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 of incorporation or organization)		(Commission File Number)		(IRS Employer Identification No.)

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

(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))

 

 

2.02. Results of Operations and Financial Condition.

     On November 14, 2007, Targa Resources Partners LP (the “Partnership”) issued a press release regarding its financial results for the three and nine months ended September 30, 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 November 21.

     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 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 November 14, 2007.

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: November 19, 2007		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 November 14, 2007.

Exhibit 99.1

TARGA RESOURCES PARTNERS LP REPORTS
THIRD QUARTER 2007 EARNINGS

HOUSTON—November 14, 2007—Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) (NASDAQ: NGLS) today announced its financial results for the three and nine months ended September 30, 2007. For the third quarter of 2007, the Partnership reported (i) net income of $3.9 million, or 12¢ per unit on a fully diluted basis, (ii) income from operations of $9.3 million and (iii) earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $23.6 million. EBITDA is a non-generally accepted accounting principle (or “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 first nine months of 2007, the Partnership reported (i) net income of $3.2 million (ii) income from operations of $26.9 million and (iii) EBITDA of $69.8 million. Results for the nine month period include the results of the Partnership’s predecessor (“the Predecessor”) from January 1, 2007 through February 13, 2007 (the “Pre-IPO Period”) and the results of operations since the completion of its initial public offering (“IPO”) from February 14, 2007 to September 30, 2007 (the “Post-IPO Period”). Unless stated otherwise, the year to date results discussed in this release are for the full nine month period, including both the Pre-IPO and the Post-IPO periods. Results for 2006 are for the Predecessor.

As discussed in more detail below, on October 24, 2007 the Partnership announced that it acquired certain natural gas gathering and processing businesses located in west Texas (“SAOU”) and Louisiana (“LOU”) 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 common units (the “Newly Issued Units”) and borrowings under its increased $750 million senior secured revolving credit facility.

On October 23, 2007, the board of Targa Resources Partners’ general partner declared a cash distribution of $0.3375 per common unit, or $1.35 per unit on an annualized basis, for the third quarter payable to all unitholders, including holders of the Newly Issued Units. Distributable cash flow for the third quarter of 2007, which does not include distributable cash flow from the LOU and SAOU systems, was $14.8 million, corresponding to distribution coverage of 1.4 times excluding the Newly Issued Units or 1.0 times if the Newly Issued Units are included. 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 has recommended an 18% increase in the fourth quarter 2007 distribution (which will be paid in the first quarter of 2008) to 39.75¢, or $1.59 annually. The board has indicated their support of the recommendation which remains subject to final board approval following a review of fourth quarter financial results.

Review of Third Quarter Results

Revenues were $107.7 million for the three-month period ended September 30, 2007, 6% higher than revenues of $102.0 million for the three months ended September 30, 2006. Income from

operations for the third quarter of 2007 increased by 32% to $9.3 million from $7.0 million in 2006.

The primary drivers for these improvements were increases of 1%, 5% and 4% % in average realized natural gas, NGL and condensate prices, respectively, including the impacts of our hedging program.

Net income for the third quarter was $3.9 million versus a net loss of $12.2 million for the same period last year. The net loss in 2006 is principally due to interest expense totaling $18.7 million for the three months ended September 30, 2006 that is related to debt that was allocated to the Predecessor by Targa. In connection with the IPO, the Partnership repaid a portion of this indebtedness and the balance was retired and treated as a capital contribution to the Partnership.

For the quarter ended September 30, 2007, gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines), was 165.7 MMcf/d compared to 170.1 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 160.8 MMcf/d compared to 164.0 MMcf/d. During the third quarter a major producer conducted a multi-well workover program slightly reducing volumes available for processing.

Gross NGL production of 19.2 MBbl/d for the three months ended September 30, 2007 compares to NGL production of 19.1 MBbl/d for the three months ended September 30, 2006. Natural gas sales volumes of 75.6 BBtu/d in the quarter ended September 30, 2007 were slightly lower than the 76.6 BBtu/d sold in the comparable 2006 period. Conversely, condensate sales of 1.6 MBbl/d for the third quarter of 2007 were higher than the 1.5 MBbl/d sold in the same 2006 period.

Review of First Nine Months’ Results

For the nine months ended September 30, 2007 revenues were $307.7 million, 6% higher than revenues of $290.9 million for the nine months ended September 30, 2006. Income from operations for the first nine months of 2007 increased by 29%, to $26.9 million from $20.9 million in 2006. The primary drivers for these improvements were increases of 7%, 5% and 2% in realized natural gas, NGL and condensate prices, respectively, including the impacts of our hedging program.

Net income for the nine months ended September 30, 2007 was $3.2 million versus a net loss of $35.4 million for the same period last year. The 2007 total includes affiliate interest expense of $9.8 million during the Pre-IPO Period. The 2006 net loss is primarily due to interest expense totaling $54.4 million for the nine months ended September 30, 2006 that is related to debt that was allocated to the Predecessor by Targa. In connection with the IPO, the Partnership repaid a portion of this indebtedness and the balance was retired and treated as a capital contribution to the Partnership.

For the nine months ended September 30, 2007, gathering throughput was 166.1 MMcf/d and plant natural gas inlet was 160.3 MMcf/d, approximately 1% lower than levels in the same 2006 period. In addition to the impacts of producer well workover activities mentioned above, year-to-date 2007 throughput and inlet volumes were adversely impacted by unseasonable amounts of rain in the second quarter and by freezing weather during the first quarter which reduced wellhead volumes and impeded new well connections.

Gross NGL production of 18.0 MBbl/d for the first nine months of 2007 was 4% lower than the comparable 2006 production of 18.8 MBbl/d, while natural gas sales of 75.8 BBtu/d for the nine months ended September 30, 2007 were up from the 75.2 BBtu/d of natural gas sales during the nine months ended September 30, 2006. The decline in gross NGL production and related increase in natural gas sales were primarily due to operational issues with a liquids treater during the first quarter of 2007 which limited our liquids recovery. The operational issues with the treater were resolved during March of 2007. Finally, condensate sales for the nine months ended September 30, 2007 of 1.8 MBbl/d were 13% higher than the 1.6 MBbl/d sold during the first nine months of 2006.

Contract Mix, Hedges and Realized Prices

Approximately 97% of the Partnership’s gathered volumes are processed under percent-of-proceeds contracts with the balance covered by keep-whole and fee-for-service 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 our business, we enter into hedging contracts.

For the three months ended September 30, 2007 our average realized prices, including the impact of hedges, for natural gas, NGL and condensate were $5.93 per MMBtu, $1.00 per gallon and $60.93 per barrel, respectively, compared to $5.85 per MMBtu, 95¢ per gallon and $58.66 per barrel, respectively, in the third quarter of 2006.

Capitalization

In conjunction with the Partnership’s IPO, we entered into a five-year, $500 million senior secured revolving credit facility (the “Credit Facility”), the full amount of which is available for the issuance of letters of credit. Total funded debt at September 30, 2007 was approximately $294.5 million, approximately 28% of total book capitalization.

In conjunction with the acquisition of SAOU and LOU from Targa, the Partnership increased the aggregate commitments under the Credit Facility by $250 million to $750 million and borrowed an additional $378.8 million bringing total funded debt to $673.3 million or approximately 54% of total book capitalization on a pro forma basis as of September 30, 2007.

Recent Acquisition

As mentioned above, on October 24, 2007 the Partnership recently acquired the SAOU and LOU systems from 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. Total consideration paid by the Partnership consisted of cash of approximately $721.7 million (including the hedge termination payment) and approximately 275,000 general partner units issued to Targa to maintain its 2% general partner interest in the Partnership.

For the six month period ended June 30, 2007, the acquired businesses generated Adjusted EBITDA of approximately $38.4 million and pro forma distributable cash flow of approximately $22.4 million. Adjusted EBITDA is a non-GAAP financial measure that is defined and reconciled later in

this press release to its most directly comparable financial measure calculated and presented in accordance GAAP net income (loss).

The SAOU system consists of (i) the approximately 1,350 mile San Angelo natural gas gathering system, which is located in the Permian Basin of west Texas, and (ii) the Mertzon, Sterling and Conger processing plants with aggregate processing capacity of approximately 135 MMcf/d. The LOU system consists of (i) an approximately 700-mile natural gas gathering system, which is located in southwest Louisiana, (ii) the Gillis and Acadia processing plants with aggregate processing capacity of approximately 260 MMcf/d and (iii) an integrated fractionation facility at the Gillis processing plant with processing capacity of approximately 13 MBbls/d.

Recent Volumes and Development Activities

As a result of certain of our development activities and increased production in our areas of operations, fourth quarter operating results to date have been well in excess of the third quarter and first nine months of 2007. From October 1 through November 10, average daily plant inlet volumes for the Chico and Shackelford plants were 171.6 MMcf/d. Additionally, plant inlet for SAOU and LOU for the month of October was approximately 287.7 MMcf/d.

Since the IPO, the Partnership has added more than 30,000 acres of new dedications and approved several growth projects including:

	1.		$15.1 million for a new residue pipeline to improve takeaway capacity from the Chico plant and improve market access points;
	2.		$5.3 million for the expansion of the Chico plant’s CO2 amine treater. With CO2 flows at the Chico plant continuing to increase, completion of this project has been expedited to the middle of 2008. This project is supported by treating fees that justify it on a standalone basis, but more importantly, the project allows us to continue to add producer volumes;
	3.		$5.7 million for the installation of a pipeline system and the acquisition of a producer owned pipeline system in Wise and Montague counties. The project includes over 4,400 acres of dedications;
	4.		$3.9 million for the installation of a pipeline and compression system in Wise county which includes a 20,000 acreage dedication in Wise and Southern Montague counties; and
	5.		the installation of 4.3 MMcf/d of compression and 10 MMcf/d of dehydration in Jack and Palo Pinto counties.

In addition, we are evaluating over $170 million of potential organic growth projects including the addition of compression and system expansion projects in Jack, Wise, Palo Pinto and Montague counties.

Conference Call

Targa Resources Partners will host a conference call for investors and analysts at 10 a.m. ET (9 a.m. CT) on November 14, 2007 to discuss third quarter earnings. 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 800-257-2101. The pass code is 11100295#. Please call in 5 to 10 minutes prior to the scheduled start time. A replay of the Webcast will be available through the Investors section of the Partnership’s web site approximately 2 hours following completion of the Webcast and will remain available until November 21.

About Targa Resources Partners

The Partnership 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. The Partnership 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 the Partnership. The Partnership owns an extensive network of integrated gathering pipelines, seven natural gas processing plants and two fractionators.

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

Use of Non-GAAP Financial Measures

This press release and accompanying schedules include non-GAAP financial measures of EBITDA, 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.

EBITDA — We define EBITDA as net income or loss before interest, income taxes, depreciation and amortization. EBITDA is used as a supplemental financial measure by us and by external users of our financial statements, such as investors, commercial banks and others, to assess: (i) the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; (ii) 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 (iii) the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. The economic substance behind our use of 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 EBITDA is net income (loss). Our non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net income (loss). EBITDA is not a presentation made in accordance with GAAP and has important limitations

as an analytical tool. You should not consider EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of EBITDA may not be comparable to similarly titled measures of other companies.

We compensate for the limitations of EBITDA as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between the measures and incorporating these learnings into our decision making processes.

The following table presents a reconciliation of EBITDA to net income (loss) for the periods shown:

		Three Months				Three Months				Nine Months				Nine Months
		Ended September				Ended September				Ended September				Ended September
		30, 2007				30, 2006				30, 2007				30, 2006
		(in millions)
		(unaudited)
Reconciliation of Non-GAAP Measures
Reconciliation of net income to “EBITDA”:
Net loss		$	3.9			$	(12.2	)		$	3.2			$	(35.4	)
Add:
Interest expense, net			5.0				18.7				22.7				54.4
Deferred income tax expense			0.3				0.5				1.0				2.0
Depreciation and amortization expense			14.4				14.3				42.9				41.7
EBITDA		$	23.6			$	21.3			$	69.8			$	62.7

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 distributable cash flow to net income (loss) for the Partnership for the periods shown:

		Three Months				Three Months				Nine Months				Nine Months
		Ended September				Ended September				Ended September				Ended September
		30, 2007				30, 2006				30, 2007				30, 2006
		(in millions)
		(unaudited)
Reconciliation of “Distributable cash flow” to net income (loss):
Net income (loss)		$	3.9			$	(12.2	)		$	3.2			$	(35.4	)
Depreciation and amortization expense			14.4				14.3				42.9				41.7
Deferred income tax expense			0.3				0.5				1.0				2.0
Amortization of debt issue costs			0.2				1.3				0.5				3.9
Maintenance capital expenditures			(4.0	)			(2.7	)			(9.3	)			(9.0	)
Distributable cash flow		$	14.8			$	1.2			$	38.3			$	3.2

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

		Six Months
		Ended June
$ in millions		30, 2007
Pro forma net income (loss)			(3 0	)
Non cash mark-to-market hedge adjustment			21.0
Depreciation and amortization expense			7.2
Deferred tax expense			0.0
Incremental debt issue costs *			0.3
Accretion expense			0.1
Maintenance capital expenditures			(3.2	)
Distributable cash flow			22.4

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.

The following table presents a reconciliation of Adjusted EBITDA to net income (loss) for LOU and SAOU for the periods shown:

		Six Months
		Ended June
$ in millions		30, 2007
Pro forma net income (loss)			(3.0	)
Add:
Pro forma interest expense *			13.2
Deferred tax expense			0.0
Depreciation and amortization expense			7.2
Non cash mark-to-market hedge adjustment			21.0
Adjusted EBITDA			38.4

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 Annual Report on Form 10-K for the year ended December 31, 2006 and other reports filed 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:
Howard Tate
Vice President — Finance, Treasurer
713-584-1000
Web site: http://www.targaresources.com

Media contact:
Kenny Juarez
212-371-5999

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS

		September 30,				December 31,
		2007				2006
		(Unaudited)
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	28,441			$	—
Receivables from third parties			208				1,310
Receivables from affiliated companies			32,437				—
Inventory			919				—
Assets from risk management activities			8,312				17,250
Other			373				—
Total current assets			70,690				18,560
Property, plant and equipment, at cost			1,146,566				1,129,210
Accumulated depreciation			(107,981	)			(65,102	)
Property, plant and equipment, net			1,038,585				1,064,108
Long-term assets from risk management activities			5,755				15,541
Other long-term assets			5,572				17,612
Total assets		$	1,120,602			$	1,115,821
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable		$	2,392			$	2,789
Accrued liabilities			37,015				28,832
Current maturities of debt allocated from Parent			—				281,083
Liabilities from risk management activities			12,540				—
Total current liabilities			51,947				312,704
Long-term debt allocated from Parent			—				582,877
Long-term debt			294,500				—
Long-term liabilities from risk management activities			10,094				96
Other long-term liabilities			1,834				1,684
Deferred income tax liability			3,529				2,844
Commitments and contingencies (Note 9)
Partners’ capital:
Common unitholders (19,336,000 units issued and outstanding at September 30, 2007)			373,970				—
Subordinated unitholders (11,528,231 units issued and outstanding at September 30, 2007)			374,201				—
General partner (629,555 units issued and outstanding at September 30, 2007)			20,436				—
Accumulated other comprehensive income (loss)			(9,909	)			30,843
Net parent investment			—				184,773
Total partners’ capital			758,698				215,616
Total liabilities and partners’ capital		$	1,120,602			$	1,115,821

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS

		Three Months				Three Months				Nine Months				Nine Months
		Ended				Ended				Ended				Ended
		September 30,				September 30,				September 30,				September 30,
		2007				2006				2007				2006
		(Unaudited)
		(In thousands, except per unit amounts)
Revenues from third parties		$	6,951			$	3,505			$	17,335			$	8,233
Revenues from affiliates			100,712				98,461				290,324				282,657
Total operating revenues			107,663				101,966				307,659				290,890
Costs and expenses:
Product purchases from third parties			74,457				72,182				212,208				204,532
Product purchases from affiliates			228				270				742				670
Operating expenses, excluding DD&A			6,543				6,362				18,576				17,905
Depreciation and amortization expense			14,396				14,274				42,880				41,713
General and administrative expense			2,779				1,882				6,310				5,137
			98,403				94,970				280,716				269,957
Income from operations			9,260				6,996				26,943				20,933
Other expense:
Interest expense, net			5,059				—				12,918				—
Interest expense from affiliates, net			—				—				9,827				—
Interest expense allocated from Parent			—				18,706				—				54,369
Income (loss) before income taxes			4,201				(11,710	)			4,198				(33,436	)
Deferred income tax expense			332				534				997				1,988
Net income (loss)		$	3,869			$	(12,244	)		$	3,201			$	(35,424	)
Allocation of net income (loss) for the three and nine months ended September 30, 2007:
Net loss attributable to the period from January 1, 2007 to February 13, 2007		$	—							$	(6,861	)
Net income attributable to the period from February 14, 2007 to September 30, 2007			3,869								10,062
Net income		$	3,869							$	3,201
General partner interest in net income for the period from February 14, 2007 to September 30, 2007		$	77							$	201
Common and subordinated unitholders’ interest in net income for the period from February 14, 2007 to September 30, 2007		$	3,792							$	9,861
Basic net income per common and subordinated unit		$	0.12							$	0.32
Diluted net income per common and subordinated unit		$	0.12							$	0.32
Basic average number of common and subordinated units outstanding			30,848								30,848
Diluted average number of common and subordinated units outstanding			30,857								30,855

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Nine Months				Nine Months
		Ended				Ended
		September 30,				September 30,
		2007				2006
		(Unaudited)
		(In thousands)
Cash flows from operating activities
Net income (loss)		$	3,201			$	(35,424	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation			42,880				41,713
Accretion of asset retirement obligations			118				108
Amortization of debt issue costs			507				3,864
Noncash compensation			128				—
Loss on sale of assets			2				—
Deferred income tax expense			997				1,988
Risk management activities			198				—
Changes in operating assets and liabilities:
Accounts receivable			7,521				369
Inventory			(919	)			584
Other			(2,307	)			630
Accounts payable			(397	)			(10	)
Accrued liabilities			8,183				(2,675	)
Net cash provided by operating activities			60,112				11,147
Cash flows from investing activities
Purchases of property, plant and equipment			(17,362	)			(17,769	)
Other			35				32
Net cash used in investing activities			(17,327	)			(17,737	)
Cash flows from financing activities
Proceeds from initial public offering			380,768				—
Costs incurred in connection with public offerings			(3,313	)			—
Distributions			(15,943	)			—
Proceeds from borrowings under credit facility			342,500				—
Costs incurred in connection with financing arrangements			(4,145	)			—
Repayments of loans:
Affiliated			(665,692	)			—
Credit facility			(48,000	)			—
Deemed parent contributions (distributions)			(519	)			6,590
Net cash provided by (used in) financing activities			(14,344	)			6,590
Net change in cash and cash equivalents			28,441				—
Cash and cash equivalents, beginning of period			—				—
Cash and cash equivalents, end of period		$	28,441			$	—
Supplemental cash flow information:
Net settlement of allocated indebtedness and debt issue costs		$	190,493			$	256
Net contribution of affiliated receivables			38,856				—
Noncash long-term debt allocation of payments from Parent			—				3,699