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

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware		001-33303		65-1295427
(State or other jurisdiction		(Commission		(IRS Employer
of incorporation or organization)		File Number)		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 March 31, 2008, Targa Resources Partners LP (the “Partnership”) issued a press release regarding its financial results for the three months and year ended December 31, 2007 and held a webcast conference call discussing those results. A copy of the earnings press release is filed as Exhibit 99.1 to this report, which is hereby incorporated by reference into this Item 2.02. A replay of the webcast will be available through the Investors section of the Partnership’s web site (http://www.targaresources.com) until April 14, 2008.

     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 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 income, operating income, net cash flows provided by operating activities 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 March 31, 2008.

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.

		TARGA RESOURCES PARTNERS LP
		By:		Targa Resources GP LLC,
				its general partner
Dated: April 2, 2008		By:		/s/ Jeffrey J. McParland
				Jeffrey J. McParland
				Executive Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit
Number		Description
Exhibit 99.1		Targa Resources Partners LP Press Release dated March 31, 2008.

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 2007 Financial Results

HOUSTON—March 31, 2008—Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) (NASDAQ: NGLS) today announced its financial results for the three months and year ended December 31, 2007. For the fourth quarter of 2007, the Partnership reported (i) net income of $22.7 million as determined under Generally Accepted Accounting Principles (“GAAP”) for entities under common control (excluding results of operations for periods prior to the acquisition of a business by the Partnership, fourth quarter net income was $17.6 million or 42¢ per unit on a fully diluted basis); (ii) income from operations of $34.5 million and (iii) earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments (“Adjusted EBITDA”) of $52.6 million. Adjusted EBITDA is a non-GAAP financial measure that is defined and reconciled later in this press release to its most directly comparable GAAP financial measure net income (loss).

For the full year 2007, the Partnership reported (i) net income of $40.3 million, as determined under GAAP for entities under common control (excluding results of operations for periods prior to the acquisition of a business by the Partnership, 2007 net income was $27.5 million or 81¢ per unit on a fully diluted basis); (ii) income from operations of $113.4 million and (iii) Adjusted EBITDA of $185.8 million.

In accordance with the accounting treatment for entities under common control, the results of operations for the year ended December 31, 2007 include the combined results for the full twelve months of both the North Texas system and the combined SAOU and LOU Systems (“SAOU” and “LOU”, respectively). For the year ended December 31, 2006, the Partnership’s results include the full year historical results of the combined SAOU and LOU Systems and of North Texas.

Operating results attributable to the unitholders of the Partnership include the results of the North Texas system subsequent to the Partnership’s February 14, 2007 IPO, and the combined results of SAOU and LOU subsequent to the acquisition of these businesses by the Partnership on October 24, 2007.

The Partnership acquired the SAOU System located in the Permian Basin and the LOU System located in southwest Louisiana from Targa Resources, Inc. (“Targa”) for approximately $705 million, subject to certain post-closing adjustments. In addition, the Partnership paid approximately $24.2 million to Targa for the termination of certain hedge transactions. The Partnership financed the acquisition with the proceeds from its public offering of 13,500,000 units and borrowings under its increased $750 million senior secured revolving credit facility. On November 20, 2007, the Partnership closed the partial exercise of the over-allotment option granted to the underwriters for an additional 1,800,000 common units.

On January 24, 2008, the board of Targa Resources Partners’ general partner (the “Board”) declared a cash distribution of $0.3975 per unit, or $1.59 per unit on an annualized basis, for the fourth quarter of 2007 payable to all unitholders. Distributable cash flow for the fourth quarter of 2007 was $36.7 million, including the results of SAOU and LOU for the full quarter, which corresponds to distribution coverage of 1.96 times for the 47.1 million units outstanding on December 31, 2007 (as

compared to a weighted average of 41.8 million units reported for the fourth quarter in accordance with GAAP). Distributable cash flow was $29.6 million excluding results of operations for SAOU and LOU for the period prior to their acquisition on October 24, 2007. Distributable cash flow is a non-GAAP financial measure that is defined and reconciled later in this press release to its most directly comparable GAAP financial measure, net income (loss).

In addition, management informed the Board at its most recent meeting that it will recommend an increase in the first quarter 2008 distribution (which will be paid in the second quarter of 2008) to 41.75¢ per unit, or $1.67 per unit on an annualized basis. Management believes the Board will be supportive of this recommendation, although any distribution increase remains subject to final Board approval following a review of first quarter financial results.

Note on Entities Under Common Control

Targa’s contribution of North Texas to us in connection with our February 14, 2007 IPO and our acquisition of SAOU and LOU from Targa on October 24, 2007 are treated as transfers of net assets between entities under common control under GAAP. This treatment has the following impact on the presentation of the Partnership’s financial results:

	•		The underlying assets of North Texas and of SAOU and LOU were transferred to the Partnership at their recorded carrying values on the balance sheet of the common parent (Targa) with no step-up in book basis.
	•		The combined SAOU and LOU Systems became the predecessor for the Partnership as they were the first entities owned by the common parent. Our financial information has been restated accordingly.
	•		The historical results for the North Texas System are included starting with its acquisition by the common parent on October 31, 2005.
	•		Debt allocated from the parent along with related interest expense and financing costs are recorded in the financial statements until the contribution to or acquisition by us of the relevant business (February 14, 2007 for North Texas and October 24, 2007 for the SAOU and LOU Systems ).

Review of Fourth Quarter Results

		Three Months Ended				Three Months Ended
		December 31, 2007				December 31, 2006
		(in millions of dollars, except operating and price data)
Revenues		$	474.0			$	359.7
Product purchases			402.8				306.6
Operating expense, excluding DD&A			14.2				13.0
Depreciation and amortization expense			18.1				18.1
General and administrative expense			4.4				6.9
Loss (gain) on sale of assets			—				—
Income from operations		$	34.5			$	15.1
Financial data:
Operating margin		$	57.1			$	40.1
Adjusted EBITDA		$	52.6			$	33.2
Operating data:
Gathering throughput, MMcf/d			465.0				424.7
Plant natural gas inlet, MMcf/d			446.3				409.1
Gross NGL production, MBbl/d			44.4				41.7
Natural gas sales, BBtu/d(6)			430.5				403.8
NGL sales, MBbl/d			38.5				35.3
Condensate sales, MBbl/d			3.3				3.4
Natural Gas, per MMBtu
Average realized sales price		$	6.51			$	6.19
Impact of hedging			0.07				0.07
Average realized price		$	6.58			$	6.26
NGL, per gal
Average realized sales price		$	1.32			$	0.79
Impact of hedging			(0.06	)			—
Average realized price		$	1.26			$	0.79
Condensate, per Bbl
Average realized sales price		$	83.04			$	55.18
Impact of hedging			(1.71	)			1.72
Average realized price		$	81.33			$	56.90

Revenues were $474.0 million for the three-month period ended December 31, 2007, 32% higher than revenues of $359.7 million for the three months ended December 31, 2006. Income from operations for the fourth quarter of 2007 increased to $34.5 million from $15.1 million in 2006.

Net income for the fourth quarter 2007 was $22.7 million versus a net loss of $7.9 million for the same period 2006. The net loss in 2006 is principally due to interest expense totaling $22.5 million

that is related to debt that was allocated to North Texas and to the SAOU and LOU Systems by Targa prior to the acquisition of these businesses by the Partnership.

For the quarter ended December 31, 2007, gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) increased by 9% to 465.0 MMcf/d compared to 424.7 MMcf/d for the same period in 2006. For the same periods, plant natural gas inlet (the volume of natural gas passing through the meter located at the inlet of a processing plant) was 9% higher at 446.3 MMcf/d compared to 409.1 MMcf/d in 2006.

Gross NGL production of 44.4 MBbl/d for the three months ended December 31, 2007 was 6% higher than NGL production of 41.7 MBbl/d for the three months ended December 31, 2006. Natural gas sales volumes increased 7% to 430.5 BBtu/d in the three months ended December 31, 2007 as compared to the 403.8 BBtu/d sold in the 2006 period. Additionally, NGL sales of 38.5 MBbl/d for the fourth quarter of 2007 were 9% higher than the 35.3 MBbl/d sold in the same 2006 period.

Average realized natural gas price increased 32¢ per MMBtu from $6.26 per MMBtu for the three months ended December 31, 2006, to $6.58 per MMBtu for the twelve months ended December 31, 2007, including the impact of our hedging program. Average realized NGL prices were higher by 47¢ or 60% at $1.26 per gallon in 2007 and average realized condensate prices were $24.43 per barrel higher, or 43%, for 2007 at $81.33 per barrel, including the impacts of our hedging program.

Review of Year End Results

		Year Ended				Year Ended
		December 31, 2007				December 31, 2006
		(in millions of dollars, except operating and price data)
Revenues		$	1,661.5			$	1,738.5
Product purchases			1,406.8				1,517.7
Operating expense, excluding DD&A			50.9				49.1
Depreciation and amortization expense			71.8				69.9
General and administrative expense			18.9				16.1
Loss (gain) on sale of assets			(0.3	)			—
Income from operations		$	113.4			$	85.7
Financial data:
Operating margin		$	203.8			$	171.7
Adjusted EBITDA		$	185.8			$	154.1
Operating data:
Gathering throughput, MMcf/d			452.0				433.8
Plant natural gas inlet, MMcf/d			429.2				419.6
Gross NGL production, MBbl/d			42.6				42.4
Natural gas sales, BBtu/d(6)			410.2				489.4
NGL sales, MBbl/d			36.4				36.0
Condensate sales, MBbl/d			3.6				3.3
Natural Gas, per MMBtu
Average realized sales price		$	6.58			$	6.66
Impact of hedging			0.08				0.02
Average realized price		$	6.66			$	6.68
NGL, per gal
Average realized sales price		$	1.05			$	0.86
Impact of hedging			(0.02	)			(0.01	)
Average realized price		$	1.03			$	0.85
Condensate, per Bbl
Average realized sales price		$	65.43			$	59.28
Impact of hedging			0.19				0.59
Average realized price		$	65.62			$	59.87

For the year ended December 31, 2007 revenues were $1,661.5 million, a 4.4% decline from $1,738.5 million for the year ended December 31, 2006. The decrease was primarily due to a decrease in affiliate-related volumes, somewhat offset by increases in prices, fees and other revenues. Income from operations increased by 32% to $113.4 million in 2007 from $85.7 million in 2006, driven by an improvement in third party volumes and a stronger pricing environment.

Net income for the year ended December 31, 2007 increased 347% to $40.3 million versus $11.6 million for 2006. The 2007 net income includes $19.4 million of interest expense allocated from Targa to North Texas and to the SAOU and LOU Systems prior to their acquisition by the Partnership, and $22.0 million of interest for borrowings under our credit facility. Net income for 2006 reflects $88.0 million of allocated interest expense from Targa.

For the year ended December 31, 2007, gathering throughput was up 4.2% at 452.0 MMcf/d and plant natural gas inlet was up 2.3% at 429.2 MMcf/d, compared to 2006 throughput of 433.8MMcf/d and 419.6 MMcf/d respectively.

Gross NGL production of 42.6 MBbl/d for the year ended 2007 was slightly higher than the comparable 2006 production of 42.4 MBbl/d, primarily driven by additional well connections partially offset by the natural decline in field production. Natural gas sales of 410.2 BBtu/d for the year ended December 31, 2007 were down 19% from the 489.4 BBtu/d of natural gas sales during the same period 2006, primarily due to a decrease in purchases from affiliates and increases in take-in-kind volumes by producers, offset by a net increase in wellhead supply attributable to additional well connections. Finally, NGL and condensate sales for the year ended December 31, 2007 were up 1% at 36.4 MBbl/d and up 9% at 3.6 MBbl/d compared to 2006 levels of 36.0 MBbl/d and 3.3 MBbl/d respectively.

Average realized natural gas price decreased 2¢ per MMBtu from $6.68 per MMBtu for the twelve months ended December 31, 2006, to $6.66 per MMBtu for the twelve months ended December 31, 2007, including the impact of our hedging program. Average realized NGL prices were higher by 18¢ or 21% at $1.03 per gallon in 2007 and average realized condensate prices were $5.75 per barrel higher, or 10%, for 2007 at $65.62 per barrel, including the impacts of our hedging program.

Contract Mix, Hedges and Realized Prices

For the year ended December 31, 2007, approximately 79% of the Partnership’s gathered volumes were processed under percent-of-proceeds contracts, 19% were wellhead purchases or keep-whole, with the remaining volumes processed under hybrid or fee based contract types comprising 1% each. 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 our business, we enter into hedging contracts. Average realized prices are discussed above.

Capitalization

In conjunction with the Partnership’s IPO, we entered into a five-year, $500 million senior secured revolving credit facility (the “Credit Facility”), and borrowed $294.5 million. Concurrent with the acquisition of the SAOU and LOU Systems on October 24, 2007, we entered into a Commitment Increase Supplement to the Credit Agreement, increasing our aggregate commitments under the Credit Agreement by $250 million to an aggregate total of $750 million. Furthermore, we entered into the First Amendment to Credit Agreement (the “Amendment”). The Amendment increased by $250 million the maximum amount of increases to the aggregate commitments that may be

requested by us. The Amendment allows us to request commitments under the Credit Agreement, as supplemented and amended, up to $1 billion.

Total funded debt at December 31, 2007 was approximately $626.3 million, approximately 50.5% of total book capitalization. In the first quarter of 2008, the Partnership repaid $50.0 million under the Credit Facility, bringing total debt to $576.3 million.

Recent Activities

Activity continues to remain strong in all areas of operations, and total volumes continue to increase steadily. Additional recent activities include:

	1.		We continue to add significant acreage dedications in North Texas and SAOU.
	2.		Work on several potential prospects to expand the gathering footprint and bring additional processable gas to LOU and to add take away capacity to North Texas is ongoing.
	3.		We have successfully executed or extended several key industrial sales contracts in LOU.
	4.		Efforts toward securing long term options to optimize take away capacity from the Chico plant which could serve as an alternative to the capital project announced earlier are progressing.
	5.		Additionally, expansion of the Chico plant’s CO2 amine treater continues as expected to assist with increasing CO2levels from area production.
	6.		We achieved a record number of well connections in SAOU (131 connections in 2007 versus 123 in 2006) with continued strong drilling activity.
	7.		Finally, the Partnership expects to commission a significant butane storage project in LOU in the second quarter of 2008.

In addition, we are pursuing or evaluating multiple organic growth projects and expect capital expenditures to approximate $60 million in 2008.

Conference Call

Targa Resources Partners will host a conference call for investors and analysts at 10 a.m. ET (9 a.m. CT) on March 31, 2008 to discuss fourth quarter and year end financial results. The conference call can be accessed via Webcast through the Investors section of the Partnership’s web site at http://www.targaresources.com or by dialing 800-257-7063. The pass code is 11107692. Please dial in five to ten minutes prior to the scheduled start time. A replay will be available through the Investors section of the Partnership’s web site approximately two hours following completion of the Webcast and will remain available until April 14, 2008.

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.

Use of Non-GAAP Financial Measures

This press release and accompanying schedules include non-GAAP financial measures of distributable cash flow 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 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.

We compensate for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these 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:

		For the Year Ended December 31, 2007
						Pre-Acquisition								Post Acquisition
						SAOU-LOU				North Texas
						Jan 1, 2007 to				Jan 1, 2007 to
		TRP LP				Oct 23, 2007				Feb 13, 2007				TRP LP
						(in millions)
Reconcilaition of “Distributable Cash Flow” to net income
Net income (loss)		$	40.3			$	19.1			$	(6.9	)		$	28.1
Depreciation and amortization expense			71.8				11.7				6.9				53.2
Deferred income tax expense			1.5				—				—				1.5
Amortization of debt issue costs			1.8				0.9				—				0.9
Loss/(gain) on mark-to-market derivative contracts			30.2				30.2				—				—
Maintenance capital expenditures			(21.5	)			(5.9	)			(1.5	)			(14.1	)
Distributable Cash Flow		$	124.1			$	56.0			$	(1.5	)		$	69.6

		For the Three Months Ended December 31, 2007
						Pre-Acquisition				Post Acquisition
						SAOU-LOU
						Oct 1, 2007 to
		TRP LP				Oct 23, 2007				TRP LP
						(in millions)
Reconcilaition of “Distributable Cash Flow” to net income
Net income (loss)		$	22.7			$	4.7			$	18.0
Depreciation and amortization expense			18.1				0.9				17.2
Deferred income tax expense			0.4				(0.1	)			0.5
Amortization of debt issue costs			0.4				—				0.4
Loss/(gain) on mark-to-market derivative contracts			1.9				1.9				—
Maintenance capital expenditures			(6.8	)			(0.4	)			(6.4	)
Distributable Cash Flow		$	36.7			$	7.0			$	29.7

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 (loss). Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income (loss). 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. 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.

										Three Months				Three Months
		Year Ended				Year Ended				Ended				Ended
		December 31,				December 31,				December 31,				December 31,
		2007				2006				2007				2006
						(in millions)
Reconciliation of “Adjusted EBITDA” to net income:
Net income		$	40.3			$	11.6			$	22.7			$	(7.9	)
Add:
Allocated interest expense, net			19.4				88.0				0.4				22.5
Interest expense, net			22.0				—				9.2				0.0
Deferred income tax expense			1.5				2.9				0.4				0.5
Depreciation and amortization expense			71.8				69.9				18.1				18.1
Risk Management Activities			0.6				(1.5	)			(0.1	)			—
Noncash mark-to-market loss (gain)			30.2				(16.8	)			1.9				0.0
Adjusted EBITDA		$	185.8			$	154.1			$	52.6			$	33.2
Reconciliation of “operating margin” to net income:
Net income		$	40.3			$	11.6			$	22.7			$	(7.9	)
Add:
Depreciation and amortization expense			71.8				69.9				18.1				18.1
Deferred income tax expense			1.5				2.9				0.4				0.5
Allocated interest expense, net			19.4				88.0				0.4				22.5
Interest expense, net			22.0				—				9.2				0.0
Loss/(gain) on mark-to-market derivative contracts			30.2				(16.8	)			1.9				0.0
General and administrative expense			18.9				16.1				4.4				6.9
Gain on sale of assets			(0.3	)			—				—				—
Operating margin		$	203.8			$	171.7			$	57.1			$	40.1

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:
Eric Curry
Sr. Manager — Corporate Finance and Investor Relations
713-584-1133
Web site: http://www.targaresources.com

Media contact:
Kenny Juarez
212-371-5999

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS

		December 31,				December 31,
		2007				2006
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	50,994			$	—
Receivables from third parties			59,346				61,559
Receivables from affiliated companies			87,547				—
Inventory			1,624				958
Assets from risk management activities			8,695				25,683
Other			269				—
Total current assets			208,475				88,200
Property, plant and equipment, at cost			1,433,955				1,391,644
Accumulated depreciation			(174,361	)			(103,073	)
Property, plant and equipment, net			1,259,594				1,288,571
Debt issue costs			6,588				—
Debt issue costs allocated from Parent			—				21,353
Long-term assets from risk management activities			3,040				15,851
Other long-term assets			2,275				2,396
Total assets		$	1,479,972			$	1,416,371
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable		$	5,693			$	3,773
Accrued liabilities			142,836				109,337
Current maturities of debt allocated from Parent			—				340,747
Liabilities from risk management activities			44,003				3,296
Total current liabilities			192,532				457,153
Long-term debt allocated from Parent			—				706,597
Long-term debt			626,300				—
Long-term liabilities from risk management activities			43,109				551
Other long-term liabilities			3,266				2,919
Deferred income tax liability			559				3,238
Commitments and contingencies (Note 13)
Partners’ capital:
Common unitholders (34,636,000 units issued and outstanding at December 31, 2007)			770,207				—
Subordinated unitholders (11,528,231 units issued and outstanding at December 31, 2007)			(84,999	)			—
General partner (942,128 units issued and outstanding at December, 2007)			4,234				—
Accumulated other comprehensive income (loss)			(75,236	)			30,964
Net parent investment			—				214,949
Total partners’ capital			614,206				245,913
Total liabilities and partners’ capital		$	1,479,972			$	1,416,371

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

		Year				Year				Three Months				Three Months
		Ended				Ended				Ended				Ended
		December 31, 2007				December 31, 2006				December 31, 2007				December 31, 2006
						(in thousands, except per unit amounts)
Revenues from third parties		$	630,773			$	951,936			$	166,447			$	164,255
Revenues from affiliates			1,030,696				786,589				307,588				195,424
Total operating revenues			1,661,469				1,738,525				474,035				359,679
Costs and expenses:
Product purchases from third parties			1,215,733				1,194,751				351,622				257,310
Product purchases from affiliates			191,064				322,917				51,214				49,194
Operating expenses			50,931				49,075				14,248				13,032
Depreciation and amortization expense			71,756				69,957				18,115				18,118
General and administrative expense			18,927				16,063				4,367				6,904
Other			(296	)			—				2				—
			1,548,115				1,652,763				439,568				344,558
Income from operations			113,354				85,762				34,467				15,121
Other expense:
Interest expense, net			21,998				—				9,159				—
Interest expense allocated from Parent			19,436				88,025				376				22,479
Loss/(gain) on mark-to-market derivative contracts			30,221				(16,756	)			1,852				15
Other			(30	)			—				(13	)			—
Income before income taxes			41,729				14,493				23,093				(7,373	)
Deferred income tax expense			1,479				2,926				419				544
Net income			40,250			$	11,567			$	22,674			$	(7,917	)
Less net income (loss) attributable to predecessor operations:
For the period January 1, 2007 to February 13, 2007 for North Texas			(6,861	)
For the period January 1, 2007 to October 23, 2007 for SAOU/LOU			19,045								4,670
Total			12,184								4,670
Net income allocable to partners			28,066								18,004
General partner interest in net income for the period			561								360
Net income available to common and subordinated unitholders		$	27,505							$	17,644
Basic net income per common and subordinated unit		$	0.81							$	0.42
Diluted net income per common and subordinated unit		$	0.81							$	0.42
Basic average number of common and subordinated units outstanding			33,986								41,795
Diluted average number of common and subordinated units outstanding			33,994								41,805

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Year				Year
		Ended				Ended
		December 31, 2007				December 31, 2006
		(In thousands)
Cash flows from operating activities
Net income		$	40,250			$	11,567
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation			71,632				69,832
Accretion of asset retirement obligations			342				245
Amortization of intangibles			124				125
Amortization of debt issue costs			1,805				6,246
Noncash compensation			180				—
Gain on sale of assets			(296	)			—
Deferred income tax expense			1,479				2,926
(Gain) loss on mark-to-market derivative contracts			30,221				(16,756	)
Risk management activities			530				(1,541	)
Changes in operating assets and liabilities:			—				—
Accounts receivable			89,760				78,467
Inventory			(666	)			1,373
Other			(273	)			1,106
Accounts payable			1,920				(13,748	)
Accrued liabilities			33,472				(15,408	)
Net cash provided by operating activities			270,480				124,434
Cash flows from investing activities
Purchases of property, plant and equipment			(41,088	)			(32,575	)
Other			372				(317	)
Net cash used in investing activities			(40,716	)			(32,892	)
Cash flows from financing activities
Proceeds from equity offerings			777,471				—
Costs incurred in connection with public offerings			(4,640	)			—
Distributions to unit holders			(31,221	)			—
Proceeds from borrowings under credit facility			721,300				—
Costs incurred in connection with financing arrangements			(7,491	)			—
Repayments of loans:
Affiliated			(665,692	)			—
Credit facility			(95,000	)			—
Distributions to Parent			(873,497	)			(91,542	)
Net cash used in financing activities			(178,770	)			(91,542	)
Net change in cash and cash equivatents			50,994				—
Cash and cash equivalents, beginning of period			—				—
Cash and cash equivalents, end of period		$	50,994			$	—