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 August 11, 2008, Targa Resources Partners LP (the “Partnership”) will issue a press release regarding its financial results for the three and six months ended June 30, 2008. A conference call to discuss these results is scheduled for 11:00 a.m. Eastern time on Monday, August 11, 2008. 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 August 25, 2008. 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.

     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 August 11, 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: August 11, 2008		By:		/s/ John Robert Sparger   John Robert Sparger
				Senior Vice President and Chief Accounting Officer

EXHIBIT INDEX

Exhibit
Number		Description
Exhibit 99.1		Targa Resources Partners LP Press Release dated August 11, 2008.

Exhibit 99.1

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

Targa Resources Partners LP Reports Second Quarter 2008 Financial Results

HOUSTON—August 11, 2008—Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) (NASDAQ: NGLS) today announced its financial results for the three months ended June 30, 2008. For the second quarter of 2008, the Partnership reported (i) net income of $28.2 million or $0.54 per common and subordinated unit on a fully diluted basis as determined under Generally Accepted Accounting Principles (“GAAP”) for entities under common control; (ii) income from operations of $36.5 million and (iii) earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments (“Adjusted EBITDA”) of $55.5 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).

On July 23, 2008, Targa Resources Partners announced a cash distribution of $0.5125 per common and subordinated unit, or $2.05 per unit on an annualized basis, for the second quarter of 2008. This cash distribution will be paid August 14, 2008 on all outstanding common and subordinated units to holders of record as of the close of business on August 4, 2008. Distributable cash flow for the second quarter of 2008 was $40.1 million which corresponds to distribution coverage of 1.6 times for the 47.1 million total units outstanding on June 30, 2008. 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).

		Three Months Ended June 30,								Six Months Ended June 30,
		2008				2007				2008				2007
		(In millions, except operating and price data)
Revenues		$	630.5			$	433.6			$	1,142.6			$	782.4
Product purchases			555.2				371.7				997.3				666.2
Operating expense, excluding DD&A			14.7				11.8				27.3				23.9
Depreciation and amortization expense			18.4				17.6				36.7				35.7
General and administrative expense			5.7				4.6				10.9				8.0
Gain on sale of assets			—				(0.3	)			(0.1	)			(0.3	)
Income from operations			36.5				28.2				70.5				48.9
Interest expense, net			(8.0	)			(5.2	)			(16.7	)			(7.8	)
Interest expense, allocated from Parent			—				(2.7	)			—				(16.2	)
Loss on mark-to-market derivative instruments			—				(6.2	)			—				(21.0	)
Deferred income tax expense			(0.3	)			(0.3	)			(0.7	)			(0.7	)
Net income(loss)		$	28.2			$	13.8			$	53.1			$	3.2
Financial data:
Operating margin		$	60.7			$	50.1			$	118.1			$	92.3
Adjusted EBITDA			55.5				45.5				108.2				84.8
Distributable cash flow			40.1				33.0				79.6				51.6

		Three Months Ended June 30,								Six Months Ended June 30,
		2008				2007				2008				2007
		(In millions, except operating and price data)
Operating data:
Gathering throughput, MMcf/d			463.9				453.1				463.4				439.2
Plant natural gas inlet, MMcf/d			435.2				427.1				436.4				412.5
Gross NGL production, MBbl/d			44.5				43.2				44.1				41.1
Natural gas sales, BBtu/d			410.0				414.6				414.2				397.5
NGL sales, MBbl/d			39.1				36.5				38.5				34.8
Condensate sales, MBbl/d			3.7				3.7				3.7				3.6
Average realized prices:
Natural Gas, $/MMBtu
Average realized sales price			10.52				7.30				9.22				6.97
Impact of hedging			(0.05	)			0.06				—				0.07
Average realized price			10.47				7.36				9.22				7.04
NGL, $/gal
Average realized sales price			1.46				0.97				1.38				0.90
Impact of hedging			(0.11	)			(0.01	)			(0.09	)			—
Average realized price			1.35				0.96				1.29				0.90
Condensate, $/ Bbl
Average realized sales price			106.17				59.36				96.84				55.34
Impact of hedging			(5.06	)			0.90				(3.46	)			1.36
Average realized price			101.11				60.26				93.38				56.70

Review of Second Quarter Results

Revenues were $630.5 million for the three months ended June 30, 2008, 45% higher than revenues of $433.6 million for the three months ended June 30, 2007. Income from operations for the second quarter of 2008 increased 29% to $36.5 million from $28.2 million in the same period of 2007. The increase was due to higher commodity prices for the three months ended June 30, 2008 compared to the three months ended June 30, 2007.

Net income for the second quarter 2008 was $28.2 million versus $13.8 million for the same period 2007. The increase in net income was attributable to higher commodity prices partially offset by higher operating expenses and higher general and administrative expenses during the second quarter 2008. In addition, second quarter 2007 includes a $6.2 million loss on mark-to-market derivative contracts related to the SAOU and LOU Systems prior to the acquisition of these businesses by the Partnership. Prior to the sale of SAOU and LOU to the Partnership, Targa Resources, Inc. (“Targa”) entered into derivative instruments for forecasted transactions of the SAOU and LOU businesses that were accorded hedge accounting treatment in Targa’s consolidated financial statements. Because the SAOU and LOU businesses were not a direct party to the derivative instruments, they were not entitled to hedge accounting treatment in their separate financial statements. Accordingly, all unrealized gains and losses on the allocated derivatives were reflected in the SAOU and LOU businesses financial statements as mark-to-market losses on derivative instruments.

For the second quarter of 2008, gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) increased by 2% to 463.9 MMcf/d compared to 453.1 MMcf/d for the same period in 2007. For the same periods, plant natural gas inlet volume (the volume of natural gas passing through the meter located at the inlet of a processing plant) was 2% higher at 435.2 MMcf/d compared to 427.1 MMcf/d in the second quarter of 2007.

Gross NGL production of 44.5 MBbl/d for the three months ended June 30, 2008 was 3% higher than NGL production of 43.2 MBbl/d for the three months ended June 30, 2007. Natural gas sales volumes decreased 1% to 410.0 BBtu/d in the three months ended June 30, 2008 as compared to the 414.6 BBtu/d sold in the same 2007 period. Additionally, NGL sales of 39.1 MBbl/d for the second quarter of 2008 were 7% higher than the 36.5 MBbl/d sold in the same 2007 period. The increase was primarily due to increased NGL recoveries from higher inlet volumes and decreased NGL take-in-kind volumes.

The average realized natural gas price increased 42% or $3.11 per MMBtu from $7.36 per MMBtu for the three months ended June 30, 2007, to $10.47 per MMBtu for the three months ended June 30, 2008, including the impact of our hedging program. The average realized price for NGLs increased by $0.39 per gallon, or 41%, to $1.35 per gallon for the three months ended June 30, 2008 compared to $0.96 per gallon for the three months ended June 30, 2007, including the impact of our hedging program. The average realized price for condensate increased by $40.85 per barrel, or 68%, to $101.11 per barrel for the three months ended June 30, 2008 compared to $60.26 per barrel for the three months ended June 30, 2007, including the impact of our hedging program.

Review of Six Month Results

Revenues were $1,142.6 million for the six months ended June 30, 2008, 46% higher than revenues of $782.4 million for the six months ended June 30, 2007. Income from operations for the six months ended June 30, 2008 increased 44% to $70.5 million from $48.9 million in the same period of 2007. The increase was primarily due to higher commodity prices and higher inlet volumes for the six months ended June 30, 2008 compared to the six months ended June 30, 2007.

Net income for the six months ended June 30, 2008 was $53.1 million versus $3.2 million for the same period 2007. The increase in net income is attributable to higher commodity prices and higher inlet volumes partially offset by higher operating expenses and higher general and administrative expenses for the six months ended June 30, 2008. In addition, the six months ended June 30, 2007 includes the $21.0 million loss on mark-to-market derivative contracts related to the SAOU and LOU Systems recognized in the second quarter prior to the acquisition of these businesses by the Partnership.

For the six months ended June 30, 2008, gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) increased by 6% to 463.4 MMcf/d compared to 439.2 MMcf/d for the same period in 2007. For the same periods, plant natural gas inlet volume (the volume of natural gas passing through the meter located at the inlet of a processing plant) for the six months ended June 30, 2008 was 6% higher at 436.4 MMcf/d compared to 412.5 MMcf/d for the same period in 2007.

Gross NGL production of 44.1 MBbl/d for the six months ended June 30, 2008 was 7% higher than NGL production of 41.1 MBbl/d for the six months ended June 30, 2007. Natural gas sales volumes increased 4% to 414.2 BBtu/d in the six months ended June 30, 2008 as compared to the 397.5 BBtu/d sold in the same 2007 period. Additionally, NGL sales of 38.5 MBbl/d for the six months ended June 30, 2008 were 11% higher than the 34.8 MBbl/d sold in the same 2007 period. The increase was primarily due to increased NGL recoveries from higher inlet volumes and decreased NGL take-in-kind volumes.

The average realized natural gas price increased 31% or $2.18 per MMBtu from $7.04 per MMBtu for the six months ended June 30, 2007, to $9.22 per MMBtu for the six months ended June 30, 2008, including the impact of our hedging program. The average realized price for NGLs increased by $0.39 per gallon, or 43%, to $1.29 per gallon for the six months ended June 30, 2008 compared to $0.90 per gallon for the six months ended June 30, 2007, including the impact of our hedging program. The average realized price for condensate increased by $36.68 per barrel, or 65%, to $93.38 per barrel for the six months ended June 30, 2008 compared to $56.70 per barrel for the six months ended June 30, 2007, including the impact of our hedging program.

Capitalization

On June 18, 2008 we completed a private placement under Rule 144A and Regulation S of the Securities Act of 1933 (“Rule 144A”) of $250 million in aggregate principal amount of 8.25% senior unsecured notes (“Notes”) due 2016 at an offering price equal to 100% of par. Proceeds from the Notes were used to repay borrowings under our senior secured credit facility.

Concurrent with the closing of the private placement of the $250 million senior notes, we increased the commitments under our senior secured credit facility by $100 million, bringing the total commitments under our senior secured credit facility to $850 million. We may still request additional commitments of up to $150 million under the senior secured credit facility, which would increase the total commitments under our senior secured credit facility to $1 billion.

Total funded debt as of June 30, 2008 was approximately $575.0 million, approximately 57% of total book capitalization.

As of June 30, 2008, we had approximately $484 million in capacity available under our $850 million senior secured credit facility, after giving effect to outstanding borrowings of $325 million and the issuance of $41 million of letters of credit.

Hedging Update

During July 2008, we borrowed $87.4 million under our senior secured credit facility to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, the swaps were designated as hedges in accordance with SFAS 133, “Derivative Instruments and Hedging Activities.” Deferred loss of approximately $20.8 million, $38.2 million and $27.9 million will be reclassified from OCI as a non-cash reduction of revenues during 2008, 2009 and 2010, respectively, when the hedged forecasted sales transactions were expected to occur. We also entered

into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps through 2010.

Recent Activities

Strong producer activity in our Texas areas of operations remains impressive, resulting in volume increases for those operations.  Additional recent highlights include:

1.

Continued to experience growth in new acreage dedications in North Texas and SAOU in the second quarter of 2008;

2.

Well connection activity remains strong, especially in SAOU, where we expect to have a record number of well connections in 2008;

3.

The expansion of the Chico plant’s CO2 amine treater is under construction and should be online in the third quarter of 2008;

4.

Approved the expenditure of approximately $11 million of related pipeline projects to handle additional Barnett growth near our Bryan Compressor Station in Wise County;

5.

A significant butane storage project in LOU began receiving liquids from ConocoPhillips’ Lake Charles refinery on May 8th;

6.

We extended our footprint into new active areas in SAOU with the purchase of third party pipelines and rights of way; and

7.

We continue to pursue expansion and optimization projects utilizing existing infrastructure, which increases profitability without the need for large capital expenditure outlays and are pursuing or evaluating multiple growth projects. We expect 2008 maintenance and expansion capital expenditures to approximate $70 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 August 11, 2008 to discuss second quarter 2008 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 800-240-5318. The pass code is 11116778. 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 August 25, 2008. Replay access numbers are 303-590-3000 or 800-405-2236 with pass code 11116778.

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 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 income (loss) 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:

		Three Months Ended June 30,								Six Months Ended June 30,
		2008				2007 (a)				2008				2007 (a)
						(In millions)
Reconciliation of “distributable cash flow” to “net income”:
Net income		$	28.2			$	13.8			$	53.1			$	3.2
Depreciation and amortization expense			18.4				17.6				36.7				35.7
Deferred income tax expense			0.4				0.3				0.7				0.7
Amortization of debt issue costs			0.5				0.3				0.9				1.0
Loss on mark-to-market derivative instruments			—				6.1				—				21.0
Maintenance capital expenditures			(7.4	)			(5.1	)			(11.8	)			(10.0	)
Distributable Cash Flow		$	40.1			$	33.0			$	79.6			$	51.6

		For the Six Months Ended June 30, 2007
						Pre-Acquisition								Post Acquisition
						SAOU-LOU				North Texas
						Jan 1, 2007 to				Jan 1, 2007 to
		TRP LP				June 30, 2007				Feb 13, 2007				TRP LP
		(In millions)
Net income (loss)		$	3.2			$	3.9			$	(6.9	)		$	6.2
Depreciation and amortization expense			35.7				7.2				6.9				21.6
Deferred income tax expense			0.7				—				—				0.7
Amortization of debt issue costs			1.0				0.7				—				0.3
Loss on mark-to-market derivative instruments			21.0				21.0				—				—
Maintenance capital expenditures			(10.0	)			(4.8	)			(1.5	)			(3.7	)
Distributable Cash Flow		$	51.6			$	28.0			$	(1.5	)		$	25.1

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.

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 (loss). 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.

		Three Months				Three Months
		Ended June 30,				Ended June 30,				Six Months Ended				Six Months Ended
		2008				2007				June 30, 2008				June 30, 2007
Reconciliation of Non-GAAP Measures
Reconciliation of “Adjusted EBITDA” to net cash provided by operationing activities:
Net cash provided by operating activities		$	46.6			$	25.3			$	99.4			$	68.9
Allocated interest expense from Parent			—				2.4				—				15.2
Interest expense, net			7.5				5.2				15.8				7.9
Changes in operating working capital which used (provided) cash:
Accounts receivable and other			43.5				25.0				48.9				7.9
Accounts payable			(1.1	)			0.2				0.1				(2.6	)
Accrued liabilities			(41.0	)			(12.6	)			(56.0	)			(12.5	)
Adjusted EBITDA		$	55.5			$	45.5			$	108.2			$	84.8
Reconciliation of “Adjusted EBITDA” to net income (loss):
Net income (loss)			28.2			$	13.8			$	53.1			$	3.2
Add:
Allocated interest expense, net			—				2.7				—				16.2
Interest expense, net			8.0				5.2				16.7				7.9
Deferred income tax expense			0.4				0.3				0.7				0.7
Depreciation and amortization expense			18.4				17.6				36.7				35.7
Risk Management Activities			0.5				5.9				1.0				21.1
Adjusted EBITDA		$	55.5			$	45.5			$	108.2			$	84.8
Reconciliation of “operating margin” to net income (loss):
Net income (loss)		$	28.2			$	13.8			$	53.1			$	3.2
Add:
Depreciation and amortization expense			18.4				17.6				36.7				35.7
Deferred income tax expense			0.4				0.3				0.7				0.7
Allocated interest expense, net			—				2.7				—				16.2
Interest expense, net			8.0				5.2				16.7				7.9
Non-cash gain related to derivative instruments			—				6.1				—				21.0
General and administrative expense			5.7				4.4				10.9				7.6
Operating margin		$	60.7			$	50.1			$	118.1			$	92.3

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
Sr. Manager — Finance/Investor Relations

Matt Meloy
Vice President — Finance and Treasurer

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS

		June 30,				December 31,
		2008				2007
		(Unaudited)
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	31,988			$	50,994
Receivables from third parties			84,847				59,346
Receivables from affiliated companies			107,367				87,547
Inventory			2,350				1,624
Assets from risk management activities			1,926				8,695
Other current assets			395				269
Total current assets			228,873				208,475
Property, plant and equipment, at cost			1,455,834				1,433,955
Accumulated depreciation			(210,923	)			(174,361	)
Property, plant and equipment, net			1,244,911				1,259,594
Debt issue costs			12,321				6,588
Long-term assets from risk management activities			3,362				3,040
Other assets			2,285				2,275
Total assets		$	1,491,752			$	1,479,972
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable		$	5,616			$	5,693
Accrued liabilities			198,820				142,836
Liabilities from risk management activities			115,293				44,003
Total current liabilities			319,729				192,532
Long-term debt			575,000				626,300
Long-term liabilities from risk management activities			153,697				43,109
Deferred income taxes			1,259				559
Other long-term liabilities			3,451				3,266
Commitments and contingencies
Partners’ capital:
Common unitholders (34,652,000 and 34,636,000 units issued and outstanding at June 30, 2008 and December 31, 2007, respectively)			778,039				770,207
Subordinated unitholders (11,528,231units issued and outstanding at June 30, 2008 and December 31, 2007)			(82,431	)			(84,999	)
General partner (942,455 and 942,128 units issued and outstanding at June 30, 2008 and December 31, 2007, respectively)			8,424				4,234
Accumulated other comprehensive loss			(265,416	)			(75,236	)
Total partners’ capital			438,616				614,206
Total liabilities and partners’ capital		$	1,491,752			$	1,479,972

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

		Three Months Ended June 30,								Six Months Ended June 30,
		2008				2007				2008				2007
		(Unaudited)
		(In thousands, except per unit amounts)
Revenues from third parties		$	243,138			$	175,149			$	438,210			$	315,339
Revenues from affiliates			387,382				258,466				704,379				467,057
Total operating revenues			630,520				433,615				1,142,589				782,396
Costs and expenses:
Product purchases from third parties			478,890				310,465				854,515				564,619
Product purchases from affiliates			76,269				61,236				142,794				101,580
Operating expenses			14,701				11,795				27,271				23,947
Depreciation and amortization expense			18,421				17,619				36,669				35,657
General and administrative expense			5,715				4,632				10,916				7,986
Other			—				—
Gain on sale of assets			(1	)			(315	)			(75	)			(315	)
Loss (gain) on sale of assets			—				—
			593,995				405,432				1,072,090				733,474
Income from operations			36,525				28,183				70,499				48,922
Other income (expense):
Interest expense, net			(7,976	)			(5,154	)			(16,694	)			(7,859	)
Interest expense allocated from Parent			—				(2,732	)			—				(16,175	)
Loss on mark-to-market derivative instruments			—				(6,122	)			—				(21,002	)
Other			20				(16	)			36				5
Income before income taxes			28,569				14,159				53,841				3,891
Deferred income tax expense			363				348				700				707
Net income			28,206				13,811				53,141				3,184
Net income (loss) attributable to predecessor operations			—				9,771				—				(3,009	)
Net income allocable to partners			28,206				4,040				53,141				6,193
Net income attributable to general partner interests			3,384				81				5,230				124
Net income available to common and subordinated unitholders		$	24,822			$	3,959			$	47,911			$	6,069
Basic net income per common and subordinated unit		$	0.54			$	0.13			$	1.04			$	0.20
Diluted net income per common and subordinated unit		$	0.54			$	0.13			$	1.04			$	0.20
Basic average number of common and subordinated units outstanding			46,154				30,848				46,152				30,848
Diluted average number of common and subordinated units outstanding			46,163				30,855				46,160				30,854

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Six Months Ended June 30,
		2008				2007
		(Unaudited)
		(In thousands)
Cash flows from operating activities
Net income		$	53,141			$	3,184
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			36,607				35,596
Amortization			1,038				1,173
Accretion of asset retirement obligations			72				204
Deferred income tax expense			700				707
Risk management activities			1,011				21,087
Gain on sale of assets			(75	)			(315	)
Changes in operating assets and liabilities:
Accounts receivable			(45,321	)			(7,151	)
Inventory			(726	)			(270	)
Other			(2,992	)			(503	)
Accounts payable			(77	)			2,641
Accrued liabilities			55,984				12,549
Net cash provided by operating activities			99,362				68,902
Cash flows from investing activities
Purchases of property, plant and equipment			(17,586	)			(23,352	)
Other			(4,150	)			(30	)
Net cash used in investing activities			(21,736	)			(23,382	)
Cash flows from financing activities
Proceeds from equity offerings			—				380,768
Costs incurred in connection with public offerings			(72	)			(3,175	)
General partner contributions			8				—
Distributions			(38,678	)			(5,315	)
Proceeds from borrowings under credit facility			—				342,500
Proceeds from issuance of senior notes			250,000				—
Costs incurred in connection with financing arrangements			(6,590	)			(4,145	)
Repayments of loans:
Affiliated			—				(665,692	)
Credit facility			(301,300	)			(48,000	)
Deemed Parent distributions			—				(33,100	)
Net cash used in financing activities			(96,632	)			(36,159	)
Net change in cash and cash equivalents			(19,006	)			9,361
Cash and cash equivalents, beginning of period			50,994				—
Cash and cash equivalents, end of period		$	31,988			$	9,361
Supplemental cash flow information:
Net settlement of allocated indebtedness and debt issue costs		$	—			$	239,065
Net contribution of affiliated receivables			—				38,856