SEC Filing | Targa Resources Corp.

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e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended September 30, 2008
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission File Number 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		65-1295427 (I.R.S. Employer Identification No.)
1000 Louisiana, Suite 4300, Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

Registrant’s telephone number, including area code:

(713) 584-1000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No þ

There were 34,652,000 Common Units, 11,528,231 Subordinated Units and 942,455 General Partner Units outstanding as of November 1, 2008.


PART I — FINANCIAL INFORMATION
	Item 1.	Financial Statements	4
		Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007	4
		Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2007	5
		Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2008 and 2007	6
		Consolidated Statement of Changes in Partners’ Capital for the nine months ended September 30, 2008	7
		Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007	8
		Notes to Consolidated Financial Statements	9
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	29
	Item 4T.	Controls and Procedures	33
PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings	34
	Item 1A.	Risk Factors	34
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
	Item 3.	Defaults Upon Senior Securities	35
	Item 4.	Submission of Matters to a Vote of Security Holders	35
	Item 5.	Other Information	35
	Item 6.	Exhibits	36
SIGNATURES			37
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2

As generally used in the energy industry and in this Quarterly Report on Form 10-Q, the identified terms have the following meanings:


Bbl		Barrels
BBtu		Billion British thermal units, a measure of heating value
/d		Per day
Gal		Gallons
MBbl		Thousand barrels
MMBtu		Million British thermal units
MMcf		Million cubic feet
NGL(s)		Natural gas liquid(s)


Price Index
Definitions

IF-HSC		Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC		Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha		Inside FERC Gas Market Report, West Texas Waha
NY-HH		NYMEX, Henry Hub Natural Gas
NY-WTI		NYMEX, West Texas Intermediate Crude Oil
OPIS-MB		Oil Price Information Service, Mont Belvieu, Texas

As used in this Quarterly Report, unless the context otherwise requires, “we,” “us”, “our,” the “Partnership” and similar terms refer to Targa Resources Partners LP, together with its consolidated subsidiaries.

Cautionary Statement About Forward-Looking Statements

This Quarterly Report contains “forward-looking statements” as defined in Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this Quarterly Report are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our future financial position, business strategy, future capital and other expenditures, plans and objectives of management for future operations. You can typically identify forward-looking statements by the use of forward-looking words such as “may,” “potential,” “project,” “plan,” “believe,” “expect,” “anticipate,” “intend,” “estimate” or similar expressions or variations on such expressions. Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors, known and unknown, which could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties, many of which are beyond our control, include, but are not limited to:


	•	our ability to access the debt and equity markets, which will depend on general market conditions and the credit ratings for our debt obligations;

	•	the amount of collateral required to be posted from time to time in our transactions;

	•	our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks;

	•	the level of creditworthiness of counterparties to transactions;

	•	changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the gathering and processing industry;

	•	the timing and extent of changes in natural gas, NGL and commodity prices, interest rates and demand for our services;

	•	weather and other natural phenomena;


	•	industry changes, including the impact of consolidations and changes in competition;

	•	our ability to obtain necessary licenses, permits and other approvals;

	•	the level and success of crude oil and natural gas drilling around our assets, and our success in connecting natural gas supplies to our gathering and processing systems;

	•	our ability to grow through acquisitions or internal growth projects, and the successful integration and future performance of such assets;

	•	general economic, market and business conditions; and

	•	the risks described in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2007.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in this Quarterly Report and under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

Forward-looking statements contained in this Quarterly Report and all subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this cautionary statement.

PART I — FINANCIAL INFORMATION


Item 1.	*Financial Statements*

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2008			2007
	(Unaudited)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	34,319		$	50,994
Receivables from third parties		63,692			59,346
Receivables from affiliated companies		43,683			87,547
Inventory		2,033			1,624
Assets from risk management activities		35,799			8,695
Other current assets		367			269

Total current assets		179,893			208,475
Property, plant and equipment, at cost		1,466,901			1,433,955
Accumulated depreciation		(229,429	)		(174,361	)

Property, plant and equipment, net		1,237,472			1,259,594
Debt issue costs		12,172			6,588
Long-term assets from risk management activities		22,091			3,040
Other assets		2,277			2,275

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


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	9,599		$	5,693
Accrued liabilities		126,797			142,836
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
Deferred income taxes		1,659			559
Other long-term liabilities		3,522			3,266
Commitments and contingencies (Note 8)		—			—
Partners’ capital:
Common unitholders (34,652,000 and 34,636,000 units issued and outstanding at September 30, 2008 and December 31, 2007, respectively)		771,163			770,207
Subordinated unitholders (11,528,231 units issued and outstanding at September 30, 2008 and December 31, 2007)		(84,744	)		(84,999	)
General partner (942,455 and 942,128 units issued and outstanding at September 30, 2008 and December 31, 2007, respectively)		6,491			4,234
Accumulated other comprehensive loss		(61,250	)		(75,236	)

Total partners’ capital		631,660			614,206

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

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands, except per unit amounts)

Revenues from third parties	$	224,535		$	148,987		$	662,745		$	464,326
Revenues from affiliates		354,212			256,051			1,058,591			723,108

Total operating revenues		578,747			405,038			1,721,336			1,187,434
Costs and expenses:
Product purchases from third parties		412,664			299,492			1,267,179			864,111
Product purchases from affiliates		99,779			38,270			242,573			139,850
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	)

		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	)		(5,059	)		(27,443	)		(12,918	)
Interest expense allocated from Parent		—			(2,806	)		—			(18,981	)
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
Deferred income tax expense		(400	)		(353	)		(1,100	)		(1,060	)

Net income		14,692			14,392			67,833			17,576
Less: Net income allocable to predecessor operations		—			10,523			—			7,514

Net income allocable to partners		14,692			3,869			67,833			10,062
Net income attributable to general partner interests		294			77			5,524			201

Net income available to common and subordinated unitholders	$	14,398		$	3,792		$	62,309		$	9,861

Basic net income per common and subordinated unit	$	0.31		$	0.12		$	1.35		$	0.32

Diluted net income per common and subordinated unit	$	0.31		$	0.12		$	1.35		$	0.32

Basic average number of common and subordinated units outstanding		46,154			30,848			46,153			30,848
Diluted average number of common and subordinated units outstanding		46,164			30,857			46,161			30,855

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands)

Net income	$	14,692		$	14,392		$	67,833		$	17,576
Other comprehensive income (loss):
Commodity hedges:
Change in fair value of commodity hedges		185,017			(1,083	)		(35,219	)		(34,418	)
Reclassification adjustment for settled periods		19,985			(1,070	)		49,696			(6,070	)
Related income taxes		—			—			—			311
Interest rate hedges:
Change in fair value of interest rate hedges		(1,705	)		(102	)		(1,975	)		(633	)
Reclassification adjustment for settled periods		869			228			1,484			140

Other comprehensive income (loss)		204,166			(2,027	)		13,986			(40,670	)

Comprehensive income (loss)	$	218,858		$	12,365		$	81,819		$	(23,094	)

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL


	Accumulated
	Other			Partners’ Capital
	Comprehensive			Limited Partners						General
	Loss			Common			Subordinated			Partner			Total
	(Unaudited)
	(In thousands)

Balance as of December 31, 2007	$	(75,236	)	$	770,207		$	(84,999	)	$	4,234		$	614,206
Contributions		—			—			—			8			8
Amortization of equity awards		—			200			—			—			200
Other comprehensive income		13,986			—			—			—			13,986
Net income		—			46,751			15,558			5,524			67,833
Distributions		—			(45,995	)		(15,303	)		(3,275	)		(64,573	)

Balance as of September 30, 2008	$	(61,250	)	$	771,163		$	(84,744	)	$	6,491		$	631,660

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months
	Ended
	September 30,
	2008			2007
	(Unaudited)
	(In thousands)

Cash flows from operating activities
Net income	$	67,833		$	17,576
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense		1,495			1,375
Amortization in general and administrative expense		200			128
Other depreciation and amortization expense		55,235			53,641
Accretion of asset retirement obligations included in operating expenses		198			257
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:
Accounts receivable		39,518			20,040
Inventory		(409	)		(1,292	)
Other		(3,193	)		(4,086	)
Accounts payable		3,906			3,210
Accrued liabilities		(16,039	)		13,575

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

Supplemental cash flow information:
Net settlement of allocated indebtedness and debt issue costs	$	—		$	249,446
Net contribution of affiliated receivables		—			38,856

See notes to consolidated financial statements

Targa Resources Partners LP

Notes to Consolidated Financial Statements
(Unaudited)


Note 1 —	Organization and Operations

Targa Resources Partners LP (“we,” “us,” “our” or the “Partnership”) is a publicly traded Delaware limited partnership. Our common units are listed on The NASDAQ Stock Market LLC under the symbol “NGLS.” We were formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”), a leading provider of midstream natural gas and NGL services in the United States, to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling natural gas liquids (“NGLs”) and NGL products. We currently operate in the Fort Worth Basin/Bend Arch in North Texas (the “North Texas system”), the Permian Basin in West Texas (the “SAOU system”) and in Southwest Louisiana (the “LOU system”).


Note 2 —	Basis of Presentation

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. The unaudited consolidated financial statements for the three and nine months ended September 30, 2008 and 2007 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair statement of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Transactions between us and other Targa operations have been identified in the unaudited consolidated financial statements as transactions between affiliates (see Note 5). Our results of operations for the three and nine months ended September 30, 2007 were adjusted to reflect the consideration of common control accounting and change in predecessor entities as discussed in Notes 4 and 15 in our Annual Report on Form 10-K for the year ended December 31, 2007. Our financial results for the three and nine months ended September 30, 2008 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2008. These unaudited consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.


Note 3 —	Accounting Pronouncements

Accounting Pronouncements Recently Adopted.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements.” SFAS 157 establishes a framework for measuring fair value and expands disclosures about fair value measurements. The FASB partially deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We adopted SFAS 157 with respect to financial assets and liabilities that are recognized on a recurring basis on January 1, 2008. Although the adoption of SFAS 157 did not materially impact our financial condition, results of operations, or cash flows, we are now required to provide additional disclosures as part of our financial statements.

SFAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are either readily available in public markets or are quoted by counterparties to these contracts. In situations where we obtain inputs via quotes from our counterparties, we verify the reasonableness of these quotes via similar quotes from another source for each date for which financial statements are presented. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3. The price quotes for the Level 3 inputs are provided by a counterparty with whom we regularly transact business.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.


	Total		Level 1		Level 2		Level 3
	(In thousands)

Assets from commodity derivative contracts	$	57,663	$	—	$	18,086	$	39,577
Assets from interest rate derivative		227		—		227		—

Total assets	$	57,890	$	—	$	18,313	$	39,577

Liabilities from commodity derivative contracts	$	38,718	$	—	$	13,999	$	24,719
Liabilities from interest rate derivative		1,950		—		1,950		—

Total liabilities	$	40,668	$	—	$	15,949	$	24,719

The following table sets forth a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy:


	Commodity
	Derivative
	Contracts
	(In thousands)

Balance, December 31, 2007	$	(71,370	)
Total gains or losses (realized/unrealized) Included in loss on mark-to-market derivatives		(991	)
Included in OCI		(28,553	)
Purchases		2,866
Terminations		77,792
Settlements		35,114

Balance, September 30, 2008	$	14,858

No unrealized gains or losses were reported relating to assets and liabilities still held as of September 30, 2008.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115.” SFAS 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. Our adoption of SFAS 159 on January 1, 2008 did not have a material impact on our consolidated financial statements.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

Accounting Pronouncements Recently Issued

In March 2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus on EITF 07-4, “Application of the Two - Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” EITF 07-4 improves the comparability of earnings per unit calculations for master limited partnerships (“MLPs”) with incentive distribution rights (“IDRs”) in accordance with Statement 128 and its related interpretations. Under EITF 07-4, when an MLP’s current-period earnings are in excess of cash distributions and the IDRs are a separate limited partner interest, undistributed earnings should be allocated to the general partner, limited partners and IDR holder utilizing the contractual terms of the partnership agreement. The distribution formula for available cash specified in the partnership agreement contractually mandates the way in which earnings are distributed.

Additionally, EITF 07-4 requires an MLP to reflect its contractual obligation to make distributions as of the end of the current reporting period. Therefore, an MLP would reduce (increase) income (loss) from continuing operations (or net income or loss) for the current reporting period by the amount of available cash that has been or will be distributed to the general partner, limited partners, and IDR holder for that current reporting period. If distributions to the IDR holder are contractually limited to available cash as defined in the partnership agreement, then the specified threshold for the current reporting period would be the holder’s share of available cash that has been or will be distributed to the IDR holder for that current reporting period.

EITF 07-4 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted. Our adoption of EITF 07-4 will not impact our consolidated financial position, results of operations, cash flows or our computation of earnings per common and subordinated unit.

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133, “Derivative Instruments and Hedging Activities” and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early adoption is encouraged. Our adoption of SFAS 161 will not impact our consolidated financial position, results of operations or cash flows.


Note 4 —	Net Income per Limited Partner Unit and Distributions

Our net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner.

Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

These required disclosures do not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds the first target distribution level, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings is

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

allocated to the incentive distribution rights held by the general partner as if distributed, even though we make distributions on the basis of available cash and not earnings. In periods in which our aggregate net income does not exceed the first target distribution level, there is no impact on our calculation of earnings per limited partner unit. For the nine months ended September 30, 2008, our aggregate net income per limited partner unit was greater than the first target distribution level and, as a result, we allocated $4.2 million in additional earnings to the general partner. For the three and nine months ended September 30, 2007, our aggregate net income per limited partner unit was less than the first target distribution level, and as a result, there was no impact on our calculation of earnings per limited partner unit.

Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions as described above, by the weighted-average number of outstanding limited partner units during the period.

The following table shows the distributions we declared subsequent to the third quarter of 2008 and distributions declared and paid in the nine months ended September 30, 2008 and 2007:


		Distributions Paid/To Be Paid										Distributions
		Common		Subordinated		General Partner						per Limited
Date Declared	Date Paid or To Be Paid	Units		Units		Incentive		2%		Total		Partner Unit
		(In thousands, except per unit amounts)

October 24, 2008	November 14, 2008⁽¹⁾	$	17,932	$	5,966	$	1,932	$	527	$	26,357	$	0.51750
July 23, 2008	August 14, 2008		17,759		5,908		1,711		518		25,896		0.51250
April 23, 2008	May 15, 2008		14,467		4,813		208		398		19,886		0.41750
January 23, 2008	February 14, 2008		13,768		4,582		66		376		18,792		0.39750
October 24, 2007	November 14, 2007		11,082		3,891		—		305		15,278		0.33750
July 24, 2007	August 14, 2007		6,526		3,890		—		212		10,628		0.33750
April 23, 2007	May 15, 2007		3,263		1,945		—		107		5,315		0.16875


⁽¹⁾		Payable to unitholders of record on November 4, 2008, for the period from July 1, 2008 to September 30, 2008.

The following table illustrates our calculation of net income per common and subordinated unit for the three and nine months ended September 30, 2008 and 2007:


	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
	2008		2007		2008		2007
	(In thousands)
Net income	$	14,692	$	14,392	$	67,833	$	17,576
Less: Net income attributable to predecessor operations		—		10,523		—		7,514

Net income allocable to partners		14,692		3,869		67,833		10,062
Net income attributable to general partner interests		294		77		5,524		201

Net income available to common and subordinated unitholders	$	14,398	$	3,792	$	62,309	$	9,861

Basic net income per common and subordinated unit	$	0.31	$	0.12	$	1.35	$	0.32

Diluted net income per common and subordinated unit	$	0.31	$	0.12	$	1.35	$	0.32

Basic average number of common and subordinated units outstanding		46,154		30,848		46,153		30,848
Restrictive equivalents		10		9		8		7

Diluted average number of common and subordinated units outstanding		46,164		30,857		46,161		30,855

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)


Note 5 —	Related Party Transactions

Targa Resources, Inc.

We are a party to various agreements with Targa, our general partner and others that address (i) the reimbursement of costs incurred on our behalf by our general partner, (ii) our sales of certain NGLs and NGL products to, and purchases from, Targa; and (iii) our sales of our natural gas to, and purchases from, Targa.

The following table summarizes the sales to and purchases from affiliates of Targa, payments made or received by Targa on behalf of the Partnership and allocations of costs from Targa. Prior to the Partnership’s ownership of the North Texas, SAOU and LOU systems, these transactions were settled through adjustments to partners’ capital. Management believes these transactions are executed on terms that are fair and reasonable.


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands)

Sales to affiliates	$	354,212		$	256,051		$	1,058,591		$	723,108
Purchases from affiliates		99,779			38,270			242,573			139,850
Allocations of general & administrative expenses — pre IPO		—			3,795			—			8,952
Allocations of general & administrative expenses under Omnibus Agreement		4,105			2,779			12,203			5,608
Allocated interest		—			2,806			—			18,992
Receipts made by Parent on our behalf		—			226,091			—			460,070
Net change in affiliate receivable		(63,684	)		(18,264	)		(43,864	)		32,437

Centralized Cash Management

Prior to the contribution of the North Texas, SAOU and LOU systems to us, the excess cash from these subsidiaries was held in separate bank accounts and swept to a centralized account under Targa. Beginning with the contribution of these systems to the Partnership, their bank accounts have been maintained under the Partnership’s separate centralized cash management system.

For the North Texas system, prior to February 14, 2007, cash distributions are deemed to have occurred through partners’ capital and are reflected as an adjustment to partners’ capital. For the period from January 1, 2007 through February 13, 2007, deemed net capital distributions from the Partnership were $0.5 million.

For the SAOU and LOU systems, for the period from January 1, 2007 though September 30, 2007, deemed net capital distributions from the Partnership were $56.7 million.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

Other

Commodity hedges. An affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”) is an equity investor in the holding company that indirectly owns our general partner. We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. The following table shows our open commodity derivatives with MLCI as of September 30, 2008:

Period

Commodity

Instrument Type

Daily Volumes

Average Price

Index

Oct 2008 — Dec 2008

Natural gas

Swap

3,847

MMBtu

8.76

per MMBtu

IF-Waha

Oct 2008 — Dec 2008

Natural gas

Swap

879

MMBtu

7.50

per MMBtu

NY-HH

Jan 2009 — Dec 2009

Natural gas

Swap

3,556

MMBtu

8.07

per MMBtu

IF-Waha

Jan 2010 — Dec 2010

Natural gas

Swap

3,289

MMBtu

7.39

per MMBtu

IF-Waha

Apr 2010 — Jun 2010

Natural gas

Swap

330

MMBtu

8.25

per MMBtu

NY-HH

Oct 2008 — Dec 2008

NGL

Swap

3,175

Bbl

1.26

per gallon

OPIS-MB

Jan 2009 — Dec 2009

NGL

Swap

3,000

Bbl

1.18

per gallon

OPIS-MB

Oct 2008 — Dec 2008

Condensate

Swap

264

Bbl

72.66

per barrel

NY-WTI

Jan 2009 — Dec 2009

Condensate

Swap

202

Bbl

70.60

per barrel

NY-WTI

Jan 2010 — Dec 2010

Condensate

Swap

181

Bbl

69.28

per barrel

NY-WTI

As of September 30, 2008, the fair value of these open positions is a liability of $1.9 million. For the three and nine months ended September 30, 2008, we paid MLCI $6.6 million and $18.3 million to settle payments due under hedge transactions. For the three and nine months ended September 30, 2007, we paid MLCI $1.0 million and $2.8 million to settle commodity derivative transactions.


Note 6 —	Long-Term Debt

Our outstanding debt, including outstanding borrowings, issued letters of credit and available borrowings under our senior secured credit facility as of the dates shown below was:


	September 30,		December 31,
	2008		2007
	(In thousands)

Senior notes, 81/4% fixed rate, due July 1, 2016	$	250,000	$	—
Senior secured credit facility, variable rate, due February 14, 2012⁽¹⁾		390,000		626,300

Total long-term debt	$	640,000	$	626,300

Letters of credit issued	$	34,700	$	25,900

Available borrowings under credit facility⁽¹⁾	$	425,300	$	97,800


⁽¹⁾		In October 2008, Lehman Brothers Commercial Bank (“Lehman Bank”) a lender under our senior secured credit facility, defaulted on a borrowing request. As a result, we believe the availability under the senior secured credit facility has been effectively reduced by $9.5 million.

81/4% Senior Notes due 2016

On June 18, 2008, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 (“Rule 144A”) of $250 million in aggregate principal amount of 81/4% senior notes due 2016 (the “Notes”). Proceeds from the Notes were used to repay borrowings under our senior secured credit facility.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

The Notes:


	•	are our unsecured senior obligations;

	•	rank pari passu in right of payment with our existing and future senior indebtedness, including indebtedness under our senior secured credit facility;

	•	are senior in right of payment to any of our future subordinated indebtedness; and

	•	are unconditionally guaranteed by us.

The Notes are effectively subordinated to all secured indebtedness under our senior secured credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.

Interest on the Notes accrues at the rate of 81/4% per annum and is payable semi-annually in arrears on January 1 and July 1, commencing on January 1, 2009. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.

At any time prior to July 1, 2011, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes with the net cash proceeds of one or more equity offerings by us; at a redemption price of 108.25% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:

(1) at least 65% of the aggregate principal amount of the Notes (excluding Notes held by us) remains outstanding immediately after the occurrence of such redemption; and

(2) the redemption occurs within 90 days of the date of the closing of such equity offering.

At any time prior to July 1, 2012, we may also redeem all or a part of the Notes at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the applicable premium as defined in the indenture agreement as of, and accrued and unpaid interest and liquidated damages, if any, to the date of redemption.

On or after July 1, 2012, we may redeem all or a part of the Notes at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated damages, if any, on the Notes redeemed, if redeemed during the twelve-month period beginning on July 1 of each year indicated below:


Year	Percentage

2012		104.125	%
2013		102.063	%
2014 and thereafter		100.000	%

The Notes are subject to a registration rights agreement dated as of June 18, 2008. Under the registration rights agreement, we are required to file by June 19, 2009 a registration statement with respect to any Notes that are not freely transferable without volume restrictions by holders of the Notes that are not affiliates of the Partnership. If we fail to do so, additional interest will accrue on the principal amount of the Notes. Under EITF 00-19-2, “Accounting for Registration Payment Arrangements,” we have determined that the payment of additional interest is not probable, as that term is defined in SFAS 5, “Accounting for Contingencies.” As a result, we have not recorded a liability for any contingent obligation. Any subsequent accruals of a liability or payments made under this registration rights agreement will be charged to earnings as interest expense in the period they are recognized or paid.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

Senior Secured Credit Facility

Concurrent with the closing of the private placement of the 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 request additional commitments under our senior secured credit facility of up to $150 million, which would increase the total commitments under our senior secured credit facility to $1 billion. On October 16, 2008, we requested a $100 million funding under our senior secured credit facility. Lehman 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 default, we believe the availability under the senior secured credit facility has been effectively reduced by $9.5 million.

Our weighted average interest rate on outstanding borrowings under our senior secured credit facility for the nine months ended September 30, 2008 was 4.7%.


Note 7 —	Derivative Instruments and Hedging Activities

As of December 31, 2007, accumulated other comprehensive income (loss) (“OCI”) consisted of $74.0 million of unrealized net losses on commodity hedges and $1.2 million of unrealized net losses on interest rate hedges.

In May 2008 we entered into certain NGL derivative contracts with Lehman Brothers Commodity Services Inc., a subsidiary of Lehman Brothers Holdings Inc. (“Lehman”). Due to Lehman’s bankruptcy filing, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, we discontinued hedge accounting treatment for these contracts as of July 1, 2008. Deferred losses of $0.1 million and $0.3 million will be reclassified from OCI to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. During the three months ended September 30, 2008, we recognized a non-cash loss on mark-to-market derivatives of $1.0 million to adjust the fair value of the Lehman derivative contracts to zero. On October 22, 2008, we terminated the Lehman derivative contracts.

During July 2008, we paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, these swaps were designated as hedges in accordance with SFAS 133. Deferred losses of approximately $20.8 million, $38.2 million, and $27.9 million will be reclassified from OCI as a non-cash reduction of revenue during 2008, 2009 and 2010, when the hedged forecasted sales transactions are expected to occur. During the three months ended September 30, 2008, deferred losses of $9.3 million were reclassified from OCI as a non-cash reduction to revenue. 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.

For the three and nine months ended September 30, 2008, deferred net losses on commodity hedges of $20.0 million and $49.7 million were reclassified from OCI to revenues, and deferred losses on interest rate hedges of $0.9 million and $1.5 million were reclassified from OCI to interest expense. For the three and nine months ended September 30, 2007, deferred net gains on commodity hedges of $1.1 million and $6.1 million were reclassified from OCI to revenues, and deferred losses on interest rate hedges of $0.2 million and $0.1 million were reclassified from OCI to interest expense. There were no adjustments for hedge ineffectiveness.

As of September 30, 2008, OCI consisted of $59.6 million of deferred net losses on commodity hedges and $1.7 million of deferred net losses on interest rate hedges. Deferred net losses of $25.7 million on commodity hedges and $0.3 million on interest rate hedges recorded in OCI are expected to be reclassified to revenues from third parties and interest expense during the next twelve months.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

As of September 30, 2008, we had the following hedge arrangements which will settle during the years ending December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from October 1, 2008 through December 31, 2008):

Natural Gas


		Avg. Price		MMBtu per Day
Instrument Type	Index	$/MMBtu		2008		2009		2010		2011		2012		Fair Value
														(In thousands)

Natural Gas Purchases
Swap	NY-HH		8.69		1,300		—		—		—		—	$	(133	)

Total Purchases					1,300		—		—		—		—

Natural Gas Sales
Swap	IF-HSC		8.09		2,328		—		—		—		—		206
Swap	IF-HSC		7.39		—		1,966		—		—		—		(262	)

					2,328		1,966		—		—		—

Swap	IF-NGPL MC		8.86		6,964		—		—		—		—		2,613
Swap	IF-NGPL MC		9.18		—		6,256		—		—		—		4,515
Swap	IF-NGPL MC		8.86		—		—		5,685		—		—		2,061
Swap	IF-NGPL MC		7.34		—		—		—		2,750		—		(485	)
Swap	IF-NGPL MC		7.18		—		—		—		—		2,750		(539	)

					6,964		6,256		5,685		2,750		2,750

Swap	IF-Waha		8.91		7,389		—		—		—		—		2,330
Swap	IF-Waha		8.73		—		6,936		—		—		—		3,482
Swap	IF-Waha		7.52		—		—		5,709		—		—		(631	)
Swap	IF-Waha		7.36		—		—		—		3,250		—		(520	)
Swap	IF-Waha		7.18		—		—		—		—		3,250		(615	)

					7,389		6,936		5,709		3,250		3,250

Total Swaps					16,681		15,158		11,394		6,000		6,000

Floor	IF-NGPL MC		6.55		1,000		—		—		—		—		172
Floor	IF-NGPL MC		6.55		—		850		—		—		—		186

					1,000		850		—		—		—

Floor	IF-Waha		6.85		670		—		—		—		—		92
Floor	IF-Waha		6.55		—		565		—		—		—		111

					670		565		—		—		—

Total Floors					1,670		1,415		—		—		—

Total Sales					18,351		16,573		11,394		6,000		6,000

														$	12,583

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

NGLs


			Avg. Price		Barrels per Day
Instrument Type	Index		$/gal		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

NGL Sales
Swap		OPIS-MB		1.44		7,080		—		—		—		—	$	6,282
Swap		OPIS-MB		1.32		—		6,248		—		—		—		11,733
Swap		OPIS-MB		1.27		—		—		4,809		—		—		8,603
Swap		OPIS-MB		0.92		—		—		—		3,400		—		(8,470	)
Swap		OPIS-MB		0.92		—		—		—		—		2,700		(5,515	)

Total Swaps						7,080		6,248		4,809		3,400		2,700

Floor		OPIS-MB		1.44		—		—		—		199		—		978
Floor		OPIS-MB		1.43		—		—		—		—		231		1,247

Total Floors						—		—		—		199		231

Total Sales						7,080		6,248		4,809		3,599		2,931

															$	14,858

Condensate


			Avg. Price		Barrels per Day
Instrument Type	Index		$/Bbl		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

Condensate Sales
Swap		NY-WTI		70.68		384		—		—		—		—	$	(1,054	)
Swap		NY-WTI		69.00		—		322		—		—		—		(3,823	)
Swap		NY-WTI		68.10		—		—		301		—		—		(3,643	)

Total Swaps						384		322		301		—		—

Floor		NY-WTI		60.50		55		—		—		—		—		1
Floor		NY-WTI		60.00		—		50		—		—		—		24

Total Floors						55		50		—		—		—

Total Sales						439		372		301		—		—

															$	(8,495	)

These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

Customer Hedges

As of September 30, 2008, we had the following commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market through earnings:

Period

Commodity

Instrument Type

Daily Volume

Average Price

Index

Fair Value

(In thousands)

Purchases

Oct 2008 — Dec 2008

Natural gas

Swap

14,630 MMBtu

8.07 per MMBtu

NY-HH

(788)

Jan 2009 — Dec 2009

Natural gas

Swap

1,890 MMBtu

9.94 per MMBtu

NY-HH

(1,238)

Apr 2010 — Jun 2010

Natural gas

Swap

326 MMBtu

8.25 per MMBtu

NY-HH

(3)

Sales

Oct 2008 — Dec 2008

Natural gas

Fixed price sale

14,630 MMBtu

8.07 per MMBtu

NY-HH

788

Jan 2009 — Dec 2009

Natural gas

Fixed price sale

1,890 MMBtu

9.94 per MMBtu

NY-HH

1,238

Apr 2010 — Jun 2010

Natural gas

Fixed price sale

326 MMBtu

8.25 per MMBtu

NY-HH

(0)

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets.

Interest Rate Swaps

As of September 30, 2008, we had $390 million outstanding under our senior secured credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates we have entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:


				Notional
Expiration Date	Fixed Rate			Amount		Fair Value
						(In thousands)

01/24/2011		3.91	%	$	100 million	$	(1,334	)
01/24/2012		3.75	%		200 million		(389	)

						$	(1,723	)


Note 8 —	Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs are reasonably estimated in accordance with the American Institute of Certified Public Accountants Statement of Position 96-1, “Environmental Remediation Liabilities.” Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

This liability was transferred as part of the assets contributed to us at the time of our Initial Public Offering of common units (“IPO”).

Our environmental liability, primarily for ground water assessment and remediation, was less than $0.1 million as of September 30, 2008.

Litigation

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc., and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU system from ConocoPhillips, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal, and on May 6, 2008 filed its appellant’s brief with the 14th Court of Appeals in Houston, Texas. Targa filed its appellee’s brief on June 26, 2008 and WTG filed a reply on August 13, 2008. We are contesting the appeal, but can give no assurances regarding the outcome of the proceeding. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.


Note 9 —	Share-Based Compensation

Our general partner has adopted a long-term incentive plan (“the Plan”) for employees, consultants and directors of the general partner and its affiliates. We account for awards under the Plan utilizing the fair value recognition provisions of SFAS 123R, “Share-Based Payment.”

Non-Employee Director Grants

On March 25, 2008, our general partner made equity-based awards of 16,000 restricted common units of the Partnership (2,000 restricted common units in the Partnership to each of the Partnership’s non-management directors and to each of Targa Resources Investments Inc.’s independent directors) under the Plan. The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date.

Compensation expense on the restricted common units is recognized on a straight-line basis over the vesting period. The fair value of an award of restricted common units is measured on the grant date using the market price of a common unit on such date. For the three and nine months ended September 30, 2008, we recognized compensation expense of approximately $80,000 and $199,000 related to equity-based awards. For the three months ended September 30, 2007 and for the period of commencement of Partnership operations (February 14, 2007) through September 30, 2007, we recognized compensation expense of approximately $52,000 and $129,000 related to equity-based awards. We estimate that the remaining fair value of $320,000 will be recognized in expense over a weighted average period of approximately two years.


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Quarterly Report on Form 10-Q and in our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Overview

We are a Delaware limited partnership formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products. We currently operate in the Fort Worth Basin/Bend Arch in North Texas, the Permian Basin in West Texas and in Southwest Louisiana.

We are owned 98% by our limited partners and 2% by our general partner, Targa Resources GP LLC, an indirect, wholly-owned subsidiary of Targa. Our limited partner common units are publicly traded on The NASDAQ Stock Market LLC under the symbol “NGLS.”

Our Operations

We sell the majority of our processed natural gas, NGLs and high-pressure condensate to Targa at market-based rates pursuant to natural gas, NGL and condensate purchase agreements. Low-pressure condensate is sold to third parties. For a more complete description of these arrangements, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” and “Item 1. Business — Market Access” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Critical Accounting Policies and Estimates

There have been no significant changes to our critical accounting policies and estimates since December 31, 2007. For a more complete description of our critical accounting polices and estimates, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Accounting Pronouncements

On January 1, 2008, we adopted the provisions of SFAS 157. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report for information regarding fair value disclosures pertaining to our financial assets and liabilities.

The accounting standard-setting bodies have recently issued the following accounting guidelines that will or may affect our future financial statements:


	•	EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.”

	•	SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.”

For additional information regarding these recent accounting developments and others that may affect our future financial statements, see Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Results of Operations

The following table and discussion relate to the three and nine months ended September 30, 2008 and 2007 and is a summary of our results of operations for the periods then ended:


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In millions, except operating and price data)

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(1)	$	50.9		$	54.5		$	168.8		$	146.7
Adjusted EBITDA(2)		55.0			48.2			163.1			132.7
Distributable cash flow(3)		37.7			35.8			118.2			87.3
Operating data:
Gathering throughput, MMcf/d(4)		438.3			464.3			455.0			447.7
Plant natural gas inlet, MMcf/d(5)(6)		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(6)		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

NGL, $/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


(1)		Operating margin is revenues less product purchases and operating expense. See “Non-GAAP Financial Measures.”

(2)		Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash gain or loss related to derivative instruments. See “Non-GAAP Financial Measures.”


(3)		Distributable Cash Flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses on mark-to-market derivative contracts, less maintenance capital expenditures. See “Non-GAAP Financial Measures.”

(4)		Gathering throughput represents the volume of natural gas gathered and passed through natural gas gathering pipelines from connections to producing wells and central delivery points.

(5)		Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.

(6)		Plant inlet volumes include producer take-in-kind, while natural gas sales exclude producer take-in-kind volumes.

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Our operating margin decreased by $3.6 million, or 7%, to $50.9 million for the three months ended September 30, 2008 compared to $54.5 million for the three months ended September 30, 2007. Our operating margin for the three months ended September 30, 2008 was reduced by $2.2 million for estimated lost business as a result of Hurricanes Gustav and Ike.

Our revenues increased by $173.7 million, or 43%, to $578.7 million for the three months ended September 30, 2008 compared to $405.0 million for the three months ended September 30, 2007. The increase is primarily due to:


	•	An increase attributable to commodity prices of $182.8 million, comprising increases in natural gas, NGL and condensate revenues of $129.0 million, $45.0 million and $8.8 million;

	•	A decrease attributable to commodity sales volume of $8.8 million comprising decreases in natural gas, NGL and condensate revenues of $5.7 million, $0.3 million and $2.8 million;

	•	A decrease in other revenues of $0.3 million, primarily from miscellaneous processing activities.

Our average realized prices for natural gas increased by $3.46 per MMBtu (net of a $0.14 decrease related to hedge settlements), or 58%, to $9.42 per MMBtu for the three months ended September 30, 2008 compared to $5.96 per MMBtu for the three months ended September 30, 2007. Our average realized price for NGLs increased by $0.32 per gallon (net of a $0.09 decrease related to hedge settlements), or 31%, to $1.36 per gallon for the three months ended September 30, 2008 compared to $1.04 per gallon for the three months ended September 30, 2007. Our average realized price for condensate increased by $29.05 per barrel (net of a $5.28 decrease related to hedge settlements), or 42%, to $97.79 per barrel for the three months ended September 30, 2008 compared to $68.74 per barrel for the three months ended September 30, 2007.

Our natural gas sales volumes decreased by 10.4 BBtu/d, or 3%, to 404.4 BBtu/d for the three months ended September 30, 2008 compared to 414.8 BBtu/d for the three months ended September 30, 2007. Our natural gas sales for the three months ended September 30, 2008 decreased by 7.1 BBtu/d as a result of reductions in demand in the Lake Charles industrial market caused by Hurricanes Gustav and Ike. In addition, our inability to transport NGLs to market due to hurricane-related curtailments on third-party owned pipelines forced us to temporarily shutdown some of our West Texas natural gas processing plants, resulting in a 1.8 BBtu/d reduction in natural gas sales volumes for the three months ended September 30, 2008.

Our NGL sales volumes decreased by 0.1 MBbl/d, or less than 1.0%, to 37.4 MBbl/d for the three months ended September 30, 2008 compared to 37.5 MBbl/d for the three months ended September 30, 2007. In October 2007 our Gillis fractionation facility in Louisiana began fractionating and selling purchased third-party raw NGLs, which increased NGL sales by 2.2 MBbl/d for the three months ended September 30, 2008. Offsetting this increase was a 1.7 MBbl/d decrease due to the aforementioned hurricane-related curtailments on third-party owned pipelines.

Our product purchases increased by $174.6 million, or 52%, to $512.4 million for the three months ended September 30, 2008 compared to $337.8 million for the three months ended September 30, 2007. The increase in product purchase cost was due primarily to higher commodity prices in the three months ended

September 30, 2008 versus the three months ended September 30, 2007, partially offset by a volume decrease in gas purchases.

Our operating expenses increased by $2.7 million, or 21%, to $15.4 million for the three months ended September 30, 2008 compared to $12.7 million for the three months ended September 30, 2007. The increase in operating expenses was primarily the result of increases of $0.7 million in compensation related expenses, $0.8 million in gathering system maintenance, $0.5 million in lube oils and chemical expenses, $0.2 million in utilities and $0.5 million in other operating expenses.

Our general and administrative expenses decreased by $1.2 million, or 18%, to $5.3 million for the three months ended September 30, 2008 compared to $6.5 million for the three months ended September 30, 2007. The decrease consisted of a $0.5 million decrease in professional service fees and a $0.7 million decrease in the allocation of corporate level expenses. For additional information regarding our allocation of general and administrative costs, see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Our operating margin increased by $22.1 million, or 15%, to $168.8 million for the nine months ended September 30, 2008 compared to $146.7 million for the nine months ended September 30, 2007. Our operating margin for the nine months ended September 30, 2008 was reduced by approximately $2.2 million for estimated lost business as a result of Hurricanes Gustav and Ike.

Our revenues increased $533.9 million, or 45%, to $1,721.3 million for the nine months ended September 30, 2008 compared to $1,187.4 million for the nine months ended September 30, 2007. The increase is primarily due to:


	•	An increase attributable to commodity prices of $485.4 million, comprising increases in natural gas, NGL and condensate revenues of $293.0 million, $159.2 million and $33.2 million:

	•	An increase attributable to commodity sales volume of $44.3 million comprising increases in natural gas and NGL revenues of $16.6 million and $28.5 million, partially offset by a decrease in condensate revenues of $0.8 million.

	•	An increase in other revenue of $4.2 million, primarily from miscellaneous processing activities.

Our average realized prices for natural gas increased by $2.60 per MMBtu (net of a $0.10 decrease related to hedge settlements), or 39%, to $9.29 per MMBtu for the nine months ended September 30, 2008 compared to $6.69 per MMBtu for the nine months ended September 30, 2007. The average realized price for NGLs increased by $0.37 per gallon (net of a $0.09 decrease related to hedge settlements), or 39%, to $1.31 per gallon for the nine months ended September 30, 2008 compared to $0.94 per gallon for the nine months ended September 30, 2007. The average realized price for condensate increased by $33.87 per barrel (net of a $4.90 decrease related to hedge settlements), or 56%, to $94.74 per barrel for the nine months ended September 30, 2008 compared to $60.87 per barrel for the nine months ended September 30, 2007.

Our natural gas sales volumes increased by 7.6 BBtu/d, or 2%, to 410.9 BBtu/d for the nine months ended September 30, 2008 compared to 403.3 BBtu/d for the nine months ended September 30, 2007.

Our NGL sales volumes increased by 2.5 MBbl/d, or 7%, to 38.2 MBbl/d for the nine months ended September 30, 2008 compared to 35.7 MBbl/d for the nine months ended September 30, 2007. The increase was primarily due to processing and sales of third party raw NGL volumes.

Our product purchases increased by $505.8 million, or 50%, to $1,509.8 million for the nine months ended September 30, 2008 compared to $1,004.0 million for the nine months ended September 30, 2007. The increase in product purchases was due primarily to higher commodity prices, increased spot price purchases for industrial sales customers and changing contract mix in North Texas.

Our operating expenses increased by $6.0 million, or 16%, to $42.7 million for the nine months ended September 30, 2008 compared to $36.7 million for the nine months ended September 30, 2007. The increase

in operating expenses was primarily the result of increases of $2.0 million in compensation related expenses, $1.5 million in general maintenance and supplies, $0.9 million in lube oil, environmental, and automotive expenses, $0.7 million in utilities, $0.5 million in ad valorem taxes and $0.4 million in other operating expenses.

Our general and administrative and other expenses increased by $1.7 million, or 12%, to $16.2 million for the nine months ended September 30, 2008 compared to $14.5 million for the nine months ended September 30, 2007. The increase comprised $0.2 million in professional service fees, $0.3 million in insurance expenses, $1.0 million in allocated corporate level expenses and $0.2 million in other general and administrative expenses. For additional information regarding our allocation of general and administrative costs, see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Liquidity and Capital Resources

Our ability to finance our operations, including to fund capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements depends on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and our ongoing efforts to manage operating costs and maintenance capital expenditures as well as general economic, financial, competitive, legislative, regulatory and other factors.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a senior secured credit facility with both uncommitted and committed availability and access to both the debt and equity capital markets. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit crisis includes our revolving credit facility, cash investments and counterparty performance risks. Continued volatility in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. In order to increase our cash position in the face of the credit and capital market disruptions, on October 16, 2008, we requested a $100 million funding under our senior secured credit facility. Lehman Bank, a lender under our senior secured credit facility, defaulted on its portion of this borrowing request resulting in actual funding of $97.8 million. The proceeds from this borrowing request are currently available to us as cash deposits. As a result of the default, we believe the availability under our senior secured credit facility has been effectively reduced by $9.5 million.

Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. We have all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices. We sell a significant portion of our natural gas and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil and natural gas prices are also volatile and have declined significantly during the quarter, continuing downward since the end of the quarter. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity contracts for a portion of our estimated equity volumes through 2012 (see Note 7 — Derivative Instruments and Hedging Activities). The current market conditions may also impact our availability to enter into future commodity derivative contracts. In the event of a global recession commodity prices may stay depressed or reduce further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

At this point, we do not believe our liquidity has been materially affected by the current credit crisis and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the capital markets. Additionally, we will continue to monitor events and circumstances surrounding each of the other twenty three lenders under our senior secured credit facility. To date, other than the Lehman Bank default, we have experienced no disruptions in our ability to access funds committed under our senior secured credit facility. However, we cannot predict with any certainty the impact to us of any

further disruptions in the credit environment. See “Item 1A. Risk Factors” in this Quarterly Report and “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Historically, our cash generated from operations has been sufficient to finance our operating expenditures and fund most of our maintenance and expansion capital expenditures, with remaining amounts being distributed to Targa during its period of ownership and to our unitholders since Targa’s contribution of assets to us and our acquisition of assets from Targa.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, much of our long-term capital expenditure requirements and our minimum quarterly cash distributions for at least the next year.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 4 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

As of September 30, 2008, we had working capital of $30.6 million, including a net short-term asset for commodity and interest rate derivatives of $22.9 million. In accordance with SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” we record the fair value of all derivative instruments on the balance sheet. Our hedge agreements provide for monthly settlement (quarterly for interest rate swaps) based on the differential between the agreement price and published commodity price and interest rate indexes. Cash received from physical sales of commodities and cash paid for interest will be based on actual market prices and interest rates and will generally offset any gains or losses realized on the derivative instruments. Our derivative contracts do not have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. Excluding derivatives our working capital surplus was $7.7 million as of September 30, 2008. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2007.

Contractual Obligations. In June 2008, we issued $250 million aggregate principal amount of 81/4% Senior Notes due 2016 (the “Notes”). The proceeds from the offering were used to reduce outstanding indebtedness under our senior secured credit facility. The interest rate on the Notes is fixed at 8.25% with interest to be paid on January 1 and July 1 of each year and the Notes mature on July 1, 2016.

Available Credit. As of September 30, 2008, we had approximately $415.8 million in capacity available under our senior secured credit facility, after giving effect to outstanding borrowings of $390 million, the issuance of $34.7 million of letters of credit, and the default by Lehman Bank. Our senior secured credit facility allows us to request increases in the commitments under the facility by up to $150 million.

Capital Requirements. The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A portion of the cost of constructing new gathering lines to connect to our gathering system is paid for by the natural gas producer. However, we expect to continue to incur significant expenditures through the remainder of 2008 related to the expansion of our natural gas gathering and processing infrastructure.

We categorize our capital expenditures as either: (i) maintenance expenditures or (ii) expansion expenditures. Maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations. Expansion expenditures improve the service capability from existing levels, expand systems to new areas of supply or market, reduce costs or enhance revenues.


	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
	2008		2007		2008		2007
			(In millions)

Capital expenditures:
Expansion	$	3.5	$	4.5	$	9.6	$	17.8
Maintenance		7.2		4.9		19.0		14.9

	$	10.7	$	9.4	$	28.6	$	32.7

We estimate that our total capital expenditures for 2008 will be approximately $55 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that we will invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our senior secured credit facility, the issuance of additional partnership units and debt offerings.

Cash Flow. Net cash provided by or used in operating activities, investing activities and financing activities for the nine months ended September 30, 2008 and 2007 were as follows:


	Nine Months
	Ended
	September 30,
	2008			2007
	(In millions)

Net cash provided by operating activities	$	74.0		$	133.8
Net cash used in investing activities		(32.7	)		(33.9	)
Net cash used in financing activities		(58.0	)		(71.4	)

Operating Activities. Net cash provided by operating activities decreased by $59.8 million, or 45%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. This decrease is primarily attributable to our payment of $87.4 million in July 2008 to terminate certain out-of-the-money natural gas and commodity swaps offset by an increase in our net income, adjusted for other non-cash charges, as presented in the combined statements of cash flows.

Investing Activities. Net cash used in investing activities for the nine months ended September 30, 2008 decreased $1.2 million, or 4%, compared to the nine months ended September 30, 2007. Purchases of property, plant and equipment during the nine months ended September 30, 2008 decreased by $5.7 million versus the nine months ended September 30, 2007. This decrease was due to the timing of expansion capital projects. Other investing activities for the nine months ended September 30, 2008 included $4.3 million for our share of contractually obligated line fill on a third-party owned pipeline.

Financing Activities. Net cash used in financing activities decreased $13.4 million, or 19%, for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007. Net cash used in financing activities for the nine months ended September 30, 2008 is primarily associated with distributions to unitholders of $64.6 million and the repayment of $323.8 million on our senior secured credit facility, which was offset by the net proceeds of $250 million from our issuance of the Notes and additional borrowings on our senior secured credit facility of $87.5 million. The net cash used in financing activities for the nine months ended September 30, 2007 is primarily associated with the completion of our IPO, the establishment of our

senior secured credit facility, deemed parent contribution prior to the IPO and subsequent drop down of assets to us and the contribution of the North Texas System to us, which were offset by payments of debt, offering costs and debt issuance costs related to our senior secured credit facility.

Non-GAAP Financial Measures

For a complete discussion of the measures that management uses to evaluate our operations, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate our Operations” in our Annual Report on Form 10-K for the year ended December 31, 2007. The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the three and nine months ended September 30, 2008 and 2007:


	Three Months						Nine Months
	Ended						Ended
	September 30,						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(1)		—			2.4			—			17.6
Interest expense, net(1)		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

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

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(2)	$	50.9		$	54.5		$	168.8		$	146.7


(1)		Net of amortization of debt issue costs of $0.6 million and $1.5 million for the three and nine months ended September 30, 2008 and $0.4 million and $1.4 million for the three and nine months ended September 30, 2007.


(2)		Includes non-cash charges related to commodity hedges of $9.6 million and $10.6 million for the three and nine months ended September 30, 2008; and $0.1 million for each of the three and nine months ended September 30, 2007.


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2008			2007(1)			2008			2007(1)
	(In millions)

Reconciliation of “Distributable cash flow” to net income:
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


(1)		Distributable cash flow for the three and nine months ended September 30, 2007 reflects allocated interest from Parent of $2.8 million and $19.0 million.

Below is a reconciliation of net income (loss) as reported and distributable cash flow which excludes the results of operations of the North Texas System and the SAOU and LOU Systems prior to their ownership by the Partnership.


	For the Nine Months Ended September 30, 2007
				Pre-Acquisition						Post Acquisition
				SAOU-LOU			North Texas
				Jan 1, 2007 to			Jan 1, 2007 to
	TRP LP			Sep 30, 2007			Feb 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


Item 3.	*Quantitative and Qualitative Disclosures about Market Risk*

For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, (including the impact of reduced commodity prices on oil and gas drilling levels), changes in interest rates, as well as nonperformance by our customers. We do not use risk sensitive instruments for trading purposes.

Commodity Price Risk. A significant portion of our revenues is derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs, or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as

the cash flows from the item being hedged. For an in-depth discussion of our hedging strategies, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Our payment obligations in connection with substantially all of these hedging transactions, and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges, are secured by a first priority lien in the collateral securing our senior secured credit facility that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.

For the nine months ended September 30, 2008, our operating revenues were decreased by net hedge settlements of $49.7 million. During 2006 through 2008, we entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). As of September 30, 2008, we had the following open commodity derivative positions (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from October 1, 2008 through December 31, 2008):

Natural Gas


			Avg. Price		MMBtu per day
Instrument Type	Index		$/MMBtu		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

Natural Gas Purchases
Swap		NY-HH		8.69		1,300		—		—		—		—	$	(133	)

Total Purchases						1,300		—		—		—		—

Natural Gas Sales
Swap		IF-HSC		8.09		2,328		—		—		—		—		206
Swap		IF-HSC		7.39		—		1,966		—		—		—		(262	)

						2,328		1,966		—		—		—

Swap		IF-NGPL MC		8.86		6,964		—		—		—		—		2,613
Swap		IF-NGPL MC		9.18		—		6,256		—		—		—		4,515
Swap		IF-NGPL MC		8.86		—		—		5,685		—		—		2,061
Swap		IF-NGPL MC		7.34		—		—		—		2,750		—		(485	)
Swap		IF-NGPL MC		7.18		—		—		—		—		2,750		(539	)

						6,964		6,256		5,685		2,750		2,750

Swap		IF-Waha		8.91		7,389		—		—		—		—		2,330
Swap		IF-Waha		8.73		—		6,936		—		—		—		3,482
Swap		IF-Waha		7.52		—		—		5,709		—		—		(631	)
Swap		IF-Waha		7.36		—		—		—		3,250		—		(520	)
Swap		IF-Waha		7.18		—		—		—		—		3,250		(615	)

						7,389		6,936		5,709		3,250		3,250

Total Swaps						16,681		15,158		11,394		6,000		6,000

Floor		IF-NGPL MC		6.55		1,000		—		—		—		—		172
Floor		IF-NGPL MC		6.55		—		850		—		—		—		186

						1,000		850		—		—		—

Floor		IF-Waha		6.85		670		—		—		—		—		92
Floor		IF-Waha		6.55		—		565		—		—		—		111

						670		565		—		—		—

Total Floors						1,670		1,415		—		—		—

Total Sales						18,351		16,573		11,394		6,000		6,000

															$	12,583

NGLs


			Avg. Price		Barrels per day
Instrument Type	Index		$/gal		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

NGL Sales
Swap		OPIS-MB		1.44		7,080		—		—		—		—	$	6,282
Swap		OPIS-MB		1.32		—		6,248		—		—		—		11,733
Swap		OPIS-MB		1.27		—		—		4,809		—		—		8,603
Swap		OPIS-MB		0.92		—		—		—		3,400		—		(8,470	)
Swap		OPIS-MB		0.92		—		—		—		—		2,700		(5,515	)

Total Swaps						7,080		6,248		4,809		3,400		2,700

Floor		OPIS-MB		1.44		—		—		—		199		—		978
Floor		OPIS-MB		1.43		—		—		—		—		231		1,247

Total Floors						—		—		—		199		231

Total Sales						7,080		6,248		4,809		3,599		2,931

															$	14,858

Condensate


			Avg. Price		Barrels per day
Instrument Type	Index		$/Bbl		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

Condensate Sales
Swap		NY-WTI		70.68		384		—		—		—		—	$	(1,054	)
Swap		NY-WTI		69.00		—		322		—		—		—		(3,823	)
Swap		NY-WTI		68.10		—		—		301		—		—		(3,643	)

Total Swaps						384		322		301		—		—

Floor		NY-WTI		60.50		55		—		—		—		—		1
Floor		NY-WTI		60.00		—		50		—		—		—		24

Total Floors						55		50		—		—		—

Total Sales						439		372		301		—		—

															$	(8,495	)

Customer Hedges

Period

Commodity

Instrument Type

Daily Volume

Average Price

Index

Fair Value

(In thousands)

Purchases

Oct 2008 — Dec 2008

Natural gas

Swap

14,630 MMBtu

8.07 per MMBtu

NY-HH

(788

)

Jan 2009 — Dec 2009

Natural gas

Swap

1,890 MMBtu

9.94 per MMBtu

NY-HH

(1,238

)

Apr 2010 — Jun 2010

Natural gas

Swap

326 MMBtu

8.25 per MMBtu

NY-HH

)

Sales

Oct 2008 — Dec 2008

Natural gas

Fixed price sale

14,630 MMBtu

8.07 per MMBtu

NY-HH

788

Jan 2009 — Dec 2009

Natural gas

Fixed price sale

1,890 MMBtu

9.94 per MMBtu

NY-HH

1,238

Apr 2010 — Jun 2010

Natural gas

Fixed price sale

326 MMBtu

8.25 per MMBtu

NY-HH

)

Interest Rate Risk

As of September 30, 2008, we had $390 million outstanding under our senior secured credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates we have entered into interest rate swaps and basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:


				Notional
Expiration Date	Fixed Rate			Amount		Fair Value
						(In thousands)

01/24/2011		3.91	%	$	100 million	$	(1,334	)
01/24/2012		3.75	%		200 million		(389	)

						$	(1,723	)

We have designated all interest rate swaps and interest rate basis swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the swaps are deferred in OCI until interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account our interest rate swaps and interest rate basis swaps, would increase our annual interest expense by $0.9 million.

Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We operate under the Targa credit policy and closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with this credit policy. In addition to third party contracts, we have entered into several agreements with Targa. For example, we are party to natural gas, NGL and condensate purchase agreements pursuant to which Targa purchases the majority of our natural gas, NGLs and high-pressure condensate. In addition, we are also a party to an omnibus agreement with Targa which addresses, among other things, the provision of general and administrative and operating services to us. Any material nonperformance under the omnibus and purchase agreements by Targa could materially and adversely impact our ability to operate and make distributions to our unitholders.


Item 4T.	*Controls and Procedures*

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective at a reasonable assurance level to provide reasonable assurance that all material information relating to us required to be included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.

There has been no change in our internal control over financial reporting during the three months ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION


Item 1.	*Legal Proceedings*

The information required for this item is provided in Note 8, Commitments and Contingencies, under the heading “Litigation” included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which is incorporated by reference into this item.


Item 1A.	*Risk Factors*

For an in-depth discussion of our risk factors, see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations, as could the following:

We may not be able to obtain funding or obtain funding on acceptable terms because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

In addition, Lehman Bank recently defaulted on a borrowing request under our senior secured credit facility which effectively reduced our total commitments under this facility by $9.5 million. As a result, we can provide no assurance that other lending counterparties will be willing or able to meet their existing funding obligations under our senior secured credit facility.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to grow our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on our revenues and results of operations.

Our substantial amount of indebtedness could adversely affect our financial position.

We currently have a substantial amount of indebtedness. As of September 30, 2008 we had approximately $640 million of total indebtedness outstanding, approximately $34.7 million of letters of credit outstanding and approximately $425.3 million of additional borrowing capacity under our senior secured credit facility. In October 2008, one of the lenders under our senior secured credit facility, Lehman Bank, defaulted on a borrowing request. As a result, the total commitments under the facility have been effectively reduced by $9.5 million. Our senior secured credit facility allows us to request increases in the commitments under the facility of up to $150 million. We may also incur additional indebtedness in the future.

Our substantial indebtedness may:


	•	make it difficult for us to satisfy our financial obligations, including making scheduled principal and interest payments on our indebtedness;

	•	limit our ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes;

	•	limit our ability to use our cash flow or obtain additional financing for future working capital, capital expenditures, acquisitions or other general business purposes;

	•	require us to use a substantial portion of our cash flow from operations to make debt service payments;

	•	limit our flexibility to plan for, or react to, changes in our business and industry;

	•	place us at a competitive disadvantage compared to our less leveraged competitors; and

	•	increase our vulnerability to the impact of adverse economic and industry conditions.

We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit agreement or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness at or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.


Item 2.	*Unregistered Sales of Equity Securities and Use of Proceeds*

Not applicable.


Item 3.	*Defaults Upon Senior Securities*

Not applicable.


Item 4.	*Submission of Matters to a Vote of Security Holders*

Not applicable.


Item 5.	*Other Information*

Not applicable.


Item 6.	*Exhibits*


Exhibit
Number			Description

	3	.1	Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
	3	.2	Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
	3	.3	Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
	3	.4	First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
	3	.5	Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
	3	.6	Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
	31	.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
	31	.2*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
	32	.1*	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2*	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith

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
(Registrant)

By: Targa Resources GP LLC,

its general partner


	By:	/s/ John Robert Sparger

John Robert Sparger

Senior Vice President and Chief Accounting Officer

(Authorized signatory and Principal Accounting Officer)

Date: November 12, 2008

Exhibit Index


Exhibit
Number			Description

	3	.1	Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
	3	.2	Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
	3	.3	Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
	3	.4	First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
	3	.5	Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
	3	.6	Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
	31	.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
	31	.2*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
	32	.1*	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2*	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith

exv31w1

Exhibit 31.1

Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002

I, Rene R. Joyce, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2008 of Targa Resources Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	By:	/s/ Rene R. Joyce

Name: Rene R. Joyce


	Title:	Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

Date: November 12, 2008

exv31w2

Exhibit 31.2

Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002

I, Jeffrey J. McParland, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2008 of Targa Resources Partners LP;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	By:	/s/ Jeffrey J. McParland

Name: Jeffrey J. McParland


	Title:	Executive Vice President and Chief Financial Officer

of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Financial Officer)

Date: November 12, 2008

exv32w1

Exhibit 32.1

CERTIFICATION OF CEO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2008 of Targa Resources Partners LP (the “Partnership”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Rene R. Joyce, as Chief Executive Officer of Targa Resources GP LLC, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.


	By:	/s/ Rene R. Joyce

Name: Rene R. Joyce


	Title:	Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

Date: November 12, 2008

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

exv32w2

Exhibit 32.2

CERTIFICATION OF CFO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2008 of Targa Resources Partners LP (the “Partnership”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Jeffrey J. McParland, as Chief Financial Officer of Targa Resources GP LLC, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.


	By:	/s/ Jeffrey J. McParland

Name: Jeffrey J. McParland


	Title:	Executive Vice President and Chief Financial Officer

of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Financial Officer)

Date: November 12, 2008

Large accelerated filer o

Accelerated filer o

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Smaller reporting company o

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