UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported)
February 25, 2009

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

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

1000 Louisiana, Suite 4300
Houston, TX 77002
(Address of principal executive office and Zip Code)

(713) 584-1000
(Registrants’ telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o       Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o       Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o       Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o       Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 2.02 Results of Operations and Financial Condition.

     On February 25, 2009, Targa Resources Partners LP (the “Partnership”) issued a press release regarding its financial results for the three months and year ended December 31, 2008. A conference call to discuss these results is scheduled for 11:00 a.m. Eastern time on Wednesday, February 25, 2009. The conference call will be webcast live and a replay of the webcast will be available through the Investors section of the Partnership’s web site ( http://www.targaresources.com) until March 11, 2009. A copy of the earnings press release is furnished as Exhibit 99.1 to this report, which is hereby incorporated by reference into this Item 2.02.

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

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit
Number		Description
Exhibit 99.1		Targa Resources Partners LP Press Release dated February 25, 2009.

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXHIBIT INDEX

Exhibit
Number		Description
Exhibit 99.1		Targa Resources Partners LP Press Release dated February 25, 2009.

Exhibit 99.1

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

Targa Resources Partners LP Reports
Fourth Quarter and Full Year 2008 Financial Results

HOUSTON — February 25, 2009 -Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) (NASDAQ: NGLS) today reported fourth quarter 2008 net income of $23.7 million, or $0.48 per diluted limited partner unit as compared to net income of $22.7 million, or $0.42 per diluted limited partner unit for the fourth quarter of 2007. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments (“Adjusted EBITDA”) of $65.8 million for the fourth quarter of 2008 compared to Adjusted EBITDA of $53.1 million for the fourth quarter of 2007.

For the full year 2008, the Partnership reported net income of $91.5 million, or $1.83 per diluted limited partner unit as compared to net income of $40.3 million, or $0.81 per diluted limited partner unit for 2007. The Partnership reported Adjusted EBITDA of $228.9 million for 2008 compared to Adjusted EBITDA of $185.8 million for 2007. The full year and fourth quarter 2008 results include a $13.1 million debt extinguishment gain in connection with the repurchase of a portion of the Partnership’s senior unsecured notes.

Distributable cash flow for the fourth quarter of 2008 of $34.7 million excludes this debt extinguishment gain and corresponds to distribution coverage of 1.3 times for the 47.1 million total units outstanding on December 31, 2008 (see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, operating margin and distributable cash flow, and reconciliations of such measures to the comparable GAAP measures). Distributable cash flow for the year ended December 31, 2008 increased 23% to $152.9 million from $124.7 million in the same period a year ago.

“Our fourth quarter results reflect the underlying strength of our assets and hedge program. Despite the continued declines in commodity prices and processing margins, our coverage remained solid in the fourth quarter. We believe that our healthy coverage ratio, strong liquidity and hedge program currently allow us to fund our operations primarily from internal cash flow as we continue to assess the durations and ultimate impacts of the decline in commodity prices and the disruption in the capital markets. We will continue to execute with a focus on cost control and discipline regarding capital expenditures while we monitor developments in our markets and areas of operation,” said Rene Joyce, Chief Executive Officer of the Partnership’s general partner and of Targa Resources, Inc. (“Targa”).

On January 23, 2009, the Partnership announced a cash distribution of 51.75¢ per common and subordinated unit, or $2.07 per unit on an annualized basis, for the fourth quarter of 2008. This cash distribution was paid February 13, 2009 on all outstanding common and subordinated units to holders of record as of the close of business on February 4, 2009. The distribution was equal to the previous quarter’s distribution and reflects an increase of approximately 30% over the distribution for the fourth quarter of 2007.

		Quarter Ended								Year Ended
		December 31,								December 31,
		2008				2007				2008				2007
		(In millions, except operating and price data)
Revenues		$	352.8			$	474.1			$	2,074.1			$	1,661.5
Product purchases			293.2				402.8				1,803.0				1,406.8
Operating expense, excluding DD&A			12.6				14.2				55.3				50.9
Depreciation and amortization expense			19.1				18.2				74.3				71.8
General and administrative expense			6.2				4.4				22.4				18.9
Casualty loss			(0.1	)			—				0.1				—
Gain on sale of assets			—				—				(0.1	)			(0.3	)
Income from operations			21.8				34.5				119.1				113.4
Interest expense, net			(10.9	)			(9.1	)			(38.3	)			(22.0	)
Interest expense, allocated from Parent			—				(0.4	)			—				(19.4	)
Gain on debt extinguishment			13.1				—				13.1				—
Loss on mark-to-market derivative instruments			—				(1.8	)			(1.0	)			(30.2	)
Deferred income tax expense			(0.3	)			(0.5	)			(1.4	)			(1.5	)
Net income		$	23.7			$	22.7			$	91.5			$	40.3
Financial data:
Operating margin		$	47.0			$	57.1			$	215.8			$	203.8
Adjusted EBITDA			65.8				53.1				228.9				185.8
Distributable cash flow			34.7				37.4				152.9				124.7
Operating data:
Gathering throughput, MMcf/d			418.5				465.0				445.8				452.0
Plant natural gas inlet, MMcf/d			392.6				446.3				421.2				429.2
Gross NGL production, MBbl/d			38.7				44.4				42.0				42.6
Natural gas sales, BBtu/d			429.4				430.5				415.6				410.2
NGL sales, MBbl/d			34.6				38.5				37.3				36.4
Condensate sales, MBbl/d			3.6				3.3				3.6				3.6
Average realized prices:
Natural gas, $/MMBtu			6.05				6.53				8.45				6.60
NGL, $/gal			0.71				1.26				1.17				1.03
Condensate, $/ Bbl			46.42				81.34				82.52				65.63

Review of Fourth Quarter Results

Net income for the fourth quarter of 2008 was $23.7 million, up from $22.7 million for the 2007 period. The increase in net income was primarily attributable to a $13.1 million gain on debt extinguishment and lower operating expenses, partially offset by lower commodity prices and volumes and higher interest and general and administrative expenses. Net income for the fourth quarter of 2008 also includes $11.8 million in non-cash hedge losses and expenses compared to $2.2 million in non-cash hedge losses and expenses in 2007.

Revenues decreased $121.3 million, or 26%, to $352.8 million for the fourth quarter of 2008 from $474.1 million for the fourth quarter of 2007, driven primarily by lower prices for natural gas, NGL and condensate and lower natural gas and NGL sales volumes.

Gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) for the fourth quarter of 2008 decreased 10% to 418.5 MMcf/d compared to 465.0 MMcf/d for the same period in 2007. Plant natural gas inlet volume (the volume of natural gas passing through the meters located at the inlets of our processing plants) was 12% lower at 392.6 MMcf/d for the fourth quarter of 2008 compared to 446.3 MMcf/d for the same period in 2007. These decreases result primarily from reduced purchases of discretionary volumes in our LOU operations from third party pipeline systems.

Gross NGL production of 38.7 MBbl/d for the fourth quarter of 2008 was 13% lower than gross NGL production of 44.4 MBbl/d for the fourth quarter of 2007. NGL sales of 34.6 MBbl/d for the fourth quarter of 2008 were 10% lower than the 38.5 MBbl/d sold during the fourth quarter of 2007. Natural gas sales volumes decreased less than 1% to 429.4 BBtu/d in the fourth quarter of 2008 compared to 430.5 BBtu/d during the fourth quarter of 2007. Sales volumes in 2008 were impacted primarily by the discretionary LOU purchases mentioned above and periods of liquids rejection.

The average realized natural gas price decreased by $0.48 per MMBtu, or 7%, to $6.05 per MMBtu for the fourth quarter of 2008 compared to $6.53 per MMBtu for the same period in 2007. The average realized price for NGLs decreased by $0.55 per gallon, or 44%, to $0.71 per gallon for the fourth quarter of 2008 compared to $1.26 per gallon for the same period in 2007. The average realized price for condensate decreased by $34.92 per barrel, or 43%, to $46.42 per barrel for the fourth quarter of 2008 compared to $81.34 per barrel for the fourth quarter of 2007. Realized prices reflect the impact of our hedging program.

Review of Annual Results

Net income for the year ended December 31, 2008 was $91.5 million compared to $40.3 million for the year ended December 31, 2007. The increase in net income was primarily attributable to higher commodity prices and sales volumes and a gain on debt extinguishment, partially offset by higher operating and general and administrative expenses. The 2008 period also includes $23.4 million in non-cash hedge losses and expenses. In addition, 2007 includes $0.6 million in non-cash hedge losses and a $30.2 million loss on mark-to-market derivative contracts related to the SAOU and LOU Systems that was recognized during the period prior to the acquisition of these businesses by the Partnership.

Gathering throughput for 2008 was 445.8 MMcf/d, 1% lower than 452.0 MMcf/d for 2007. Plant natural gas inlet volume was 421.2 MMcf/d for 2008, 2% lower than 429.2 MMcf/d for 2007.

Gross NGL production was 42.0 MBbl/d for 2008, 1% lower than gross NGL production of 42.6 MBbl/d for 2007. Natural gas sales volumes increased 1% to 415.6 BBtu/d for 2008 as compared to 410.2 BBtu/d for 2007. NGL sales of 37.3 MBbl/d for 2008 were 2% higher than NGL sales of 36.4 MBbl/d for 2007. The increase was primarily due to reduced take-in-kind volumes, offset by lower NGL production.

The average realized natural gas price increased by $1.85 per MMBtu, or 28%, to $8.45 per MMBtu for 2008, from $6.60 per MMBtu for 2007. The average realized price for NGL increased by $0.14 per gallon, or 14%, to $1.17 per gallon for 2008 compared to $1.03 per gallon for 2007. The average realized price for condensate increased by $16.89 per barrel, or 26%, to $82.52 per barrel for 2008 compared to $65.63 per barrel for 2007. These prices reflect the impact of our hedging program.

Contract Mix and Hedging

For the year ended December 31, 2008, approximately 77% of the Partnership’s gathered volumes were processed under percent-of-proceeds contracts, 20% under wellhead purchases or keep-whole arrangements, 2% under fee-based contracts and 1% under hybrid contracts. Under percent-of-proceeds contracts, we receive a portion of the natural gas and/or NGLs as payment for our services. As a result, we are exposed to price risk on the portion of commodities that we receive as payment, which we refer to as our equity volumes. To mitigate the impact of commodity price fluctuations on this portion of our business, we enter into hedging contracts.

Capitalization and Liquidity Update

On October 16, 2008, we requested a $100 million funding under our credit facility. Lehman Brothers Commercial Bank, a lender under our credit facility, defaulted on its portion of the borrowing request resulting in an actual funding of $97.8 million. As a result of the Lehman default, we believe the availability under our credit facility has been effectively reduced by approximately $10 million. As of December 31, 2008, we had $342.5 million in capacity available under our credit facility, after giving effect to the Lehman default.

As of December 31, 2008, we had $81.8 million of cash, bringing total liquidity to $424.3 million. In addition to our strong liquidity position, we are well within our financial covenants and have no near term maturities under our credit facility or our senior unsecured notes.

Total funded debt as of December 31, 2008 was approximately $697 million, or 48% of total book capitalization.

We estimate that our capital expenditures will be approximately $60 million in 2009 as compared to approximately $55 million in 2008. Of the $60 million, we expect that maintenance capital expenditures will not exceed $20 million.

Conference Call

Targa Resources Partners will host a conference call for investors and analysts at 11:00 a.m. Eastern Time (10:00 a.m. Central Time) on February 25, 2009 to discuss fourth quarter 2008 financial results. The conference call can be accessed via Webcast through the Investor’s section of the Partnership’s website at http://www.targaresources.com or by dialing 800-240-6709. The pass code is 11126139. Please dial in ten minutes prior to the scheduled start time. A replay will be available approximately two hours following completion of the Webcast through the Investor’s section of the Partnership’s website and will remain available until March 11, 2009. Replay access numbers are 303-590-3000 or 800-405-2236 with pass code 11126139#.

About Targa Resources Partners

Targa Resources Partners was formed by Targa to engage in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling natural gas liquids and natural gas liquids products. Targa Resources Partners owns an extensive network of integrated gathering pipelines, seven natural gas processing plants and two fractionators and currently operates in Southwest Louisiana, the Permian Basin in West Texas and the Fort Worth Basin in North Texas. A subsidiary of Targa is the general partner of Targa Resources Partners.

Targa Resources Partners’ principal executive offices are located at 1000 Louisiana, Suite 4300, Houston, Texas 77002 and its telephone number is 713-584-1000.

For more information, visit www.targaresources.com.

Non-GAAP Financial Measures

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

Distributable Cash Flow - Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP financial measure for our unitholders because it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays

to a unitholder). The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flows sufficient to make distributions to our investors.

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

The following table presents a reconciliation of net income (loss) to distributable cash flow for the Partnership for the periods shown:

		Quarter Ended December 31,								Year Ended December 31,
		2008				2007				2008				2007
		(In millions)
Reconciliation of “distributable cash flow” to “net income”:
Net income		$	23.7			$	22.7			$	91.5			$	40.3
Depreciation and amortization expense			19.1				18.2				74.3				71.8
Deferred income tax expense			0.3				0.5				1.4				1.5
Amortization of debt issue costs			0.6				0.4				2.1				1.8
Gain on debt extinguishment			(13.1	)			—				(13.1	)			—
Non-cash loss related to derivatives			11.8				2.2				23.4				30.8
Maintenance capital expenditures			(7.7	)			(6.6	)			(26.7	)			(21.5	)
Distributable cash flow		$	34.7			$	37.4			$	152.9			$	124.7

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

The economic substance behind management’s use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors. The GAAP measure most directly comparable to Adjusted EBITDA is net income. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes

some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into management’s decision-making processes.

Operating Margin - We define operating margin as total operating revenues (which consist of natural gas and NGL sales plus service fee revenues) less product purchases (which consist primarily of producer payments and other natural gas purchases) and operating expense. Management reviews operating margin monthly for consistency and trend analysis. Based on this monthly analysis, management takes appropriate action to maintain positive trends or to reverse negative trends. Management uses operating margin as an important performance measure of the core profitability of our operations.

The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility. Management compensates for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into management’s decision-making processes.

Reconciliation of Non-GAAP Measures

		Quarter Ended December 31,								Year Ended December 31,
		2008				2007				2008				2007
		(In millions)
Reconciliation of net cash provided by operating activities to “Adjusted EBITDA”:
Net cash provided by operating activities		$	21.2			$	136.7			$	95.2			$	270.5
Allocated interest expense from parent			—				0.9				—				18.5
Interest expense, net			10.3				8.2				36.2				21.1
Gain on debt extinguishment			13.1				—				13.1				—
Other			(0.5	)			(0.1	)			(0.5	)			(0.1	)
Changes in operating working capital which used (provided) cash:
Accounts receivable and other assets			(28.0	)			(74.0	)			23.1				(88.8	)
Accounts payable and other liabilities			49.7				(18.6	)			61.8				(35.4	)
Adjusted EBITDA		$	65.8			$	53.1			$	228.9			$	185.8
Reconciliation of net income to “Adjusted EBITDA”:
Net income		$	23.7			$	22.7			$	91.5			$	40.3
Add:
Allocated interest expense, net			—				0.4				—				19.4
Interest expense, net			10.9				9.1				38.3				22.0
Deferred income tax expense			0.3				0.5				1.4				1.5
Depreciation and amortization expense			19.1				18.2				74.3				71.8
Non-cash loss related to derivative instruments			11.8				2.2				23.4				30.8
Adjusted EBITDA		$	65.8			$	53.1			$	228.9			$	185.8
Reconciliation of net income to “operating margin”:
Net income		$	23.7			$	22.7			$	91.5			$	40.3
Add:
Depreciation and amortization expense			19.1				18.2				74.3				71.8
Deferred income tax expense			0.3				0.5				1.4				1.5
Allocated interest expense, net			—				0.4				—				19.4
Interest expense, net			10.9				9.1				38.3				22.0
Gain on debt extinguishment			(13.1	)			—				(13.1	)			—
Loss on mark-to-market derivative instruments			—				1.8				1.0				30.2
General and administrative and other expense			6.1				4.4				22.4				18.6
Operating margin		$	47.0			$	57.1			$	215.8			$	203.8

Forward-Looking Statements

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

Investor contact info:
Phone: 713-584-1133

Anthony Riley
Senior Manager — Finance/Investor Relations

Matt Meloy
Vice President — Finance and Treasurer

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED BALANCE SHEET DATA
(In thousands)

		December 31,				December 31,
		2008				2007
ASSETS
Current assets
Cash and cash equivalents		$	81,768			$	50,994
Assets from risk management activities			91,816				8,695
Other current assets			81,926				148,786
Total current assets			255,510				208,475
Property, plant and equipment, net			1,244,337				1,259,594
Long-term assets from risk management activities			68,296				3,040
Other assets			12,763				8,863
Total assets			1,580,906				1,479,972
LIABILITIES AND PARTNERS’ CAPITAL
Accounts payable and accrued liabilities		$	94,840			$	148,529
Liabilities from risk management activities			11,664				44,003
Total current liabilities			106,504				192,532
Long-term debt			696,845				626,300
Long term liabilities from risk management activities			9,679				43,109
Other long-term liabilities			5,514				3,825
Total liabilities			818,542				865,766
Partners’ capital			762,364				614,206
Total liabilities and partners’ capital		$	1,580,906			$	1,479,972

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

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

		Quarter Ended								Year Ended
		December 31,								December 31,
		2008				2007				2008				2007
REVENUES		$	352,782			$	474,035			$	2,074,118			$	1,661,469
COSTS AND EXPENSES:
Product purchases			293,279				402,836				1,803,031				1,406,797
Operating expenses			12,652				14,248				55,325				50,931
Depreciation and amortization expense			19,039				18,115				74,274				71,756
General and administrative expense			6,109				4,367				22,392				18,927
Casualty loss			—				—				167				—
(Gain) loss on sale of assets			(17	)			2				(105	)			(296	)
Total costs and expenses			331,062				439,568				1,955,084				1,548,115
INCOME FROM OPERATIONS			21,720				34,467				119,034				113,354
Other income (expense):
Interest expense, net			(10,831	)			(9,535	)			(38,274	)			(41,434	)
Gain on debt extinguishment			13,061				—				13,061				—
Loss on mark-to-market derivative instruments			—				(1,852	)			(991	)			(30,221	)
Other			11				13				64				30
Income before income taxes			23,961				23,093				92,894				41,729
Income tax expense			(300	)			(419	)			(1,400	)			(1,479	)
NET INCOME		$	23,661			$	22,674			$	91,494			$	40,250
Income attributable to:
Predecessor operations		$	—			$	4,670			$	—			$	12,184
General partner			1,525				360				7,049				561
Limited partners			22,136				17,644				84,445				27,505
		$	23,661			$	22,674			$	91,494			$	40,250
Net income per limited partner unit, basic and diluted		$	0.48			$	0.42			$	1.83			$	0.81
Weighted average limited partner units outstanding:
Basic			46,154				41,795				46,153				33,986
Diluted			46,161				41,805				46,161				33,994

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED CASH FLOW INFORMATION
(In thousands)

		Quarter Ended								Year Ended
		December 31,								December 31,
		2008				2007				2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	23,661			$	22,674			$	91,494			$	40,250
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion			19,773				18,682				76,901				74,083
Deferred income tax expense			300				419				1,400				1,479
Risk management activities			11,774				2,184				(63,973	)			30,751
Gain on debt extinguishment			(13,061	)			—				(13,061	)			—
Gain on sale of assets			(17	)			2				(105	)			(296	)
Changes in operating assets and liabilities			(21,204	)			92,766				2,579				124,213
Net cash provided by operating activities			21,226				136,727				95,235				270,480
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment			(22,606	)			(6,848	)			(51,169	)			(41,088	)
Other			4,255				—				167				372
Net cash used in investing activities			(18,351	)			(6,848	)			(51,002	)			(40,716	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility			97,765				378,800				185,265				721,300
Repayments on credit facility			—				(47,000	)			(323,800	)			(95,000	)
Proceeds from issuance of senior notes			—				—				250,000				—
Repurchases of senior notes			(26,832	)			—				(26,832	)			—
Repayment of affiliated indebtedness			—				—				—				(665,692	)
Proceeds from equity offerings			—				396,703				—				777,471
Distributions			(26,359	)			(15,278	)			(90,932	)			(31,221	)
General partner contributions			—				—				8				—
Costs incurred in connection with public offerings			—				(1,327	)			(89	)			(4,640	)
Costs incurred in connection with financing arrangements			—				(2,926	)			(7,079	)			(7,491	)
Deemed Parent distributions			—				(816,298	)			—				(873,497	)
Net cash used in financing activities			44,574				(107,326	)			(13,459	)			(178,770	)
Net change in cash and cash equivalents			47,449				22,553				30,774				50,994
Cash and cash equivalents, beginning of period			34,319				28,441				50,994				—
Cash and cash equivalents, end of period		$	81,768			$	50,994			$	81,768			$	50,994