Targa Resources Partners 8K Reports Third Quarter 2008 Financial Results | NGLS-PA 12 Nov 08

Exhibit 99.1


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

Targa Resources Partners LP Reports Third Quarter 2008 Financial Results

HOUSTON-November 12, 2008-Targa Resources Partners LP (“Targa Resources Partners” or the “Partnership”) (NASDAQ: NGLS) today reported third quarter 2008 net income of $14.7 million (which includes a $9.4 million non-cash hedge loss, a $1.0 million loss related to Lehman hedges, $0.2 million in other hedge amortization and an estimated $2.2 million impact due to Hurricane Gustav and Ike disruptions), or $0.31 per diluted limited partner unit as compared to net income of $14.4 million, or $0.12 per diluted limited partner unit for the third quarter of 2007. The Partnership reported earnings before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments (“Adjusted EBITDA”) of $55.0 million for the third quarter of 2008 compared to Adjusted EBITDA of $48.2 million for the third quarter of 2007.

Distributable cash flow for the third quarter of 2008 was $37.7 million which corresponds to distribution coverage of 1.4 times for the 47.1 million total units outstanding on September 30, 2008 (see the section of this release entitled “Non-GAAP Financial Measures” for a discussion of Adjusted EBITDA, operating margin and distributable cash flow, and reconciliations of such measures to the comparable GAAP measures).

“Third quarter results reflect the impact of discrete events and non-cash items. Excluding those items, third quarter results were largely in line with second quarter results, but these results occurred in a drastically different commodity price environment than we are in today. Going forward, we believe that our healthy coverage ratio, strong liquidity and hedge program will enable us to weather commodity price volatility and the strained credit market environment. Based on completed and approved projects and support from current producer drilling programs, we believe 2009 volumes will be at or above 2008 levels. Obviously, projected commodity prices and producer activities in our areas of operations must be closely monitored for impacts to our 2009 business plan and we will continue to execute with a focus on operating cost control and discipline regarding capital expenditures,” said Rene Joyce, Chief Executive Officer of the Partnership’s general partner and of Targa Resources, Inc. (“Targa”).

On October 24, 2008, the Partnership announced a cash distribution of 51.75¢ per common and subordinated unit, or $2.07 per unit on an annualized basis, for the third quarter of 2008. This cash distribution will be paid November 14, 2008 on all outstanding common and subordinated units to holders of record as of the close of business on November 4, 2008. The distribution reflects an increase of approximately 1% over the previous quarter’s distribution and approximately 53% over the distribution for the third quarter of 2007.

For the first nine months of 2008, Adjusted EBITDA rose 23% to $163.1 million, compared with $132.7 million in the same period a year ago. Distributable cash flow for the nine months ended September 30, 2008 increased 35% to $118.2 million from $87.3 million in the same period a year ago. Both metrics were driven primarily by favorable increases in both gathering throughput and plant inlet volumes and natural gas, NGL, and condensate prices.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Revenues	$	578.7		$	405.0		$	1,721.3		$	1,187.4
Product purchases		512.4			337.8			1,509.8			1,004.0
Operating expense, excluding DD&A		15.4			12.7			42.7			36.7
Depreciation and amortization expense		18.6			18.0			55.2			53.6
General and administrative expense		5.3			6.5			16.2			14.5
Casualty loss		0.2			—			0.2			—
Gain on sale of assets		—			—			(0.1	)		(0.3	)

Income from operations		26.8			30.0			97.3			78.9
Interest expense, net		(10.7	)		(5.1	)		(27.4	)		(12.9	)
Interest expense, allocated from Parent		—			(2.8	)		—			(19.0	)
Loss on mark-to-market derivative instruments		(1.0	)		(7.4	)		(1.0	)		(28.4	)
Deferred income tax expense		(0.4	)		(0.3	)		(1.1	)		(1.0	)

Net income	$	14.7		$	14.4		$	67.8		$	17.6


Financial data:
Operating margin	$	50.9		$	54.5		$	168.8		$	146.7
Adjusted EBITDA		55.0			48.2			163.1			132.7
Distributable cash flow		37.7			35.8			118.2			87.3

Operating data:
Gathering throughput, MMcf/d		438.3			464.3			455.0			447.7
Plant natural gas inlet, MMcf/d		415.9			445.1			430.8			423.5
Gross NGL production, MBbl/d		41.3			43.9			43.2			42.1
Natural gas sales, BBtu/d		404.4			414.8			410.9			403.3
NGL sales, MBbl/d		37.4			37.5			38.2			35.7
Condensate sales, MBbl/d		3.3			3.7			3.6			3.6

Average realized prices:
Natural gas, $/MMBtu
Average realized sales price		9.47			5.87			9.31			6.61
Impact of hedging		(0.05	)		0.09			(0.02	)		0.08

Average realized price		9.42			5.96			9.29			6.69


NGLs, $/gal
Average realized sales price		1.47			1.06			1.41			0.95
Impact of hedging		(0.11	)		(0.02	)		(0.10	)		(0.01	)

Average realized price		1.36			1.04			1.31			0.94


Condensate, $/ Bbl
Average realized sales price		103.38			69.05			98.86			60.09
Impact of hedging		(5.59	)		(0.31	)		(4.12	)		0.78

Average realized price		97.79			68.74			94.74			60.87

Review of Third Quarter Results

Net income for the three months ended September 30, 2008 was $14.7 million, up from $14.4 million for the three months ended September 30, 2007. The increase in net income was attributable to higher commodity prices partially offset by higher operating expenses and higher interest expense during the 2008 period. Net income for the three months ended September 30, 2008 also includes a $9.4 million non-cash hedge loss, a $1.0 million loss related to Lehman hedges, $0.2 million in other hedge amortization and an estimated $2.2 million impact due to the hurricanes. The third quarter of 2007 includes a $7.4 million loss on mark-to-market derivative contracts related to the SAOU and LOU Systems that was recognized during the period prior to the acquisition of these businesses by the Partnership.

Revenues increased $173.7 million, or 43%, to $578.7 million for the third quarter of 2008 from $405.0 million for the third quarter of 2007, driven by higher prices for natural gas, NGL and condensate. The benefit of higher prices was partially offset by the impact of lower sales volumes, mainly the result of processing plant disruptions and lower industrial sales primarily due to the impact of the hurricanes.

Gathering throughput (the volume of natural gas gathered and passed through natural gas gathering pipelines) for the third quarter of 2008 decreased by 26.0 MMcf/d, or 6%, to 438.3 MMcf/d compared to 464.3 MMcf/d for the same period in 2007. Plant natural gas inlet volume (the volume of natural gas passing through the meter located at the inlet of a processing plant) was 7% lower at 415.4 MMcf/d for the third quarter of 2008 compared to 445.1 MMcf/d for the same period in 2007 due primarily to the impact of the hurricanes.

Gross NGL production of 41.3 MBbl/d for the third quarter of 2008 was 6% lower than gross NGL production of 43.9 MBbl/d for the third quarter of 2007. Natural gas sales volumes decreased 3% to 404.4 BBtu/d in the third quarter of 2008 compared to 414.8 BBtu/d during the third quarter of 2007. NGL sales of 37.4 MBbl/d for the third quarter of 2008 were less than 1% lower than the 37.5 MBbl/d sold during the third quarter of 2007. These volume decreases were due primarily to the impact of the hurricanes offset by the purchase of raw NGL mix for fractionation at Gillis.

The average realized natural gas price increased by $3.46 per MMBtu, or 58%, to $9.42 per MMBtu for the third quarter of 2008 compared to $5.96 per MMBtu for the same period in 2007. The average realized price for NGLs increased by $0.32 per gallon, or 31%, to $1.36 per gallon for the third quarter of 2008 compared to $1.04 per gallon for the same period in 2007. The average realized price for condensate increased by $29.05 per barrel, or 42%, to $97.79 per barrel for the third quarter of 2008 compared to $68.74 per barrel for the third quarter of 2007. All of the average realized prices reflect the impact of our hedging program.

Review of Nine Month Results

Net income for the first nine months of 2008 was $67.8 million compared to $17.6 million for the same period of 2007. The increase in net income was attributable to higher commodity prices and higher inlet volumes partially offset by higher operating expenses and higher general and administrative expenses for the 2008 period. The nine months ended September 30, 2008 also includes a $10.1 million non-cash hedge loss, a $1.0 million loss related to Lehman hedges, and $0.5 million of other hedge amortization as well as an estimated $2.2 million impact due to the

hurricanes. In addition, the first nine months of 2007 includes a $28.4 million loss on mark-to-market derivative contracts related to the SAOU and LOU Systems recognized during the period prior to the acquisition of these businesses by the Partnership.

For the first nine months of 2008, gathering throughput was 455.0 MMcf/d, 2% higher than 447.7 MMcf/d for the same period in 2007. Plant natural gas inlet volume was 430.8 MMcf/d for the first nine months of 2008, 2% higher than 423.5 MMcf/d for the same period in 2007.

Gross NGL production of 43.2 MBbl/d for the first nine months of 2008 was 3% higher than gross NGL production of 42.1 MBbl/d for the first nine months of 2007. Natural gas sales volumes increased 2% to 410.9 BBtu/d for the first nine months of 2008 as compared to 403.3 BBtu/d for the same period in 2007. NGL sales of 38.2 MBbl/d for the first nine months of 2008 were 7% higher than NGL sales of 35.7 MBbl/d for the same period in 2007. 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 by $2.60 per MMBtu, or 39%, to $9.29 per MMBtu for the first nine months of 2008, from $6.69 per MMBtu for the first nine months of 2007. The average realized price for NGLs increased by $0.37 per gallon, or 39%, to $1.31 per gallon for the first nine months of 2008 compared to $0.94 per gallon for the first nine months of 2007. The average realized price for condensate increased by $33.87 per barrel, or 56%, to $94.74 per barrel for the first nine months of 2008 compared to $60.87 per barrel for the first nine months of 2007. All of the average realized prices reflect the impact of our hedging program.

Capitalization / Liquidity Update

As of September 30, 2008, we had approximately $425.3 million in capacity available under our senior secured credit facility, after giving effect to outstanding borrowings of $390 million and the issuance of $34.7 million of letters of credit. Our senior secured credit facility allows us to request increases in the commitments under the facility by up to $150 million.

On October 16, 2008, we requested a $100 million funding under our senior secured credit facility to increase our cash on hand in the face of significant deterioration in the credit markets. Lehman Brothers Commercial Bank, a lender under our senior secured credit facility, defaulted on its portion of the borrowing request resulting in an actual funding of $97.8 million. The proceeds from this borrowing are currently available to us as cash deposits. As a result of the Lehman default, we believe that our availability under the senior secured credit facility has been effectively reduced by $9.5 million to $415.8 million.

As of October 31, 2008, we had approximately $130 million of cash and approximately $313 million of availability under the senior secured credit facility, after giving effect to the Lehman default, bringing total liquidity to approximately $443 million. In addition to our strong liquidity position, we are well within our financial covenants and have no near term maturities under our senior secured credit facility or our senior unsecured notes.

Total funded debt as of September 30, 2008 was $640.0 million, approximately 50% of total book capitalization.

Conference Call

Targa Resources Partners will host a conference call for investors and analysts at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on November 12, 2008 to discuss third quarter 2008 financial results. The conference call can be accessed via Webcast through the Investors section of the Partnership’s web site athttp://www.targaresources.com or by dialing 800-240-6709. The pass code is 11121588. 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 November 26, 2008. Replay access numbers are 303-590-3000 or 800-405-2236 with pass code 11121588.

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, visitwww.targaresources.com.

Non-GAAP Financial Measures

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

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

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

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Reconciliation of net income to “distributable cash flow”:
Net income	$	14.7		$	14.4		$	67.8		$	17.6
Depreciation and amortization expense		18.6			18.0			55.2			53.6
Deferred income tax expense		0.4			0.3			1.1			1.0
Amortization of debt issue costs		0.6			0.4			1.5			1.4
Non-cash loss related to derivative instruments		10.6			7.6			11.6			28.6
Maintenance capital expenditures		(7.2	)		(4.9	)		(19.0	)		(14.9	)

Distributable cash flow	$	37.7		$	35.8		$	118.2		$	87.3


	Nine Months Ended September 30, 2007
				Pre-Acquisition						Post Acquisition
				SAOU-LOU			North Texas
				Jan 1, 2007 to Sep			Jan 1, 2007 to Feb
	TRP LP			30, 2007			13, 2007			TRP LP
	(In millions)
Net income (loss)	$	17.6		$	14.4		$	(6.9	)	$	10.1
Depreciation and amortization expense		53.6			10.8			6.9			35.9
Deferred income tax expense		1.0			—			—			1.0
Amortization of debt issue costs		1.4			0.9			—			0.5
Loss on mark-to-market derivative instruments		28.6			28.6			—			—
Maintenance capital expenditures		(14.9	)		(5.6	)		(1.5	)		(7.8	)

Distributable Cash Flow	$	87.3		$	49.1		$	(1.5	)	$	39.7

Adjusted EBITDA- We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by our management and by external

users of our financial statements such as investors, commercial banks and others, to assess: (1) the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; (2) our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and (3) the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

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

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions)
Reconciliation of net cash provided by (used in) operating activities to “Adjusted EBITDA”:
Net cash provided by (used in) operating activities	$	(25.4	)	$	64.9		$	74.0		$	133.8
Allocated interest expense from parent		—			2.4			—			17.6
Interest expense, net		10.1			5.1			25.9			12.9
Changes in operating working capital which used (provided) cash:
Accounts receivable and other		2.3			(22.5	)		51.1			(14.8	)
Accounts payable		(4.0	)		(0.6	)		(3.9	)		(3.2	)
Accrued liabilities		72.0			(1.1	)		16.0			(13.6	)

Adjusted EBITDA	$	55.0		$	48.2		$	163.1		$	132.7


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In millions)
Reconciliation of net income to “Adjusted EBITDA”:
Net income		14.7	$	14.4	$	67.8	$	17.6
Add:
Allocated interest expense, net		—		2.8		—		19.0
Interest expense, net		10.7		5.1		27.4		12.9
Deferred income tax expense		0.4		0.3		1.1		1.0
Depreciation and amortization expense		18.6		18.0		55.2		53.6
Non-cash loss related to derivative instruments		10.6		7.6		11.6		28.6

Adjusted EBITDA	$	55.0	$	48.2	$	163.1	$	132.7


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In millions)
Reconciliation of net income to “operating margin”:
Net income	$	14.7	$	14.4	$	67.8	$	17.6
Add:
Depreciation and amortization expense		18.6		18.0		55.2		53.6
Deferred income tax expense		0.4		0.3		1.1		1.0
Allocated interest expense, net		—		2.8		—		19.0
Interest expense, net		10.7		5.1		27.4		12.9
Loss on mark-to-market derivative instruments		1.0		7.4		1.0		28.4
General and administrative and other expense		5.5		6.5		16.3		14.2

Operating margin	$	50.9	$	54.5	$	168.8	$	146.7

Forward-Looking Statements

Certain statements in this release are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside Targa Resources Partners’ control, which could cause results to differ materially from those expected by management of Targa Resources Partners. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including declines in the production of natural gas or in the price and market demand for natural gas and natural gas liquids, the timing and success of business development

efforts, the credit risk of customers and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Partnership’s reports and other filings with the Securities and Exchange Commission. Targa Resources Partners undertakes no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

Investor contact info:
Phone: 713-584-1133

Anthony Riley
Senior Manager — Finance/Investor Relations

Matt Meloy
Vice President — Finance and Treasurer

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED BALANCE SHEET DATA
(In thousands)


	September 30,		December 31,
	2008		2007
ASSETS
Current assets
Cash and cash equivalents	$	34,319	$	50,994
Assets from risk management activities		35,799		8,695
Other current assets		109,775		148,786

Total current assets		179,893		208,475


Property, plant and equipment, net		1,237,472		1,259,594
Long-term assets from risk management activities		22,091		3,040
Other assets		14,449		8,863

Total assets		1,453,905		1,479,972

LIABILITIES AND PARTNERS’ CAPITAL
Accounts payable and accrued liabilities	$	136,396	$	148,529
Liabilities from risk management activities		12,888		44,003

Total current liabilities		149,284		192,532


Long-term debt		640,000		626,300
Long term liabilities from risk management activities		27,780		43,109
Other long-term liabilities		5,181		3,825

Total liabilities		822,245		865,766
Partners’ capital		631,660		614,206

Total liabilities and partners’ capital	$	1,453,905	$	1,479,972

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
REVENUES	$	578,747		$	405,038		$	1,721,336		$	1,187,434

COSTS AND EXPENSES:
Product purchases		512,443			337,762			1,509,752			1,003,961
Operating expenses		15,402			12,736			42,673			36,683
Depreciation and amortization expense		18,566			17,984			55,235			53,641
General and administrative expense		5,367			6,574			16,283			14,560
Casualty loss		167			—			167			—
(Gain) loss on sale of assets		(13	)		17			(88	)		(298	)

Total costs and expenses		551,932			375,073			1,624,022			1,108,547

INCOME FROM OPERATIONS		26,815			29,965			97,314			78,887
Other income (expense):
Interest expense, net		(10,749	)		(7,865	)		(27,443	)		(31,899	)
Loss on mark-to-market derivative instruments		(991	)		(7,367	)		(991	)		(28,369	)
Other		17			12			53			17

Income before income taxes		15,092			14,745			68,933			18,636
Income tax expense		(400	)		(353	)		(1,100	)		(1,060	)

NET INCOME	$	14,692		$	14,392		$	67,833		$	17,576

Income attributable to:
Predecessor operations	$	—		$	10,523		$	—		$	7,514
General partner		294			77			5,524			201
Limited partners		14,398			3,792			62,309			9,861

	$	14,692		$	14,392		$	67,833		$	17,576

Net income per limited partner unit:
Basic	$	0.31		$	0.12		$	1.35		$	0.32

Diluted	$	0.31		$	0.12		$	1.35		$	0.32

Weighted average limited partner units outstanding:
Basic		46,154			30,848			46,153			30,848
Diluted		46,164			30,857			46,161			30,855

TARGA RESOURCES PARTNERS LP
FINANCIAL SUMMARY (unaudited)

CONSOLIDATED CASH FLOW INFORMATION
(In thousands)


	Nine Months Ended September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	67,833		$	17,576
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion		57,128			55,401
Deferred income tax expense		1,100			1,060
Risk management activities		(75,747	)		28,567
Gain on sale of assets		(88	)		(298	)
Changes in operating assets and liabilities		23,783			31,447

Net cash provided by operating activities		74,009			133,753

CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment		(28,563	)		(34,240	)
Other		(4,088	)		372

Net cash used in investing activities		(32,651	)		(33,868	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings under credit facility		87,500			342,500
Repayments on credit facility		(323,800	)		(48,000	)
Proceeds from issuance of senior notes		250,000			—
Repayment of affiliated indebtedness		—			(665,692	)
Proceeds from equity offerings		—			380,768
Distributions		(64,573	)		(15,943	)
General partner contributions		8			—
Costs incurred in connection with public offerings		(89	)		(3,313	)
Costs incurred in connection with financing arrangements		(7,079	)		(4,565	)
Deemed Parent distributions		—			(57,199	)

Net cash used in financing activities		(58,033	)		(71,444	)

Net change in cash and cash equivalents		(16,675	)		28,441
Cash and cash equivalents, beginning of period		50,994			—

Cash and cash equivalents, end of period	$	34,319		$	28,441

Targa Resources Partners (NGLS-PA) 8-KTarga Resources Partners LP Reports Third Quarter 2008 Financial Results