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, 2010


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		65-1295427
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1000 Louisiana, Suite 4300, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 584-1000
(Registrant’s telephone number, including area code)

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.

þ Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

o Yes o No

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.


Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes þ No

As of November 1, 2010, there were 75,545,409 Common Units and 1,541,744 General Partner Units outstanding.


PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.			5

Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009			5

Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009			6

Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2010 and 2009			7

Consolidated Statement of Changes in Owners’ Equity for the nine months ended September 30, 2010 and 2009			8

Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009			9

Notes to Consolidated Financial Statements			10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.			32

Item 3. Quantitative and Qualitative Disclosures About Market Risk.			49

Item 4. Controls and Procedures.			53

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.			54

Item 1A. Risk Factors.			54

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.			56

Item 3. Defaults Upon Senior Securities.			57

Item 4. (Removed and Reserved).			57

Item 5. Other Information.			57

Item 6. Exhibits.			57

SIGNATURES

Signatures			59
EX-4.3
EX-4.4
EX-4.5
EX-4.6
EX-4.7
EX-4.8
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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


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

Price Index Definitions

IF-NGPL MC		Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha		Inside FERC Gas Market Report, West Texas Waha
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

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” as well as the following:

	•		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;

	•		the timing and extent of changes in natural gas, natural gas liquids and other 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 and NGL supplies to our logistics and marketing facilities;

	•		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, our Annual Report on Form 10-K for the year ended December 31, 2009 (the “Annual Report”) and our Current Report on Form 8-K filed on August 9, 2010 (“the Update 8-K”).

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 “Item 1A. Risk Factors” in this Quarterly Report, our Annual Report and the Update 8-K. 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.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2010			2009
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	54.5		$	90.9
Trade receivables, net of allowances of $7.6 million and $7.9 million		351.0			405.5
Inventory		54.9			39.3
Assets from risk management activities		37.9			32.9
Other current assets		1.0			1.9

Total current assets		499.3			570.5

Property, plant and equipment, at cost		3,236.6			3,155.5
Accumulated depreciation		(756.6	)		(628.9	)

Property, plant and equipment, net		2,480.0			2,526.6
Long-term assets from risk management activities		27.5			13.9
Investment in unconsolidated affiliate		17.4			18.5
Other long-term assets		38.8			23.3

Total assets	$	3,063.0		$	3,152.8


LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable to third parties	$	161.4		$	193.1
Accounts payable to affiliates		11.8			20.2
Accrued liabilities		247.7			261.5
Liabilities from risk management activities		20.5			29.2

Total current liabilities		441.4			504.0

Long-term debt payable to third parties		1,433.2			908.4
Long-term debt allocated from Targa Resources, Inc.		—			151.8
Long-term debt payable to Targa Resources, Inc.		—			764.8
Long-term liabilities from risk management activities		29.0			43.9
Deferred income taxes		9.1			5.8
Other long-term liabilities		47.4			45.8

Commitments and contingencies (see Note 14)

Owners’ equity:
Common unitholders (75,545,409 and 61,639,846 units issued and outstanding as of September 30, 2010 and December 31, 2009)		965.1			850.6
General partner (1,541,744 and 1,257,957 units issued and outstanding as of September 30, 2010 and December 31, 2009)		14.6			10.1
Net parent investment		—			(218.0	)
Accumulated other comprehensive loss		(1.0	)		(37.8	)

		978.7			604.9
Noncontrolling interests in subsidiaries		124.2			123.4

Total owners’ equity		1,102.9			728.3

Total liabilities and owners’ equity	$	3,063.0		$	3,152.8

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Unaudited)
	(In millions)
Revenues	$	1,216.9		$	1,118.0		$	3,938.3		$	3,120.6
Product purchases		1,032.1			936.2			3,387.7			2,624.6
Operating expenses		66.0			63.2			190.2			182.1
Depreciation and amortization expenses		43.3			43.1			128.3			125.0
General and administrative expenses		26.7			22.6			80.0			81.9
Casualty loss adjustment		—			—			—			(3.8	)

Income from operations		48.8			52.9			152.1			110.8
Other income (expense):
Interest expense from affiliate		(2.5	)		(27.2	)		(23.8	)		(84.2	)
Interest expense allocated from Parent		(1.4	)		(2.2	)		(5.6	)		(6.9	)
Other interest expense, net		(23.3	)		(16.1	)		(56.4	)		(35.2	)
Equity in earnings of unconsolidated investments		1.1			1.4			3.8			3.2
Gain (loss) on mark-to-market derivative instruments		(1.9	)		(6.7	)		26.0			(12.1	)
Other		(0.7	)		(0.9	)		(0.8	)		(0.3	)

		(28.7	)		(51.7	)		(56.8	)		(135.5	)

Income (loss) before income taxes		20.1			1.2			95.3			(24.7	)
Income tax benefit (expense):
Current		(1.8	)		0.3			(3.6	)		—
Deferred		0.1			(0.1	)		(0.3	)		(0.9	)

		(1.7	)		0.2			(3.9	)		(0.9	)

Net income (loss)		18.4			1.4			91.4			(25.6	)
Less: Net income attributable to noncontrolling interests		4.6			5.6			18.2			11.9

Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)


Net income (loss) attributable to predecessor operations	$	(1.3	)	$	(18.4	)	$	25.8		$	(53.4	)
Net income (loss) attributable to general partner		5.0			2.8			12.0			6.7
Net income allocable to limited partners		10.1			11.4			35.4			9.2

Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)


Net income per limited partner unit — basic and diluted	$	0.14		$	0.23		$	0.51		$	0.19

Weighted average limited partner units outstanding — basic and diluted		72.0			50.6			69.2			47.7

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(Unaudited)
	(In millions)
Net income (loss)	$	18.4		$	1.4		$	91.4		$	(25.6	)
Other comprehensive income (loss):
Commodity hedges:
Change in fair value		(1.2	)		(9.8	)		58.8			(30.7	)
Settlements reclassified to Revenue		(7.1	)		(17.0	)		(7.0	)		(36.9	)
Interest rate hedges:
Change in fair value		(6.7	)		(7.5	)		(23.5	)		(3.0	)
Settlements reclassified to Interest		3.5			2.7			8.5			7.8
Foreign currency translation adjustment		—			(0.5	)		—			—

Other comprehensive income (loss)		(11.5	)		(32.1	)		36.8			(62.8	)

Comprehensive income (loss)		6.9			(30.7	)		128.2			(88.4	)

Less: Comprehensive income attributable to noncontrolling interests		4.7			5.6			18.2			11.9

Comprehensive income (loss) attributable to Targa Resources Partners LP	$	2.2		$	(36.3	)	$	110.0		$	(100.3	)

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENT OF CHANGES IN OWNERS’ EQUITY


							Accumulated
							Other			Net
	Limited			General			Comprehensive			Parent			Noncontrolling
	Partners			Partner			Income (Loss)			Investment			Interest			Total
	(Unaudited)
	(In millions)
Balance, December 31, 2009	$	850.6		$	10.1		$	(37.8	)	$	(218.0	)	$	123.4		$	728.3
Issuance of common units:
Equity offerings		317.8			6.8			—			—			—			324.6
Distributions to Parent		—			—			—			(102.5	)		—			(102.5	)
Affiliate debt contributed at conveyance dates		—			—			—			205.8			—			205.8
Distributions under common control		(132.7	)		(2.8	)		—			88.9			—			(46.6	)
Distributions to noncontrolling interests		—			—			—			—			(17.4	)		(17.4	)
Amortization of equity awards		0.3			—			—			—			—			0.3
Other comprehensive income		—			—			36.8			—			—			36.8
Net income		35.4			12.0			—			25.8			18.2			91.4
Distributions to unitholders		(106.3	)		(11.5	)		—			—			—			(117.8	)

Balance, September 30, 2010	$	965.1		$	14.6		$	(1.0	)	$	—		$	124.2		$	1,102.9

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	September 30,
	2010			2009
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income (loss)	$	91.4		$	(25.6	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Amortization in interest expense		3.6			3.8
Amortization in general and administrative expense		0.3			0.2
Depreciation and amortization expense		128.3			125.0
Interest expense on affiliate indebtedness		29.4			91.1
Accretion of asset retirement obligations		2.4			2.2
Deferred income tax expense		0.3			0.9
Equity in earnings of unconsolidated investment, net of distributions		1.1			0.7
Risk management activities		(5.4	)		71.2
Loss on extinguishment		0.8			0.4
Loss on sale of assets		—			0.3
Changes in operating assets and liabilities:
Receivables and other assets		56.3			(1.0	)
Inventory		(16.0	)		18.6
Accounts payable and other liabilities		(52.5	)		15.8

Net cash provided by operating activities		240.0			303.6

Cash flows from investing activities
Outlays for property, plant and equipment		(82.5	)		(72.0	)
Other, net		2.1			(2.0	)

Net cash used in investing activities		(80.4	)		(74.0	)

Cash flows from financing activities
Proceeds from borrowings under credit facility		1,178.1			397.6
Repayments of credit facility		(904.0	)		(374.9	)
Proceeds from issuance of senior notes		250.0			237.4
Repayment of affiliated indebtedness		(582.8	)		(397.4	)
Repayment of allocated indebtedness		(157.4	)		—
Repurchases of senior notes		—			(18.9	)
Parent distributions		(102.5	)		(137.5	)
Proceeds from equity offerings		317.8			103.5
Costs incurred in connection with financing arrangements		(20.2	)		(9.8	)
General partner contributions		6.8			2.2
Distributions to unitholders		(117.8	)		(79.0	)
Distributions under common control		(46.6	)		—
Distributions to noncontrolling interests		(17.4	)		(19.2	)

Net cash used in financing activities		(196.0	)		(296.0	)

Net change in cash and cash equivalents		(36.4	)		(66.4	)
Cash and cash equivalents, beginning of period		90.9			143.2

Cash and cash equivalents, end of period	$	54.5		$	76.8

See notes to consolidated financial statements

Targa Resources Partners LP

Notes to Consolidated Financial Statements
(Unaudited)

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in millions of dollars.

Note 1 — Organization and Operations

Targa Resources Partners LP is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis.

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”). We report our results of operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments — (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two segments — (a) Logistics Assets and (b) Marketing and Distribution.

Our gathering and processing assets are located in the Fort Worth Basin/Bend Arch in North Texas, the Permian Basin in West Texas and New Mexico and the onshore and offshore coastal regions of Louisiana.

Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the U.S. See Note 18.

Targa Resources GP LLC is a Delaware single-member limited liability company formed in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa. As of September 30, 2010, Targa and its subsidiaries own a 17.1% interest in the Partnership in the form of 1,541,744 general partner units and 11,645,659 common units.

We acquired from Targa its ownership interests in the following operations on the dates indicated:

	•		February 14, 2007 — North Texas System

	•		October 24, 2007 — San Angelo (“SAOU”) System and Louisiana (“LOU”) System

	•		September 24, 2009 — Downstream Business

	•		April 27, 2010 — Permian and Straddle Systems

	•		August 25, 2010 — Versado System (See Note 5)

	•		September 28, 2010 — Venice Operations (See Note 5)

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions collectively as our “predecessors.”

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements 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. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. The unaudited consolidated financial statements for the three and nine months ended September 30, 2010 and 2009 include all adjustments and disclosures which we believe are necessary for a fair presentation of the results for the interim periods.

We are required by GAAP to record the acquisitions described in Note 1 based on Targa historical amounts, assuming that the acquisitions occurred at the date they qualified as entities under common control (October 31, 2005) following the acquisition of the SAOU and LOU System. We recognize the difference between our acquisition cost and the Targa basis in the net assets as an adjustment to owners’ equity. We have retrospectively adjusted the financial statements, footnotes and other financial information presented for any period affected by common control accounting to reflect the results of the combined entities.

We have prepared the separate financial results of our predecessors from the records maintained by Targa and eliminated all significant intercompany transactions. We have included allocations of corporate general and administrative expense, interest expense and the financial effects of certain commodity derivative contracts. Transactions with Targa have been identified in the consolidated financial statements as transactions among affiliates. The consolidated financial results of our predecessors may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as unaffiliated entities.

Our financial results for the nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2010. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Current Report on Form 8-K ( the “Recast 8-K”) dated August 9, 2010, which updated our financial statements included in the Annual Report to account for our acquisitions from Targa of the Permian and Straddle Systems as transfers of assets under common control.

Note 3 —Out of Period Adjustment

During 2009, we recorded an adjustment related to prior periods which increased our income before income taxes for the three and nine months ended September 30, 2009 by $1.8 million. The adjustment related to natural gas sales transactions which occurred during 2006. After evaluating the quantitative and qualitative aspects of the error, we concluded that our previously issued financial statements were not materially misstated and the effect of recognizing this adjustment in the 2009 financial statements was not material to the 2009 results of operations, financial position, or cash flows.

Note 4 —Accounting Policies and Related Matters

Accounting Policy Updates/Revisions

The accounting policies followed by us are set forth in Note 4 of the Notes to the Supplemental Consolidated Financial Statements in the Recast 8-K, and are supplemented by the notes to these consolidated financial statements. There have been no significant changes to these policies.

Accounting Pronouncements Recently Adopted

In January 2010, the FASB issued ASU 2010-06, “Improving Disclosures About Fair Value Measurements,” which provides amendments to fair value disclosures. ASU 2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. We adopted the revised guidance for transfers into and out of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, on January 1, 2010. The amendments to Level 3 disclosures were delayed until periods beginning after December 15, 2010 and are not anticipated to have a material impact on our financial statements upon adoption.

Note 5 —Acquisitions under Common Control

On September 24, 2009, we acquired Targa’s Downstream Business for $530.0 million, effective September 1, 2009. The consideration consisted of $397.4 million in cash and $132.6 million in partnership interests represented by 174,033 general partner units and 8,527,615 common units. This consideration was used to repay $530.0 million of affiliated indebtedness. Targa contributed the remaining $287.3 million of affiliated indebtedness as a capital contribution.

On April 27, 2010, we acquired Targa’s interests in its Permian and Straddle Systems for $420.0 million, effective April 1, 2010. We financed this acquisition substantially through borrowings under our senior secured revolving credit facility. The total consideration was used to repay outstanding affiliated indebtedness of $332.8 million, with the remaining $87.2 million of consideration reported as a parent distribution.

On August 25, 2010, we acquired Targa’s 63% equity interest in the Versado System, effective August 1, 2010, for $247.2 million in the form of $244.7 million in cash and $2.5 million in partnership interests represented by 89,813 common units and 1,833 general partner units. This consideration was used to repay $247.2 million of affiliated indebtedness. Targa contributed the remaining $205.8 million of affiliate indebtedness as a capital contribution. Under the terms of the Versado acquisition Purchase and Sale Agreement, Targa will reimburse us future maintenance capital expenditures required pursuant to our New Mexico Environmental Department settlement agreement, of which our share is currently estimated at $19 million, to be incurred through 2011.

On September 28, 2010, we acquired Targa’s Venice Operations, which includes Targa’s 76.8% interest in Venice Energy Services, L.L.C. (“VESCO”), for aggregate consideration of $175.6 million, effective September 1, 2010. This consideration was used to repay $160.2 million of affiliate indebtedness, with the remaining $15.4 million of consideration reported as a parent distribution.

These acquisitions have been accounted for as acquisitions under common control, resulting in the retrospective adjustment of our prior results similar to a pooling of interests. The following tables present the impact of combining the Versado System and Venice Operations on our previously reported consolidated financial position and consolidated results of operations for the dates and periods indicated.

The previously reported amounts, included in the table column labeled “Historical Targa Resources Partners LP,” already incorporate the acquisitions of the Downstream Business and the Permian and Straddle Systems, as well as all prior Targa acquisitions.


	December 31, 2009
	Historical
	Targa												Targa
	Resources			Versado			Venice						Resources
	Partners LP			System			Operations			Eliminations			Partners LP
Current assets	$	517.1		$	64.2		$	26.9		$	(37.7	)	$	570.5

Property, plant and equipment, net		1,983.6			334.8			208.2			—			2,526.6

Other assets		50.0			4.2			1.5			—			55.7


Total assets	$	2,550.7		$	403.2		$	236.6		$	(37.7	)	$	3,152.8


Current liabilities	$	470.9		$	38.7		$	32.1		$	(37.7	)	$	504.0

Long-term debt		1,235.4			435.0			154.6			—			1,825.0

Other long-term liabilities		59.7			11.6			24.1			0.1			95.5

Owners of Targa Resources Partners LP		822.9			—			—			—			822.9

Net parent investment		(51.5	)		(153.9	)		(12.6	)		—			(218.0	)

Noncontrolling interest in subsidiary		13.3			71.8			38.4			—			123.4


Total owners’ equity		784.7			(82.1	)		25.8			—	)		728.3


Total liabilities and owners’ equity	$	2,550.7		$	403.2		$	236.6		$	(37.7	)	$	3,152.8


	Three Months Ended September 30, 2009
	Historical			Permian
	Targa			and												Targa
	Resources			Straddle			Versado			Venice						Resources
	Partners LP			Systems			System			Operations			Eliminations			Partners LP
Revenues	$	1,003.8		$	263.1		$	72.3		$	42.4		$	(263.6	)	$	1,118.0

Costs and expenses:

Product purchases		874.2			239.6			48.6			30.6			(256.8	)		936.2

Operating expenses		47.6			9.7			8.2			4.5			(6.8	)		63.2

Depreciation and amortization expense		25.6			7.2			7.2			3.1			—			43.1

General and administrative expense and other		17.1			1.2			(1.2	)		5.5			—			22.6


		964.5			257.7			62.8			43.7			(263.6	)		1,065.1


Income (loss) from operations		39.3			5.4			9.5			(1.3	)		—			52.9

Other income (expense):

Interest expense		(29.8	)		(5.7	)		(7.7	)		(2.3	)		—			(45.5	)

Other income (expense)		1.0			(3.0	)		(4.2	)		—			—			(6.2	)

Income tax benefit (expense)		0.3			(0.1	)		—			—			—			0.2


Net income (loss)		10.8			(3.4	)		(2.4	)		(3.6	)		—			1.4

Less: Net income attributable to noncontrolling interest		0.9			—			3.8			0.9			—			5.6


Net income (loss) attributable to Targa Resources Partners LP	$	9.9		$	(3.4	)	$	(6.2	)	$	(4.5	)	$	—		$	(4.2	)


	Nine Months Ended September 30, 2009
	Historical			Permian
	Targa			and												Targa
	Resources			Straddle			Versado			Venice						Resources
	Partners LP			Systems			System			Operations			Eliminations			Partners LP
Revenues	$	2,822.3		$	694.2		$	192.2		$	113.1		$	(701.2	)	$	3,120.6

Costs and expenses:

Product purchases		2,459.3			630.6			134.1			82.4			(681.8	)		2,624.6

Operating expenses		141.9			27.3			21.5			10.8			(19.4	)		182.1

Depreciation and amortization expense		75.5			18.2			21.9			9.4			—			125.0

General and administrative expense and other		54.6			12.9			3.3			7.3			—			78.1


		2,731.3			689.0			180.8			109.9			(701.2	)		3,009.8

Income (loss) from operations		91.0			5.2			11.4			3.2			—			110.8

Other income (expense):

Interest expense		(78.8	)		(17.3	)		(23.1	)		(7.1	)		—			(126.3	)

Other income (expense)		3.4			(6.7	)		(5.9	)		—			—			(9.2	)

Income tax expense		(0.7	)		(0.2	)		—			—			—			(0.9	)


Net income (loss)		14.9			(19.0	)		(17.6	)		(3.9	)		—			(25.6	)

Less: Net income attributable to noncontrolling interest		1.2			—			8.1			2.6			—			11.9


Net income (loss) attributable to Targa Resources
Partners LP	$	13.7		$	(19.0	)	$	(25.7	)	$	(6.5	)	$	—		$	(37.5	)

Note 6 —Inventory

Due to fluctuating commodity prices for natural gas liquids (“NGL”), we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases in the period they are recognized, with the related cash impact in the subsequent period of sale. For the three and nine months ended September 30, 2010, we recognized zero and $1.0 million and for the same periods in 2009, zero and $2.4 million to reduce the carrying value of NGL inventory to its net realizable value.

Note 7 — Property, Plant and Equipment

Property, plant and equipment, at cost, and the related estimated useful lives of the assets were as follows as of the dates indicated:


	September 30,		December 31,		Range of
	2010		2009		Years
Natural gas gathering systems	$	1,616.3	$	1,578.2		5 to 20
Processing and fractionation facilities		955.3		949.8		5 to 25
Terminalling and natural gas liquids storage facilities		241.1		238.5		5 to 25
Transportation assets		272.7		271.6		10 to 25
Other property, plant and equipment		46.4		45.3		3 to 25
Land		51.2		50.9		—
Construction in progress		53.6		21.2		—

	$	3,236.6	$	3,155.5

Note 8 —Investment in Unconsolidated Affiliate

Our unconsolidated investment consists of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”). The following table shows the activity related to our unconsolidated investment in GCF for the periods indicated:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Beginning of period	$	19.2		$	19.5		$	18.5		$	18.5
Equity in earnings		1.1			1.4			3.8			3.2
Cash distributions		(2.9	)		(3.1	)		(4.9	)		(3.9	)

End of period	$	17.4		$	17.8		$	17.4		$	17.8

Our allocated cost basis of GCF at our acquisition date was less than our partnership equity balance by approximately $5.2 million. This basis difference is being amortized over the estimated useful life of the underlying fractionating assets (25 years) on a straight-line basis and is included as a component of our equity in earnings of unconsolidated investments.

Note 9 — Debt Obligations

Consolidated debt obligations consisted of the following as of the dates indicated:


	September 30,			December 31,
	2010			2009
Targa Resources Partners LP:
Senior secured revolving credit facility, variable rate, due February 2012	$	—		$	479.2
Senior secured revolving credit facility, variable rate, due July 2015		753.3			—
Senior unsecured notes, 8¹/4% fixed rate, due July 2016		209.1			209.1
Senior unsecured notes, 11¹/4% fixed rate, due July 2017		231.3			231.3
Unamortized discounts, net of premiums		(10.5	)		(11.2	)
Senior unsecured notes 7 7/8% fixed rate, due October 2018		250.0			—
Targa Permian LP:
Note payable to Parent, 10% fixed rate		—			170.2
Targa Straddle LP:
Note payable to Parent, 10% fixed rate		—			156.8
Targa Versado LP:
Note payable to Parent, 10% fixed rate		—			435.0
Targa Venice Operations:
Allocated note payable to Parent, variable rate		—			151.8
Affilate note payable to Parent, 10% fixed rate		—			2.8

	$	1,433.2		$	1,825.0


Letters of credit issued	$	101.5		$	108.4

The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations during the nine months ended September 30, 2010:


	Range of interest	Weighted average
	rates paid	interest rate paid
Senior secured revolving credit facilities	1.2% to 5.0%		1.9	%

Compliance with Debt Covenants

As of September 30, 2010, we are in compliance with the covenants contained in our various debt agreements.

Senior Secured Credit Facility

On July 19, 2010, we entered into an Amended and Restated Credit Agreement that replaced our existing variable rate Senior Secured Credit Facility with a new variable rate Senior Secured Credit Facility due July 2015. The new Senior Secured Credit Facility increases available commitments to $1.1 billion from $958.5 million, and allows us to request increases in commitments up to an additional $300 million. We incurred a charge of $0.8 million related to a partial write-off of debt issue costs associated with this amended and restated credit facility related to a change in syndicate members. The remaining balance in debt issue costs of $4.7 million is being amortized over the life of the amended and restated credit facility.

The new credit facility bears interest at LIBOR plus an applicable margin ranging from 2.25% to 3.5% dependent on our consolidated funded indebtedness to consolidated adjusted EBITDA ratio. Our new credit facility is secured by substantially all of our assets.

As of September 30, 2010, availability under our senior secured revolving credit facility was $245.2 million, after giving effect to $101.5 million in outstanding letters of credit.

Senior Unsecured Notes 7 7/8% due 2018

On August 13, 2010, we closed a $250 million face value notes offering. These notes issued bear interest at 7 7/8% and will mature in October 2018. The net proceeds of this offering were $245 million, after deducting debt issue costs. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility.

Affiliated Indebtedness

The contributions of the Permian and Straddle Systems, the Versado System and Targa’s Venice Operations have been treated as transfers between entities under common control and periods prior to the transfer have been adjusted to present comparative information. On January 1, 2007, Targa contributed to us affiliated indebtedness applicable to each of these predecessor businesses. In addition, as a result of accounting treatment related to our acquisition of Targa’s Venice Operations, Targa contributed to us allocated indebtedness in August 2008 in connection with its acquisition of a controlling interest in VESCO. We include the financial effects of this affiliated indebtedness in our consolidated financial statements prepared on common control accounting basis. The following table summarizes the financial effects of this affiliated indebtedness:


				Permian and
	Downstream			Straddle			Versado			Venice
	Business			Systems			System			Operations
Original principal December 1, 2005	$	568.7		$	232.2		$	308.9		$	2.0
Interest accrued during 2005 and 2006		61.8			25.1			33.4			0.2
Borrowings during 2006		9.2			—			—			—

Parent debt contributed January 1, 2007		639.7			257.3			342.3			2.2
Additional borrowings:
For the year ended December 31, 2007		13.0			—			—			—
For the year ended December 31, 2008		3.4			—			—			137.1
Interest accrued prior to Targa conveyance:
For the year ended December 31, 2007		58.5			23.2			30.9			0.2
For the year ended December 31, 2008		59.3			23.2			30.9			4.8
For the year ended December 31, 2009		43.4			23.3			30.9			10.2
For the nine months ended September 30, 2010		—			5.8			18.0			5.7

		177.6			75.5			110.7			158.0
Outstanding affiliate debt at conveyance date		817.3			332.8			453.0			160.2
Payment of affiliated debt		(530.0	)		(332.8	)		(247.2	)		(160.2	)

Affiliate debt contributed at conveyance date	$	287.3		$	—		$	205.8		$	—

Note 10 — Partner Equity and Distributions

On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under an existing shelf registration statement on Form S-3 (“Registration Statement”) at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of $121.4 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units, providing net proceeds of $18.3 million. In addition, our general partner contributed $3.0 million for 129,082 common units to maintain a 2% interest in the Partnership. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.

On April 14, 2010, we completed a secondary public offering of 8,500,000 common units owned by Targa. The Partnership did not receive any of the proceeds from this offering and the number of outstanding common units of the Partnership remained unchanged.

On August 13, 2010, we completed a public offering of 6,500,000 of our common units under the Registration Statement at a price of $24.80 per common unit ($23.82 per common unit, net of underwriting discounts) providing net proceeds of approximately $154.8 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 975,000 common units, providing net proceeds of approximately $23.2 million. In addition, our general partner contributed $3.8 million for 152,551 common units to maintain a 2% interest in us. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility.

Distributions declared and paid during the nine months ended September 30, 2010 and 2009 were as follows:


		Distributions Paid										Distributions
	For the Three	Limited Partners				General Partner						per limited
Date Paid	Months Ended	Common		Subordinated		Incentive		2%		Total		partner unit
				(In millions, except per unit amounts)
2010
August 13, 2010	June 30, 2010	$	35.9	$	—	$	3.5	$	0.8	$	40.2	$	0.5275
May 14, 2010	March 31, 2010		35.2		—		2.8		0.8		38.8		0.5175
February 12, 2010	December 31, 2009		35.2		—		2.8		0.8		38.8		0.5175

2009
August 14, 2009	June 30, 2009	$	23.9	$	—	$	1.9	$	0.5	$	26.3	$	0.5175
May 15, 2009	March 31, 2009		18.0		5.9		1.9		0.5		26.3		0.5175
February 13, 2009	December 31, 2008		18.0		6.0		1.9		0.5		26.4		0.5175

Subsequent Event. On October 8, 2010, we announced a cash distribution of $0.5375 per unit on our outstanding common units for the three months ended September 30, 2010. The distribution, which totals $46.1 million, will be paid on November 12, 2010.

Note 11 – Hurricane Update

Hurricanes Katrina and Rita

In 2005, Hurricanes Katrina and Rita, which occurred prior to the close of Targa’s acquisitions of Dynegy’s midstream business, damaged certain of our acquired Gulf Coast facilities. The final purchase price allocation for this acquisition included an $81.1 million receivable for insurance claims related to our share of the property damage caused by Katrina and Rita. During the three and nine months ended September 30, 2009, expenditures related to these hurricanes included $0.1 million and $0.4 million capitalized as improvements. The insurance claim process is now complete with respect to Hurricanes Katrina and Rita for property damage and business interruption insurance.

Hurricanes Gustav and Ike

Certain of our Louisiana and Texas facilities sustained damage and had disruptions to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2009, the estimate was reduced by $3.8 million. During the three and nine months ended September 30, 2010, expenditures related to the hurricanes included $0.1 million and $0.4 million for previously accrued repair costs and less than $0.1 million capitalized as improvements. During the three and nine months ended September 30, 2009, expenditures related to the hurricanes included $3.6 million and $32.6 million for previously accrued repair costs and $0.4 million and $7.4 million capitalized as improvements.

Under common control accounting, we must include the effect of insurance claims on predecessor operations in our financial statements. However, as part of the 2005 acquisition agreements with Dynegy, Targa retained the right to receive any future insurance proceeds associated with claims arising before the acquisition closing date.

During the three and nine months ended September 30, 2009, we recognized revenue from business interruption insurance of:


	September 30, 2009
	Three Months Ended		Nine Months Ended
Coastal Gathering and Processing	$	1.0	$	3.6
Logistics Assets		—		1.9
Marketing and Distribution		—		0.5

	$	1.0	$	6.0

Hurricane insurance recoveries reported in our financial statements reflect the application of common control accounting and relate to predecessor periods only. Our financial statements do not include hurricane insurance recoveries realized after the asset conveyance date as these are retained by Targa under the terms of the related purchase and sale agreements.

Note 12 – Derivative Instruments and Hedging Activities

Commodity Hedges

In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes for the remainder of 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period.

We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover baskets of ethane, propane, normal butane, iso-butane and natural gasoline based upon our expected equity NGL composition, as well as specific NGL hedges of ethane and propane. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Mid-Continent, Waha and Permian Basin (El Paso), which closely approximate our actual NGL and natural gas delivery points.

We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximates the prices received for condensate. This necessarily exposes us to a market differential risk if the NYMEX futures do not move in exact parity with the sales price of our underlying West Texas condensate equity volumes.

At September 30, 2010, the notional volumes of our commodity hedges were:


Commodity	Instrument	Unit	2010		2011		2012		2013
Natural Gas	Swaps	MMBtu/d		36,146		30,100		23,100		8,000
NGL	Swaps	Bbl/d		9,064		7,000		4,650		—
NGL	Floors	Bbl/d		—		253		294		—
Condensate	Swaps	Bbl/d		851		750		400		400

Interest Rate Swaps

As of September 30, 2010, we had $753.3 million outstanding under our 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
Period	Fixed Rate			Amount	Fair Value
Remainder of 2010		3.67	%	$300 million	$	(2.6	)
2011		3.52	%	300 million		(7.7	)
2012		3.38	%	300 million		(7.9	)
2013		3.39	%	300 million		(5.8	)
1/1/2014 - 4/24/2014		3.39	%	300 million		(2.0	)


					$	(26.0	)

All interest rate swaps and interest rate basis swaps have been designated as cash flow hedges of variable rate interest payments on borrowings under our credit facility.

The following schedules reflect the fair values of derivative instruments in our financial statements:


	Asset Derivatives					Liability Derivatives
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	September 30,		December 31,		Sheet	September 30,		December 31,
	Location	2010		2009		Location	2010		2009
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	37.3	$	24.6	Current liabilities	$	12.3	$	7.8
	Long-term assets		27.5		6.8	Long-term liabilities		11.0		24.2

Interest rate contracts	Current assets		—		0.3	Current liabilities		8.0		8.0
	Long-term assets		—		1.9	Long-term liabilities		18.0		4.7

Total derivatives designated as hedging instruments			64.8		33.6			49.3		44.7


Derivatives not designated as hedging instruments
Commodity contracts	Current assets		0.6		8.0	Current liabilities		0.2		13.4
	Long-term assets		—		5.2	Long-term liabilities		—		15.0

Total derivatives not designated as hedging instruments			0.6		13.2			0.2		28.4

Total derivatives		$	65.4	$	46.8		$	49.5	$	73.1

Targa allocated to us a portion of our predecessor’s derivatives under its corporate wide hedging program. All of these derivatives are recorded on the balance sheets at fair value. As we were not a direct party to those hedge transactions, we did not apply hedge accounting. Therefore, changes in the unrealized fair value of these allocated hedges were recognized on a mark-to-market basis in earnings as a component of other income and expense. Upon our acquisition of the predecessor business, we became a legal party to the hedge transactions and applied hedge accounting prospectively.

In addition to the allocated derivatives noted above, our earnings are also affected by the use of the mark-to-market method of accounting for our derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheets and

through earnings, i.e., using the mark-to-market method rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices.

The following tables reflect amounts recorded in OCI and amounts reclassified from OCI to revenue and expense:


				Gain (Loss)
				Recognized in OCI on
Derivatives in	Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended September 30,						Nine Months Ended September 30,
Relationships	2010			2009			2010			2009
Interest rate contracts	$	(6.7	)	$	(7.5	)	$	(23.5	)	$	(3.0	)
Commodity contracts		(1.2	)		(9.8	)		58.8			(30.7	)

	$	(7.9	)	$	(17.3	)	$	35.3		$	(33.7	)


				Amount of Gain (Loss)
				Reclassified from OCI into
	Income (Effective Portion)
	Three Months Ended September 30,						Nine Months Ended September 30,
Location of Gain (Loss)	2010			2009			2010			2009
Interest expense, net	$	(3.5	)	$	(2.7	)	$	(8.5	)	$	(7.8	)
Revenues		7.1			17.0			7.0			36.9

	$	3.6		$	14.3		$	(1.5	)	$	29.1


			Amount of Gain (Loss)
			Recognized in Income on
	Derivatives (Ineffective Portion)
	Three Months Ended September 30,					Nine Months Ended September 30,
Location of Gain (Loss)	2010		2009			2010		2009
Revenues	$	0.7	$	(0.3	)	$	0.4	$	(0.3	)

The following table shows the realized and unrealized gains (losses) recorded as a component of other income (expense) related to derivative contracts not designated as cash flow hedging instruments:


		Amount of Gain (Loss) Recognized
		in Income on Derivatives
Derivatives	Location of Gain (Loss)	Three Months Ended						Nine Months Ended
Not Designated as	Recognized in Income	September 30,						September 30,
Hedging Instruments	on Derivatives	2010			2009			2010			2009
Realized gain (loss) on allocated commodity contracts	Revenue	$	(0.2	)	$	(1.7	)	$	(0.9	)	$	(4.8	)
Realized gain (loss) on allocated commodity contracts	Other income (expense)		0.8			7.4			(0.5	)		24.1
Unrealized gain (loss) on allocated commodity contracts	Other income (expense)		1.1			(0.7	)		26.5			(36.1	)

		$	1.7		$	5.0		$	25.1		$	(16.8	)

The following table shows the unrealized gains (losses) included in OCI:


	September 30,			December 31,
	2010			2009
Unrealized net gains (losses) on commodity hedges	$	23.2		$	(28.6	)


Unrealized net losses on interest rate hedges	$	(24.2	)	$	(9.2	)

Deferred net gains of $32.1 million on commodity hedges and deferred net losses of $7.4 million on interest rate hedges recorded in AOCI are expected to be reclassified to revenues from third parties and interest expense during the next twelve months.

During the three and nine months ended September 30, 2010, we reclassified deferred losses of $6.6 million and $20.5 million from AOCI as a non-cash reduction of revenue. During the three and nine months ended September 30, 2009, deferred losses of $4.3 million and $33.7 million were reclassified from AOCI as a non-cash reduction of revenue. These deferred losses are primarily related to the 2008 termination of certain out-of-the-money natural gas and NGL commodity swaps.

See Note 14, Note 17 and Note 20 for additional disclosures related to derivative instruments and hedging activities.

Note 13—Related Party Transactions

Relationship with Targa

We are or have been a party to various agreements with Targa, our general partner, Targa affiliates and others that address (i) the reimbursement of costs incurred on our behalf by our general partner, (ii) allocation of general administrative costs, (iii) distribution support to us under certain circumstances, (iv) intercompany purchases and sales of natural gas and NGLs, (v) cash distributions and (vi) acquisition transactions. With the acquisition of Targa’s remaining operating asset, the Venice Operations, we own all parties to the intercompany commodity purchase and sales agreements, and, therefore, all activity is eliminated in our consolidated results. See the Consolidated Statement of Changes in Owners’ Equity and Note 5, which summarize the transactional activity related to our acquisitions of various Targa operations.

The following table summarizes transactions with Targa and its affiliates:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009

Cash
Payroll and related costs included in operating expense	$	19.8		$	16.6		$	56.8		$	49.2
Parent allocation of general & administrative expense		22.1			20.0			67.4			69.9
Net change in affiliate receivable (payable)		11.8			(15.0	)		(8.4	)		26.4
Cash distributions to Targa		10.4			8.4			41.5			37.1

Cash distributions to Targa from the Permian/Straddle & Venice acquisitions		102.5			—			102.5			—
Distributions (contributions) under common control		57.4			58.4			149.1			137.5

Noncash

Affiliate interest expense accrued		(9.8	)		(30.6	)		(29.5	)		(91.7	)

Relationship with Warburg Pincus LLC

Chansoo Joung and Peter Kagan, two of the directors of our general partner, who are also directors of Targa, are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. During the three and nine months ended September 30, 2010, we purchased $13.3 million and $29.4 million of product from Broad Oak. During the three and nine months ended September 30, 2009, we purchased $2.5 million and $5.7 million of product from Broad Oak.

Peter Kagan is also a director of Antero Resources Corporation (“Antero”) from whom we buy natural gas and NGL products. An affiliate of Warburg Pincus LLC is a principal owner in Antero and holds a 40.8% interest in Antero. We purchased $0.5 million and $0.1 million of product from Antero during the nine months ended September 30, 2010 and 2009. There were no purchases of product from Antero during the three months ended September 30, 2010 and 2009. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationship with Maritech Resources, Inc.

One of the directors of the General Partner of the Partnership is also a director of Tetra Technologies, Inc. (“Tetra”). Maritech Resources, Inc. (“Maritech”) is a subsidiary of Tetra. three and nine months ended September 30, 2010, we purchased $1.0 million and $2.5 million of product from Maritech. During the three and nine months ended September 30, 2009, we purchased $0.4 million and $0.7 million of product from Maritech. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationship with Bank of America

Financial Services. An affiliate of Bank of American (“BofA”) is a lender and an agent under our and our subsidiaries’ senior credit facilities with commitments of $72 million. BofA and its affiliates have engaged, and may in the future engage, in other commercial and investment banking transactions with subsidiaries of the Company in the ordinary course of their business. They have received, and expect to receive, customary compensation and expense reimbursement for these commercial and investment banking transactions.

Commodity hedges. We have entered into various commodity derivative transactions with BofA. The following table shows our open commodity derivatives with BofA as of September 30, 2010:

Period

Commodity

Daily Volumes

Average Price

Index

Oct 2010 - Dec 2010

Natural Gas

3,289

MMBtu

7.39

per MMBtu

WAHA_IF

Oct 2010 - Dec 2010

Condensate

181

Bbl

69.28

per Bbl

WTI

As of September 30, 2010, the aggregate fair value of these open positions was $0.9 million. For the three and nine months ended September 30, 2010, we received $0.9 million and $2.1 million from BofA under hedge settlement transactions. For the three and nine months ended September 30, 2009, we received $6.5 million and $16.0 million from BofA under hedge settlement transactions.

Commercial Relationships. Our product sales and product purchases with BofA were:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Included in revenues	$	5.5	$	6.4	$	20.9	$	29.1
Included in costs and expenses		1.0		—		3.2		0.4

Note 14 —Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of any 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.

Under the terms of the Versado Purchase and Sale Agreement, Targa will reimburse the Partnership for future maintenance capital expenditures required pursuant to our New Mexico Environmental Department settlement agreement, of which our share is currently estimated at $19 million, to be incurred through 2011.

Legal Proceedings

We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business that have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows, except for the items more fully described below.

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 two 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. In October 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. In February 2010, the 14^th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. WTG’s appeal is pending before the Texas Supreme Court, and Targa intends to contest 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 15—Fair Value of Financial Instruments

We have determined the estimated fair values of our assets and liabilities classified as financial instruments using available market information and valuation methodologies described below. We apply considerable judgment when interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value.

The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The carrying value of the notes payable to Parent at December 31, 2009 and 2008 approximates their fair value as they were settled at their stated amount at the time of conveyance of the affected assets. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt as of the dates indicated in the following table:


	September 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior unsecured notes, 8¹/4% fixed rate	$	209.1	$	220.6	$	209.1	$	206.5
Senior unsecured notes, 11¹/4% fixed rate		231.3		266.0		231.3		253.5
Senior unsecured notes, 7 7/8% fixed rate		250.0		261.6		—		—

Note 16 — Fair Value Measurements

We categorize the inputs to the fair value of our financial assets and liabilities using a three-tier fair value hierarchy that prioritizes the significant inputs used in measuring fair value:

	•		Level 1 – observable inputs such as quoted prices in active markets;

	•		Level 2 – inputs other than quoted prices in active markets that are either directly or indirectly observable; and

	•		Level 3 – unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain counterparties. 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 readily available in public markets. 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.

The following tables present the fair value of our financial assets and liabilities according to the fair value hierarchy. 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.


	September 30, 2010
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	65.4	$	—	$	64.3	$	1.1

Total assets	$	65.4	$	—	$	64.3	$	1.1

Liabilities from commodity derivative contracts	$	23.5	$	—	$	21.2	$	2.3
Liabilities from interest rate derivatives		26.0		—		26.0		—

Total liabilities	$	49.5	$	—	$	47.2	$	2.3


	December 31, 2009
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	44.7	$	—	$	44.7	$	—
Assets from interest rate derivatives		2.1		—		2.1		—

Total assets	$	46.8	$	—	$	46.8	$	—

Liabilities from commodity derivative contracts	$	60.4	$	—	$	46.7	$	13.7
Liabilities from interest rate derivatives		12.7		—		12.7		—

Total liabilities	$	73.1	$	—	$	59.4	$	13.7

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
Balance, December 31, 2009	$	(13.7	)
Unrealized gains included in OCI		12.2
Settlements		0.3

Balance, September 30, 2010	$	(1.2	)

Note 17 — Segment Information

We reassessed our reportable segments during the second quarter of 2010 in connection with the April 2010 acquisition of Targa’s interest in the Permian and Straddle Systems and its impact on our internal management structure. As a result, our operations are now presented under four reportable segments: (1) Field Gathering and Processing, (2) Coastal Gathering and Processing, (3) Logistics Assets and (4) Marketing and Distribution. The financial results of our hedging activities are reported in Other. Prior period information in this report has been revised to conform to the 2010 reported segment presentation.

Prior to the second quarter of 2010, we reported our results under four segments: (1) Natural Gas Gathering and Processing, (2) Logistics Assets, (3) NGL Distribution and Marketing and (4) Wholesale Marketing. The increase in our Coastal Gathering and Processing businesses as a result of our acquisition of the Permian and Straddle Systems, and consideration of underlying operational and economic differences between Field and Coastal gathering and processing systems led to more granular analysis of the Natural Gas Gathering and Processing results. Also, we have aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant operational interrelationships among the Marketing and Distribution activities apparent in our current business model.

The Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. The Field Gathering and Processing segment assets are located in North Texas and the Permian Basin of West Texas and New Mexico and the Coastal Gathering and Processing segment assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico.

The NGL Logistics and Marketing division is also referred to as our Downstream Business. It includes all the activities necessary to convert raw natural gas liquids into NGL products, market the finished products and provide certain value added services.

The Logistics Assets segment is involved in transporting and storing mixed NGLs and fractionating, storing, and transporting finished NGLs. These assets are generally connected to and supplied, in part, by our gathering and processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana.

The Marketing and Distribution segment covers all activities required to distribute and market raw and finished natural gas liquids and all natural gas marketing activities. It includes (1) marketing our own natural gas liquids production and purchasing natural gas liquids products in selected United States markets; (2) providing liquefied petroleum gas balancing services to refinery customers; (3) transporting, storing and selling propane and providing related propane logistics services to multi-state retailers, independent retailers and other end users; and (4) marketing natural gas available to us from our Gathering and Processing segments and the purchase and resale of natural gas in selected United States markets.

Our reportable segment information is shown in the following tables:


	Three Months Ended September 30, 2010
	Field		Coastal
	Gathering		Gathering				Marketing					Corporate
	and		and		Logistics		and					and
	Processing		Processing		Assets		Distribution			Other		Eliminations			Total
Revenues	$	47.9	$	113.3	$	23.2	$	1,025.3		$	7.1	$	0.1		$	1,216.9
Revenues from affiliates		—		—		—		(0.1	)		—		0.1			—
Intersegment revenues		253.7		163.2		19.9		113.6			—		(550.4	)		—

Revenues		301.6		276.5		43.1		1,138.8			7.1		(550.2	)		1,216.9

Operating margin		49.6		23.5		23.6		15.0			7.1		—			118.8

Other financial information:
Capital expenditures	$	13.6	$	2.0	$	19.3	$	1.2		$	—	$	—		$	36.1


	Three Months Ended September 30, 2009
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Revenues	$	52.2	$	95.2	$	19.6	$	934.5	$	16.7	$	(0.2	)	$	1,118.0
Revenues from affiliates		—		—		—		—		—		—			—
Intersegment revenues		192.9		141.6		19.8		84.8		—		(439.1	)		—

Revenues		245.1		236.8		39.4		1,019.3		16.7		(439.3	)		1,118.0

Operating margin		45.9		20.1		21.4		14.6		16.7		(0.1	)		118.6

Other financial information:
Capital expenditures	$	12.6	$	1.2	$	3.5	$	1.5	$	—	$	—		$	18.8


	Nine Months Ended September 30, 2010
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Revenues	$	160.5	$	350.0	$	59.7	$	3,361.2	$	7.0	$	(0.1	)	$	3,938.3
Revenues from affiliates		—		—		—		—		—		—			—
Intersegment revenues		793.4		567.2		61.8		380.3		—		(1,802.7	)		—

Revenues		953.9		917.2		121.5		3,741.5		7.0		(1,802.8	)		3,938.3

Operating margin		176.8		74.9		52.9		48.8		7.0		—			360.4

Other financial information:
Total assets	$	1,627.7	$	448.5	$	432.7	$	426.4	$	65.4	$	62.3		$	3,063.0

Capital expenditures		40.9		4.3		33.1		1.9		—		—			80.2


	Nine Months Ended September 30, 2009
	Field		Coastal
	Gathering		Gathering				Marketing				Corporate
	and		and		Logistics		and				and
	Processing		Processing		Assets		Distribution		Other		Eliminations			Total
Revenues	$	134.5	$	271.5	$	52.4	$	2,625.6	$	36.6	$	—		$	3,120.6
Revenues from affiliates		—		—		—		—		—		—			—
Intersegment revenues		530.8		346.8		57.5		229.4		—		(1,164.5	)		—

Revenues		665.3		618.3		109.9		2,855.0		36.6		(1,164.5	)		3,120.6

Operating margin		123.4		52.8		47.5		53.6		36.6		—			313.9

Other financial information:
Total assets		1,665.7		472.8		412.7		394.2		84.5		61.0			3,090.9

Capital expenditures	$	36.4	$	10.3	$	11.1	$	4.7	$	—	$	—		$	62.5

The following table shows our revenues by product and services for each period presented:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
Natural gas sales	$	269.2	$	204.4	$	847.5	$	588.2
NGL sales		880.7		838.6		2,896.8		2,326.2
Condensate sales		22.4		29.7		72.7		71.0
Fractionation & Treating fees		12.4		14.8		40.7		41.5
Storage & Terminalling fees		11.4		10.6		30.2		30.9
Transportation fees		10.0		10.8		24.9		36.0
Gas processing fees		8.2		6.3		23.3		17.6
Business interruption insurance		—		1.0		—		6.0
Other		2.6		1.8		2.2		3.2

	$	1,216.9	$	1,118.0	$	3,938.3	$	3,120.6

The following table is a reconciliation of operating margin to net income (loss):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Reconciliation of operating margin to net income (loss):
Operating margin	$	118.8		$	118.6		$	360.4		$	313.9
Depreciation and amortization expense		(43.3	)		(43.1	)		(128.3	)		(125.0	)
General and administrative expense		(26.7	)		(22.6	)		(80.0	)		(81.9	)
Interest expense, net		(27.2	)		(45.5	)		(85.8	)		(126.3	)
Income tax (benefit) expense		(1.7	)		0.2			(3.9	)		(0.9	)
Other, net		(1.5	)		(6.2	)		29.0			(5.4	)


Net Income (loss)	$	18.4		$	1.4		$	91.4		$	(25.6	)

Note 18 — Supplemental Cash Flow Information

The following table provides supplemental cash flow information for each period presented:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010			2009		2010		2009
Cash:
Interest paid	$	28.9		$	12.8		60.6	$	316
Non-cash:
Inventory line-fill transferred to property, plant and equipment		(0.1	)		—		0.4		9.8

Note 19 —Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry. Our business activities include gathering, transporting, processing, fractionating and storage of natural gas and NGLs. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products and changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of natural gas, NGLs and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or condensate production, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and condensate handled by our facilities.

A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, as well as changes in interest rates. The fair value of our commodity and interest rate 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. 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.

Commodity Price Risk. A majority of the revenues from our natural gas gathering and processing business are 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 market 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 commodity derivative 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.

2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market 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. See Note 13.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate borrowings under our credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement. See Note 13.

Counterparty Risk — Credit and Concentration

Financial instruments which potentially subject us to concentrations of credit risk consist primarily of commodity derivative instruments and trade accounts receivable.

Derivative Counterparty Risk.

Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.

We have master agreements with all of our hedge counterparties that allow us to net settle asset and liability positions with the same counterparty. As of September 30, 2010, we had $19.7 million in liabilities to offset the default risk of counterparties with which we also had asset positions of $41.9 million as of that date.

Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date. At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

As of September 30, 2010, affiliates of Barclays, Goldman Sachs and BP accounted for 47%, 20% and 18% of our net counterparty credit exposure related to commodity derivative instruments. Goldman Sachs and Barclays are major financial institutions, and BP is a major industrial company, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

Customer Credit Risk.

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.

Significant Commercial Relationships.

We are exposed to concentration risk when a significant customer or supplier accounts for a significant portion of our business activity. We have not had a material change in the make-up of our customers or suppliers during the nine months ended September 30, 2010.

Casualty or Other Risks

Targa maintains coverage in various insurance programs on our behalf, which provides us with significant property damage, business interruption and other coverages which are customary for the nature and scope of our operations. A portion of the cost of these insurance programs is allocated to us pursuant to the Omnibus Agreement.

Note 20 — Revenue Reclassification

During 2009, we reclassified NGL marketing fractionation and other service fees to revenues that were originally recorded in product purchase costs. This reclassification had no impact on our income from operations, net income, financial position or cash flows. In the three and nine months ended September 30, 2009, the adjustments were $4.7 million and $18.6 million.

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 and in our consolidated financial statements and notes thereto included in our Annual Report, as well as our supplemental financial statements in our Current Report on Form 8-K filed August 9, 2010.

Overview

Targa Resources Partners LP, is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis.

Targa Resources GP LLC is a Delaware limited liability company, formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa.

We acquired Targa’s ownership interests in the following assets, liabilities and operations on the dates indicated (collectively, the “dropdown transactions”):

	•		February 14, 2007 — North Texas System;

	•		October 24, 2007 — San Angelo (“SAOU”) System and Louisiana (“LOU”) System;

	•		September 24, 2009 — Downstream Business;

	•		April 27, 2010 — Permian and Straddle Systems

	•		August 25, 2010 — Versado System; and

	•		September 28, 2010 — Venice Operations.

For periods prior to the above acquisition dates, we refer to the operations, assets and liabilities of these acquisitions as our “predecessors.”

Our Operations

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”).

We report our operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two segments — (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) NGL Logistics and Marketing consisting of two segments — (a) Logistics Assets and (b) Marketing and Distribution. Other includes the impact on operating income of our derivatives hedging activities. Prior period information in this report has been revised to conform to the 2010 reported segment presentation.

aggregated the previously separately reported NGL Distribution and Marketing segment and Wholesale Marketing segment into one reportable segment, Marketing and Distribution. This combined marketing segment reflects significant operational interrelationships among the Marketing and Distribution activities apparent in our current business model.

The Natural Gas Gathering and Processing division includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. The Field Gathering and Processing segment’s assets are located in North Texas and the Permian Basin of West Texas and New Mexico and the Coastal Gathering and Processing segment’s assets are located in the onshore and near offshore region of the Louisiana Gulf Coast and the Gulf of Mexico.

Recent Developments

On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under our existing shelf registration statement on Form S-3 at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of $121.4 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units, providing net proceeds of $18.3 million. In addition, our general partner contributed $3.0 million for 129,082 common units to maintain its 2% interest in the Partnership. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.

On April 14, 2010, we completed a secondary public offering of 8,500,000 common units owned by Targa LP Inc., a wholly-owned subsidiary of Targa. The Partnership did not receive any of the proceeds from this offering and the number of outstanding common units of the Partnership remained unchanged.

On April 27, 2010, we completed our acquisition of Targa’s interests in its Permian and Straddle Systems, which consists of natural gas gathering and processing businesses located in West Texas and the Gulf Coast region of Louisiana, for $420.0 million, effective April 1, 2010. We financed this acquisition substantially through borrowings under our senior secured revolving credit facility. The total consideration was used to repay outstanding affiliated indebtedness of $332.8 million, with the remaining $87.2 million reported as a distribution to our parent. This acquisition is reflected in our financial statements as a transfer of assets under common control.

As part of the purchase of the Permian and Straddle assets, our Omnibus Agreement with Targa was amended and extended through April 2013 for Targa to provide services including general and administrative to us associated with (1) these assets, (2) any additional assets, operations or businesses that may be sold to us by Targa, and (3) subject to mutual consent, additional assets, operations or businesses that we may acquire from third parties.

On July 19, 2010, we entered into an amended and restated five-year $1.1 billion senior secured revolving credit facility, which allows us to request increases in commitments up to an additional $300 million. The new senior

secured credit facility amends and restates our former $977.5 million senior secured revolving credit facility due February 2012.

On August 13, 2010, we completed a public offering of 7,475,000 common units (6,500,000 common units plus an overallotment option of 975,000 common units) and a separate private offering of $250,000,000 of 7 7/8% Senior Notes due 2018. We used the net proceeds from these offerings to reduce borrowings under our senior secured credit facility. In addition, our general partner contributed $3.8 million for 152,551 common units to maintain a 2% interest in us. We used the net proceeds from this offering to reduce borrowings under our senior secured credit facility.

On August 25, 2010, we completed our acquisition of Targa’s 63% ownership interest in Versado Gas Processors (“Versado”) a joint venture that is operated by Targa, for aggregate consideration of $247.2 million, subject to adjustment. Versado owns a natural gas gathering and processing business consisting of the Eunice, Monument and Saunders gathering and processing systems, including treating operations, processing plants and related assets. The Versado System includes three refrigerated cryogenic processing plants and approximately 3,200 miles of combined gathering pipelines in Southeast New Mexico and West Texas.

On September 28, 2010, we completed our acquisition of Targa’s Venice Operations, which includes Targa’s 76.8% interest in Venice Energy Services Company, L.L.C. (“VESCO”), a joint venture that is operated by Targa. Vesco’s natural gas gathering and processing business is located near Venice, Louisiana in Plaquemines Parish along the Louisiana Gulf Coast and also includes VESCO’s wholly-owned subsidiary Venice Gathering System (“VGS”). VGS is an offshore gathering system that collects natural gas from producers and transports these volumes to the system’s gas processing plant. Total value of the transaction was $175.6 million including cash acquired by us, subject to certain adjustments.

On October 8, 2010, we announced a cash distribution of $0.5375 per common unit on our outstanding common units for the three months ended September 30, 2010. The aggregate distribution to be paid on November 12, 2010 is $46.1 million.

Recently Issued Pronouncements

See Note 4 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, 2010 and 2009 and is a summary of our results of operations for the periods then ended:


	Three Months Ended September 30,												Nine Months Ended September 30,
	2010			2009			Change			% Change			2010			2009			Change			% Change
	(In millions, except operating and price data)												(In millions, except operating and price data)
Revenues (1)	$	1,216.9		$	1,118.0		$	98.9			9	%	$	3,938.3		$	3,120.6		$	817.7			26	%
Product purchases		1,032.1			936.2			95.9			10	%		3,387.7			2,624.6			763.1			29	%

Gross Margin(2)		184.8			181.8			3.0			2	%		550.6			496.0			54.6			11	%
Operating expenses		66.0			63.2			2.8			4	%		190.2			182.1			8.1			4	%

Operating Margin (3)		118.8			118.6			0.2			—			360.4			313.9			46.5			15	%
Depreciation and amortization expense		43.3			43.1			0.2			—			128.3			125.0			3.3			3	%
General and administrative expense		26.7			22.6			4.1			18	%		80.0			81.9			(1.9	)		(2	%)
Casualty loss adjustment		—			—			—			—			—			(3.8	)		3.8			100	%

Income from operations		48.8			52.9			(4.1	)		(8	%)		152.1			110.8			41.3			37	%
Interest expense, net		(27.2	)		(45.5	)		(18.3	)		(40	%)		(85.8	)		(126.3	)		(40.5	)		(32	%)
Other income (expense)		(1.5	)		(6.2	)		(4.7	)		(76	%)		29.0			(9.2	)		38.2			415	%
Income tax benefit (expense)		(1.7	)		0.2			(1.9	)		(950	%)		(3.9	)		(0.9	)		3.0			333	%

Net income (loss)		18.4			1.4			17.0			1,214	%		91.4			(25.6	)		117.0			457	%
Less: Net income attributable to noncontrolling interest		4.6			5.6			(1.0	)		(18	%)		18.2			11.9			6.3			53	%

Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)	$	18.0			429	%	$	73.2		$	(37.5	)	$	110.7			295	%


Financial and operating data:
Financial data:
Adjusted EBITDA (4)		91.4			98.9			(7.5	)		(8	%)		278.7			278.6			0.1			—
Distributable cash flow (5)		57.1			78.8			(21.7	)		(28	%)		198.8			216.8			(18.0	)		(8	%)
Operating data:
Plant natural gas inlet, MMcf/d (6)(7)		2,216.4			2,274.2			(57.8	)		(3	%)		2,296.5			2,097.7			198.8			9	%
Gross NGL production, MBbl/d		121.6			123.5			(1.9	)		(2	%)		120.8			117.1			3.7			3	%
Natural gas sales, BBtu/d (7)		671.9			662.8			9.1			1	%		678.4			590.4			88.0			15	%
NGL sales, MBbl/d		244.2			269.2			(25.0	)		(9	%)		246.0			285.1			(39.1	)		(14	%)
Condensate sales, MBbl/d		3.4			4.8			(1.4	)		(29	%)		3.6			4.8			(1.2	)		(25	%)
Average realized prices :(8)
Natural Gas, $/MMBtu		4.35			3.35			1.00			30	%		4.58			3.65			0.93			25	%
NGL, $/gal		0.93			0.81			0.12			15	%		1.03			0.71			0.32			45	%
Condensate, $/Bbl		72.13			67.57			4.56			7	%		73.62			54.36			19.26			35	%


(1)		Includes business interruption insurance revenues of $1.0 million and $6.0 million for the three and nine months ended September 30, 2009.

(2)		Gross margin is revenues less product purchases. See “Non-GAAP Financial Measures.”

(3)		Operating margin is gross margin less operating expenses. See “Non-GAAP Financial Measures.”

(4)		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.”

(5)		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.”

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

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

(8)		Average realized prices include the impact of hedging activities.

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include gross margin, operating margin, operating expenses, plant inlet, gross NGL production, adjusted EBITDA and distributable cash flow, among others. For a discussion of these measures, see

“Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations” in the Recast 8-K.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Revenue increased $98.9 million due to higher commodity prices ($183.1 million) offset by lower sales volumes ($83.8 million) and lower fee-based and other revenues ($0.4 million).

The $3.0 million increase in gross margin reflects higher revenue of $98.9 million offset by higher product purchase costs of $95.9 million.

For additional information regarding the period to period changes in our gross margins, see “Results of Operations—By Segment.”

The $2.8 million increase in operating expenses was primarily due to increased compensation and benefit costs and increased non-capitalized maintenance costs, offset by decreased costs associated with outside contract services and lower professional fees. See “Results of Operations — By Segment” for additional discussion regarding changes in operating expenses.

The increase in depreciation and amortization expense is primarily attributable to assets acquired in 2009 that now have a full period of depreciation and capital expenditures during 2010, as well as incremental depreciation on capital expenditures in 2010 of $36.5 million.

The increase in general and administrative expense reflects primarily higher compensation costs and the timing of allocations under common control.

The decrease in interest expense was primarily due to lower principal amounts and lower interest rates on third party debt than on affiliate debt associated with predecessor operations. See “—Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Revenues increased $817.7 million due to higher commodity prices ($1,080.5 million) offset by lower sales volumes ($249.0 million), lower business interruption proceeds ($6.0 million) and lower fee-based and other revenues ($7.8 million).

The $54.6 million increase in gross margin reflects higher revenues of $817.7 million, offset by higher product purchase costs of $763.1 million.

For additional information regarding the period to period changes in our gross margins, see "—Results of Operations—By Segment.”

The $8.1 million increase in operating expenses was primarily due to increased compensation and benefits costs, increased non-capitalized maintenance costs and increased environmental spending, offset by decreased costs associated with outside contract services and lower professional fees. See “Results of Operations — By Segment” for additional discussion regarding changes in operating expenses.

The decrease in general and administrative expense was primarily driven by the timing of allocations under common control.

Results of Operations—By Segment

Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volume or sales for the period and the denominator is the number of calendar days for the period.

Field Gathering and Processing Segment

The following table provides summary financial data regarding results of operations of our Field Gathering and Processing segment for the periods indicated:


	Three Months Ended September 30,												Nine Months Ended September 30,
	2010			2009			Change			% Change			2010			2009			Change			% Change
Gross margin	$	77.4		$	68.5		$	8.9			13	%	$	250.4		$	187.1		$	63.3			34	%
Operating expenses		(27.8	)		(22.6	)		5.2			23	%		(73.6	)		(63.7	)		9.9			16	%

Operating margin(1)	$	49.6		$	45.9		$	3.7			8	%	$	176.8		$	123.4		$	53.4			43	%

Operating statistics:(2)
Plant natural gas inlet, MMcf/d		583.7			580.0			3.7			1	%		582.0			585.6			(3.6	)		(1	%)
Gross NGL production, MBbl/d		70.6			69.5			1.1			2	%		70.2			70.1			0.1			—
Natural gas sales, BBtu/d		254.5			241.4			13.1			5	%		257.2			244.0			13.2			5	%
NGL sales, MBbl/d		54.9			55.3			(0.4	)		(1	%)		55.6			55.4			0.2			—
Condensate sales, MBbl/d		3.1			3.3			(0.2	)		(6	%)		3.0			3.5			(0.5	)		(14	%)
Average realized prices:
Natural gas, $/MMBtu		4.00			2.95			1.05			36	%		4.30			3.12			1.18			38	%
NGL, $/gal		0.86			0.72			0.14			19	%		0.91			0.63			0.28			44	%
Condensate, $/Bbl		72.10			63.61			8.49			13	%		73.82			51.41			22.41			44	%


(1)		Operating margin is revenues less product purchases and operating expenses.

(2)		Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

The $8.9 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($56.5 million) and an increase in natural gas sales volumes ($3.6 million) partially offset by a decrease in NGL and condensate revenue ($2.1 million), fee-based and other revenues ($1.5 million) and an increase in commodity purchase costs ($47.6 million). The increased volumes were largely attributable to new well connects throughout our systems, partially offset by production declines at our Versado System, combined with planned and unplanned operational outages at our Eunice Plant.

The $5.2 million increase in operating expenses for 2010 was primarily due to increases in system maintenance expenses of $3.2 million, primarily attributable to the Eunice Plant operational outages and higher compensation and benefits costs of $1.3 million.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $63.3 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($280.1 million), an increase in natural gas and NGL sales volumes ($12.4 million) and an increase in fee-based and other revenues ($2.4 million), offset by lower condensate sales volumes ($6.2 million) and increased commodity

purchase costs ($225.4 million). The increased volumes were largely attributable to new well connects throughout our systems, partially offset at our Versado System by production declines in the high-volume Morrow formation combined with operational outages.

The $9.9 million increase in operating expenses for 2010 was primarily due to increases in system maintenance expenses of $5.2 million and compensation and benefits costs of $2.5 million.

Coastal Gathering and Processing Segment

The following table provides summary financial data regarding results of operations of our Coastal Gathering and Processing segment for the periods indicated:


	Three Months Ended September 30,												Nine Months Ended September 30,
	2010			2009			Change			% Change			2010			2009			Change			% Change
	($ in millions)												($ in millions)
Gross margin	$	34.2		$	34.2		$	—			—		$	106.3		$	87.7		$	18.6			21	%
Operating expenses		(10.7	)		(14.1	)		(3.4	)		(24	%)		(31.4	)		(34.9	)		(3.5	)		(10	%)

Operating margin (1)		23.5			20.1			3.4			17	%		74.9			52.8			22.1			42	%

Operating statistics (2):
Plant natural gas inlet, MMcf/d (3)		1,632.7			1,694.2			(61.5	)		(4	%)		1,714.5			1,512.1			202.4			13	%
Gross NGL production, MBbl/d		51.0			54.0			(3.0	)		(6	%)		50.5			47.0			3.5			7	%
Natural gas sales, BBtu/d		292.0			283.5			8.5			3	%		305.3			249.2			56.1			23	%
NGL sales, MBbl/d		42.4			44.2			(1.8	)		(4	%)		44.0			39.5			4.5			11	%
Condensate sales, MBbl/d		0.2			1.5			(1.3	)		(87	%)		0.6			1.6			(1.0	)		(63	%)
Average realized prices:
Natural gas, $/MMBtu		4.41			3.42			0.99			29	%		4.64			3.88			0.76			20	%
NGL, $/gal		0.93			0.78			0.15			19	%		1.00			0.69			0.31			45	%
Condensate, $/Bbl		72.42			78.81			(6.39	)		(8	%)		78.45			55.59			22.86			41	%


(1)		Operating margin is revenues less product purchases and operating expenses.

(2)		Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

(3)		The majority of Straddle System volumes are gathered on third party offshore pipeline systems and delivered to the plant inlets.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Gross margin for 2010 was flat compared to 2009 due to an increase in commodity sales prices ($51.3 million), natural gas sales volumes ($2.7 million) and fee-based and other revenues ($0.2 million), offset by a decrease in NGL and condensate sales volumes ($14.5 million) and an increase in product purchase costs ($39.7 million). Natural gas sales volumes increased due to increased sales to affiliates for resale partially offset by a decrease in demand from our industrial customers. NGL sales volumes decreased primarily due to reduced plant inlet volumes resulting from a decline in traditional wellhead and offshore supply volumes.

The $3.4 million decrease in operating expenses for 2010 was primarily due to lower system maintenance expenses.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $18.6 million increase in gross margin for 2010 is primarily due to an increase in commodity sales prices ($224.0 million) and commodity sales volumes ($80.6 million), offset by a decrease in fee-based and other revenues ($5.7 million) and increased commodity purchase costs ($280.3 million). Natural gas sales volumes increased due to increased demand from our industrial customers and increased sales to affiliates for resale. NGL sales volumes

increased primarily due to the straddle plants recovering operations in 1Q and 2Q 2009 after Hurricanes Gustav and Ike in 2008.

The $3.5 million decrease in operating expenses for 2010 was primarily due to lower system maintenance expenses and lower contract services and professional fees, reflecting hurricane-related spending in 2009.

Logistics Assets Segment

The following table provides summary financial data regarding results of operations of our Logistics segment for the periods indicated:


	Three Months Ended September 30,												Nine Months Ended September 30,
	2010			2009			Change			% Change			2010			2009			Change			% Change
	($ in millions)												($ in millions)
Gross margin (1)	$	43.1		$	39.4		$	3.7			9	%	$	121.5		$	109.9		$	11.6			11	%
Operating expenses		(19.5	)		(18.0	)		1.5			8	%		(68.6	)		(62.4	)		6.2			10	%

Operating margin (2)	$	23.6		$	21.4		$	2.2			10	%	$	52.9		$	47.5		$	5.4			11	%

Operating statistics:
Fractionation volumes, MBbl/d		224.6			225.9			(1.3	)		(1	%)		220.9			215.4			5.5			3	%
Treating volumes, MBbl/d (3)		23.8			27.5			(3.7	)		(13	%)		17.8			18.5			(0.7	)		(4	%)


(1)		Gross margin consists of fee revenue and business interruption proceeds

(2)		Operating margin is revenues less product purchases and operating expenses.

(3)		Consists of the volumes treated in our low sulfur natural gasoline unit.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

The $3.7 million improvement in gross margin was primarily due to fractionation fee improvement.

Operating expenses increased primarily due to higher fuel and electricity expenses of $2.5 million driven by higher gas prices, higher compensation costs of $0.9 million, partially offset by favorable system product gains of $1.6 million.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $11.6 million improvement in gross margin reflects higher fractionation fees of $15.1 million, offset by lower terminalling and storage revenues of $1.0 million. During 2009, we received $1.9 million in business interruption proceeds.

Operating expenses increased due to higher fuel and electricity expense of $5.8 million primarily driven by higher gas prices and higher compensation costs of $3.2 million, which were partially offset by favorable system product gains of $3.3 million.

Marketing and Distribution Segment

The following table provides summary financial data regarding results of operations of our Marketing and Distribution segment for the periods indicated:


	Three Months Ended September 30,												Nine Months Ended September 30,
	2010			2009			Change			% Change			2010			2009			Change			% Change
	($ in millions)												($ in millions)
Gross margin	$	26.4		$	26.5		$	(0.1	)		—		$	82.3		$	89.5		$	(7.2	)		(8	%)
Operating expenses		(11.4	)		(11.9	)		(0.5	)		(4	%)		(33.5	)		(35.9	)		(2.4	)		(7	%)

Operating margin (1)	$	15.0		$	14.6		$	0.4			3	%	$	48.8		$	53.6		$	(4.8	)		(9	%)

Operating statistics:
Natural gas sales, Bbtu/d		612.6			561.9			50.7			9	%		630.1			497.7			132.4			27	%
NGL sales, MBbl/d		242.9			266.6			(23.7	)		(9	%)		241.3			281.4			(40.1	)		(14	%)
Natural gas realized price, $/MMBtu		4.22			3.17			1.05			33	%		4.50			3.46			1.04			30	%
NGL realized price, $/gal		0.95			0.81			0.14			17	%		1.06			0.72			0.34			47	%


(1)		Operating margin is revenues less product purchases and operating expenses.

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

Gross margin was flat for the quarter, reflecting the impact of higher commodity prices on revenues ($184.0 million) and increased natural gas volumes ($14.8 million), offset by lower NGL volumes ($74.4 million) and increased product purchases ($125.2 million).

Natural gas sales volumes were higher due to increased purchases for resale. NGL sales volumes were lower due to a change in contract terms with a petrochemical supplier that has a minimal impact to gross margin.

Operating expenses were relatively flat versus the prior quarter.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

The $7.2 million decrease in gross margin reflects increased commodity prices ($1,127.8 million) and higher natural gas volumes ($124.9 million), more than offset by lower NGL volumes ($330.8 million), lower fee-based and other revenues ($20.5 million), lower business interruption proceeds ($0.5 million) and increased product purchases ($893.7 million). Lower 2010 margins on sales at inventory locations were primarily attributable to 2009 sales that were fixed at relatively high 2008 prices, along with higher spot fractionation volumes and associated fees. These items were partially offset by higher marketing fees on contract purchase volumes attributable to higher 2010 market prices. Margins on transportation activity decreased due to the expiration of a barge contract partially offset by increased truck activity.

The decrease in operating expenses was primarily due to lower outside services of $5.5 million, partially offset by higher maintenance and supplies expenses of $2.6 million and higher compensation costs of $0.5 million. Factors contributing to the decrease were the expiration of a barge contract, partially offset by increased truck utilization.

Other

Three Months Ended September 30, 2010 Compared to Three Months Ended September 30, 2009

During 2010 and 2009, the settlement of our commodity derivatives resulted in $7.1 million and $16.7 million in additional revenue (cash and non-cash) from our hedge counterparties, which were recorded as an increase to gross

margin from hedge settlements during the quarters. Cash receipts or payments on our hedge settlements are due to the contracted price of our hedge contracts falling above or below the market prices of the commodity settled.

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

During 2010 and 2009, the settlement of our commodity derivatives resulted in $7.0 million and $36.6 million in additional revenue (cash and non-cash) from our hedge counterparties, which were recorded as an increase to gross margin from hedge settlements during the quarters. Cash receipts or payments on our hedge settlements are due to the contracted price of our hedge contracts falling above or below the market prices of the commodity settled.

Liquidity and Capital Resources

The ability to finance our operations, including funding capital expenditures and acquisitions, to meet indebtedness obligations, to refinance indebtedness or to meet collateral requirements depends on our ability to generate cash in the future. The 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 ongoing efforts to manage operating costs and maintenance capital expenditures as well as general economic, financial, competitive, legislative, regulatory and other factors. See “Item 1A. Risk Factors” in this Quarterly Report, our Annual Report, and the Updated 8-K.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our credit facility, the issuance of additional equity and access to debt markets. The capital markets continue to experience volatility. Many financial institutions have or have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit conditions includes our credit facility, cash investments and counterparty performance risks. Continued volatility in the debt 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.

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 or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a material adverse effect on our results of operation. We sell our natural gas, NGLs 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. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2013 (see Note 13 of the Notes to Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report). Market conditions may also impact our ability to enter into future commodity derivative contracts. In the event of a continuing global recession, commodity prices may stay depressed or fall further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

As of September 30, 2010, our liquidity of $299.7 million consisted of $54.5 million of available cash and $245.2 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the lenders in our credit facility. On July 19, 2010, we entered into an amended and restated credit agreement that replaced our existing variable rate senior secured credit facility with a new variable rate senior secured credit facility due July 2015. The new senior secured credit facility increases available commitments to $1.1 billion, an allows us to request increases in commitments up to an additional $300 million. The amended and restated credit agreement increased our availability by $141.5 million.

Our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures, with remaining amounts being distributed in accordance with our distribution policy. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated

cash flow and borrowings available under our senior secured credit facility should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, long-term indebtedness obligations, collateral requirements and minimum quarterly cash distributions for at least the next twelve months.

A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status, as determined by Moody’s Investors Service, Inc. and Standard and Poor’s Rating Service, and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of September 30, 2010, our total outstanding letter of credit postings were $101.5 million.

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). As of September 30, 2010, such annual minimum amounts payable to non-Targa unitholders total approximately $86.3 million. 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 debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 10 and Note 11 of the Notes to Consolidated Financial Statements included in Part I, 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, 2010, we had a positive working capital balance of $57.9 million.

Contractual Obligations. As of September 30, 2010, except for changes in the ordinary course of our business, our contractual obligations have not changed materially from those reported in our Annual Report.

Cash Flow. Net cash provided by or used in operating activities, investing activities and financing activities for the nine months ended September 30, 2010 and 2009 were as follows:


	Nine Months Ended September 30,
	2010			2009			$ Change			% Change
	(In millions)
Net cash provided by (used in):
Operating activities	$	240.0		$	303.6		$	(63.6	)		(21	%)
Investing activities		(80.4	)		(74.0	)		(6.4	)		(9	%)
Financing activities		(196.0	)		(296.0	)		100.0			34	%

Operating Activities

The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges as presented in the Consolidated Statements of Cash Flows included in these financial statements and related notes thereto and changes in working capital as discussed above under “— Liquidity and Capital Resources — Working Capital.” We expect our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months.

For the nine months ended September 30, 2010 compared to 2009, net cash provided by operating activities decreased $63.6 million primarily due to the following:

•

an increase in net income of $117.0 million

•

a decrease in interest expense associated with affiliate and allocated debt of $61.7 million

•

a decrease in non-cash risk management activities of $76.6 million due to higher average future prices on commodity valuations

•

a decrease in the change in operating assets and liabilities of $45.6 million, primarily driven by higher payable and receivable balances in 2009.

Investing Activities

Net cash used in investing activities increased $6.4 million for the nine months ended September 30, 2010 compared to 2009 due to increased outlays for property, plant and equipment.

Financing Activities

Net cash used in financing activities decreased $100.0 million for the nine months ended September 30, 2010 compared to 2009 primarily due to the following:

•

an increase in repayment of affiliated and allocated indebtedness of $342.8 million, related to our purchase of the Permian and Versado Systems, the Coastal Straddles and the Venice Operations from Targa in 2010, compared to the purchase of Targa’s Downstream Businesses in 2009

•

an increase in distributions to our unitholders of $38.8 million

•

deemed distributions to our parent increased $46.6 million primarily due to the purchase of assets from Targa, which were treated as acquisitions of assets under common control

•

an increase in net borrowings under our credit facility of $251.4 million

•

an increase in proceeds from equity offerings of $214.3 million

•

an increase in proceeds from note offerings of $12.6 million

•

no repurchases of Senior Notes in 2010, compared to $18.9 million of purchases in 2009

Capital Requirements

The following table lists gross additions to property, plant and equipment; cash flows used in property, plant and equipment additions; and the difference, which is primarily settled accruals:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010		2009			2010			2009
	(In millions)
Gross additions to property, plant and equipment	$	36.1	$	18.8		$	80.6		$	72.3
Non-cash additions to property, plant and equipment		0.1		—			(0.4	)		(9.8	)
Change in accruals		0.3		(0.9	)		2.3			9.5

Cash expenditures	$	36.5	$	19.7		$	82.5		$	72.0

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 2010 related to the expansion of our natural gas gathering and processing infrastructure and our logistics assets.

We categorize our capital expenditures as either: (i) expansion expenditures or (ii) maintenance expenditures. Expansion expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs or enhance revenues. 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.

The following table shows the breakout of our capital expenditures between expansion expenditures and maintenance expenditures:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(In millions)
Capital expenditures:
Expansion	$	23.2	$	10.8	$	52.1	$	38.9
Maintenance		12.9		8.0		28.5		33.4

	$	36.1	$	18.8	$	80.6	$	72.3

Our planned capital expenditures for 2010 are approximately $145 million with maintenance capital expenditures accounting for approximately 35%. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that over time 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 revolving credit facility, the issuance of additional partnership units and debt offerings.

Non-GAAP Financial Measures

Gross Margin. With respect to our Natural Gas Gathering and Processing segments, we define gross margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. With respect to our Logistics Assets segment we define gross margin as total revenue, which consists primarily of service fee revenue. With respect to our Marketing and Distribution segment, we define gross margin as total revenue, which consists primarily of service fee revenues and NGL sales, less cost of sales, which consists primarily of NGL purchases and changes in inventory valuation.

Operating Margin. With respect to our Natural Gas Gathering and Processing segments, our Logistics Assets segment and our Marketing and Distribution segment, we define operating margin as gross margin less operating expense.

The GAAP measure most directly comparable to gross margin and operating margin is net income. The non-GAAP financial measures of gross margin and operating margin should not be considered as an alternative to GAAP net income. Gross margin and operating margin are not presentations made in accordance with GAAP and have important limitations as analytical tools. You should not consider gross margin and operating margin in isolation or

as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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

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, 2010 and 2009:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions)
Reconciliation of net cash provided by (used in) operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	60.8		$	114.3		$	240.0		$	303.6
Net income attributable to noncontrolling interest		(4.6	)		(5.6	)		(18.2	)		(11.9	)
Interest expense, net (1)		22.4			13.5			52.8			31.4
Current income tax expense		1.8			(0.3	)		3.6			—
Other		(6.0	)		(5.4	)		(11.7	)		(11.1	)
Changes in operating working capital which used (provided) cash:		—			—			—			—
Accounts receivable and other		26.6			(27.3	)		(40.3	)		(17.6	)
Accounts payable and other liabilities		(9.6	)		9.7			52.5			(15.8	)

Adjusted EBITDA	$	91.4		$	98.9		$	278.7		$	278.6


(1)		Net of amortization of debt issuance costs of $0.9 million and $3.6 million for the three and nine months ended 2010 and $2.5 million and $3.8 million for the three and nine months ended 2009. Excludes affiliate and allocated interest expense.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions)
Reconciliation of net income (loss) attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)	$	73.2		$	(37.5	)
Add:
Interest expense, net		27.2			45.5			85.8			126.3
Income tax expense		1.7			(0.2	)		3.9			0.9
Depreciation and amortization expense		43.3			43.1			128.3			125.0
Non-cash loss related to mark-to-market derivative instruments		7.8			17.1			(5.4	)		71.2
Noncontrolling interest adjustment		(2.4	)		(2.4	)		(7.1	)		(7.3	)

Adjusted EBITDA	$	91.4		$	98.9		$	278.7		$	278.6

Distributable Cash Flow. We define distributable cash flow as net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for non-cash losses/(gains) related to mark-to-market derivative instruments and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). The impact of noncontrolling interests is included in our measure. Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks, research analysts and others to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by the board of directors of our general partner) to the cash distributions we expect to pay our unitholders. Using this metric, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder).

The economic substance behind our use of distributable cash flow is to measure the ability of our assets to generate cash flow sufficient to make distributions to our investors.

The GAAP measure most directly comparable to distributable cash flow is net income attributable to Targa Resources Partners LP. Distributable cash flow should not be considered as an alternative to GAAP net income. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be compatible to similarly titled measures of other companies, thereby diminishing its utility.

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In millions)
Reconciliation of net income (loss) attributable to Targa Resources Partners LP to distributable cash flow:
Net income (loss) attributable to Targa Resources Partners LP	$	13.8		$	(4.2	)		73.2		$	(37.5	)
Add:
Allocated and affiliate interest expense		3.9			29.4			29.4			91.1
Depreciation and amortization expense		43.3			43.1			128.3			125.0
Deferred income tax (expense) benefit		(0.1	)		0.1			0.3			0.9
Amortization of debt issue costs		0.9			2.5			3.6			3.8
Extinguishment of debt issue costs		0.8			0.4			0.8			0.4
Non-cash loss related to mark-to-market derivative instruments		7.8			17.1			(5.4	)		71.2
Maintenance capital expenditures		(12.9	)		(8.0	)		(28.5	)		(33.4	)
Reimbursements		0.4			—			0.4			—
Other		(0.8	)		(1.6	)		(3.3	)		(4.7	)

Distributable cash flow	$	57.1		$	78.8			198.8		$	216.8

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. Please see the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change depreciation amounts prospectively. Examples of such circumstances include:

•

changes in energy prices;

•

changes in competition;

•

changes in laws and regulations that limit the estimated economic life of an asset;

•

changes in technology that render an asset obsolete;

•

changes in expected salvage values; or

•

changes in the forecast life of applicable resource basins, if any.

As of September 30, 2010, the net book value of property, plant and equipment was $2,480.0 million and we recorded $43.3 million and $128.3 million in depreciation and amortization expense for the three and nine months ended September 30, 2010. The weighted-average life of long-lived assets is approximately 20 years. If the useful lives of these assets were found to be shorter than originally estimated, depreciation and amortization expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result. For example, if the depreciable lives of assets were reduced by 10%, we estimate that depreciation and amortization expense would increase by $14.3 million, which would result in a corresponding reduction in operating income. In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, operating income would decrease by $24.8 million. There have been no material changes impacting estimated useful lives of the assets.

Revenue Recognition. Revenues for a period reflect collections to the report date, plus any uncollected revenues reported for the period, which are reflected as accounts receivable in the balance sheet. As of September 30, 2010, the balance sheet reflects total accounts receivable of $351.0 million, which is due from third-parties. The allowance for doubtful accounts as of September 30, 2010 was $7.6 million.

Exposure to uncollectible accounts receivable relates to the financial health of our counterparties. We and our indirect parent, Targa, have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectibility resulted in a 1% reduction of third-party accounts receivable, operating income would decrease by $3.5 million. There have been no material changes impacting accounts receivable.

Price Risk Management (Hedging). Net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of cash flows, we have entered into (i) derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities and (ii) interest rate financial instruments to fix the interest rate on a portion of our variable debt. We are exposed to the credit risk of our counterparties in these derivative financial instruments.

Our cash flow is affected by the derivative financial instruments we enter into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.

One of the primary factors that can affect our financial position each period is the price assumptions we use to value derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.

The estimated fair value of our commodity derivative financial instruments was $41.9 million as of September 30, 2010, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities, by year, for each counterparty’s traded credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to $0.4 million as of September 30, 2010. If a financial instrument counterparty were to declare bankruptcy, we would be exposed to the loss of fair value of the financial instrument transaction with that counterparty. Ignoring our adjustment for credit risk, if a bankruptcy by a financial instrument counterparty impacted 10% of the fair value of commodity-based financial instruments, we estimate that operating income would decrease by $4.2 million per year.


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 as supplemented by the Recast 8-K.

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

Commodity Price Risk. A majority of the revenues from our natural gas gathering and processing business are 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 market 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 commodity derivative 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.

Our commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form with customized credit and legal terms. Our principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. 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 indebtedness 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.

In an effort to reduce the variability of our cash flows we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market 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.

As of September 30, 2010, we had the following hedge arrangements which will settle during the years ending December 31, 2010 through 2013 (except as indicated otherwise, the 2010 volumes reflect daily volumes for the period from October 1, 2010 through December 31, 2010):


Natural Gas
Instrument		Price		MMBtu per day
Type	Index	$/MMBtu		2010		2011		2012		2013		Fair Value
												(In millions)
Swap	IF-WAHA		6.61		28,509		—		—		—	$	7.5

Swap	IF-WAHA		6.29		—		23,750		—		—		17.9

Swap	IF-WAHA		6.61		—		—		14,850		—		9.6
Swap	IF-WAHA		5.59		—		—		—		4,000		0.8


					28,509		23,750		14,850		4,000


Swap	IF-PB		5.42		2,000		—		—		—		0.3
Swap	IF-PB		5.42		—		2,000		—		—		0.9
Swap	IF-PB		5.54		—		—		4,000		—		1.1
Swap	IF-PB		5.54		—		—		—		4,000		0.9

					2,000		2,000		4,000		4,000


Swap	IF-NGPL MC		8.94		5,637		—		—		—		2.7
Swap	IF-NGPL MC		6.87		—		4,350		—		—		4.3
Swap	IF-NGPL MC		6.82		—		—		4,250		—		3.1

					5,637		4,350		4,250		—


					36,146		30,100		23,100		8,000



Natural Gas Basis Swaps
Basis Swaps	Various Indexes, Maturities October 2010- May 2011												0.5
Swaps	Various Indexes, Maturities October 2010-May 2011												(0.1	)
												$	49.5


NGL
Instrument		Price		Barrels per day
Type	Index	$/Bbl		2010		2011		2012		2013		Fair Value
												(In millions)
Swap	OPIS_MB		1.06		9,064		—		—		—	$	1.7
Swap	OPIS_MB		0.85		—		7,000		—		—		(5.0	)
Swap	OPIS_MB		0.89		—		—		4,650		—		(0.4	)

Total Swaps					9,064		7,000		4,650		—


Floor	OPIS_MB		1.44		—		253		—		—		1.3
Floor	OPIS_MB		1.43		—		—		294		—		1.6

Total Floors					—		253		294		—


Total Sales					9,064		7,253		4,944		—

												$	(0.8	)


Condensate
Instrument		Price		Barrels per day
Type	Index	$/Bbl		2010		2011		2012		2013		Fair Value
												(In millions)
Swap	NY-WTI		71.76		851		—		—		—	$	(0.7	)
Swap	NY-WTI		77.00		—		750		—		—		(2.1	)
Swap	NY-WTI		72.60		—		—		400		—		(2.1	)
Swap	NY-WTI		73.90		—		—		—		400		(2.0	)

Total Swaps					851		750		400		400	$	(6.9	)

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant 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. We determine the value of our NGL 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.

As of September 30, 2010, we had the following open interest rate swaps:


Period	Fixed Rate			Notional Amount	Fair Value
					(In millions)
Remainder of 2010		3.67	%	$300 million	$	(2.6	)
2011		3.52	%	300 million		(7.7	)
2012		3.38	%	300 million		(7.9	)
2013		3.39	%	300 million		(5.8	)
1/1 - 4/24/2014		3.39	%	300 million		(2.0	)

					$	(26.0	)

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 interest rate swaps and interest rate basis swaps, would increase annual interest expense by $4.5 million.

Counterparty Risk – Credit and Concentration

Derivative Counterparty Risk. Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.

We have master agreements with most of our hedge counterparties. These netting agreements allow us to net settle asset and liability positions with the same counterparty. As of September 30, 2010, we had $26.0 million in liabilities to offset the default risk of counterparties with which we also had asset positions of $42.2 million as of that date.

As of September 30, 2010, affiliates of Barclays, Goldman Sachs and BP accounted for 47%, 20% and 18% of our counterparty credit exposure related to commodity derivative instruments. Barclays, and Goldman Sachs are major financial institutions, BP is a major industrial company, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

Customer Credit Risk. We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.

Item 4. 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 design and 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 our disclosure controls and procedures were designed at the reasonable assurance level and, as of the end of the period covered by this report, our disclosure controls and procedures are effective at the reasonable assurance level to provide that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the nine months ended September 30, 2010 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 15—Commitments and Contingencies, under the heading “Legal Proceeding” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, 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, 2009 as supplemented in our Quarterly Reports for the periods ending March 31, 2010 and June 30, 2010. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations, as could the following:

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on the Partnership’s ability to hedge risks associated with its business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require the Partnership to comply with margin requirements in connection with its derivative activities, although the application of those provisions to the Partnership is uncertain at this time. The financial reform legislation also requires many counterparties to the Partnership’s derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including those requirements to post collateral which could adversely affect the Partnership’s available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Partnership encounters, reduce the Partnership’s ability to monetize or restructure its existing derivative contracts, and increase the Partnership’s exposure to less creditworthy counterparties. If the Partnership reduces its use of derivatives as a result of the legislation and regulations, its results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect its ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. The Partnership’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Partnership, its financial condition, and its results of operations.

Recent events in the Gulf of Mexico may adversely affect the operations of the Partnership.

On April 20, 2010, the Transocean Deepwater Horizon drilling rig exploded and subsequently sank 130 miles south of New Orleans, Louisiana, and the resulting release of crude oil into the Gulf of Mexico was declared a Spill of National Significance by the United States Department of Homeland Security. The Partnership cannot predict with any certainty the impact of this oil spill, the extent of cleanup activities associated with this spill, or possible changes in laws or regulations that may be enacted in response to this spill, but this event and its aftermath could adversely affect the Partnership’s operations. It is possible that the direct results of the spill and clean-up efforts could interrupt certain offshore production processed by our facilities. Furthermore, additional governmental regulation of, or delays in issuance of permits for, the offshore exploration and production industry may negatively impact current or future volumes being gathered or processed by the Partnership’s facilities, and may potentially reduce volumes in its downstream logistics and marketing business.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact the Partnership’s revenues by decreasing the volumes of natural gas that the Partnership gathers, processes and fractionates.

Hydraulic fracturing is a process used by oil and gas exploration and production operators in the completion of certain oil and gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate gas and, to a lesser extent, oil production. Due to concerns that hydraulic fracturing may adversely affect drinking water supplies, the U.S. Environmental Protection Agency (“EPA”) recently announced its plan to conduct a comprehensive research study to investigate the potential adverse impact that hydraulic fracturing may have on water quality and public health. The initial study results are expected to be available in late 2012. Additionally, legislation has been introduced in the U.S. Congress to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. If enacted, such a provision could require hydraulic fracturing activities to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping requirements and meet plugging and abandonment requirements. In unrelated oil spill legislation being considered by the U.S. Senate in the aftermath of the April 2010 Macondo well release in the Gulf of Mexico, an amending provision has been prepared that would require natural gas drillers to disclose the chemicals they pump into the ground as part of the hydraulic fracturing process. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. Adoption of legislation or of any implementing regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect the Partnership’s revenues and results of operations by decreasing the volumes of natural gas that it gathers, processes and fractionates.

A change in the jurisdictional characterization of some of the Partnership’s assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of the Partnership’s assets, which may cause its revenues to decline and operating expenses to increase.

Venice Gathering System, L.L.C. (“VGS”) is a wholly owned subsidiary of VESCO engaged in the business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”). VGS owns and operates a natural gas gathering system extending from South Timbalier Block 135 to an onshore interconnection to a natural gas processing plant owned by VESCO. With the exception of our interest in VGS, our operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses. The NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. The Partnership believes that the natural gas pipelines in its gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of the Partnership’s gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. In addition, the courts have determined that certain pipelines that would otherwise be subject to the ICA are exempt from regulation by FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classification and regulation of some of the Partnership’s gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress.

While the Partnerships’ natural gas gathering operations are generally exempt from FERC regulation under the NGA, its gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. FERC has issued a final rule (as amended by orders on rehearing and clarification), Order 704, requiring certain participants in the natural gas market, including intrastate pipelines, natural gas gatherers, natural gas marketers and natural gas processors, that engage in a minimum level of natural gas sales or purchases to submit annual reports regarding those transactions to FERC. In June 2010, FERC issued an Order granting clarification regarding Order 704.

In addition, FERC has issued a final rule, (as amended by orders on rehearing and clarification), Order 720, requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has design capacity equal to or greater than 15,000 MMBtu/d and requiring interstate pipelines to post information regarding the provision of no-notice service. The Partnership takes the position that at this time Targa Louisiana Intrastate LLC is exempt from this rule.

In addition, FERC recently extended certain of the open-access requirements including the prohibition on buy/sell arrangements and shipper-must-have-title provisions to include Hinshaw pipelines to the extent such pipelines provide interstate service. Requests for rehearing on this requirement are pending. However, since Targa Louisiana Intrastate LLC does not provide interstate service pursuant to any limited blanket certificate, these requirements do not apply.

Other FERC regulations may indirectly impact the Partnership’s businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for the natural gas and NGL services the Partnership provides.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to proceed with the adoption and implementation of regulations restricting emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted two sets of regulations under the Clean Air Act that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. Moreover, on October 30, 2009, the EPA published a “Mandatory Reporting of Greenhouse Gases” final rule that establishes a new comprehensive scheme requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually on a facility-by-facility basis. On April 12 2010, the EPA proposed to expand its existing GHG reporting rule to include owners and operators of onshore oil and natural gas production, processing, transmission, storage and distribution facilities. If the proposed rule is finalized in its current form, reporting of GHG emissions from such onshore activities would be required on an annual basis beginning in 2012 for emissions occurring in 2011.

In addition, both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and NGL fractionation plants, to acquire and surrender emission allowances with the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. The adoption of legislation or regulations imposing reporting or permitting obligations on, or limiting emissions of GHGs from, the Partnership’s equipment and operations could require it to incur additional costs to reduce emissions of GHGs associated with its operations, could adversely affect its performance of operations in the absence of any permits that may be required to regulate emission of greenhouse gases, or could adversely affect demand for the natural gas it gathers, treats or otherwise handles in connection with its services.

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

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. (Removed and Reserved).

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.


Exhibit
Number		Description
2.1*		Purchase and Sale Agreement, dated as of August 6, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303).

2.2*		Purchase and Sale Agreement, dated as of September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303).

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)).

4.1		Indenture dated as of August 13, 2010 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).

4.2		Registration Rights Agreement dated as of August 13, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303).

4.3**		Supplemental Indenture dated September 20, 2010 to Indenture dated June 18, 2008, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.4**		Supplemental Indenture dated September 20, 2010 to Indenture dated July 6, 2009, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.5**		Supplemental Indenture dated September 20, 2010 to Indenture dated August 13, 2010, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.


Exhibit
Number		Description
4.6**		Supplemental Indenture dated October 25, 2010 to Indenture dated June 18, 2008, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.7**		Supplemental Indenture dated October 25, 2010 to Indenture dated July 6, 2009, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.8**		Supplemental Indenture dated October 25, 2010 to Indenture dated August 13, 2010, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.1		Amended and Restated Credit Agreement, dated July 19, 2010, by and among Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 21, 2010 (file No. 001-33303)).

10.2		Purchase Agreement dated as of August 10, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (file No. 001-33303)).

10.3		Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 26, 2010 (file No. 001-33303)).

10.4		Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 4, 2010 (file No. 001-33303)).

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.


*		Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

**		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 5, 2010

Exhibit Index


Exhibit
Number		Description
2.1*		Purchase and Sale Agreement, dated as of August 6, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303).

2.2*		Purchase and Sale Agreement, dated as of September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303).

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)).

4.1		Indenture dated as of August 13, 2010 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303)).

4.2		Registration Rights Agreement dated as of August 13, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (File No. 001-33303).

4.3**		Supplemental Indenture dated September 20, 2010 to Indenture dated June 18, 2008, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.4**		Supplemental Indenture dated September 20, 2010 to Indenture dated July 6, 2009, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.5**		Supplemental Indenture dated September 20, 2010 to Indenture dated August 13, 2010, among Targa Versado LP and Targa Versado GP LLC, subsidiaries of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.6**		Supplemental Indenture dated October 25, 2010 to Indenture dated June 18, 2008, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.7**		Supplemental Indenture dated October 25, 2010 to Indenture dated July 6, 2009, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.8**		Supplemental Indenture dated October 25, 2010 to Indenture dated August 13, 2010, among Targa Capital LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

10.1		Amended and Restated Credit Agreement, dated July 19, 2010, by and among Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 21, 2010 (file No. 001-33303)).


Exhibit
Number		Description
10.2		Purchase Agreement dated as of August 10, 2010 among the Issuers, the Guarantors and Banc of America Securities LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 16, 2010 (file No. 001-33303)).

10.3		Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 26, 2010 (file No. 001-33303)).

10.4		Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa Versado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 4, 2010 (file No. 001-33303)).

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.


*		Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

**		Filed herewith

exv4w3

Exhibit 4.3

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”) dated as of September 20, 2010 is among Targa Versado GP LLC, a Delaware limited liability company (“Versado GP”), Targa Versado LP, a Delaware limited partnership (together with Versado GP, the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (“Finance Corporation” and, together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

INTRODUCTION

The Issuers have executed and delivered to the Trustee an indenture (the “Indenture”) dated as of June 18, 2008 providing for the issuance of 8¹/4% Senior Notes due 2016 (the “Notes”).

The Indenture provides that under certain circumstances the Guaranteeing Subsidiaries shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall each unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture (the “Note Guarantee”).

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiaries and the Trustee mutually agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of any Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or any Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

Signature pages follow.

-2-

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.


TARGA VERSADO GP LLC
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA VERSADO LP By: Targa Versado GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS LP By: Targa Resources GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS FINANCE CORPORATION
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer

Signature Page to Supplemental Indenture


	U.S. BANK NATIONAL ASSOCIATION, as Trustee
	By:	/s/ Steven A. Finklea
		Authorized Signatory

Signature Page to Supplemental Indenture

exv4w4

Exhibit 4.4

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”) dated as of September 20, 2010 is among Targa Versado GP LLC, a Delaware limited liability company (“Versado GP”), Targa Versado LP, a Delaware limited partnership (together with Versado GP, the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (“Finance Corporation” and, together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

INTRODUCTION

The Issuers have executed and delivered to the Trustee an indenture (the “Indenture”) dated as of July 6, 2009 providing for the issuance of 11¹/4% Senior Notes due 2017 (the “Notes”).

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.


TARGA VERSADO GP LLC
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA VERSADO LP By: Targa Versado GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS LP By: Targa Resources GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS FINANCE CORPORATION
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer

Signature Page to Supplemental Indenture


	U.S. BANK NATIONAL ASSOCIATION, as Trustee
	By:	/s/ Steven A. Finklea
		Authorized Signatory

Signature Page to Supplemental Indenture

exv4w5

Exhibit 4.5

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”) dated as of September 20, 2010 is among Targa Versado GP LLC, a Delaware limited liability company (“Versado GP”), Targa Versado LP, a Delaware limited partnership (together with Versado GP, the “Guaranteeing Subsidiaries” and each individually, a “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (“Finance Corporation” and, together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

INTRODUCTION

The Issuers have executed and delivered to the Trustee an indenture (the “Indenture”) dated as of August 13, 2010 providing for the issuance of 7 7/8% Senior Notes due 2018 (the “Notes”).

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.


TARGA VERSADO GP LLC
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA VERSADO LP By: Targa Versado GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS LP By: Targa Resources GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS FINANCE CORPORATION
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer

Signature Page to Supplemental Indenture


	U.S. BANK NATIONAL ASSOCIATION, as Trustee
	By:	/s/ Steven A. Finklea
		Authorized Signatory

Signature Page to Supplemental Indenture

exv4w6

Exhibit 4.6

SUPPLEMENTAL INDENTURE

Supplemental Indenture (this “Supplemental Indenture”) dated as of October 25, 2010 is among Targa Capital LLC, a Delaware limited liability company (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (“Finance Corporation” and, together with Targa Resources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

INTRODUCTION

The Issuers have executed and delivered to the Trustee an indenture (the “Indenture”) dated as of June 18, 2008 providing for the issuance of 8¹/4% Senior Notes due 2016 (the “Notes”).

The Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture (the “Note Guarantee”).

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually agree for the equal and ratable benefit of the Holders of the Notes as follows:

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Indenture including Article 10 thereof.

3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of the Guaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

-2-

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.


TARGA CAPITAL LLC
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS LP By: Targa Resources GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS FINANCE CORPORATION
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer

Signature Page to Supplemental Indenture


	U.S. BANK NATIONAL ASSOCIATION, as Trustee
	By:	/s/ Steven A. Finklea
		Authorized Signatory

Signature Page to Supplemental Indenture

exv4w7

EXHIBIT 4.7

SUPPLEMENTAL INDENTURE

INTRODUCTION

The Issuers have executed and delivered to the Trustee an indenture (the “Indenture”) dated as of July 6, 2009 providing for the issuance of 11¹/4% Senior Notes due 2017 (the “Notes”).

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.


TARGA CAPITAL LLC
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS LP By: Targa Resources GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS FINANCE CORPORATION
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer

Signature Page to Supplemental Indenture


	U.S. BANK NATIONAL ASSOCIATION, as Trustee
	By:	/s/ Steven A. Finklea
		Authorized Signatory

Signature Page to Supplemental Indenture

exv4w8

EXHIBIT 4.8

SUPPLEMENTAL INDENTURE

INTRODUCTION

The Issuers have executed and delivered to the Trustee an indenture (the “Indenture”) dated as of August 13, 2010 providing for the issuance of 7 7/8% Senior Notes due 2018 (the “Notes”).

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.

6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.

Signature pages follow.

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.


TARGA CAPITAL LLC
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS LP By: Targa Resources GP LLC, its General Partner
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer


TARGA RESOURCES PARTNERS FINANCE CORPORATION
By:	/s/ Matthew J. Meloy
	Name:	Matthew J. Meloy
	Title:	Vice President — Finance and Treasurer

Signature Page to Supplemental Indenture


	U.S. BANK NATIONAL ASSOCIATION, as Trustee
	By:	/s/ Steven A. Finklea
		Authorized Signatory

Signature Page to Supplemental Indenture

exv31w1

Exhibit 31.1

CERTIFICATIONS

I, Rene R. Joyce, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2010 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-15(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.

Date: November 5, 2010



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)

exv31w2

Exhibit 31.2

CERTIFICATIONS

I, Jeffrey J. McParland, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2010 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-15(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.

Date: November 5, 2010



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)

exv32w1

Exhibit 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

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended September 30, 2010 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, the general partner of the Partnership, 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 5, 2010

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 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

In connection with the Quarterly Report on Form 10-Q of Targa Resources Partners LP (the “Partnership”) for the three months ended September 30, 2010 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, the general partner of the Partnership, 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 5, 2010