Targa Resources Corp. - FORM 8-K - EX-99.1 - PRESS RELEASE DATED FEBRUARY 23, 2012

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EXHIBIT 99.1

Targa Resources Partners LP and Targa Resources Corp. Report

Fourth Quarter and Full Year 2011 Financial Results

HOUSTON —February 23, 2012—Targa Resources Partners LP (NYSE: NGLS) (“Targa Resources Partners” or the “Partnership”) and Targa Resources Corp. (NYSE: TRGP) (“TRC” or the “Company”) today reported fourth quarter and full year 2011 results. Fourth quarter 2011 net income attributable to Targa Resources Partners was $75.5 million compared to $35.9 million for the fourth quarter of 2010. The income per basic and diluted limited partner unit was $0.75 in the fourth quarter of 2011 compared to $0.39 for the fourth quarter of 2010. Net income for the fourth quarters of 2011 and 2010 included non-cash losses of $1.3 million and $9.3 million related to derivative instruments, respectively. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments (“Adjusted EBITDA”) of $146.3 million for the fourth quarter of 2011 compared to $114.1 million for the fourth quarter of 2010.

For the full year 2011, net income attributable to Targa Resources Partners was $204.5 million compared to $109.1 million for 2010. Net income per basic and diluted limited partner unit was $1.98 for 2011 compared to $0.92 for 2010. Net income for the full year 2011 and 2010 included $7.2 million and $6.4 million in non-cash charges related to derivative instruments, respectively. The 2010 full year also included $29.4 million in affiliate and allocated interest expense for periods prior to the acquisitions of the Permian Business, Coastal Straddles, Versado and VESCO by the Partnership. The Partnership reported Adjusted EBITDA of $490.8 for the full year 2011 compared to $396.1 million for the full year of 2010.

The Partnership’s distributable cash flow for the fourth quarter 2011 of $107.2 million corresponds to distribution coverage of approximately 1.6 times the $66.0 million in total distributions paid on February 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 the Partnership’s record full year EBITDA of $491 million for 2011 and record quarter with $146 million of fourth quarter EBITDA. The Partnership’s EBITDA increased approximately 25% over the prior year driven significantly by successful execution of our growth strategy. We had approximately $300 million of growth projects come into service in 2011 and announced a total of $1 billion of organic growth projects for 2012 and 2013,” said Joe Bob Perkins, Chief Executive Officer of the Partnership’s general partner and of Targa Resources Corp. “We have clear momentum going forward as our announced projects come on line through 2013 and add significant fee based margin to our cash flow profile. We are well positioned to execute on our growth strategy in 2012 having raised over $565 million in both debt and equity this year. We will continue to pursue high quality organic growth projects, steadily execute our strategy and deliver exceptional customer service.”

On January 12, 2012, the Partnership announced a cash distribution for the fourth quarter 2011 of 60.25¢ per common unit, or $2.41 per unit on an annualized basis, representing an increase of approximately 3% over the third quarter 2011 and 10% over the annualized distribution paid with respect to the fourth quarter 2010. The cash distribution was paid on February 14, 2012 on all outstanding common units to holders of record as of the close of business on January 23, 2012. The total distribution paid was $66.0 million, with $45.9 million to the Partnership’s third-party limited partners, and $20.1 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 December 31, 2011 was $1,477.7 million including $498.0 million outstanding under the Partnership’s $1.1 billion senior secured revolving credit facility, $209.1 million of 8¹/4% senior unsecured notes due 2016, $72.7 million of 11¹/4% senior unsecured notes due 2017, $250.0 million of 7⁷/8% senior unsecured notes due 2018, $483.6 million of 6⁷/8% senior unsecured notes due 2021 and $35.7 million of unamortized discounts.

As of December 31, 2011, after giving effect to $92.5 million in outstanding letters of credit, the Partnership had available revolver capacity of $509.5 million and $55.6 million of cash resulting in total liquidity of $565.1 million.

On January 23, 2012, the Partnership completed a public offering of 4,000,000 common units representing limited partner interests in the Partnership, providing net proceeds of $150 million. Pursuant to the exercise of the underwriter’s overallotment option, the Partnership sold an additional 405,000 units providing net proceeds of approximately $15 million. The net proceeds from the offering were used to reduce borrowings under the Partnership’s senior secured credit facility.

On January 30, 2012 the partnership closed on a private placement of $400 million in aggregate principal amount of 6³/8% senior unsecured notes due 2022 resulting in net proceeds of $395 million. The net proceeds were used to reduce borrowings under the Partnership’s senior secured credit facility and for general partnership purposes.

Pro forma for the completion of the unit offering and note offering, the Partnership had available revolver capacity of over $1 billion after giving effect to $92.5 million in outstanding letters of credit.

For 2012, the Partnership expects total capital expenditures will be $680 million gross and $650 million net of noncontrolling interest share and reimbursements. Maintenance capital expenditures are expected to be approximately 12% of the total net capital expenditures. In addition, the Partnership estimates that it will invest approximately $13 million in 2012 for its pro rata share of the Gulf Coast Fractionators expansion.

The Partnership’s previous 2012 Adjusted EBITDA forecast of $515 to $550 million remains unchanged, and, based on current market prices, including ethane of about $0.50 per gallon, the Partnership is comfortable with the midpoint of that range of approximately $530 million.

Targa Resources Corp.—Fourth Quarter and Full Year 2011 Financial Results

Targa Resources Corp., the parent of Targa Resources Partners, today reported its fourth quarter and full year 2011 results. The Company, which at December 31, 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.

TRC reported net income attributable to the Company of $8.5 million and $30.7 million for the fourth quarter and full year 2011, respectively, compared with a net loss of $7.8 million and $15 million for the fourth quarter and full year 2010, respectively.

On January 23, 2012, TRC purchased 1,300,000 common units of the Partnership’s public offering of a total of 4,000,000 common units. These new units received the distribution declared by the Partnership with respect to the fourth quarter of 2011. Pro forma for the additional units, TRC owns 12,945,659 common units of the Partnership.

Fourth quarter 2011 distributions paid on February 14, 2012 by the Partnership to the Company totaled $20.1 million, with $7.8 million, $11.0 million and $1.3 million paid with respect to common units, IDRs and general partner interests, respectively.

On January 12, 2012, TRC declared a quarterly dividend of 33.625¢ per share of its common stock for the three months ended December 31, 2011, or $1.345 per share on an annualized basis, representing increases of approximately 9% over the previous quarter’s dividend and 31% over the prorated dividend for the fourth quarter of 2010. Total cash dividends of approximately $14.3 million were paid February 15, 2012 on all outstanding common shares to holders of record as of the close of business on January 23, 2012.

The Company’s distributable cash flow for the fourth quarter 2011 of $14.1 million corresponds to dividend coverage of approximately 1.0 times the $14.3 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).

Targa Resources Corp.—Capitalization, Liquidity and Financing Update

Total funded debt of the Company as of December 31, 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 $90.2 million as of December 31, 2011, resulting in total liquidity of $165.2 million.

On January 23, 2012 the Company closed on its purchase of 1,300,000 common units from the Partnership for approximately $49.8 million. The Company also contributed to the Partnership approximately $3.4 million for 89,898 general partner units to maintain its 2% general partner interest in the Partnership. Pro forma for these transactions, the Company’s cash balance as of December 31, 2011 was $37.0 million resulting in total liquidity of $112.0 million.

Conference Call

Targa Resources Partners and Targa Resources Corp. will host a joint conference call for investors and analysts at 11:30 a.m. Eastern Time (10:30 a.m. Central Time) on February 23, 2012 to discuss fourth quarter and full year 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 47310792. 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 47310792 and will remain available, along with the Webcast, until March 8, 2012.

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 December 31,						Year Ended December 31,
	2011			2010			2011			2010
	(In millions except per unit data)
Revenues	$	1,933.3		$	1,522.4		$	6,987.1		$	5,467.0
Product purchases		1,674.5			1,300.7			6,039.0			4,695.7

Gross margin (1)		258.8			221.7			948.1			771.3
Operating expenses		72.9			69.4			287.0			258.6

Operating margin (2)		185.9			152.3			661.1			512.7
Depreciation and amortization expense		46.0			47.8			178.2			176.2
General and administrative expense		29.2			42.5			127.8			122.4
Other		0.5			(3.3	)		0.2			(3.3	)

Income from operations		110.2			65.3			354.9			217.4
Interest expense, net		(27.3	)		(24.2	)		(107.7	)		(110.8	)
Equity earnings		3.6			1.6			8.8			5.4
Gain (loss) on mark-to-market derivative instruments		—			—			(5.0	)		26.0
Other		(0.5	)		—			(1.2	)		—
Income tax expense		0.9			0.1			(4.3	)		(4.0	)

Net income (loss)		86.9			42.8			245.5			134.0
Less: Net income attributable to noncontrolling interest		11.4			6.9			41.0			24.9

Net income (loss) attributable to Targa Resources Partners LP	$	75.5		$	35.9		$	204.5		$	109.1

Net income attributable to predecessor operations	$	—		$	—		$	—		$	25.8
Net income (loss) attributable to general partner		11.9			6.1			38.0			18.1
Net income attributable to limited partners		63.6			29.8			166.5			65.2

Net income attributable to Targa Resources Partners LP	$	75.5		$	35.9		$	204.5		$	109.1

Basic and diluted net income per limited partner unit	$	0.75		$	0.39		$	1.98		$	0.92

Financial data:
Adjusted EBITDA (3)	$	146.3		$	114.1		$	490.8		$	396.1
Distributable cash flow (4)		107.2			75.9			336.7			277.0

Operating data:
Plant natural gas inlet, MMcf/d (5)(6)		2,189.6			2,183.4			2,162.1			2,268.0
Gross NGL production, MBbl/d		129.1			122.6			123.9			121.2
Natural gas sales, BBtu/d (6)		876.4			704.9			779.3			685.8
NGL sales, MBbl/d		282.9			267.9			269.6			251.5
Condensate sales, MBbl/d		2.7			3.0			3.0			3.5

(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 Fourth Quarter and Full Year Results

Three Months Ended December 31, 2011 Compared to Three Months Ended December 31, 2010

Revenues (including the impacts of hedging) increased due to the higher net impact of realized prices on NGLs and condensate ($245.8 million), higher NGL and natural gas sales volumes ($170.9 million) and higher fee-based and other revenues ($24.6 million), partially offset by lower realized prices on natural gas ($28.4 million) and lower condensate sales volumes ($2.0 million).

Operating margin increased $33.6 million, reflecting higher gross margin partially offset by higher operating expenses. The increase in gross margin resulted from higher revenues ($410.9 million) partially offset by increases in product purchase costs ($373.8 million). The increase in operating expenses primarily reflects increased contract labor, 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 decrease in depreciation and amortization expenses of $1.8 million is primarily due to an impairment taken on an asset in the fourth quarter of 2010 partially offset by increases from the impact of gathering, fractionating and storage terminal assets purchased in 2011 and expansion projects placed in service since the fourth quarter of 2010.

General and administrative expenses decreased $13.3 million reflecting lower compensation and benefit costs.

The increase in interest expense of $3.1 million is attributable to an increase in interest expense on third party debt due to higher borrowings and a higher effective interest rate.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Revenues (including the impacts of hedging) increased due to the higher net impact of realized prices on NGLs and condensate ($1,067.3 million), higher natural gas and NGL sales volumes ($486.4 million) and higher fee-based and other revenues ($81.8 million) partially offset by lower natural gas prices ($105.2 million) and lower condensate sales volumes ($11.1 million).

Operating margin increased $148.4 million, reflecting higher gross margin, partially offset by higher operating expenses. The increase in gross margin resulted from higher revenues ($1,520.1 million), partially offset by increases in product purchase costs ($1,343.3 million). The $28.4 million increase in operating expenses primarily reflects increased compensation and benefits, maintenance and fuel, utilities and catalyst costs.

The increase in depreciation and amortization expenses of $2.0 million is primarily due to the impact of gathering, fractionating and storage terminal assets purchased in 2011 and expansion projects in service since the third quarter of 2010 ($7.6 million) offset by assets that became fully depreciated in 2010 ($5.6 million).

General and administrative expenses increased $5.4 million primarily due to increased compensation and benefits.

Interest expense decreased by $3.1 million attributable to a $26.3 million increase in interest expense on third party debt, due to higher borrowings and a higher effective interest rate, offset by a $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 Business, Versado and VESCO acquisitions in 2010.

Mark-to-market gains decreased $31.0 million, moving from a gain of $26.0 million in 2010 to a loss of $5.0 million in 2011. The gain in 2010 was attributable to the accounting treatment of commodity derivatives related to the Permian Business and Versado acquisitions during 2010. These derivatives, which qualified for hedge accounting by Targa, did not qualify for hedge accounting treatment for predecessor periods included in our restated common control basis financial statements. Therefore, changes in value for these instruments for pre-acquisition periods were recorded in earnings. At the acquisition dates, the Partnership designated these derivative instruments as cash flow hedges, and therefore subsequent changes in value are recorded in OCI until the underlying transactions settle. Had the Partnership been able to account for these as hedges in pre-acquisition periods, mark-to-market results would have resulted in a loss of $0.4 million in 2010. The loss in 2011 was attributable to a portion of the Partnership’s interest rate swaps that did not qualify for hedge accounting as of February 11, 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 December 31,				Year Ended December 31,
	2011		2010		2011		2010
	($ in millions except price data)
Gross margin	$	104.2	$	88.4	$	403.6	$	338.8
Operating expenses		29.4		28.6		115.7		102.2

Operating margin	$	74.8	$	59.8	$	287.9	$	236.6

Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)
Permian		142.0		133.9		134.2		128.7
SAOU		114.0		107.2		111.0		99.8
North Texas System		221.6		189.9		203.5		180.4
Versado		154.8		173.7		162.8		178.7

		632.4		604.6		611.5		587.7

Gross NGL production, MBbl/d
Permian		16.5		15.5		15.7		14.8
SAOU		18.1		16.2		17.4		15.3
North Texas System		24.9		21.7		22.9		20.7
Versado		17.8		20.6		18.1		20.4

		77.4		74.0		74.2		71.2

Natural gas sales, BBtu/d (2),(3)		298.0		262.7		285.5		258.6
NGL sales, MBbl/d (3)		62.5		59.4		59.8		56.6
Condensate sales, MBbl/d (3)		2.4		2.6		2.8		2.9
Average realized prices (4):
Natural gas, $/MMBtu		3.32		3.53		3.80		4.09
NGL, $/gal		1.27		1.00		1.23		0.93
Condensate, $/Bbl		89.94		81.18		91.55		75.48

(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 December 31, 2011 Compared to Three Months Ended December 31, 2010

The $15.8 million increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices ($65.5 million), higher natural gas and NGL sales volumes ($23.3 million) and higher fee-based and other revenues ($0.9 million), partially offset by higher product purchases ($66.7 million), lower natural gas prices ($5.6 million) and lower condensate sales volumes ($1.6 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.

The $0.8 million increase in operating expenses was primarily due to higher fuel, utilities and catalyst expenses ($0.4 million) and higher maintenance costs ($0.4 million).

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

The $64.8 million increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices ($290.9 million), higher natural gas and NGL volumes ($85.9 million) and higher fee based and other revenues ($4.0 million), partially offset by higher product purchases ($281.2 million), lower natural gas sales prices ($30.9 million), and lower condensate sales volumes ($3.8 million). The increase in plant inlet volumes was largely attributable to new well connects, particularly at North Texas and SAOU. These factors were partially offset by the impact of severe cold weather in the first quarter of 2011, operational outages in the third quarter of 2011 and production declines at our Versado system. Natural gas sales increased on higher throughput and a decrease in take-in-kind volumes.

The $13.5 million increase in operating expenses was primarily due to higher fuel, utilities and catalyst expenses ($4.1 million), higher system maintenance expenses ($3.4 million) driven by severe cold weather and operational outages in 2011, higher compensation and benefit costs ($3.4 million) and higher contract and professional service expenses ($2.4 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 December 31,				Year Ended December 31,
	2011		2010		2011		2010
	($ in millions except price data)
Gross margin	$	65.1	$	45.0	$	221.6	$	151.2
Operating expenses		12.6		12.0		47.3		43.4

Operating margin	$	52.5	$	33.0	$	174.3	$	107.8

Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2),(3)
LOU		194.1		166.9		175.7		184.6
Coastal Straddles		812.7		972.6		876.4		1,068.4
VESCO		550.4		439.3		498.5		427.3

		1,557.2		1,578.8		1,550.6		1,680.3

Gross NGL production, MBbl/d
LOU		8.6		6.5		7.4		7.2
Coastal Straddles		14.7		18.2		16.5		19.7
VESCO		28.4		23.9		25.8		23.2

		51.7		48.6		49.8		50.1

Natural gas sales, Bbtu/d (3),(4)		290.1		258.6		268.4		294.2
NGL sales, MBbl/d (4)		45.2		42.9		43.5		43.7
Condensate sales, MBbl/d (4)		0.3		0.1		0.3		0.5

Average realized prices (5):
Natural gas, $/MMBtu		3.43		3.91		4.02		4.48
NGL, $/gal		1.35		1.13		1.31		1.03
Condensate, $/Bbl		112.67		83.65		105.10		78.82

(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)	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 December 31, 2011 Compared to Three Months Ended December 31, 2010

The $20.1 million increase in gross margin for 2011 was primarily due to higher NGL and condensate sales prices, a favorable frac spread as a result of low prices relative to NGLs and crude oil, a significant increase in higher GPM keep-whole volumes at VESCO and Lowry and higher system average GPM at LOU largely due to increased traditional wellhead volumes. The higher GPM resulted in higher gross NGL production despite lower inlet volumes.

The $0.6 million increase in operating expenses was primarily due to higher contract and professional service expenses ($0.7 million) and higher general maintenance expenses ($0.7 million) partially offset by lower compensation and benefit costs ($0.8 million).

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

The $70.4 million increase in gross margin is primarily attributable to higher NGL and condensate sales prices, a favorable frac spread as a result of low gas prices relative to NGLs and crude oil, a significant increase in higher GPM keep-whole volumes at VESCO and Lowry and higher system average GPM at LOU largely due to increased traditional wellhead volumes. The decrease in plant inlet volumes was largely attributable to a decline in traditional wellhead and offshore supply volumes. Despite these lower offshore volumes, NGL production and sales volumes remained relatively flat as a result of increased traditional wellhead gas at LOU and the diversion of throughput to more efficient, higher recovery plants, particularly VESCO. Natural gas sales volumes decreased due to lower demand from industrial customers and lower sales to other reportable segments for resale.

The $3.9 million increase in operating expenses was primarily due to higher contract and professional service expenses ($0.9 million) and higher miscellaneous and other expenses ($1.6 million), higher operating expenses on non-operated joint ventures ($0.6 million) and a decrease in recovery of expenses from an operated joint venture ($0.9 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 December 31,				Year Ended December 31,
	2011		2010		2011		2010
	($ in millions)
Gross margin	$	64.2	$	50.6	$	221.1	$	171.4
Operating expenses		26.9		19.9		98.0		87.6

Operating margin	$	37.3	$	30.7	$	123.1	$	83.8

Operating statistics (1):
Fractionation volumes, MBbl/d		293.2		243.9		268.4		230.8
Treating volumes, MBbl/d		—		18.8		15.3		18.0

(1)

Three Months Ended December 31, 2011 Compared to Three Months Ended December 31, 2010

The $13.6 million increase in gross margin primarily reflects higher fractionation volumes driven by the CBF expansion as well as contributions from petroleum terminaling assets acquired in 2011. LSNG customers, contractually bound to take-or-pay for treating services, decided not to use their reserved throughput in the fourth quarter of 2011, leading to lower treating volumes compared to the fourth quarter of 2010.

The $7.0 million increase in operating expenses was primarily due to higher utility, power and catalyst costs, higher compensation and benefit expenses, and higher system maintenance and contract and professional services costs resulting from the increased volumes from the CBF expansion.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

The $49.7 million increase in gross margin was primarily due to higher fractionation and treating revenue ($28.2 million), higher terminaling and storage revenue ($16.7 million) and higher fee-based and other revenue ($4.4 million). Higher fractionation revenues were driven by the expansion at CBF. LSNG customers, contractually bound to take-or-pay for treating services, decided not to use their reserved throughput in the fourth quarter of 2011, leading to lower treating volumes compared to 2010. The increase in terminaling and storage revenue was partially due to the impact of propane and normal butane exports. The increase in fee-based and other revenue is due to the 2011 acquisitions of petroleum terminaling assets.

The $10.4 million increase in operating expenses was primarily due to higher utility, power and catalyst costs as a result of the expansion of the CBF facility ($6.4 million), higher compensation and benefit expense ($4.4 million), system maintenance costs ($2.6 million), and contract and professional services fees ($2.7 million), partially offset by an increase in system product gains ($5.3 million) as a result of increased volumes at the recently expanded CBF, which provides more favorable product upgrades. Higher operating expenses also reflect the 2011 acquisitions of petroleum terminaling assets.

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 December 31,				Year Ended December 31,
	2011		2010		2011		2010
	($ in millions, except price data)
Gross margin	$	40.4	$	43.1	$	156.4	$	125.3
Operating expenses		9.8		11.3		43.0		44.8

Operating margin	$	30.6	$	31.8	$	113.4	$	80.5

Operating statistics (1):
Natural gas sales, BBtu/d		1,022.5		649.3		877.8		634.9
NGL sales, MBbl/d		287.8		262.5		272.5		246.7
Natural gas, $/MMBtu		3.42		3.76		3.94		4.31
NGL realized price, $/gal		1.40		1.21		1.34		1.10

(1)

Three Months Ended December 31, 2011 Compared to Three Months Ended December 31, 2010

The $2.7 million decrease in gross margin was primarily due to lower wholesale propane activity in the fourth quarter of 2011. The lower activity was the result of warmer weather that reduced the demand for propane compared with the fourth quarter of 2010. Natural gas sales volumes increased due to higher natural gas purchases which resulted in incremental increases in volumes processed by other reportable segments.

Operating expenses decreased $1.5 million primarily due to lower contractor and professional services expenses ($1.2 million).

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

The $31.1 million increase in gross margin was primarily due to higher NGL sales prices ($996.1 million), higher natural gas and NGL sales volumes ($816.3 million) and increased fee-based and other revenues ($37.5 million), partially offset by increased product purchases ($1,698.2 million), lower natural gas sales prices ($119.9 million) and lower condensate sales volumes ($1.0 million). NGL sales volumes rose on increased demand from industrial customers and from increased export sales. Natural gas sales volumes increased due to higher natural gas purchases which resulted in incremental increases in volumes processed by other reportable segments.

Operating expenses decreased $1.8 million due to lower railcar expenses ($2.2 million) and contractor and professional services fees ($1.9 million), partially offset by higher system maintenance costs ($1.7 million) and compensation and benefit expenses ($0.8 million).

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 December 31, 2011 Compared to Three Months Ended December 31, 2010

For the three months ended December 31, 2011, the Partnership’s cash flow hedging program decreased gross margin by $9.2 million compared to a decrease of $2.8 million for the same period during 2010. The decrease was driven by NGL and crude oil prices increasing above the fixed prices the Partnership receives on its commodity hedges partially offset by natural gas prices falling to levels below the fixed price received.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

For the year ended December 31, 2011, the Partnership’s cash flow hedging program decreased gross margin by $37.6 million compared to an increase of $4.0 million for the same period during 2010. The decrease was driven by NGL and crude oil prices increasing above the fixed prices the Partnership receives on its commodity hedges partially offset by natural gas prices falling to levels below the fixed price received.

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 attributable to Targa Resources Partners LP 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 December 31,						Year Ended December 31,
	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	$	75.5		$	35.9		$	204.5		$	109.1
Affiliate and allocated interest expense		—			—			—			29.4
Depreciation and amortization expenses		46.0			47.8			178.2			176.2
Deferred income tax expense		0.2			0.7			0.8			1.2
Amortization in interest expense		4.2			1.0			12.4			6.1
Risk management activities		1.3			9.3			7.2			6.4
Maintenance capital expenditures		(24.6	)		(20.7	)		(81.8	)		(50.4	)
Other (1)		4.6			1.9			15.4			(1.0	)

Distributable cash flow	$	107.2		$	75.9		$	336.7		$	277.0

(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 attributable to Targa Resources Partners LP 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 attributable to Targa Resources Partners LP. 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 attributable to Targa Resources Partners LP 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 December 31,						Year Ended December 31,
	2011			2010			2011			2010
	(In millions)
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	209.6		$	129.0		$	400.9		$	367.9
Net income attributable to noncontrolling interests		(11.4	)		(6.7	)		(41.0	)		(24.9	)
Interest expense, net (1)		21.6			22.0			95.3			74.8
Current income tax expense		(1.1	)		(0.8	)		3.5			2.8
Other (2)		(2.8	)		(4.1	)		7.9			(11.4	)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		(19.5	)		111.5			150.3			71.2
Accounts payable and other liabilities		(50.1	)		(136.8	)		(126.1	)		(84.3	)

Adjusted EBITDA	$	146.3		$	114.1		$	490.8		$	396.1

(1)

Net of amortization of debt issuance costs, discount and premium included in interest expense of $5.7 million and $12.4 million for the three months and year ended December 31, 2011; and $2.2 million and $6.6 million for the three months and year ended December 31, 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 December 31,						Year Ended December 31,
	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	$	75.5		$	35.9		$	204.5		$	109.1
Add:
Interest expense, net (1)		27.3			24.2			107.7			110.8
Income tax expense		(0.9	)		0.1			4.3			4.0
Depreciation and amortization expenses		46.0			47.9			178.2			176.2
Risk management activities		1.3			9.3			7.2			6.4
Noncontrolling interests adjustment		(2.9	)		(3.3	)		(11.1	)		(10.4	)

Adjusted EBITDA	$	146.3		$	114.1		$	490.8		$	396.1

(1)	Includes affiliate and allocated interest expense.

The following schedules present reconciliations of net income attributable to Targa Resources Partners LP to Adjusted EBITDA for the guidance given for the twelve months ending December 31, 2012:


	Twelve Months Ending December 31, 2012
	Low Range			High Range
	($ in millions)
Reconciliation of net income (loss) attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income (loss) to Targa Resources Partners LP	$	220.0		$	255.0
Add:
Interest expense, net		110.0			110.0
Income tax expense		6.0			6.0
Depreciation and amortization expense		188.0			188.0
Risk management activities		2.0			2.0
Noncontrolling interest adjustment		(11.0	)		(11.0	)

Adjusted EBITDA	$	515.0		$	550.0

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 is 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 December 31,						Year Ended December 31,
	2011			2010			2011			2010
	(In millions)
Reconciliation of gross margin and operating margin to net income:
Gross margin	$	258.8		$	221.7		$	948.1		$	771.3
Operating expenses		(72.9	)		(69.4	)		(287.0	)		(258.6	)

Operating margin		185.9			152.3			661.1			512.7
Depreciation and amortization expenses		(46.0	)		(47.8	)		(178.2	)		(176.2	)
General and administrative expenses		(29.2	)		(42.5	)		(127.8	)		(122.4	)
Other operating income (loss)		—			3.3			—			3.3
Interest expense, net		(27.3	)		(24.2	)		(107.7	)		(110.8	)
Income tax expense		0.9			0.1			(4.3	)		(4.0	)
Gain (loss) on sale of assets		(0.5	)		—			(0.2	)		—
Other, net (1)		3.1			1.6			2.6			31.4

Net income	$	86.9		$	42.8		$	245.5		$	134.0

(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 attributable to Targa Resources Corp. Distributable cash flow should not be considered as an alternative to GAAP net income attributable to Targa Resources Corp. 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 attributable to Targa Resources Corp. 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 December 31, 2011			Year Ended December 31, 2011
	(In millions)
Reconciliation of net income attributable to Targa Resources Corp. to Distributable Cash Flow
Net income of Targa Resources Corp.	$	74.8		$	215.4
Less: Net income of Targa Resources Partners LP		(86.9	)		(245.5	)

Net income (loss) for TRC Non-Partnership		(12.1	)		(30.1	)
Plus: TRC Non-Partnership income tax expense		9.0			22.3
Plus: Distributions declared by the Partnership		20.1			66.9
Plus: Non-cash loss (gain) on hedges		(0.6	)		(4.4	)
Plus: Depreciation - Non-Partnership assets		0.7			2.8
Less: Current cash tax expense (1)		(8.0	)		(7.4	)
Plus: Taxes funded with cash on hand (2)		5.0			10.1

Distributable cash flow	$	14.1		$	60.2

(1)

Excludes $1.2 million and $4.7 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 months and year ended December 31, 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 December 31, 2011			Year Ended December 31, 2011
	(In millions)
Targa Resources Corp Distributable Cash Flow
Distributions declared by Targa Resources
Partners LP associated with:
General Partner Interests	$	1.3		$	4.8
Incentive Distribution Rights		11.0			34.4
Common Units		7.8			27.7

Total distributions declared by Targa Resources Partners LP Income (expenses) of TRC Non-Partnership		20.1			66.9
General and administrative expenses		(1.8	)		(8.3	)
Interest expense, net		(1.1	)		(4.0	)
Current cash tax expense (1)		(8.0	)		(7.4	)
Taxes funded with cash on hand (2)		5.0			10.1
Other income (expense)		(0.1	)		2.9

Distributable cash flow	$	14.1		$	60.2

(1)	Excludes $1.2 million and $4.7 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 months and year ended December 31, 2011.

(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)


	December 31, 2011		December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	55.6	$	76.3
Trade receivables		575.9		466.1
Inventory		92.1		50.3
Assets from risk management activities		41.0		25.2
Other current assets		2.7		2.9

Total current assets		767.3		620.8

Property, plant and equipment, net		2,806.1		2,495.2
Long-term assets from risk management activities		10.9		18.9
Other assets		73.7		51.5

Total assets	$	3,658.0	$	3,186.4

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	707.8	$	575.6
Liabilities from risk management activities		41.1		34.2

Total current liabilities		748.9		609.8

Long-term debt payable to third parties		1,477.7		1,445.4
Long-term liabilities from risk management activities		15.8		32.8
Other long-term liabilities		53.9		49.3

Owners’ equity:
Targa Resources Partners LP owner’s equity		1,222.8		919.8
Noncontrolling interests in subsidiaries		138.9		129.3

Total owners’ equity		1,361.7		1,049.1

Total liabilities and owners’ equity	$	3,658.0	$	3,186.4

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit amounts)


	Three Months Ended December 31,						Year Ended December 31,
	2011			2010			2011			2010
REVENUES	$	1,933.3		$	1,522.4		$	6,987.1		$	5,467.0
Product purchases		1,674.5			1,300.7			6,039.0			4,695.7
Operating expenses		72.9			69.4			287.0			258.6
Depreciation and amortization expenses		46.0			47.8			178.2			176.2
General and administrative expenses		29.2			42.5			127.8			122.4
Other		0.5			(3.3	)		0.2			(3.3	)

Total costs and expenses		1,823.1			1,457.1			6,632.2			5,249.6
INCOME FROM OPERATIONS		110.2			65.3			354.9			217.4
Other income (expense):
Interest expense from affiliate		—			—			—			(23.8	)
Interest expense allocated from Parent		—			—			—			(5.6	)
Other interest expense, net		(27.3	)		(24.2	)		(107.7	)		(81.4	)
Equity in earnings of unconsolidated investments		3.6			1.6			8.8			5.4
Gain (loss) on mark-to-market derivative instruments		—			—			(5.0	)		26.0
Other income (expense)		(0.5	)		—			(1.2	)		—

Income (loss) before income taxes		86.0			42.7			249.8			138.0
Income tax (expense) benefit:		0.9			0.1			(4.3	)		(4.0	)

NET INCOME		86.9			42.8			245.5			134.0
Less: Net income attributable to noncontrolling interests		11.4			6.9			41.0			24.9

NET INCOME ATTRIBUTABLE TO TARGA RESOURCES PARTNERS LP	$	75.5		$	35.9		$	204.5		$	109.1

Net income (loss) attributable to predecessor operations	$	—		$	—		$	—		$	25.8
Net income attributable to general partner		11.9			6.1			38.0			18.1
Net income allocable to limited partners		63.6			29.8			166.5			65.2

Net income (loss) attributable to Targa Resources Partners LP	$	75.5		$	35.9		$	204.5		$	109.1

Basic net income per limited partner unit	$	0.75		$	0.39		$	1.98		$	0.92

Diluted net income per limited partner unit	$	0.75		$	0.39		$	1.98		$	0.92

Basic weighted average limited partner units outstanding		84.8			75.5			84.1			70.8
Diluted weighted average limited partner units outstanding		84.8			75.5			84.2			70.8

TARGA RESOURCES PARTNERS LP

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED CASH FLOW INFORMATION

(In millions)


	Year Ended December 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	245.5		$	134.0
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense		12.4			6.6
Compensation on equity grants		1.5			0.4
Interest expense on affiliate and allocated indebtedness		—			29.4
Depreciation and other amortization expense		178.2			171.3
Asset impairment charge		—			4.9
Accretion of asset retirement obligations		3.6			3.2
Deferred income tax expense		0.8			1.2
Equity in earnings of unconsolidated investment, net of distributions		(0.4	)		—
Risk management activities		(16.7	)		3.8
Loss (gain) on debt repurchases		—			—
Loss (gain) on sale of assets		0.2			—
Changes in operating assets and liabilities:		(24.2	)		13.1

Net cash used by operating activities		400.9			367.9

CASH FLOWS FROM INVESTING ACTIVITIES
Outlays for property, plant and equipment		(328.7	)		(137.0	)
Business acquisition		(156.5	)		—
Investment in unconsolidated affiliate		(21.2	)		—
Unconsolidated affiliate distributions in excess of accumulated earnings		—			3.3
Other, net		0.3			2.1

Net cash used in investing activities		(506.1	)		(131.6	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility		1,787.0			1,343.1
Repayments of credit facility		(2,054.3	)		(1,057.0	)
Proceeds from issuance of senior notes		325.0			250.0
Cash paid on note exchange		(27.7	)		—
Repayment of affiliated and allocated indebtedness		—			(737.7	)
Proceeds from equity offerings		304.1			324.6
Costs incurred in connection with financing arrangements		(6.2	)		(20.2	)
Contributions from (distributions to) parent		13.2			(102.5	)
Distributions to unitholders		(225.2	)		(164.0	)
Distributions under common control		—			(68.1	)
Contributions from noncontrolling interest		—			—
Distributions to noncontrolling interests		(31.4	)		(19.1	)

Net cash provided in financing activities		84.5			(250.9	)

Net change in cash and cash equivalents		(20.7	)		(14.6	)
Cash and cash equivalents, beginning of period		76.3			90.9

Cash and cash equivalents, end of period	$	55.6		$	76.3

TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts)


	Three Months Ended December 31,						Year Ended December 31,
	2011			2010			2011			2010
REVENUES	$	1,934.0		$	1,527.8		$	6,994.5		$	5,476.1
Costs and expenses:
Product purchases		1,674.5			1,300.7			6,039.0			4,695.5
Operating expenses		72.9			69.8			287.1			259.3
Depreciation and amortization expenses		46.6			48.6			181.0			185.5
General and administrative expenses		31.1			63.4			136.1			144.4
Other		0.6			(4.3	)		0.2			(4.7	)

Total costs and expenses		1,825.7			1,478.2			6,643.4			5,280.0

INCOME FROM OPERATIONS		108.3			49.6			351.1			196.1
Other income (expense):
Interest expense, net		(28.4	)		(27.0	)		(111.7	)		(110.9	)
Equity in earnings of unconsolidated investment		3.6			1.6			8.8			5.4
Gain (loss) on debt repurchases		—			—			—			(17.4	)
Gain on early debt extinguishment		—			4.5			—			12.5
Gain on mark-to-market derivative instruments		—			—			(5.0	)		(0.4	)
Other income (expenses)		(0.6	)		(0.3	)		(1.2	)		0.5

Income before income taxes		82.9			28.4			242.0			85.8
Income tax (expense) benefit:		(8.1	)		(4.1	)		(26.6	)		(22.5	)

NET INCOME		74.8			24.3			215.4			63.3
Less: Net income attributable to noncontrolling interests		66.3			32.1			184.7			78.3

NET INCOME (LOSS) ATTRIBUTABLE TO TARGA RESOURCES CORP.		8.5			(7.8	)		30.7			(15.0	)
Dividends on Series B preferred stock		—			(1.1	)		—			(9.5	)
Dividends on common equivalents		—			—			—			(177.8	)

Net income (loss) available to common shareholders	$	8.5		$	(8.9	)	$	30.7		$	(202.3	)

Net income (loss) available per common share—basic	$	0.21		$	(0.67	)	$	0.75		$	(30.94	)

Net income (loss) available per common share—diluted	$	0.20		$	(0.67	)	$	0.74		$	(30.94	)

Weighted average shares outstanding—basic		41.0			13.2			41.0			6.5
Weighted average shares outstanding—diluted		41.7			13.2			41.4			6.5

TARGA RESOURCES CORP.

FINANCIAL SUMMARY (unaudited)

KEY TARGA RESOURCES CORP. BALANCE SHEET ITEMS

(In millions)


	December 31, 2011
Cash and cash equivalents:
TRC Non-Partnership	$	90.2
Targa Resources Partners		55.6

Total cash and cash equivalents	$	145.8

Long-term Debt:
TRC Non-Partnership	$	89.3
Targa Resources Partners		1,477.7

Total long-term debt	$	1,567.0

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