 of 58.25¢ per common unit, or $2.33 per unit on an annualized basis, representing an increase of approximately 8% over the annualized distribution paid with respect to the third quarter 2010. The cash distribution will be paid on November 14, 2011 on all outstanding common units to holders of record as of the close of business on October 21, 2011. The total distribution to be paid is $59.4 million, with $42.6 million to the Partnership’s third-party limited partners, and $16.8 million to TRC for its ownership of common units, incentive distribution rights (“IDRs”) and its 2% general partner interest in the Partnership.

Targa Resources Partners - Capitalization, Liquidity and Financing Update

Total funded debt at the Partnership as of September 30, 2011 was $1,514.1 million including $535.0 million outstanding under the Partnership’s $1.1 billion senior secured revolving credit facility, $209.1 million of 8¼% senior unsecured notes due 2016, $72.7 million of 11¼% senior unsecured notes due 2017, $250.0 million of 7⅞% senior unsecured notes due 2018, $483.6 million of 6⅞% senior unsecured notes due 2021 and $36.3 million of unamortized discounts.

As of September 30, 2011, after giving effect to $88.3 million in outstanding letters of credit, the Partnership had available revolver capacity of $476.7 million and $68.9 million of cash resulting in total liquidity of $545.6 million.

The Partnership estimates that its total capital expenditures including business acquisitions for 2011 will be approximately $520 million gross and $480 million net of non-controlling interest share and reimbursements. The Partnership also estimates that approximately 15% of the $480 million net capital expenditures will be for maintenance.

For 2012, the Partnership expects total growth capital expenditures will be $500 million or more based on currently approved projects. The following table provides a summary of the total growth capital expenditures expected for the Partnership’s major expansion projects underway.

	Growth Capex			Growth Capex			Expected
$ in millions	2012			Total			Completion

CBF Train 4	$	200		$	360		Q1 2013
Propane Exports		125			250		Q3 2013
North Texas expansion		75			150		Mid-2013
Petroleum Logistics projects (1)		60			60		Q1 2013
Other		40	+		40	+
Total	$	500	+	$	860	+

(1) Projects in Petroleum Logistics include additional expansions of Channelview, Sound and Baltimore terminals

Net maintenance capital expenditures are estimated to be approximately $80 million for 2012.

Targa Resources Corp. - Third Quarter 2011 Financial Results

Targa Resources Corp., the parent of Targa Resources Partners, today reported its third quarter 2011 results. The Company, which at September 30, 2011 owned a 2% general partner interest (held through its 100% ownership interest in the general partner of the Partnership), all of the IDRs and 11,645,659 common units of the Partnership, presents its results consolidated with those of the Partnership.

Net income attributable to Targa Resources Corp. was $4.9 million for the third quarter 2011, compared with a net loss of $17.5 million for the third quarter 2010.

Third quarter 2011 distributions to be paid on November 14, 2011 by the Partnership to the Company will total $16.8 million with $6.8 million, $1.2 million and $8.8 million paid with respect to common units, general partner interests and IDRs, respectively.

On October 11, 2011, the Company announced a quarterly dividend of 30.75¢ per share of its common stock for the three months ended September 30, 2011, or $1.23 per share on an annualized basis, representing an approximately 6% increase over the annualized rate paid with respect to the second quarter of 2011.

The Company’s distributable cash flow for the third quarter 2011 of $20.2 million corresponds to dividend coverage of 1.5 times the $13.0 million in total declared dividends for the quarter (see the section of this release entitled “Targa Resources Corp. - Non-GAAP Financial Measures” for a discussion of distributable cash flow and reconciliations of this measure to its most directly comparable financial measure calculated and presented in accordance with GAAP). The third quarter distributable cash flow includes a one-time benefit in current tax expense related to overpayment of prior year income taxes. Excluding this one-time benefit, pro forma dividend coverage for the third quarter is 1.1 times the $13.0 million in total dividends declared. Dividends will be paid on November 15, 2011 to holders of record as of the close of business on October 21, 2011.

Targa Resources Corp. – Capitalization, Liquidity and Financing Update

Total funded debt of the Company as of September 30, 2011, excluding debt of the Partnership, was $89.3 million. The Company also has access to the full amount of its $75.0 million senior secured revolving credit facility due 2014.

The Company’s cash balance, excluding cash held at the Partnership and its subsidiaries, was $85.2 million as of September 30, 2011, resulting in total liquidity of $160.2 million.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 10:30 a.m. Eastern Time (9:30 a.m. Central Time) on November 7, 2011 to discuss third quarter 2011 financial results. The conference call can be accessed via Webcast through the Events and Presentations section of the Partnership's and the Company’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 18107673. 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 and the Company’s website. Telephone replay access numbers are 855-859-2056 or 404-537-3406 with pass code 18107673 and will remain available, along with the Webcast, until November 22, 2011.

Targa Resources Partners - Consolidated Financial Results of Operation

With the closing of the acquisitions of the Permian Business, Coastal Straddles, Versado 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 Permian Business, Coastal Straddles, Versado and VESCO for all periods presented.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In millions except per unit data)
Revenues	$	1,712.7		$	1,218.4		$	5,053.8		$	3,944.6
Product purchases		1,485.5			1,033.6			4,364.5			3,394.0
Gross margin (1)		227.2			184.8			689.3			550.6
Operating expenses		76.5			66.0			214.1			190.2
Operating margin (2)		150.7			118.8			475.2			360.4
Depreciation and amortization expense		45.0			43.3			132.2			128.3
General and administrative expense		33.7			26.7			98.6			80.0
Other		(0.3	)		-			(0.4	)		-
Income from operations		72.3			48.8			244.8			152.1
Interest expense, net		(25.7	)		(27.9	)		(80.4	)		(86.6	)
Equity in earnings of unconsolidated investment		2.2			1.1			5.2			3.8
Gain (loss) on mark-to-market derivative instruments		(1.8	)		(1.9	)		(5.0	)		26.0
Other		(0.6	)		-			(0.8	)		-
Income tax expense		(1.5	)		(1.7	)		(5.2	)		(3.9	)
Net income (loss)		44.9			18.4			158.6			91.4
Less: Net income attributable to noncontrolling interest		9.0			4.6			29.6			18.2
Net income (loss) attributable to Targa Resources Partners LP	$	35.9		$	13.8		$	129.0		$	73.2

Net income attributable to predecessor operations	$	-		$	(1.3	)	$	-		$	25.8
Net income (loss) attributable to general partner		9.5			5.0			26.0			12.0
Net income attributable to limited partners		26.4			10.1			103.0			35.4
Net income attributable to Targa Resources Partners LP	$	35.9		$	13.8		$	129.0		$	73.2

Basic and diluted net income per limited partner unit	$	0.31		$	0.14		$	1.23		$	0.51

Financial data:
Adjusted EBITDA (3)	$	107.3		$	90.5		$	344.6		$	282.0
Distributable cash flow (4)		65.4			56.4			229.5			200.8

Operating data:
Plant natural gas inlet, MMcf/d (5),(6)		2,087.0			2,216.4			2,152.8			2,296.5
Gross NGL production, MBbl/d		121.4			121.6			122.2			120.8
Natural gas sales, BBtu/d (6)		799.7			673.1			746.6			679.3
NGL sales, MBbl/d		258.9			244.2			265.1			246.0
Condensate sales, MBbl/d		3.2			3.4			3.2			3.6

(1)	Gross margin is a non-GAAP financial measure and is discussed under “Targa Resources Partners Non-GAAP Financial Measures.”

(2)	Operating margin is a non-GAAP financial measure and is discussed under “Targa Resources Partners Non-GAAP Financial Measures.”

(3)

Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. This is a non-GAAP financial measure and is discussed under “Targa Resources Partners Non-GAAP Financial Measures.”

(4)

Distributable cash flow is 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 (net of any reimbursements of project costs). This is a non-GAAP financial measure and is discussed under “Targa Resources Partners Non-GAAP Financial Measures.”

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

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

Targa Resources Partners - Review of Consolidated Third Quarter Results

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Consolidated revenues (including the impacts of hedging) increased due to the higher net impact of realized prices on NGLs and condensate ($377.9 million), higher NGL and natural gas sales volumes ($103.6 million) and higher fee-based and other revenues ($23.1 million), partially offset by lower realized prices on natural gas ($9.2 million) and lower condensate sales volumes ($1.1 million).

Consolidated operating margin increased $31.9 million, reflecting higher gross margin and higher revenues ($494.3 million), partially offset by increases in product purchase costs ($451.9 million) and increased operating expenses ($10.5 million). The increase in operating expenses primarily reflects increased compensation and benefits, maintenance and fuel, utilities and catalyst costs. See “Targa Resources Partners – Review of Segment Performance” for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses of $1.7 million is primarily due to the impact of gathering, fractionating and storage terminal assets purchased in 2011 and expansion projects placed in service since the third quarter of 2010 ($3.7 million) offset by assets that became fully depreciated in 2010 ($2.0 million).

General and administrative expenses increased $7.0 million reflecting increased compensation and benefits.

Interest expense decreased by $2.2 million attributable to $1.7 million increase in interest expense on third party debt, due to higher borrowings and a higher effective interest rate, offset by a $3.9 million decrease on affiliate and allocated interest expense. There was no interest expense related to affiliate or allocated debt in 2011 as these balances were retired as part of the Permian, Versado and VESCO acquisitions in 2010.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

Consolidated revenues (including the impacts of hedging) increased due to the net impact of higher realized commodity prices on NGLs and condensate ($823.8 million), higher NGL and natural gas sales volumes ($309.2 million) and higher fee-based and other revenues ($57.2 million), partially offset by lower realized prices on natural gas ($71.9 million) and lower condensate sales volumes ($9.1 million).

Consolidated operating margin increased $114.8 million, reflecting higher gross margin, higher revenues ($1,109.2 million) partially offset by increases in product purchase costs ($970.5 million). The increase in consolidated operating expenses of $23.9 million primarily reflects increased compensation and benefits, maintenance and fuel, utilities and catalyst costs. See “Targa Resources Partners – Review of Segment Performance” for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses of $3.9 million is primarily due to the impact of new gathering, fractionating and storage terminal assets placed in service since the third quarter of 2010 ($8.6 million) offset by assets that became fully depreciated in 2010 ($4.7 million).

General and administrative expenses increased $18.6 million reflecting increased compensation and benefits.

Interest expense decreased by $6.2 million attributable to $23.2 million increase in interest expense on third party debt, due to higher borrowings and a higher effective interest rate, offset by $29.4 million decrease on affiliate and allocated interest expense. There was no interest expense related to affiliate or allocated debt in 2011 as these balances were retired as part of the Permian, Versado and VESCO acquisitions in 2010.

Mark-to-market gains decreased $31.0 million, moving from a gain of $26.0 million to a loss of $5.0 million. The gain in 2010 was attributable to the accounting treatment of commodity derivatives related to the Permian and Versado acquisitions during 2010. Under common control accounting, these derivatives did not qualify for hedge accounting treatment for predecessor periods prior to the Partnership’s acquisition of the assets. Therefore, changes in fair value for these instruments were recorded in earnings. These derivative instruments were designated as hedges as of the date of these acquisitions, and therefore changes in value subsequent to those dates are recorded in Other Comprehensive Income until the underlying transactions settle. The loss in 2011 is attributable to interest rate swaps that did not qualify for hedge accounting as of February 11, 2011 and losses recorded when the Partnership terminated these swaps on September 6, 2011.

Targa Resources Partners - 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. For a discussion of operating margin, see “Targa Resources Partners—Non-GAAP Financial Measures—Operating Margin.” 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.

The Partnership reports its operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing, consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The financial results of the Partnership’s commodity hedging activities are reported in Other.

Field Gathering and Processing Segment

The Field Gathering and Processing segment gathers and processes natural gas from the Permian Basin in West Texas and Southeast New Mexico, and the Fort Worth Basin, including the Barnett Shale, in North Texas. The segment’s processing plants include nine owned and operated facilities.

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,
	2011		2010		2011		2010
	($ in millions except price data)
Gross margin	$	102.4	$	77.4	$	299.3	$	250.4
Operating expenses		30.6		27.8		86.3		73.6
Operating margin	$	71.8	$	49.6	$	213.0	$	176.8

Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)
Permian		139.6		127.3		131.6		127.0
SAOU		114.3		102.6		110.0		97.3
North Texas System		210.7		182.7		197.4		177.2
Versado		163.7		171.0		165.4		180.4
		628.2		583.7		604.4		582.0

Gross NGL production, MBbl/d
Permian		16.6		14.9		15.5		14.5
SAOU		17.8		15.6		17.1		15.0
North Texas System		22.9		20.9		22.2		20.3
Versado		17.9		19.2		18.2		20.4
		75.1		70.6		73.1		70.2

Natural gas sales, BBtu/d (2),(3)		295.8		254.5		281.2		257.2
NGL sales, MBbl/d (3)		60.2		54.9		58.9		55.6
Condensate sales, MBbl/d (3)		3.0		3.1		2.9		3.0

Average realized prices (4):
Natural gas, $/MMBtu		4.03		3.99		3.96		4.29
NGL, $/gal		1.29		0.85		1.22		0.90
Condensate, $/Bbl		85.99		72.10		91.99		73.82

_________

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

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

(3)

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 applicable period and the denominator is the number of calendar days during the applicable period.

(4)	Average realized prices exclude the impact of hedging activities.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

The $25.0 million increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices ($106.1 million), higher natural gas and NGL sales volumes ($32.4 million) and higher fee-based and other revenues ($0.9 million), partially offset by higher product purchases ($113.7 million) and lower condensate sales volumes ($0.7 million). The increase in plant inlet volumes was largely attributable to new well connects throughout the systems, particularly North Texas, SAOU and Sand Hills, partially offset by operational outages and production declines at the Versado system. Natural gas sales increased on higher throughput and a decrease in take-in-kind volumes.

The $2.8 million increase in operating expenses was primarily due to higher fuel, utilities and catalysts expenses ($0.9 million), higher compensation and benefit costs ($1.0 million) and higher contract and professional service expenses ($0.4 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

The $48.9 million increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices ($225.6 million), higher natural gas and NGL volumes ($61.9 million) and higher fee-based and other revenues ($3.1 million), partially offset by higher product purchases ($214.5 million), lower natural gas sales prices ($24.8 million), and lower condensate sales volumes ($2.2 million). The increase in plant inlet volumes was largely attributable to new well connects throughout the systems, particularly North Texas and SAOU, partially offset by the impact of severe cold weather in the first quarter of 2011 and operational outages in the first quarter and third quarter of 2011 and production declines at the Versado system. Natural gas sales increased on higher throughput and a decrease in take-in-kind volumes.

The $12.7 million increase in operating expenses was primarily due to higher fuel, utilities and catalysts expenses ($3.7 million), higher system maintenance expenses ($3.0 million) due to severe cold weather and operational outages in the first quarter of 2011, higher compensation and benefit costs ($3.8 million) and higher contract and professional service expenses ($2.5 million).

Coastal Gathering and Processing Segment

The Coastal Gathering and Processing segment assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico. With the strategic location of the Partnership’s assets in Louisiana, it has access to the Henry Hub, the largest natural gas hub in the U.S., and a substantial NGL distribution system with access to markets throughout Louisiana and the Southeast United States.

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,
	2011		2010		2011		2010
	($ in millions except price data)
Gross margin	$	52.9	$	34.2	$	156.6	$	106.3
Operating expenses		13.1		10.7		34.8		31.4
Operating margin	$	39.8	$	23.5	$	121.8	$	74.9

Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2),(3)
LOU		170.7		163.7		169.5		190.6
Coastal Straddles		828.4		1,041.3		897.8		1,100.6
VESCO		459.7		427.7		481.0		423.3
		1,458.8		1,632.7		1,548.3		1,714.5

Gross NGL production, MBbl/d
LOU		7.7		7.1		7.1		7.4
Coastal Straddles		16.4		19.0		17.2		20.1
VESCO		22.2		24.8		24.9		23.0
		46.3		51.0		49.1		50.5

Natural gas sales, Bbtu/d (3),(4)		256.6		293.1		261.0		306.2
NGL sales, MBbl/d (4)		41.6		42.4		43.0		44.0
Condensate sales, MBbl/d (4)		0.2		0.2		0.3		0.6

Average realized prices (5):
Natural gas, $/MMBtu		4.21		4.40		4.24		4.64
NGL, $/gal		1.35		0.93		1.30		1.00
Condensate, $/Bbl		107.72		72.42		102.38		78.45

_________

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

(2)	The majority of the Coastal Straddles plant volumes are gathered on third-party offshore pipeline systems and delivered to the plant inlets.

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

(4)

(5)	Average realized prices exclude the impact of hedging activities.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

The $18.7 million increase in gross margin for 2011 is primarily due to higher NGL and condensate sales prices ($68.0 million), partially offset by an increase in product purchases ($26.8 million), and by decreases in commodity sales volumes ($17.7 million), natural gas sales prices ($4.5 million) and fee-based and other revenues ($0.3 million). The decrease in plant inlet volumes was largely attributable to a decline in traditional wellhead and offshore supply volumes. The decreased NGL sales volumes were primarily due to lower throughput and NGL production volumes. Natural gas sales volumes decreased due to lower inlet volumes.

The $2.4 million increase in operating expenses was primarily due to higher compensation and benefit costs ($0.4 million), higher contract and professional service expenses ($0.6 million) and higher miscellaneous expenses ($1.3 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

The $50.3 million increase in gross margin for 2011 is primarily due to an increase in NGL and condensate sales prices ($148.8 million), an increase in fee-based and other revenues ($2.0 million) and a decrease in product purchases ($4.9 million), partially offset by a decrease in natural gas sales prices ($28.7 million) and a decrease in commodity sales volumes ($76.7 million). The decrease in plant inlet volumes was largely attributable to a decline in traditional wellhead and offshore supply volumes. The decreased NGL sales volumes were primarily due to lower throughput and NGL production volumes. Natural gas sales volumes decreased due to lower inlet volumes.

The $3.4 million increase in operating expenses was primarily due to higher compensation and benefit costs ($0.9 million), higher contract and professional service expenses ($0.2 million) and higher miscellaneous expenses ($1.7 million).

Logistics Assets Segment

The Logistics Assets segment is involved in transporting, storing and fractionating mixed NGLs; storing, terminaling and transporting finished NGLs; and storing and terminaling crude oil and refined petroleum products. The Partnership’s logistics assets are generally connected to, and supplied in part by, its Natural Gas Gathering and Processing segments and are predominantly located at Mont Belvieu, Texas and Southwestern Louisiana. This segment also includes the activities associated with the 2011 acquisitions of refined petroleum products and crude oil storage and terminaling facilities.

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,
	2011		2010		2011		2010
	($ in millions)
Gross margin	$	60.1	$	43.1	$	160.3	$	121.5
Operating expenses		30.0		19.5		74.4		68.6
Operating margin	$	30.1	$	23.6	$	85.9	$	52.9

Operating statistics (1):
Fractionation volumes, MBbl/d		290.4		224.6		260.1		220.9
Treating volumes, MBbl/d		23.3		23.8		20.5		17.8

________

(1)

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

The $17.0 million increase in gross margin primarily reflects increased fractionation volumes ($13.1 million) and higher terminaling and storage revenue ($3.4 million). Growth in terminaling and storage revenue is primarily due to increased supply services to petrochemical customers at the Mont Belvieu terminal and higher LPG exports at the Galena Park terminal. Additionally, operations of the recently acquired Channelview Terminal and one full quarter of operations of the 78 MBbl/d expansion of the Cedar Bayou facility resulted in higher throughput and increased gross margin.

The $10.5 million increase in operating expenses was primarily due to increases in natural gas volumes for fuel to fractionators due to the expansion of the Cedar Bayou fractionation facility, utilities ($2.9 million), NGL transportation fees ($2.5 million), higher costs associated with fractionation maintenance ($2.3 million), contractor and professional services ($1.5 million) and compensation and benefit costs ($1.4 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

The $38.8 million increase in gross margin reflects higher terminaling and storage revenue ($14.7 million) and increased fractionation volumes ($21.3 million). Growth in terminaling and storage revenue is primarily due to increased supply services to petrochemical customers at the Mont Belvieu terminal and higher LPG exports at the Galena Park terminal. Additionally, two full quarters of operations of the recently acquired Channelview Terminal and of the 78 MBbl/d expansion of the Cedar Bayou facility resulted in higher throughput and increased gross margin.

The $5.8 million increase in operating expenses was primarily due to increases in natural gas volumes for fuel to fractionators due to the expansion of the Cedar Bayou fractionation facility, utilities ($5.1 million), compensation and benefits ($3.4 million), NGL transportation fees ($3.4 million), maintenance ($2.4 million) and contractor and professional services ($1.4 million), partially offset by a more favorable system product volume gain ($8.0 million) and a decrease in miscellaneous expenses ($1.5 million).

Marketing and Distribution Segment

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes: (1) marketing of the Partnership’s natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to the Partnership from its Natural Gas Gathering and Processing division and the purchase and resale of natural gas 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,
	2011		2010		2011		2010
	($ in millions except price data)
Gross margin	$	30.1	$	26.4	$	116.0	$	82.3
Operating expenses		10.4		11.4		33.2		33.5
Operating margin	$	19.7	$	15.0	$	82.8	$	48.8

Operating statistics (1):
Natural gas sales, BBtu/d		962.1		612.6		829.1		630.1
NGL sales, MBbl/d		264.5		242.9		267.3		241.3
Natural gas, $/MMBtu		4.10		4.22		4.15		4.50
NGL realized price, $/gal		1.32		0.95		1.32		1.06

________

(1)

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

The $3.7 million increase in gross margin was due to higher NGL volumes ($79.0 million) and natural gas volumes ($135.6 million), higher NGL prices ($386.0 million) and higher fee-based and other revenues ($13.6 million), offset by lower natural gas prices ($10.7 million) and increased product purchases ($599.5 million). Increased NGL export sales contributed to a higher operating margin in 2011. Natural gas sales volumes increased due to higher purchases for resale.

Operating expenses decreased by $1.0 million due to lower contractor and professional services expenses ($1.3 million) offset by higher compensation benefits ($0.3 million).

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

The $33.7 million increase in gross margin was due to higher NGL volumes ($314.6 million) and natural gas volumes ($244.4 million), higher NGL prices ($789.6 million) and higher fee-based and other revenues ($25.7 million), offset by lower natural gas prices ($79.0 million) and increased product purchases ($1,269.7 million). Factors contributing to a higher operating margin in 2011 included increased NGL export sales and the positive impact of a contract settlement ($7.5 million) related to the current contract period of a multi-year propane exchange agreement. The contract, as restructured, provides for future payments during future contract periods through November 2014. Natural gas sales volumes increased due to higher purchases for resale.

Other

Other contains the financial effects of the Partnership’s commodity hedging program on profitability. The primary purpose of the Partnership’s commodity risk management activities is to hedge its exposure to commodity price risk and reduce fluctuations in its operating cash flow despite fluctuations in commodity prices. The Partnership has hedged the commodity price associated with a portion of its expected natural gas, NGL and condensate equity volumes by entering into derivative financial instruments. As such, these hedge positions will increase margins in periods of falling prices and decrease margins in periods of rising prices.

Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

For the three months ended September 30, 2011, the Partnership’s cash flow hedging program decreased gross margin by $10.8 million compared to an increase of $7.1 million for the same period during 2010, reflecting higher commodity prices on forward-selling hedge contracts.

Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010

For the nine months ended September 30, 2011, the Partnership’s cash flow hedging program decreased gross margin by $28.4 million compared to an increase of $7.0 million for the same period during 2010, reflecting higher commodity prices on forward-selling hedge contracts.

About Targa Resources Corp. and Targa Resources Partners

Targa Resources Corp. is a publicly traded Delaware corporation that owns a 2% general partner interest (which the Company holds through its 100% ownership interest in the general partner of the Partnership), all of the outstanding incentive distribution rights and a portion of the outstanding limited partner interests in Targa Resources Partners LP.

Targa Resources Partners is a publicly traded Delaware limited partnership that is a leading provider of midstream natural gas and natural gas liquid services in the United States. The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling natural gas liquids, or NGLs, and NGL products; and storing and terminaling refined petroleum products and crude oil. 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 onshore and near offshore region of Louisiana, the Permian Basin in West Texas and Southeast New Mexico and the Fort Worth Basin in North Texas. Additionally, the Partnership’s 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 is managed by its general partner, Targa Resources GP LLC, which is indirectly wholly owned by Targa Resources Corp.

The principal executive offices of Targa Resources Corp. and Targa Resources Partners are located at 1000 Louisiana, Suite 4300, Houston, TX 77002 and their telephone number is 713-584-1000. For more information please go to www.targaresources.com.

Targa Resources Partners – Non-GAAP Financial Measures

This press release includes the non-GAAP financial measures distributable cash flow, Adjusted EBITDA, gross margin and operating margin. The following tables provide reconciliations of these non-GAAP financial measures to their most directly comparable GAAP measures. The Partnership’s 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— The Partnership defines 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 (net of any reimbursements of project costs). The impact of noncontrolling interests is included in this measure.

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 and research analysts to compare basic cash flows generated by the Partnership (prior to the establishment of any retained cash reserves by the board of directors of the Partnership’s general partner) to the cash distributions it expects to pay its unitholders. Using this metric, management and external users can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for the Partnership’s unitholders since 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 GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Partners LP. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors 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 and is defined differently by different companies in the Partnership’s industry, 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 measure, understanding the differences between the measures and incorporating these insights into its decision making processes.

The following table presents a reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow for the periods indicated:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow:
Net income attributable to Targa Resources Partners LP	$	35.9		$	13.8		$	129.0		$	73.2
Affiliate and allocated interest expense		-			3.9			-			29.4
Depreciation and amortization expenses		45.0			43.3			132.2			128.3
Deferred income tax expense		(0.9	)		(0.1	)		0.6			0.3
Amortization in interest expense		2.5			2.4			8.1			5.1
Risk management activities		2.0			6.1			6.0			(2.9	)
Maintenance capital expenditures		(24.7	)		(12.7	)		(57.2	)		(29.7	)
Other (1)		5.6			(0.3	)		10.8			(2.9	)
Distributable cash flow	$	65.4		$	56.4		$	229.5		$	200.8

______

(1)	Includes reimbursements of certain environmental maintenance capital expenditures by TRC and the non-controlling interest portion of maintenance capital expenditures and depreciation expense.

Adjusted EBITDA—The Partnership defines Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities 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.

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 investors.

The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors 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 net cash provided by operating activities and is defined differently by different companies in the Partnership’s industry, the Partnership’s definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

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 insights into its decision-making processes.

The following table presents a reconciliation of net cash provided by operating activities to Targa Resources Partners LP Adjusted EBITDA for the periods indicated:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In millions)
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by (used in) operating activities	$	(61.3	)	$	60.3		$	191.3		$	238.9
Net income attributable to noncontrolling interests		(9.0	)		(4.6	)		(29.6	)		(18.2	)
Interest expense, net (1)		24.7			22.2			73.7			52.8
Current income tax expense		2.4			1.8			4.6			3.6
Other (2)		18.8			(7.6	)		10.8			(7.3	)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		105.4			24.5			169.8			(40.3	)
Accounts payable and other liabilities		26.3			(6.1	)		(76.0	)		52.5
Adjusted EBITDA	$	107.3		$	90.5		$	344.6		$	282.0

______

(1)

Net of amortization of debt issuance costs, discount and premium included in interest expense of $1.0 million and $6.7 million for the three months and nine months ended September 30, 2011; and $1.8 million and $4.4 million for the three and nine months ended September 30, 2010. Excludes affiliate and allocated interest expense.

(2)	Includes equity earnings from unconsolidated investments - net of distributions, accretion expenses associated with asset retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets.

The following table presents a reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP	$	35.9		$	13.8		$	129.0		$	73.2
Add:
Interest expense, net (1)		25.7			27.9			80.4			86.6
Income tax expense		1.5			1.7			5.2			3.9
Depreciation and amortization expenses		45.0			43.3			132.2			128.3
Risk management activities		2.0			6.1			6.0			(2.9	)
Noncontrolling interests adjustment		(2.8	)		(2.3	)		(8.2	)		(7.1	)
Adjusted EBITDA	$	107.3		$	90.5		$	344.6		$	282.0

______

(1)	Includes affiliate and allocated interest expense.

Gross Margin - Gross margin is defined as revenues less purchases. It is impacted by volumes and commodity prices as well as by the Partnership’s contract mix and hedging program. The Partnership defines Natural Gas Gathering and Processing gross margin as total operating revenues from the sales of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impact of cash flow settlements from commodity hedging activities are reported in Other.

Operating Margin - Operating margin is an important performance measure of the core profitability of the Partnership’s operations. The Partnership defines operating margin as gross margin less operating expenses. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.

Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income, and have important limitations as analytical tools. Investors should not consider gross margin and operating margin in isolation or as substitutes for analysis of the Partnership’s results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in the Partnership’s industry, the Partnership’s definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. The Partnership believes that investors benefit from having access to the same financial measures that its management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by the Partnership and by external users of the Partnership’s financial statements, including investors and commercial banks to assess:

·	the financial performance of the Partnership’s assets without regard to financing methods, capital structure or historical cost basis;

·	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

·	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these insights into its decision-making processes.

The following table presents a reconciliation of gross margin and operating margin to net income for the periods indicated:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In millions)
Reconciliation of gross margin and operating margin to net income:
Gross margin	$	227.2		$	184.8		$	689.3		$	550.6
Operating expenses		(76.5	)		(66.0	)		(214.1	)		(190.2	)
Operating margin		150.7			118.8			475.2			360.4
Depreciation and amortization expenses		(45.0	)		(43.3	)		(132.2	)		(128.3	)
General and administrative expenses		(33.7	)		(26.7	)		(98.6	)		(80.0	)
Interest expense, net		(25.7	)		(27.9	)		(80.4	)		(86.6	)
Income tax expense		(1.5	)		(1.7	)		(5.2	)		(3.9	)
Gain (loss) on sale of assets		0.3			-			0.4			-
Other, net (1)		(0.2	)		(0.8	)		(0.6	)		29.8
Net income	$	44.9		$	18.4		$	158.6		$	91.4

______

(1)	Includes gain on mark-to-market derivatives, equity in earnings of unconsolidated investment, insurance claims, and other income (expense).

Targa Resources Corp. - Non-GAAP Financial Measures

This press release includes the non-GAAP financial measure distributable cash flow. Distributable cash flow should not be considered as an alternative to GAAP measures such as net income or any other GAAP measure of liquidity or financial performance.

Distributable Cash Flow— The Company defines distributable cash flow as net income attributable to Targa Resources Corp. excluding the Partnership’s earnings, plus depreciation and amortization of Non-Partnership assets, Non-Partnership deferred taxes, distributions that are attributable to the current period of the Partnership, losses (gains) on derivative contracts and certain pre-IPO tax impacts. Distributable cash flow is a significant performance metric used by the Company and by external users of the Company’s financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by the Company to the cash dividends the Company expects to pay its shareholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash dividends. Distributable cash flow is also an important financial measure for the Company’s shareholders since it serves as an indicator of the Company’s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not the Company is generating cash flow at a level that can sustain or support an increase in the Company’s quarterly dividend rates. Distributable cash flow is also a quantitative standard used throughout the investment community because the share value is generally determined by the share’s yield (which in turn is based on the amount of cash dividends the entity pays to a shareholder).

The economic substance behind the Company’s use of distributable cash flow is to measure the ability of the Company’s assets to generate cash flow sufficient to pay dividends to the Company’s 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. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of the Company’s 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 the Company’s industry, the Company’s definition of distributable cash flow may not be compatible to similarly titled measures of other companies, thereby diminishing its utility.

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

	Three Months Ended			Nine Months Ended
	September 30, 2011			September 30, 2011
	(in millions)
Reconciliation of net income attributable to Targa Resources Corp. to Distributable Cash Flow
Net income of Targa Resources Corp.	$	36.5		$	140.6
Less: Net income of Targa Resources Partners LP		(44.9	)		(158.6	)
Net loss for TRC Non-Partnership		(8.4	)		(18.0	)
Plus: TRC Non-Partnership income tax expense		5.9			13.3
Plus: Distributions declared by the Partnership		16.8			46.8
Plus: Non-cash gain on hedges		(0.9	)		(3.8	)
Plus: Depreciation - Non-Partnership assets		0.7			2.1
Plus: Current tax benefit for TRC Non-Partnership (1)		6.1			0.6
Plus: Taxes funded with cash on hand (2)		-			5.1
Distributable cash flow	$	20.2		$	46.1

______

(1)

Excludes $1.2 million and $3.6 million of non-cash current tax expense arising from amortization of deferred long term tax assets from drop down gains realized for tax purposes and paid in 2010 for the three and nine months ended September 30, 2011. Includes a one-time benefit in current tax expense attributable primarily to overpayment of prior year income taxes.

(2)	Current period portion of amount established at the IPO to fund taxes related to deferred tax gains.

The following table presents an alternative reconciliation of cash distributions declared by Targa Resources Partners LP to distributable cash flow of Targa Resources Corp. for the periods indicated:

	Three Months Ended			Nine Months Ended
	September 30, 2011			September 30, 2011
	(in millions)
Targa Resources Corp Distributable Cash Flow
Distributions declared by Targa Resources Partners LP associated with:
General Partner Interests	$	1.2		$	3.5
Incentive Distribution Rights		8.8			23.4
Common Units		6.8			19.9
Total distributions declared by Targa Resources Partners LP		16.8			46.8
Income (expenses) of TRC Non-Partnership
General and administrative expenses		(1.7	)		(6.5	)
Interest expense, net		(1.1	)		(2.9	)
Plus: Current tax benefit for TRC Non-Partnership (1)		6.1			0.6
Taxes funded with cash on hand (2)		-			5.1
Other income		0.1			3.0
Distributable cash flow	$	20.2		$	46.1

______

(1)

(2)	Current period portion of amount established at the IPO to fund taxes related to deferred tax gains.

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 and the Company expect, believe or anticipate 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 the Partnership’s and the Company’s control, which could cause results to differ materially from those expected by management of the Partnership and the Company. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas and natural gas liquids, the timing and success of business development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Partnership's and the Company’s filings with the Securities and Exchange Commission, including their Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. Neither the Partnership nor the Company undertake an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Contact investor relations by phone at (713) 584-1133.

Matthew Meloy

Senior Vice President, Chief Financial Officer and Treasurer

Joe Brass

Director, Finance

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED BALANCE SHEETS
(In millions)
	September 30,		December 31,
	2011		2010

ASSETS
Current assets:
Cash and cash equivalents	$	68.9	$	76.3
Trade receivables		544.5		466.1
Inventory		139.3		50.3
Assets from risk management activities		35.2		25.2
Other current assets		8.4		2.9
Total current assets		796.3		620.8
Property, plant and equipment, net		2,603.3		2,495.2
Long-term assets from risk management activities		20.8		18.9
Other assets		201.6		51.5
Total assets	$	3,622.0	$	3,186.4

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	654.3	$	575.6
Liabilities from risk management activities		34.7		34.2
Total current liabilities		689.0		609.8
Long-term debt payable to third parties		1,514.1		1,445.4
Long-term liabilities from risk management activities		10.7		32.8
Other long-term liabilities		53.2		49.3

Owners' equity:
Targa Resources Partners LP owner's equity		1,215.9		919.8
Noncontrolling interests in subsidiaries		139.1		129.3
Total owners' equity		1,355.0		1,049.1
Total liabilities and owners' equity	$	3,622.0	$	3,186.4

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per unit amounts)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010

REVENUES	$	1,712.7		$	1,218.4		$	5,053.8		$	3,944.6
Product purchases		1,485.5			1,033.6			4,364.5			3,394.0
Operating expenses		76.5			66.0			214.1			190.2
Depreciation and amortization expenses		45.0			43.3			132.2			128.3
General and administrative expenses		33.7			26.7			98.6			80.0
Other		(0.3	)		-			(0.4	)		-
Total costs and expenses		1,640.4			1,169.6			4,809.0			3,792.5
INCOME FROM OPERATIONS		72.3			48.8			244.8			152.1
Other income (expense):
Interest expense from affiliate		-			(2.5	)		-			(23.8	)
Interest expense allocated from Parent		-			(1.4	)		-			(5.6	)
Other interest expense, net		(25.7	)		(24.0	)		(80.4	)		(57.2	)
Equity in earnings of unconsolidated investments		2.2			1.1			5.2			3.8
Gain (loss) on mark-to-market derivative instruments		(1.8	)		(1.9	)		(5.0	)		26.0
Other income (expense)		(0.6	)		-			(0.8	)		-
Income (loss) before income taxes		46.4			20.1			163.8			95.3
Income tax (expense) benefit:		(1.5	)		(1.7	)		(5.2	)		(3.9	)
NET INCOME		44.9			18.4			158.6			91.4
Less: Net income attributable to noncontrolling interests		9.0			4.6			29.6			18.2
NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP	$	35.9		$	13.8		$	129.0		$	73.2

Net income (loss) attributable to predecessor operations	$	-		$	(1.3	)	$	-		$	25.8
Net income attributable to general partner		9.5			5.0			26.0			12.0
Net income allocable to limited partners		26.4			10.1			103.0			35.4
Net income (loss) attributable to Targa Resources Partners LP	$	35.9		$	13.8		$	129.0		$	73.2

Basic and diluted net income per limited partner unit	$	0.31		$	0.14		$	1.23		$	0.51
Basic and diluted weighted average limited partner units outstanding		84.8			72.0			83.9			69.2

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED CASH FLOW INFORMATION
(In millions)
	Nine Months Ended September 30,
	2011			2010

CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	158.6		$	91.4
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization in interest expense		6.7			4.4
Compensation on equity grants		1.2			0.3
Interest expense on affiliate and allocated indebtedness		-			29.4
Depreciation and other amortization expense		132.2			128.3
Accretion of asset retirement obligations		2.7			2.4
Deferred income tax expense		0.6			0.3
Equity in earnings of unconsolidated investment, net of distributions		(1.4	)		-
Risk management activities		(15.1	)		(5.4	)
Loss (gain) on sale of assets		(0.4	)		-
Changes in operating assets and liabilities:		(93.8	)		(12.2	)
Net cash used by operating activities		191.3			238.9
CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment		(211.4	)		(82.5	)
Business acquisition		(164.2	)		-
Investment in unconsolidated affiliate		(11.9	)		-
Unconsolidated affiliate distributions in excess of accumulated earnings		-			1.1
Other, net		0.3			2.1
Net cash used in investing activities		(387.2	)		(79.3	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility		1,426.0			1,178.1
Repayments of credit facility		(1,656.3	)		(904.0	)
Proceeds from issuance of senior notes		325.0			250.0
Cash paid on note exchange		(27.7	)
Repayment of affiliated and allocated indebtedness		-			(740.2	)
Proceeds from equity offerings		304.3			317.8
Costs incurred in connection with financing arrangements		(6.2	)		(20.2	)
Contributions from (distributions to) parent		9.1			(95.7	)
Distributions to unitholders		(165.9	)		(117.8	)
Distributions under common control		-			(46.6	)
Distribution to noncontrolling interests		(19.8	)		(17.4	)
Net cash provided in financing activities		188.5			(196.0	)
Net change in cash and cash equivalents		(7.4	)		(36.4	)
Cash and cash equivalents, beginning of period		76.3			90.9
Cash and cash equivalents, end of period	$	68.9		$	54.5

TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010

REVENUES	$	1,713.6		$	1,220.0		$	5,060.5		$	3,948.3
Costs and expenses:
Product purchases		1,485.5			1,033.7			4,364.5			3,393.9
Operating expenses		76.5			66.2			214.1			190.4
Depreciation and amortization expenses		45.7			50.2			134.3			136.9
General and administrative expenses		35.4			27.0			105.1			81.0
Other		(0.3	)		(0.4	)		(0.3	)		(0.4	)
Total costs and expenses		1,642.8			1,176.7			4,817.7			3,801.8
INCOME FROM OPERATIONS		70.8			43.3			242.8			146.5
Other income (expense):
Interest expense, net		(26.8	)		(30.0	)		(83.3	)		(83.9	)
Equity in earnings of unconsolidated investment		2.2			1.1			5.2			3.8
Gain (loss) on debt repurchases (see Note 6)		-			-			-			(17.4	)
Gain on early debt extinguishment (see Note 6)		-			(10.6	)		-			8.1
Loss on mark-to-market derivative instruments		(1.8	)		(0.1	)		(5.0	)		(0.4	)
Other income (expenses)		(0.5	)		0.6			(0.6	)		0.8
Income before income taxes		43.9			4.3			159.1			57.5
Income tax (expense) benefit:		(7.4	)		(8.6	)		(18.5	)		(18.5	)
NET INCOME		36.5			(4.3	)		140.6			39.0
Less: Net income attributable to noncontrolling interests		31.6			13.2			118.4			46.2
NET INCOME (LOSS) ATTRIBUTABLE TO TARGA RESOURCES CORP.		4.9			(17.5	)		22.2			(7.2	)
Dividends on Series B preferred stock		-			(1.4	)		-			(8.4	)
Dividends on common equivalents		-			-			-			(177.8	)
Net income (loss) available to common shareholders	$	4.9		$	(18.9	)	$	22.2		$	(193.4	)

Net income (loss) available per common share - basic	$	0.12		$	(3.77	)	$	0.54		$	(45.00	)
Net income (loss) available per common share - diluted	$	0.12		$	(3.77	)	$	0.54		$	(45.00	)
Weighted average shares outstanding - basic		41.0			5.0			41.0			4.3
Weighted average shares outstanding - diluted		41.5			5.0			41.4			4.3

TARGA RESOURCES CORP.
FINANCIAL SUMMARY (unaudited)
KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS
(In millions)
	September 30, 2011
Cash and cash equivalents:
TRC Non-Partnership	$	85.2
Targa Resources Partners		68.9
Total cash and cash equivalents	$	154.1
Long-term Debt:
TRC Non-Partnership	$	89.3
Targa Resources Partners		1,514.1
Total long-term debt	$	1,603.4

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