Targa Resources Partners (NGLS-PA) 10-Q 2009 Q3 Quarterly report

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, 2009
or
	o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from           to

Commission File Number 001-33303

_____________________

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

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

Registrant’s telephone number, including area code:

(713) 584-1000

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

Indicate by check mark whether the registrant 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).  Yes oNo o

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

Large accelerated filer þ	Accelerated filer o	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) Yes o   No þ

There were 61,639,846 Common Units and 1,257,957 General Partner Units outstanding as of November 1, 2009.

PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008	4
	Consolidated Statements of Operations for the three and nine months ended September 30, 2009 and 2008	5
	Consolidated Statement of Comprehensive Income (Loss) for the three and nine months ended
	September 30, 2009 and 2008	6
	Consolidated Statements of Changes in Owners' Equity for the nine months ended September 30, 2009	7
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008	8
	Notes to Consolidated Financial Statements	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	53
Item 4.	Controls and Procedures	57
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3.	Defaults Upon Senior Securities	61
Item 4.	Submission of Matters to a Vote of Security Holders	61
Item 5.	Other Information	61
Item 6.	Exhibits	62
SIGNATURES		66

1

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

Bbl	Barrels
BBtu	Billion British thermal units, a measure of heating value
/d	Per day
gal	Gallons
MBbl	Thousand barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
Price Index Definitions
IF-CGT	Inside FERC Gas Market Report, Columbia Gulf Transmission, Louisiana
IF-HSC	Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha	Inside FERC Gas Market Report, West Texas Waha
NY-HH	NYMEX, Henry Hub Natural Gas
NY-WTI	NYMEX, West Texas Intermediate Crude Oil
OPIS-MB	Oil Price Information Service, Mont Belvieu, Texas

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

Cautionary Statement About Forward-Looking Statements

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.

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;

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-

· 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;

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· 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 and our Annual Report on Form 10-K for the year ended December 31, 2008 (the “Annual Report”).

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 under the heading Risk Factors in this Quarterly Report and our Annual Report. 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.

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PART I — FINANCIAL INFORMATION

Item 1.  Financial Statements

TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
	2009			2008
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	57,766		$	95,308
Trade receivables, net of allowances of $1,950 and $2,207		251,332			236,137
Inventory		42,251			72,183
Assets from risk management activities		48,472			91,816
Other current assets		509			782
Total current assets		400,330			496,226
Property, plant and equipment, at cost		2,083,138			2,036,378
Accumulated depreciation		(392,752	)		(317,322	)
Property, plant and equipment, net		1,690,386			1,719,056
Long term assets from risk management activities		18,860			68,296
Investment in unconsolidated affiliate		17,811			18,465
Other assets		20,931			12,776
Total assets	$	2,148,318		$	2,314,819
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable to third parties	$	123,648		$	138,745
Accounts payable to affiliates		84,549			17,227
Accrued liabilities		83,730			104,112
Liabilities from risk management activities		10,903			11,664
Total current liabilities		302,830			271,748
Long term debt payable to third parties		939,424			696,845
Long term debt payable to Targa Resources, Inc.		-			773,883
Long term liabilities from risk management activities		15,645			9,679
Deferred income taxes		3,559			3,337
Other long-term liabilities		6,501			6,239
Commitments and contingencies (see Note 15)
Owners' equity:
Common unitholders (61,639,846 and 34,652,000 units issued and
outstanding as of  September 30, 2009 and December 31, 2008)		847,663			769,921
Subordinated unitholders (11,528,231 units issued and outstanding as of
December 31, 2008)		-			(85,185	)
General partner (1,257,957 and 942,455 units issued and outstanding as of
September 30, 2009 and December 31, 2008)		9,804			5,556
Net parent investment		-			(223,534	)
Accumulated other comprehensive income		9,361			72,238
		866,828			538,996
Noncontrolling interest in subsidiary		13,531			14,092
Total owners' equity		880,359			553,088
Total liabilities and owners' equity	$	2,148,318		$	2,314,819
See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(Unaudited)
	(In thousands, except per unit amounts)
Revenues from third parties	$	961,269		$	2,079,737		$	2,682,044		$	6,001,098
Revenues from affiliates		42,509			135,114			140,240			413,466
Total operating revenues		1,003,778			2,214,851			2,822,284			6,414,564
Costs and expenses:
Product purchases from third parties		676,139			1,791,858			1,966,793			5,042,268
Product purchases from affiliates		198,089			318,570			492,503			943,187
Operating expenses		40,866			51,663			123,023			149,159
Operating expenses from affiliates		6,608			16,592			19,073			48,531
Depreciation and amortization expenses		25,597			24,431			75,490			72,785
General and administrative expenses		17,078			19,116			55,474			57,433
Casualty loss adjustment		-			-			(845	)		-
Gain on sale of assets		(1	)		(13	)		(7	)		(4,440	)
		964,376			2,222,217			2,731,504			6,308,923
Income (loss) from operations		39,402			(7,366	)		90,780			105,641
Other income (expense):
Interest expense from affiliate		(13,701	)		(14,832	)		(43,414	)		(44,400	)
Other interest expense, net		(16,097	)		(10,617	)		(35,344	)		(27,175	)
Equity in earnings of unconsolidated investment		1,417			1,102			3,221			3,028
Loss on debt repurchases (See Note 9)		(1,483	)		-			(1,483	)		-
Other		1,132			(5,700	)		1,831			(5,535	)
		(28,732	)		(30,047	)		(75,189	)		(74,082	)
Income (loss) before income taxes		10,670			(37,413	)		15,591			31,559
Income tax (expense) benefit:
Current		308			(145	)		-			(436	)
Deferred		(88	)		(502	)		(800	)		(1,406	)
		220			(647	)		(800	)		(1,842	)
Net income (loss)		10,890			(38,060	)		14,791			29,717
Less: Net income attributable to noncontrolling interest		888			162			1,179			91
Net income (loss) attributable to Targa Resources Partners LP	$	10,002		$	(38,222	)	$	13,612		$	29,626
Net loss attributable to predecessor operations	$	(4,208	)	$	(52,914	)	$	(2,377	)	$	(38,207	)
Net income attributable to general partner		2,809			294			6,765			5,524
Net income allocable to limited partners		11,401			14,398			9,224			62,309
Basic and diluted net income per limited partner unit	$	0.23		$	0.31		$	0.19		$	1.35
Basic and diluted weighted average limited partner units
outstanding		50,611			46,180			47,692			46,175
See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(Unaudited)
	(In thousands)
Net income (loss)	$	10,890		$	(38,060	)	$	14,791		$	29,717
Other comprehensive income (loss):
Commodity hedges:
Change in fair value		(10,141	)		185,008			(31,043	)		(35,221	)
Reclassification adjustment for settled periods		(16,675	)		19,985			(36,578	)		49,696
Interest rate hedges:
Change in fair value		(7,570	)		(1,698	)		(3,096	)		(1,968	)
Reclassification adjustment for settled periods		2,718			869			7,840			1,485
Foreign currency translation adjustment		(463	)		(235	)		-			(477	)
Other comprehensive income (loss)		(32,131	)		203,929			(62,877	)		13,515
Comprehensive income (loss)		(21,241	)		165,869			(48,086	)		43,232
Less: Comprehensive income attributable to
noncontrolling interest		888			162			1,179			91
Comprehensive income (loss) attributable to
Targa Resources Partners LP	$	(22,129	)	$	165,707		$	(49,265	)	$	43,141
See notes to consolidated financial statements

6

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
	Partners' Capital									Accumulated
										Other			Net
	Limited Partners						General			Comprehensive			Parent			Noncontrolling
	Common			Subordinated			Partner			Income			Investment			Interest			Total
	(Unaudited)
	(In thousands)
Balance, December 31, 2008	$	769,921		$	(85,185	)	$	5,556		$	72,238		$	(223,534	)	$	14,092		$	553,088
Issuance of common units:
Equity offering		103,470			-			2,216			-			-			-			105,686
Acquisition related		129,850			-			2,650			-			-			-			132,500
Contribution under common control		(8,122	)		-			-			-			7,322			-			(800	)
Distributions to Parent		-			-			-			-			(68,707	)		-			(68,707	)
Settlement of affiliated indebtedness		-			-			-			-			287,296			-			287,296
Distributions to noncontrolling interest		-			-			-			-			-			(1,740	)		(1,740	)
Amortization of equity awards		249			-			-			-			-			-			249
Other comprehensive loss		-			-			-			(62,877	)		-			-			(62,877	)
Conversion of subordinated units		(97,624	)		97,624			-			-			-			-			-
Net income (loss)		9,732			(508	)		6,765			-			(2,377	)		1,179			14,791
Distributions to unitholders		(59,813	)		(11,931	)		(7,383	)		-			-			-			(79,127	)
Balance, September 30, 2009	$	847,663		$	-		$	9,804		$	9,361		$	-		$	13,531		$	880,359
See notes to consolidated financial statements

7

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended September 30,
	2009			2008
	(Unaudited)
	(In thousands)
Cash flows from operating activities
Net income	$	14,791		$	29,717
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization in interest expense		2,487			1,495
Amortization in general and administrative expense		249			200
Depreciation and other amortization expense		75,490			72,785
Interest expense on affiliate indebtedness		43,414			44,400
Accretion of asset retirement obligations		308			259
Deferred income tax expense		800			1,406
Equity in earnings of unconsolidated investments, net of distributions		654			(316	)
Risk management activities		33,826			(75,747	)
Loss on debt repurchases		1,483			-
Gain on sale of assets		(7	)		(4,440	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		(14,667	)		138,456
Inventory		20,155			21,600
Accounts payable and other liabilities		40,940			(101,235	)
Net cash provided by operating activities		219,923			128,580
Cash flows from investing activities
Additions to property, plant and equipment		(46,327	)		(55,335	)
Other, net		82			183
Net cash used in investing activities		(46,245	)		(55,152	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		397,618			87,500
Repayments on credit facility		(374,900	)		(323,800	)
Proceeds from issuance of senior notes		237,433			250,000
Repurchases of senior notes		(18,882	)		-
Repayment of affiliated indebtedness		(397,500	)		-
Proceeds from equity offerings		103,470			-
Distributions to unitholders		(79,127	)		(64,574	)
General partner contributions		2,216			8
Costs incurred in connection with public offerings		(164	)		-
Costs incurred in connection with financing arrangements		(9,558	)		(7,079	)
Distributions to noncontrolling interest		(1,740	)		-
Parent distributions		(70,086	)		(36,183	)
Net cash used in financing activities		(211,220	)		(94,128	)
Net change in cash and cash equivalents		(37,542	)		(20,700	)
Cash and cash equivalents, beginning of period		95,308			64,342
Cash and cash equivalents, end of period	$	57,766		$	43,642
See notes to consolidated financial statements

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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 thousands of dollars.

Note 1—Organization and Basis of Presentation

Targa Resources Partners LP is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). 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 common units are listed on The NASDAQ Stock Market LLC under the symbol “NGLS.” Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”).

On September 24, 2009, we acquired Targa’s interests in Targa Downstream GP LLC, Targa LSNG GP LLC, Targa Downstream LP and Targa LSNG LP (collectively, the “Downstream Business”) in a transaction among entities under common control. Accordingly, these consolidated financial statements include the historical results of the Downstream Business.

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. The unaudited consolidated financial statements for the three and nine months ended September 30, 2009 and 2008 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair statement of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Transactions between us and other Targa operations have been identified in the unaudited consolidated financial statements as transactions between affiliates (see Note 17). Our financial results for the three and nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2009. 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 Annual Report.

The noncontrolling interest in our consolidated balance sheets consists primarily of the investment by entities other than the partners of Targa Resources Partners LP, including those entitie's share of net income, distributions and accumulated other comprehensive income (loss) of the Partnership. Noncontrolling interest in net income on our consolidated statements of operations consist primarily of those entities share of the net income of the Partnership.

In preparing the accompanying unaudited consolidated financial statements, the Partnership has reviewed, as determined necessary by the Partnership’s general partner, events that have occurred after September 30, 2009, up until the issuance of the financial statements, which occurred on November 9, 2009. See Note 6.

Note 2—Out of Period Adjustment

We recorded an adjustment related to prior periods which increased our revenue, income before income taxes and net income for the three and nine month periods ended September 30, 2009, by $1.8 million. The adjustment related to natural gas sales transactions which occurred during 2006.

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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 the adjustment during the third quarter of 2009 on full year 2009 are not expected to be material.

Note 3—Accounting Policies and Related Matters

Accounting Policy Updates/Revisions

 Exchanges. Exchanges are movements of NGL products between parties to satisfy timing and logistical needs of the parties. Volumes received and delivered under exchange agreements are recorded as inventory. If the locations of receipt and delivery are in different markets, a price differential may be billed or owed. The price differential is recorded as either accounts receivable or accrued liabilities.

Impairment Testing for Unconsolidated Investments. We evaluate equity method investments (which include excess cost amounts attributable to tangible or intangible assets) for impairment when events or changes in circumstances indicate that there is a loss in value of the investment which is an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the investee or long-term negative changes in the investee’s industry. In the event we determine that the decline in value of an investment is other than temporary, we record a charge to earnings to adjust the carrying value to fair value.

Net Income per Limited Partner Unit.  Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted-average number of outstanding limited partner units during the period.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are classified as participating securities and are included in our computation of basic and diluted net income per limited partner unit.

Noncontrolling Interest. Noncontrolling interest represents third party ownership in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third party investor’s interest shown as noncontrolling interest. In the statements of operations, noncontrolling interest reflects the allocation of joint venture earnings to third party investor. Distributions to and contributions from noncontrolling interest represent cash payments and cash contributions from such third party investor.

Property, Plant and Equipment. Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The estimated service lives of our functional asset groups are as follows:

Asset Group	Range of Years
Gas gathering systems and processing systems	15 to 25
Fractionation, terminalling and natural gas liquids storage facilities	5 to 25
Transportation assets	10 to 25
Other property and equipment	3 to 25

Accounting Pronouncements Recently Adopted

On July 1, 2009, the Financial Accounting Standards Board (“FASB”) issuance of Statement of Financial Accounting Standards (“SFAS”) 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162.” established the FASB Accounting Standards Codification (“Codification” or “ASC”) as the source of authoritative U.S. GAAP recognized to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification has become non-authoritative.

Following the issuance of the Codification, FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”). FASB will not consider ASUs as authoritative in their own right. They will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.

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Fair Value Measurements

In September 2006, FASB issued SFAS 157 (ASC 820), “Fair Value Measurements.” ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 applies to other accounting pronouncements that require or permit fair value measurements, and accordingly, does not require any new fair value measurements. The guidance in ASC 820 was initially effective as of January 1, 2008, but in February 2008, FASB delayed the effective date for applying the guidance to nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis, until periods beginning after November 15, 2008. We adopted the guidance in ASC 820 as of January 1, 2008 with respect to financial assets and liabilities within its scope and the impact was not material to our financial statements. As of January 1, 2009, nonfinancial assets and nonfinancial liabilities were also required to be measured at fair value. The adoption of these additional provisions did not have a material impact on our financial statements. See Note 14.

In April 2009, FASB issued FASB Staff Position ("FSP") FAS 157-4 (ASC 820), “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This update to ASC 820 provides guidance for determining fair values when there is no active market or where the price inputs being used represent distressed sales. Specifically, it reaffirms the need to use judgment to ascertain if a formerly active market has become inactive and in determining fair values when markets have become inactive. We adopted the guidance as of June 30, 2009. There have been no material financial statement implications relating to our adoption of the guidance.

In April 2009, FASB issued FSP FAS 107-1 and APB 28-1 (ASC 270), “Interim Disclosures about Fair Value of Financial Instruments.” ASC 270 requires disclosures of fair value for any financial instruments not currently reflected at fair value on the balance sheet for all interim periods. We adopted the updated provisions of ASC 270 as of  June 30, 2009. There have been no material financial statement implications relating to this adoption. See Note 16.

Business Combinations

In December 2007, FASB issued SFAS 141R (ASC 805), “Business Combinations.” ASC 805 requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed and requires the acquirer to disclose certain information related to the nature and financial effect of the business combination. ASC 805 also establishes principles and requirements for how an acquirer recognizes any noncontrolling interest in the acquiree and the goodwill acquired in a business combination. ASC 805 was effective on a prospective basis for business combinations for which the acquisition date is on or after January 1, 2009. For any business combination that takes place subsequent to January 1, 2009, ASC 805 may have a material impact on our financial statements. The nature and extent of any such impact will depend upon the terms and conditions of the transaction.

In April 2009, FASB issued FSP FAS 141R-1 (ASC 805), “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies.” This update to ASC 805 amends and clarifies application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This update is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after January 1, 2009. There have been no material financial statement implications relating to the adoption of this update.

Other

In December 2007, FASB issued SFAS 160 (ASC 810), “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51.” ASC 810 requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated statement of financial position, to clearly identify consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of income, and to provide sufficient disclosure that clearly identifies and

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distinguishes between the interest of the parent and the interests of noncontrolling owners. ASC 810 also establishes accounting and reporting standards for changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. We adopted ASC 810 as of January 1, 2009. As a result, previously presented amounts have been conformed to the required presentation and additional disclosures have been provided.

In March 2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus on EITF 07-4 (ASC 260), “Application of the Two— Class Method under FASB Statement No. 128 to Master Limited Partnerships.”  ASC 260 provides guidance as to how a master limited partnership (“MLP”) should allocate and present earnings per unit using the two-class method when the MLP’s partnership agreement contains incentive distribution rights.  Under the two-class method, current period earnings are allocated to the partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. Our adoption of this guidance on January 1, 2009, did not impact our consolidated financial position, results of operations or cash flows.

FSP EITF 03-6-1 (ASC 260), “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities was issued on June 16, 2008 and adopted January 1, 2009. This guidance requires us to retrospectively adjust our earnings per unit data that will result in us recognizing unvested unit-based payment awards as participating units in our basic earnings per unit calculation.

In May 2009, FASB issued SFAS 165 (ASC 855), “Subsequent Events.” ASC 855 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. ASC 855 is effective for interim and annual periods ended after June 15, 2009 and should be applied prospectively. The adoption of ASC 855 did not have a material impact on our financial statements.

The FASB has issued ASUs 2009-01 through 2009-15, which are either technical corrections of the Codification and/or do not apply to us.

In June 2009, the SEC Staff issued Staff Accounting Bulletin (“SAB”) 112. SAB 112 amends or rescinds portions of the SEC staff’s interpretive guidance included in the Staff Accounting Bulletin Series in order to make the relevant interpretive guidance consistent with ASC 805 and ASC 810. The adoption of SAB 112 did not have a material impact on our consolidated financial statements.

Note 4—Acquisition of Downstream Business

On September 24, 2009, we acquired Targa’s interests in the Downstream Business for $530 million. Consideration to Targa comprised $397.5 million in cash and the issuance to Targa of 174,033 general partner units and 8,527,615 common units. The form of the transaction reflected in our consolidated financial statements was:

· Targa contributed the Downstream Business to us. On the contribution date, the Downstream Business’ affiliate indebtedness payable to Targa was $530 million. Prior to the contribution, $287.3 million of the Downstream Business’ affiliated indebtedness was settled through a capital contribution from Targa.

· We repaid the affiliate indebtedness with: (i) $397.5 million in cash; (ii) 174,033 in general partner units with an agreed-upon value of $2.7 million; and (iii) 8,527,615 in common units with an agreed-upon value of $129.8 million.

Our acquisition of the Downstream Business has been accounted for as a transfer of net assets between entities under common control.

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As part of the transaction, Targa has agreed to provide distribution support to us in the form of a reduction in the reimbursement for general and administrative expense allocated to us if necessary (or make a payment to us, if needed) for a 1.0 times distribution coverage ratio, at the current distribution level of $0.5175 per limited partner unit, subject to maximum support of $8 million in any quarter. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011.

Our consolidated financial statements and all other financial information included in this report have been retrospectively adjusted to assume that the transfer of the Downstream Business from Targa to us had occurred at the date when both the Downstream Business and our original assets met the accounting requirements for entities under common control (October 31, 2005). As a result, financial statements and financial information presented for prior periods in this report have also been retrospectively adjusted.

The Partnership now operates in two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing. As a result of the acquisition of the Downstream Business, we are now reporting segment information. See Note 18.

The following table presents the impact on our previously filed consolidated financial position as of December 31, 2008, adjusted for the acquisition of the Downstream Business from Targa:

	December 31, 2008
	Historical
	Targa								Targa
	Resources		Downstream						Resources
	Partners LP		Business			Adjustments			Partners LP
Current assets	$	255,510	$	263,011		$	(22,295	)	$	496,226
Property, plant and equipment, net		1,244,337		474,719			-			1,719,056
Other assets		81,059		18,478			-			99,537
Total assets		1,580,906		756,208			(22,295	)		2,314,819
Current liabilities	$	106,504	$	187,539		$	(22,295	)	$	271,748
Long-term debt		696,845		773,883			-			1,470,728
Other long-term liabilities		15,193		4,062			-			19,255
Owners of Targa Resources Partners LP		762,364		166			-			762,530
Net parent investment		-		(223,534	)					(223,534	)
Noncontrolling interest in subsidiary		-		14,092			-			14,092
Total owners' equity		762,364		(209,276	)		-			553,088
Total liabilities and owners' equity	$	1,580,906	$	756,208		$	(22,295	)	$	2,314,819

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The following tables present the impact on our previously filed consolidated statements of operations, adjusted for the acquisition of the Downstream Business from Targa, for the periods indicated:

	Three Months Ended September 30, 2008
	Historical
	Targa									Targa
	Resources			Downstream						Resources
	Partners LP			Business			Adjustments			Partners LP
Revenues	$	578,747		$	1,868,915		$	(232,811	)	$	2,214,851
Costs and expenses:
Product purchases		512,443			1,830,796			(232,811	)		2,110,428
Operating expenses		15,402			52,853			-			68,255
Depreciation and amortization expense		18,566			5,865			-			24,431
General and administrative expense and other		5,521			13,582			-			19,103
		551,932			1,903,096			(232,811	)		2,222,217
Income from operations		26,815			(34,181	)		-			(7,366	)
Other income (expense):
Interest expense		(10,749	)		(14,700	)		-			(25,449	)
Other expense		(974	)		(3,624	)		-			(4,598	)
Income tax expense		(400	)		(247	)		-			(647	)
Net income (loss)		14,692			(52,752	)		-			(38,060	)
Less: Net income attributable to noncontrolling interest		-			162			-			162
Net loss attributable to Targa Resources Partners LP	$	14,692		$	(52,914	)	$	-		$	(38,222	)

	Nine Months Ended September 30, 2008
	Historical
	Targa									Targa
	Resources			Downstream						Resources
	Partners LP			Business			Adjustments			Partners LP
Revenues	$	1,721,336		$	5,368,033		$	(674,805	)	$	6,414,564
Costs and expenses:
Product purchases		1,509,752			5,150,441			(674,738	)		5,985,455
Operating expenses		42,673			155,084			(67	)		197,690
Depreciation and amortization expense		55,235			17,550			-			72,785
General and administrative expense and other		16,362			36,631			-			52,993
		1,624,022			5,359,706			(674,805	)		6,308,923
Income from operations		97,314			8,327			-			105,641
Other income (expense):
Interest expense		(27,443	)		(44,132	)		-			(71,575	)
Other expense		(938	)		(1,569	)		-			(2,507	)
Income tax expense		(1,100	)		(742	)		-			(1,842	)
Net income (loss)		67,833			(38,116	)		-			29,717
Less: Net income attributable to noncontrolling interest		-			91			-			91
Net income (loss) attributable to Targa Resources Partners LP	$	67,833		$	(38,207	)	$	-		$	29,626

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Note 5—Property, Plant and Equipment

Property, plant, and equipment and accumulated depreciation were as follows as of the dates indicated:

	September 30,			December 31,
	2009			2008
Natural gas gathering systems	$	1,216,457		$	1,187,139
Processing and fractionation facilities		403,038			374,011
Terminalling and natural gas liquids storage facilities		236,978			221,883
Transportation assets		150,658			144,466
Other property, plant, and equipment		16,410			14,910
Land		49,770			49,770
Construction in progress		9,827			44,199
		2,083,138			2,036,378
Accumulated depreciation		(392,752	)		(317,322	)
	$	1,690,386		$	1,719,056

Gross additions to property, plant and equipment were $46.8 million for the nine months ended September 30, 2009, including $9.8 million in noncash additions resulting from the reclassification from inventory of working NGL volumes in third-party and Targa owned facilities. Cash flows from investing activities reflect additions of $46.3 million for the same period. The difference was primarily the result of settled accruals, which decreased by $9.1 million during the period.

Note 6—Partner Equity and Distributions

Distributions declared and paid during the nine months ended September 30, 2009 and 2008 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 thousands, except per unit amounts)
2009
August 14, 2009	June 30, 2009	$	23,915	$	-	$	1,933	$	528	$	26,376	$	0.5175
May 15, 2009	March 31, 2009		17,949		5,966		1,933		528		26,376		0.5175
February 13, 2009	December 31, 2008		17,949		5,965		1,933		528		26,375		0.5175
2008
August 14, 2008	June 30, 2008		17,759		5,908		1,711		518		25,896		0.5125
May 15, 2008	March 31, 2008		14,467		4,813		208		398		19,886		0.4175
February 14, 2008	December 31, 2007		13,768		4,582		66		376		18,792		0.3975

Conversion of Subordinated Units. Under the terms of our amended and restated partnership agreement, all 11,528,231 subordinated units converted to common units on a one-for-one basis on May 19, 2009. The conversion had no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.

Public Offering of Common Units. On August 12, 2009, we completed a unit offering under our shelf registration statement of 6.9 million common units representing limited partner interests in us at a price of $15.70 per common unit. Net proceeds of the offering were $105.3 million, after deducting underwriting discounts, commissions and estimated offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. We used a portion of the proceeds to repay $103.5 million of outstanding borrowings under our senior secured revolving credit facility.

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Subsequent Event. On October 19, 2009, we announced a cash distribution of $0.5175 per unit on our outstanding common units. The distribution will be paid on November 13, 2009 to unitholders of record on November 4, 2009, for the three months ended September 30, 2009. The total distribution to be paid is $35.2 million, with $21.5 million to be paid to our non-affiliated common unitholders and $10.4 million, $0.7 million and $2.6 million to be paid to Targa for its common unit ownership, general partner interest and incentive distribution rights.

Note 7—Investment in Unconsolidated Affiliate

As of September 30, 2009 and December 31, 2008 our unconsolidated investment consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast.

Our equity in the net assets of GCF exceeded our acquisition date investment account by $5.2 million. This amount is being amortized over the estimated remaining life of the assets on a straight-line basis, and is included as a component of our equity in earnings of unconsolidated investments.

The following table shows our equity earnings and cash distributions with respect to our unconsolidated investments in GCF for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Equity in earnings	$	1,417	$	1,102	$	3,221	$	3,028
Cash distributions		3,100		1,928		3,875		2,713

Note 8—Income Tax Expense

Our income tax expense results solely from a tax on modified gross margin imposed on us by the State of Texas. Current tax expense is computed as 1% of forecasted positive annual margin as apportioned to Texas. Deferred tax expense is based upon the rate at which income and expense items attributable to current margin will become tax benefits or liabilities at some point in the future. Items contributing to current negative margin create a deferred tax liability, and we are required to record a deferred tax expense related to these items. As a result, our current and deferred tax expense does not correlate with income or loss before income taxes.

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Note 9—Long-Term Debt

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

	September 30,		December 31,
	2009		2008
Targa Resources Partners LP:
Senior secured revolving credit facility, variable rate, due February 2012	$	510,483	$	487,765
Senior unsecured notes, 8¼% fixed rate, due July 2016		209,080		209,080
Senior unsecured notes, 11¼% fixed rate, due July 2017 (1)		219,861		-
Targa Downstream LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including accrued interest of $0 and $175,343)		-		744,020
Targa LSNG LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including accrued interest of $0 and $4,281)		-		29,863
Total long-term debt	$	939,424	$	1,470,728
Letters of credit issued	$	58,844	$	9,651

____________

(1) The carrying amount of the notes includes $11.4 million of unamortized original issue discount as of September 30, 2009.

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, 2009:

	Range of interest rates paid	Weighted average interest rate paid
Senior secured revolving credit facility	1.2% to 4.5%		1.8%

11¼% Senior Unsecured Notes due July 15, 2017

On July 6, 2009, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. Proceeds from the 11¼% Notes were used to repay borrowings under our senior secured revolving credit facility.

The 11¼% Notes:

· are unsecured senior obligations;

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

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

· are unconditionally guaranteed by us.

The 11¼% Notes are effectively subordinated to all indebtedness under our credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.

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Interest on the 11¼% Notes accrues at the rate of 11¼% per annum and is payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2010. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.

At any time prior to July 15, 2012, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 11¼% Notes with the net cash proceeds of certain equity offerings by us at a redemption price of 111.25% of the principal amount, plus accrued and unpaid interest to the redemption date, provided that:

(1) at least 65% of the aggregate principal amount of the 11¼% Notes (excluding 11¼% Notes held by us) remains outstanding immediately after the occurrence of such redemption; and

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

Prior to July 15, 2013, we may also redeem all or a part of the 11¼% Notes at a redemption price equal to 100% of the principal amount of the 11¼% Notes redeemed plus the applicable premium as defined in the indenture as of, and accrued and unpaid interest to, the date of redemption.

On or after July 15, 2013, we may redeem all or a part of the 11¼% Notes at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest on the 11¼% Notes redeemed, if redeemed during the twelve-month period beginning on July 15 of each year indicated below:

Year	Percentage
2013		105.625	%
2014		102.813	%
2015 and thereafter		100.000	%

The 11¼% Notes are subject to a registration rights agreement dated as of July 6, 2009. Under the registration rights agreement, we are required to file by July 9, 2010 a registration statement with respect to any 11¼% Notes that are not freely transferable without volume restrictions by holders of the 11¼% Notes that are not our affiliates. If we fail to do so, additional interest will accrue on the principal amount of the 11¼% Notes. We have determined that the payment of additional interest is not probable. As a result, we have not recorded a liability for any contingent obligation. Any subsequent accrual of a liability under this registration rights agreement will be charged to earnings as interest expense.

11¼% Notes Repurchases

During the third quarter of 2009, we repurchased $18.7 million face value ($17.8 million carrying value, net of issue discount) of our 11¼% Notes for $18.9 million plus accrued interest of $0.3 million. We recognized a loss on the debt repurchases of $1.5 million, including $0.4 million in debt issue costs associated with the repurchased notes.

Commitment Increase

On July 29, 2009, we executed a Commitment Increase Supplement (the “Supplement”) to our existing senior secured revolving credit facility. The Supplement increased the commitments under our senior secured revolving credit facility by $127.5 million, bringing the total commitments to $977.5 million. We may request additional commitments under our senior secured revolving credit facility of up to $22.5 million, which would increase the total commitments under our senior secured revolving credit facility to $1 billion.

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Note 10—Asset Retirement Obligations

The changes in our aggregate asset retirement obligations were as follows:

	Nine Months Ended September 30, 2009
Beginning of period	$	6,206
Liabilities settled		-
Change in cash flow estimate		(35	)
Accretion expense		308
End of period	$	6,479

Note 11—Accounting for Unit-Based Compensation

Our general partner has adopted a long-term incentive plan for employees, consultants and directors of the general partner and its affiliates who perform services for us. The following table summarizes our unit-based awards for the period indicated:

	Nine Months Ended
	September 30, 2009
Outstanding at beginning of period		26,664
Granted		32,000
Vested		(10,672	)
Outstanding at end of period		47,992
Weighted average grant date fair value per share	$	12.88

In January 2009, our general partner awarded 32,000 of our restricted common units (4,000 restricted common units to each of our non-management directors and to each of Targa Resources Investments Inc.’s independent directors), which will settle with the delivery of common units and are subject to three-year vesting, without performance condition, and will vest ratably on each anniversary of the grant date.

Compensation expense on the restricted common units is recognized on a straight-line basis over the vesting period. The fair value of an award of restricted common units is measured on the grant date using the market price of a common unit on such date. For the three and nine months ended September 30, 2009, we recognized compensation expense of $0.1 million and $0.2 million related to equity-based awards. The remaining fair value of $0.3 million will be recognized in expense over a weighted-average period of less than two years.

Note 12—Insurance Claims

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 $4.8 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During 2009, the estimate was reduced by $0.8 million. For the nine months ended September 30, 2009, expenditures related to the hurricanes included $6.8 million for previously accrued repair cost and $0.3 million capitalized as improvements.

We recognize income from business interruption insurance in our combined statements of operations as a component of revenues from third parties in the period that a proof of loss is executed and submitted to the insurers for payment.

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        No business interruption insurance receipts were received during the three months ended September 30, 2009 or 2008.

During the nine months ended September 30, 2009 and 2008, we recognized revenue from business interruption insurance of:

	Nine Months Ended September 30,
	2009		2008
Included in revenues
Logistics Assets	$	1,926	$	441
NGL Distribution and Marketing		-		8,602
Wholesale Marketing		500		5,920
	$	2,426	$	14,963

Business interruption insurance receipts recognized as revenue during the nine months ended September 30, 2009 relate primarily to the 2008 hurricanes; amounts recognized during the nine months ended September 30, 2008 relate primarily to Hurricanes Katrina and Rita from the 2005 hurricane season. All property damage and business interruption claims of the Downstream Business were retained by Targa as part of our acquisition of the Downstream Business.

Note 13—Derivative Instruments and Hedging Activities

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs, changes in interest rates, as well as nonperformance by our counterparties.

Commodity Price Risk. A majority of our revenues 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.

The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2009, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 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.

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. 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

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Belvieu and our natural gas hedges are based on published index prices for delivery at Columbia Gulf, Houston Ship Channel, Mid-Continent and Waha, 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.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under our senior secured revolving credit facility. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of September 30, 2009, we had borrowings of $510.5 million outstanding under our senior secured revolving 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 and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in accumulated other comprehensive income (“OCI”) until the interest expense on the related debt is recognized in earnings.

Credit Risk. 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, 2009, affiliates of Goldman Sachs, Bank of America (“BofA”) and Barclays Bank accounted for 81%, 10% and 7% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, BofA and Barclays Bank are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

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

	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	2009		2008		Location	2009		2008
Derivatives designated as hedging instruments under ASC 815
Commodity contracts	Current assets	$	46,508	$	88,206	Current liabilities	$	1,383	$	-
	Long term assets		18,575		68,296	Long term liabilities		9,415		123
Interest rate contracts	Current assets		-		-	Current liabilities		7,876		8,020
	Long term assets		-		-	Long term liabilities		6,230		9,556
Total derivatives designated
as hedging instruments			65,083		156,502			24,904		17,699
Derivatives not designated as hedging instruments under ASC 815
Commodity contracts	Current assets		1,964		3,610	Current liabilities		1,644		3,644
	Long term assets		285		-	Long term liabilities		-		-
Total derivatives not designated
as hedging instruments			2,249		3,610			1,644		3,644
Total derivatives		$	67,332	$	160,112		$	26,548	$	21,343

The following table reflects the gain (loss) recognized in OCI on the consolidated balance sheets and the consolidated statements of comprehensive income (loss):

	Amount of Gain (Loss)						Amount of Gain (Loss)
Derivatives in	Recognized in OCI on						Recognized in OCI on
ASC 815	Derivatives (Effective Portion)						Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended September 30,						Nine Months Ended September 30,
Relationships	2009			2008			2009			2008
Interest rate contracts	$	(7,570	)	$	(1,698	)	$	(3,096	)	$	(1,968	)
Commodity contracts		(10,141	)		185,008			(31,043	)		(35,221	)
	$	(17,711	)	$	183,310		$	(34,139	)	$	(37,189	)

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

	Amount of Gain (Loss) Reclassified from OCI to Income
Location of Gain (Loss)	(Effective Portion)
Reclassified from	Three Months Ended September 30,						Nine Months Ended September 30,
OCI into Income	2009			2008			2009			2008
Interest expense, net	$	(2,718	)	$	(869	)	$	(7,840	)	$	(1,485	)
Revenues		16,974			(19,985	)		36,877			(49,696	)
	$	14,256		$	(20,854	)	$	29,037		$	(51,181	)

22

	Amount of Gain (Loss) Recognized in Income on Derivatives
Location of Gain (Loss)	(Ineffective Portion)
Reclassified from	Three Months Ended September 30,					Nine Months Ended September 30,
OCI into Income	2009			2008		2009			2008
Interest expense, net	$	-		$	-	$	-		$	-
Revenues		(299	)		-		(299	)		-
	$	(299	)	$	-	$	(299	)	$	-

As of December 31, 2008, OCI consisted of $89.6 million of unrealized net gains on commodity hedges, and $17.6 million of unrealized net losses on interest rate hedges.

As of September 30, 2009, OCI consisted of $22.0 million of unrealized net gains on commodity hedges and $12.8 million of unrealized net losses on interest rate hedges. Deferred net gains of $69.7 million on commodity hedges and deferred net losses of $9.7 million on interest rate hedges recorded in OCI are expected to be reclassified to revenues from third parties and interest expense during the next twelve months.

The fair value of our derivative instruments, depending on the type of instrument, are determined by the use of present value methods and standard option valuation models with assumptions about commodity price risk and interest rate risk based on those observed in underlying markets.

23

As of September 30, 2009, we had the following commodity derivative arrangements which will settle during the years ending December 31, 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from October 1, 2009 through December 31, 2009):

Natural Gas

Instrument		Avg. Price		MMBtu per day
Type	Index	$/MMBtu		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	IF-HSC		7.39		1,966		-		-		-		-	$	500
Swap	IF-NGPL MC		9.18		6,256		-		-		-		-		2,675
Swap	IF-NGPL MC		8.86		-		5,685		-		-		-		6,169
Swap	IF-NGPL MC		7.34		-		-		2,750		-		-		898
Swap	IF-NGPL MC		7.18		-		-		-		2,750		-		605
					6,256		5,685		2,750		2,750		-
Swap	IF-Waha		7.79		9,936		-		-		-		-		2,999
Swap	IF-Waha		6.53		-		11,709		-		-		-		2,630
Swap	IF-Waha		6.10		-		-		11,250		-		-		(1,553	)
Swap	IF-Waha		6.30		-		-		-		7,250		-		(584	)
Swap	IF-Waha		5.59		-		-		-		-		4,000		(1,251	)
					9,936		11,709		11,250		7,250		4,000
Total Swaps					18,158		17,394		14,000		10,000		4,000
Floor	IF-NGPL MC		6.55		850		-		-		-		-		114
Floor	IF-Waha		6.55		565		-		-		-		-		77
Total Floors					1,415		-		-		-		-
Total Sales					19,573		17,394		14,000		10,000		4,000
Basis Swap Oct 09-May 2011, Rec IF-CGT, Pay NYMEX less $0.11, 20,000 MMBtu/d															586
Fuel cost swap Oct 2009-May2011, Rec IF-CGT, Pay $5.96, 226 MMbtu/d															18
														$	13,883

24

NGLs

Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	OPIS-MB		1.32		6,248		-		-		-		-	$	10,931
Swap	OPIS-MB		1.23		-		5,209		-		-		-		28,074
Swap	OPIS-MB		0.89		-		-		3,800		-		-		48
Swap	OPIS-MB		0.92		-		-		-		2,700		-		1,071
Total Swaps					6,248		5,209		3,800		2,700		-
Floor	OPIS-MB		1.44		-		-		199		-		-		1,454
Floor	OPIS-MB		1.43		-		-		-		231		-		1,755
Total Floors					-		-		199		231		-
Total Sales					6,248		5,209		3,999		2,931		-
														$	43,333

Condensate

Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		69.00		322		-		-		-		-	$	(61	)
Swap	NY-WTI		68.04		-		401		-		-		-		(913	)
Swap	NY-WTI		71.00		-		-		200		-		-		(446	)
Swap	NY-WTI		72.60		-		-		-		200		-		(449	)
Swap	NY-WTI		74.00		-		-		-		-		200		(459	)
Total Swaps					322		401		200		200		200
Floor	NY-WTI		60.00		50		-		-		-		-		3
Total Floors					50		-		-		-		-
Total Sales					372		401		200		200		200
														$	(2,325	)

25

Customer Hedges

As of September 30, 2009, we had the following commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market through earnings:

Period

Commodity

Instrument Type

Daily Volume

Average Price

Index

Fair Value

Purchases

Oct 2009 - Dec 2009

Natural gas

Swap

2,935

MMBtu

$

9.15

per MMBtu

NY-HH

$

(1,189

)

Jan 2010 - Jun 2010

Natural gas

Swap

663

MMBtu

8.03

per MMBtu

NY-HH

(247

)

Sales

Oct 2009 - Dec 2009

Natural gas

Fixed price sale

2,935

MMBtu

9.15

per MMBtu

NY-HH

1,188

Jan 2010 - Jun 2010

Natural gas

Fixed price sale

663

MMBtu

8.03

per MMBtu

NY-HH

247

$

(1

)

Interest Rate Hedges

Our consolidated variable rate indebtedness accrues interest at a base rate plus an applicable margin. Our interest rate hedges effectively fix the base rate on the indicated notional amount of borrowings for the indicated periods:

Period	Fixed Rate			Notional Amount			Fair Value
Remainder of 2009		3.66	%	$	300	million	$	(647	)
2010		3.66	%		300	million		(9,166	)
2011		3.41	%		300	million		(4,566	)
2012		3.39	%		300	million		(913	)
2013		3.39	%		300	million		569
01/01-04/24/2014		3.39	%		300	million		617
							$	(14,106	)

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 recorded in OCI until interest expense on the related debt is recognized in earnings.

See Notes 14 and 17 for additional disclosures related to derivative instruments and hedging activities.

Note 14—Fair Value Measurements

We classify assets and liabilities measured at fair value on a recurring and nonrecurring basis using a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring us to develop our own assumptions.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2009. 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.

26

	Total			Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	67,332		$	-	$	67,332	$	-
Total assets	$	67,332		$	-	$	67,332	$	-
Liabilities from commodity derivative contracts	$	12,442		$	-	$	12,442	$	-
Liabilities from interest rate derivatives		14,106	��		-		14,106		-
Total liabilities	$	26,548		$	-	$	26,548	$	-

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, 2008	$	123,304
Unrealized gains (losses) included in OCI		(26,557	)
Settlements		(31,392	)
Transfers out of Level 3		(65,355	)
Balance, September 30, 2009	$	-

During the third quarter of 2009, we reclassified our NGL derivative contracts from Level 3 (unobservable inputs in which little or no market data exists) to Level 2 as we were able to obtain directly observable inputs other than quoted prices in active markets.

Our nonfinancial assets and liabilities measured at fair value on a nonrecurring basis during the three and nine months ended September 30, 2009 were not significant.

Note 15—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 the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

We do not have a reserve for environmental expenses as of September 30, 2009.

Legal Proceeding

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc. and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus LLC, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments and the appeal is pending before the 14th Court of Appeals in Houston, Texas. We are contesting WTG’s 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.

27

Note 16—Fair Value of Financial Instruments

The estimated fair values of assets and liabilities classified as financial instruments have been determined using available market information and valuation methodologies described below. Considerable judgment is required in 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 value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt.

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 amounts and fair values of our other financial instruments are as follows as of the dates indicated:

	September 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior unsecured notes, 8¼% fixed rate	$	209,080	$	193,922	$	209,080	$	128,333
Senior unsecured notes, 11¼% fixed rate (1)		219,861		242,266		-		-

____________

(1) The carrying amount of the notes includes $11.4 million of unamortized original issue discount as of September 30, 2009.

Note 17—Related Party Transactions

Relationship with Targa

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

The following table summarizes the sales to, and purchases from affiliates of Targa, payments made or received by, Targa on behalf of us and allocations of costs from Targa. Management believes these transactions are executed on terms that are fair and reasonable.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009		2008
Sales to affiliates	$	42,509		$	135,114		$	140,240	$	413,466
Purchases from affiliates		198,089			318,570			492,503		943,187
Allocations of general & administrative
expenses under Omnibus Agreement		18,197			17,458			47,436		51,934
Net change in affiliate receivable		(42,258	)		(63,685	)		-		43,683
Unit distributions to Targa		132,500			-			132,500		-
Cash distributions to Targa		8,427			8,137			25,280		18,580
Settlement of affiliated indebtedness		287,296			-			287,296		-

28

Relationship with Warburg Pincus LLC

Two of the 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, 2009, we purchased $2.5 million and $5.7 million of product from Broad Oak. During the three and nine months ended September 30, 2008, we purchased $2.2 million and $3.4 million of product from Broad Oak.

Relationship with Bank of America

An affiliate of BofA is an equity investor in Targa Resources Investments Inc., which indirectly owns our general partner.

Financial Services. BofA is a lender and an administrative agent under our senior secured revolving credit facility.

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, 2009:

Period	Commodity	Daily Volumes			Average Price			Index
Oct 2009 - Dec 2009	Natural gas		3,556	MMBtu	$	8.07	per MMBtu	IF-Waha
Oct 2009 - Dec 2009	Natural gas		652	MMBtu		8.35	per MMBtu	NY-HH
Jan 2010 - Dec 2010	Natural gas		3,289	MMBtu		7.39	per MMBtu	IF-Waha
Jan 2010 - Jun 2010	Natural gas		497	MMBtu		8.17	per MMBtu	NY-HH
Oct 2009 - Dec 2009	NGL		3,000	Bbl		1.18	per gallon	OPIS-MB
Oct 2009 - Dec 2009	Condensate		202	Bbl		70.60	per barrel	NY-WTI
Jan 2010 - Dec 2010	Condensate		181	Bbl		69.28	per barrel	NY-WTI

As of September 30, 2009, the aggregate fair value of these open positions was $6.0 million. For the three and nine months ended September 30, 2009, we received $6.2 million and $22.2 million from BofA to settle payments due under hedge transactions. For the three and nine months ended September 30, 2008, we paid BofA $6.3 million and $17.9 million for amounts due under settled commodity derivative transactions.

We have entered into several interest rate derivative transactions with BofA. Open positions as of September 30, 2009 consisted of interest rate swaps and interest rate basis swaps expiring on April 24, 2014. As of September 30, 2009, the aggregate fair value of these positions was a liability of $2.7 million. Payments to BofA related to settled portions were $0.7 million and $1.7 million for the three and nine months ended September 30, 2009.

Commercial Relationships. During the nine months ended September 30, 2009, product sales to BofA which are included in revenues were $0.5 million. For the same period, natural gas and NGL product purchases were $0.3 million. During the three and nine months ended September 30, 2008, product sales to BofA which are included in revenues were $3.9 million and $3.9 million. For the same periods, natural gas and NGL product purchases from BofA were $0.8 million and $0.8 million.

29

Transactions with Unconsolidated Affiliate

For the periods indicated, related party transactions with GCF included in our statements of operations were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Included in revenues	$	34	$	56	$	159	$	422
Included in costs and expenses		158		589		1,426		2,734

Note 18—Segment Information

We categorize the midstream natural gas industry into, and describe our business in, two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing.

The Natural Gas Gathering and Processing segment 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. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas. We are also party to natural gas processing agreements with third party plants.

The Logistics Assets segment is involved with gathering and storing mixed NGLs and fractionating, storing, and transporting finished NGLs. These assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing segment and are predominantly located in Mont Belvieu, Texas and Western Louisiana.

The NGL Distribution and Marketing segment markets our own natural gas liquids production and purchased natural gas liquids products in selected United States markets.

The Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations. In our refinery services business, we provide liquefied petroleum gas balancing services, purchase natural gas liquids products from refinery customers and sell natural gas liquids products to various customers. Our wholesale propane marketing operations include the sale of propane and related logistics services to multi-state retailers, independent retailers and other end-users. Wholesale Marketing operates principally in the United States, and has a small marketing presence in Canada.

The “Eliminations and Other” column in the following tables includes corporate level consolidation adjustments and the elimination of intersegment revenues and expenses.

30

Our reportable segment information is shown in the following tables:

	Three Months Ended September 30, 2009
	Natural Gas Gathering and Processing			Logistics Assets		NGL Distribution and Marketing			Wholesale Marketing		Eliminations and Other			Total
Revenues	$	116,180		$	30,349	$	692,166		$	122,574	$	-		$	961,269
Revenues from affiliates		156,898			24,727		71,614			19,418		(230,148	)		42,509
Revenues		273,078			55,076		763,780			141,992		(230,148	)		1,003,778
Product purchases		160,151			-		438,150			77,154		684			676,139
Product purchases from affiliates		52,530			-		317,579			61,488		(233,508	)		198,089
Product purchases		212,681			-		755,729			138,642		(232,824	)		874,228
Operating expenses		14,177			26,668		(20	)		41		-			40,866
Operating expenses from affiliates		-			3,248		-			-		3,360			6,608
Operating expenses		14,177			29,916		(20	)		41		3,360			47,474
Operating margin	$	46,220		$	25,160	$	8,071		$	3,309	$	(684	)	$	82,076
Other financial information:
Equity in earnings of   unconsolidated investment	$	-		$	1,417	$	-		$	-	$	-		$	1,417
Identifiable assets		1,309,344			490,481		234,716			70,630		43,147			2,148,318
Unconsolidated investments		-			17,811		-			-		-			17,811
Capital expenditures		5,594			5,070		-			-		-			10,664
Revenues by type:
Commodity Sales	$	270,802		$	-	$	762,371		$	141,753	$	(205,079	)	$	969,847
Services		2,541			55,076		1,409			239		(25,069	)		34,196
Other		(265	)		-		-			-		-			(265	)
	$	273,078		$	55,076	$	763,780		$	141,992	$	(230,148	)	$	1,003,778

31

	Three Months Ended September 30, 2008
	Natural Gas Gathering and Processing			Logistics Assets			NGL Distribution and Marketing			Wholesale Marketing			Eliminations and Other			Total
Revenues	$	224,535		$	25,672		$	1,514,958		$	314,572		$	-		$	2,079,737
Revenues from affiliates		354,212			39,853			139,787			5,987			(404,725	)		135,114
Revenues		578,747			65,525			1,654,745			320,559			(404,725	)		2,214,851
Product purchases		412,664			(67	)		1,179,431			199,830			-			1,791,858
Product purchases from affiliates		99,779			68			499,980			126,181			(407,438	)		318,570
Product purchases		512,443			1			1,679,411			326,011			(407,438	)		2,110,428
Operating expenses		15,405			35,938			304			16			-			51,663
Operating expenses from affiliates		(1	)		13,879			-			1			2,713			16,592
Operating expenses		15,404			49,817			304			17			2,713			68,255
Operating margin	$	50,900		$	15,707		$	(24,970	)	$	(5,469	)	$	-		$	36,168
Other financial information:
Equity in earnings of   unconsolidated investment	$	-		$	1,102		$	-		$	-		$	-		$	1,102
Unconsolidated investments		-			19,554			-			-			-			19,554
Capital expenditures		11,091			9,240			-			-			-			20,331
Revenues by type:
Commodity sales	$	576,471		$	-		$	1,653,998		$	320,564		$	(364,835	)	$	2,186,198
Services		2,266			65,526			747			(5	)		(39,889	)		28,645
Other		10			(1	)		-			-			(1	)		8
	$	578,747		$	65,525		$	1,654,745		$	320,559		$	(404,725	)	$	2,214,851

32

	Nine Months Ended September 30, 2009
	Natural Gas Gathering and Processing			Logistics Assets			NGL Distribution and Marketing			Wholesale Marketing		Eliminations and Other			Total
Revenues	$	319,604		$	87,127		$	1,767,170		$	508,143	$	-		$	2,682,044
Revenues from affiliates		433,171			67,715			247,601			52,509		(660,756	)		140,240
Revenues		752,775			154,842			2,014,771			560,652		(660,756	)		2,822,284
Product purchases		457,629			-			1,198,110			311,054		-			1,966,793
Product purchases from affiliates		135,216			-			784,089			238,752		(665,554	)		492,503
Product purchases		592,845			-			1,982,199			549,806		(665,554	)		2,459,296
Operating expenses		38,978			83,391			592			62		-			123,023
Operating expenses from affiliates		10			14,265			-			-		4,798			19,073
Operating expenses		38,988			97,656			592			62		4,798			142,096
Operating margin	$	120,942		$	57,186		$	31,980		$	10,784	$	-		$	220,892
Other financial information:
Equity in earnings of   unconsolidated investment	$	-		$	3,221		$	-		$	-	$	-		$	3,221
Identifiable assets		1,309,344			490,481			234,716			70,630		43,147			2,148,318
Unconsolidated investments		-			17,811			-			-		-			17,811
Capital expenditures		21,341			15,853			-			-		-			37,194
Revenues by type:
Commodity Sales	$	744,801		$	29		$	2,011,166		$	559,426	$	(591,699	)	$	2,723,723
Services		8,221			152,888			3,607			726		(69,057	)		96,385
Business interruption		-			1,926			-			500		-			2,426
Other		(247	)		(1	)		(2	)		-		-			(250	)
	$	752,775		$	154,842		$	2,014,771		$	560,652	$	(660,756	)	$	2,822,284

33

	Nine Months Ended September 30, 2008
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing		Wholesale Marketing			Eliminations and Other			Total
Revenues	$	662,745	$	74,120		$	4,118,034	$	1,146,199		$	-		$	6,001,098
Revenues from affiliates		1,058,591		108,243			457,260		35,033			(1,245,661	)		413,466
Revenues		1,721,336		182,363			4,575,294		1,181,232			(1,245,661	)		6,414,564
Product purchases		1,267,179		(101	)		3,040,368		734,822			-			5,042,268
Product purchases from affiliates		242,574		101			1,518,377		433,426			(1,251,291	)		943,187
Product purchases		1,509,753		-			4,558,745		1,168,248			(1,251,291	)		5,985,455
Operating expenses		42,618		105,175			1,321		45			-			149,159
Operating expenses from affiliates		54		42,847			-		-			5,630			48,531
Operating expenses		42,672		148,022			1,321		45			5,630			197,690
Operating margin	$	168,911	$	34,341		$	15,228	$	12,939		$	-		$	231,419
Other financial information:
Equity in earnings of   unconsolidated investment	$	-	$	3,028		$	-	$	-		$	-		$	3,028
Unconsolidated investments		-		19,554			-		-			-			19,554
Capital expenditures		28,755		30,933			-		-			-			59,688
Revenues by type:
Commodity Sales	$	1,713,790	$	53		$	4,564,413	$	1,175,165		$	(1,135,762	)	$	6,317,659
Services		7,512		181,870			2,267		150			(109,897	)		81,902
Business interruption		-		441			8,602		5,920			-			14,963
Other		34		(1	)		11		(3	)		(1	)		40
	$	1,721,336	$	182,363		$	4,575,293	$	1,181,232		$	(1,245,660	)	$	6,414,564

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reconciliation of operating margin to net income (loss):
Operating margin	$	82,076		$	36,168		$	220,892		$	231,419
Depreciation and amortization expense		(25,597	)		(24,431	)		(75,490	)		(72,785	)
General and administrative expense		(17,078	)		(19,116	)		(55,474	)		(57,433	)
Interest expense, net		(29,798	)		(25,449	)		(78,758	)		(71,575	)
Income tax benefit (expense)		220			(647	)		(800	)		(1,842	)
Other, net		1,067			(4,585	)		4,421			1,933
Net income (loss)	$	10,890		$	(38,060	)	$	14,791		$	29,717

34

Note 19—Supplemental Cash Flow Information

We had the following noncash transaction during the three and nine months ended September 30, 2009 and 2008:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Noncash Items:
Additions to property, plant and equipment	$	-	$	-	$	9,777	$	4,277
Issuance of Common Units		129,850		-		129,850		-
Issuance of General Partner Units		2,650		-		2,650		-
Settlement of affiliated indebtedness		287,296		-		287,296		-

35

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.

Overview

We are a Delaware limited partnership formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. 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 are owned 98% by our limited partners and 2% by our general partner, Targa Resources GP LLC, an indirect, wholly-owned subsidiary of Targa. In addition, Targa owns 20,055,846 common units, representing a 31.9% limited partner interest in us, through its indirect wholly-owned subsidiaries, Targa GP Inc. and Targa LP Inc. Our common units are publicly traded on The NASDAQ Stock Market LLC under the symbol “NGLS.”

Our Operations

Our gathering and processing assets are located primarily in the Fort Worth Basin in North Texas, the Permian Basin in West Texas and the onshore region of the Louisiana Gulf Coast. 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 United States.

We conduct our business operations through two divisions and report our results of operations under four segments: our Natural Gas Gathering and Processing division, is a single segment consisting of our natural gas gathering and processing facilities, as well as certain fractionation capability integrated within those facilities; and the NGL Logistics and Marketing division, which consists of three segments: Logistics Assets, NGL Distribution and Marketing and Wholesale Marketing.

Change in Basis of Presentation

As discussed in Note 4 to the accompanying consolidated financial statements, as a result of our acquisition of the Downstream Business, certain 2008 financial information has been reclassified so that the basis of presentation is consistent with that of the 2009 financial information.

Recent Developments

Under the terms of our amended and restated partnership agreement, all 11,528,231 subordinated units converted to common units on a one-for-one basis on May 19, 2009. The conversion had no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.

On July 6, 2009, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 11¼% senior notes due 2017. The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. Proceeds were used to repay borrowings under our credit facility.

On July 29, 2009, we executed a Commitment Increase Supplement to our existing senior secured credit facility. The Commitment Increase Supplement increased the commitments under our credit facility by $127.5 million, bringing the total commitments to $977.5 million. We may request additional commitments under our credit facility of up to $22.5 million.

36

On August 12, 2009, we completed a unit offering under our shelf registration statement of 6.9 million common units representing limited partner interests in us at a price of $15.70 per common unit. Net proceeds of the offering were $105.3 million, after deducting underwriting discounts, commissions and estimated offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. We used a portion of the proceeds to repay $103.5 million of outstanding borrowings under our senior secured revolving credit facility.

On September 24, 2009, we acquired Targa’s interests in Targa Downstream GP LLC, Targa LSNG GP LLC, Targa Downstream LP and Targa LSNG LP, collectively these interests are referred to as the “Downstream Business”, for $530 million. Consideration to Targa comprised $397.5 million in cash and the issuance to Targa of 174,033 general partner units and 8,527,615 common units.

On October 19, 2009, we announced a cash distribution of $0.5175 per unit on our outstanding common units. The distribution will be paid on November 13, 2009 to unitholders of record on November 4, 2009, for the three months ended September 30, 2009. The total distribution to be paid is $35.2 million, with $21.5 million to be paid to our non-affiliated common unitholders and $10.4 million, $0.7 million and $2.6 million to be paid to Targa for its common unit ownership, general partner interest and incentive distribution rights.

Recently Issued Pronouncements

See Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

37

Results of Operations

The following table and discussion relate to the three and nine months ended September 30, 2009 and 2008 and is a summary of our results of operations for the periods then ended:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions, except operating and price data)
Revenues	$	1,003.8		$	2,214.9		$	2,822.3		$	6,414.6
Product purchases		874.2			2,110.5			2,459.3			5,985.5
Operating expenses		47.5			68.3			142.1			197.7
Depreciation and amortization expense		25.6			24.4			75.5			72.8
General and administrative expense		17.1			19.1			55.5			57.4
Casualty loss adjustment		-			-			(0.8	)		-
Gain on sale of assets		-			-			-			(4.4	)
Income (loss) from operations		39.4			(7.4	)		90.7			105.6
Interest expense, net		(29.8	)		(25.4	)		(78.8	)		(71.6	)
Other income (expense)		1.0			(4.7	)		3.6			(2.5	)
Income tax (expense) benefit		0.2			(0.6	)		(0.8	)		(1.8	)
Net income (loss)		10.8			(38.1	)		14.7			29.7
Less: Net income attributable to noncontrolling interest		0.8			0.2			1.1			0.1
Net income (loss) attributable to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Financial and operating data:
Financial data:
Operating margin (1)	$	82.1		$	36.1		$	220.9		$	231.4
Adjusted EBITDA (2)		69.1			22.5			201.8			186.7
Distributable cash flow (3)		51.5			1.0			158.6			132.4
Operating data:
Gathering throughput, MMcf/d (4)		490.2			438.3			465.2			455.0
Plant natural gas inlet, MMcf/d (5)(6)		464.1			415.8			442.5			430.8
Gross NGL production, MBbl/d		43.5			41.3			43.1			43.2
Natural gas sales, BBtu/d (6)		414.9			404.4			383.0			410.9
NGL sales, MBbl/d		262.7			282.5			278.6			290.2
Condensate sales, MBbl/d		2.6			2.4			2.8			2.4
Average realized prices:
Natural Gas, $/MMBtu		3.49			9.42			3.83			9.29
NGL, $/gal		0.81			1.66			0.71			1.56
Condensate, $/Bbl		71.25			103.87			55.84			103.75

_____________

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

Financial Measures.”

(2) Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and

non-cash gain or loss related to derivative instruments. See “Non-GAAP Financial Measures.”

(3) Distributable Cash Flow is net income plus depreciation and amortization and deferred taxes,

adjusted for losses on mark-to-market derivative contracts, less maintenance capital expenditures.

See “Non-GAAP Financial Measures.”

(4) Gathering throughput represents the volume of natural gas gathered and passed through natural gas

38

gathering pipelines from connections to producing wells and central delivery points.

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

inlet of a natural gas processing plant.

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

take-in-kind volumes.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues decreased by $1,211.1 million, or 55%, for 2009 compared to 2008. The decrease is primarily due to:

· a decrease attributable to commodity prices of $1,099.2 million; comprising decreases in natural gas, NGL and condensate revenues of $226.4 million, $865.1 million, and $7.7 million; and

· a decrease attributable to commodity sales volumes of $116.1 million; comprising decrease in NGL revenues of $127.0 million, partially offset by increases in natural gas and condensate revenues of $9.1 million and $1.8 million; offset by

· an increase in other revenues of $4.2 million, primarily from miscellaneous processing activities.

Average realized price for natural gas decreased by $5.93 per MMBtu, or 63%, for 2009 compared to 2008. Average realized price for NGLs decreased by $0.85 per gallon, or 51%, for 2009 compared to 2008. Our average realized price for condensate decreased by $32.62 per barrel, or 31%, for 2009 compared to 2008.

Natural gas sales volumes increased by 10.5BBtu/d, or 3%, for 2009 compared to 2008. The increase in natural gas sales was primarily the result of increased demand by our industrial customers and increased sales under third party contracts. Our NGL sales volumes decreased by 19.8 MBbl/d, or 7%, for 2009 compared to for 2008. Condensate sales volumes increased by 0.2 MBbl/d, or 8%, for 2009 compared for 2008. For information regarding the period to period changes in our commodity sales volumes, see “—Results of Operations—By Segment.”

Product purchases decreased by $1,236.3 million, or 59%, for 2009 compared to 2008. The decrease in product purchases reflects lower commodity prices. See “—Results of Operations—By Segment” for a detailed explanation of the components of the decrease.

Operating expenses decreased by $20.8 million, or 30%, for 2009 compared to 2008. The decrease in operating expenses primarily resulted from lower fuel, utility, equipment rental/maintenance, and barge fees related to lower volumes and decreased fuel and utility rates.

Depreciation and amortization expense increased by $1.2 million, or 5%, for 2009 compared to 2008. The increase was due to additions to property, plant and equipment.

General and administrative expenses decreased by $2.0 million, or 10%, for 2009 compared to 2008. This was primarily due to a reduction in allocated general and administrative expenses, offset by the timing of and increases to compensation and benefit expenses as well as increases in property insurance and outside professional services. For additional information regarding our allocation of general and administrative costs, see “Item 13. Certain Relationships and Related Transactions, and Director Independence—Omnibus Agreement” in our Annual Report.

Interest expense increased by $4.4 million, or 17%, for 2009 compared to 2008. The increase was primarily attributable to the issuance of our 11¼ % Senior Unsecured Notes in July, 2009.

Other income (expense) increased by $5.7 million compared to 2008. The increase was primarily due to a $4.9 million hurricane-related casualty loss provision recorded during 2008, a $1.5 million loss on debt repurchases recorded during 2009 and a $1.5 million change in gain (loss) on mark-to-market derivatives, from a $1.0 million loss during 2008 to a $0.6 million gain during 2009.

39

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues decreased by $3,592.3 million, or 56%, for 2009 compared to 2008. The decrease was primarily due to:

· a decrease attributable to commodity prices of $3,302.1 million; comprising decreases in natural gas, NGL and condensate revenues of $570.0 million, $2,695.7 million, and $36.4 million; and

· a decrease attributable to commodity sales volumes of $290.5 million; comprising decrease in natural gas and NGL revenues of $74.6 million and $226.4 million, partially offset by increases in condensate revenues of $10.5 million; offset by

· an increase in other revenues of $0.3 million, primarily from miscellaneous processing activities.

Average realized price for natural gas decreased by $5.46 per MMBtu, or 59%, for 2009 compared to 2008. Average realized price for NGLs decreased by $0.85 per gallon, or 54%, for 2009 compared to 2008. Average realized price for condensate decreased by $47.91 per barrel, or 46%, for 2009 compared to 2008.

Natural gas sales volumes decreased by 27.9BBtu/d, or 7%, for 2009 compared to 2008. The decrease in natural gas sales was primarily the result of a decrease in purchases from affiliates for resale and a decrease in demand by our industrial customers. Our NGL sales volumes decreased by 11.6 MBbl/d, or 4%, for 2009 compared to 2008. Condensate sales volumes increased by 0.4 MBbl/d, or 17%, for 2009 compared to 2008. For information regarding the period to period changes in our commodity sales volumes, see “—Results of Operations—By Segment.”

Product purchases decreased by $3,526.2 million, or 59%, for 2009 compared to 2008. The decrease in product purchases reflects lower commodity pricing and purchases of wellhead volumes.

Operating expenses decreased by $55.6 million, or 28%, for 2009 compared to 2008. The decrease in operating expenses was primarily the result of a decrease in system maintenance expenses.

General and administrative expenses decreased by $1.9 million, or 3%, for 2009 compared to 2008. This was primarily due to a decrease in allocated general and administrative expenses, offset by the timing of and increases to compensation and benefit expenses and increased outside professional services. For additional information regarding our allocation of general and administrative costs, see “Item 13. Certain Relationships and Related Transactions, and Director Independence —Omnibus Agreement” in our Annual Report.

Depreciation and amortization expense increased by $2.7 million, or 4%, for 2009 compared to 2008. The increase was due to additions to property, plant and equipment.

Interest expense increased by $7.2 million, or 10%, for 2009 compared to 2008. The increase was primarily attributable to the issuance of the 11¼ % Senior Unsecured Notes in July, 2009.

Other income (expense) increased by $6.1 million compared to 2008. The increase was primarily due to a $4.9 million hurricane-related casualty loss provision recorded during 2008, a $1.5 million loss on debt repurchases recorded during 2009 and a $1.5 million change in gain (loss) on mark-to-market derivatives, from a $1.0 million loss during 2008 to a $0.6 million gain during 2009.

40

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 volumes or sales for the period and the denominator is the number of calendar days for the period.

Natural Gas Gathering and Processing Segment

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

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	($ in millions)
Revenues	$	273.1		$	578.6		$	752.8		$	1,721.4
Product purchases		(212.6	)		(512.5	)		(592.8	)		(1,509.8	)
Operating expenses		(14.3	)		(15.5	)		(39.0	)		(42.7	)
Operating margin (1)	$	46.2		$	50.6		$	121.0		$	168.9
Operating statistics:
Gathering throughput, MMcf/d
LOU System		213.4			178.1			183.1			189.4
SAOU System		98.5			99.0			99.9			98.7
North Texas System		178.3			161.2			182.2			166.9
		490.2			438.3			465.2			455.0
Plant natural gas inlet, MMcf/d
LOU System		199.4			168.5			174.2			178.8
SAOU System		92.0			91.3			92.1			91.2
North Texas System		172.7			156.0			176.2			160.8
		464.1			415.8			442.5			430.8
Gross NGL production, MBbl/d
LOU System		9.0			9.2			8.5			10.1
SAOU System		14.0			14.1			14.2			14.2
North Texas System		20.5			18.0			20.4			18.9
		43.5			41.3			43.1			43.2
Natural gas sales, BBtu/d		414.9			404.4			383.0			410.9
NGL sales, MBbl/d		40.6			37.4			39.2			38.2
Condensate sales, MBbl/d		2.6			3.3			3.0			3.6
Average realized prices:
Natural gas, $/MMBtu		3.49			9.42			3.83			9.29
NGL, $/gal		0.73			1.46			0.64			1.40
Condensate, $/Bbl		71.25			95.58			54.00			92.72

____________

(1) See “Non-GAAP Financial Measures” included in this Item 2.

41

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues decreased by $305.6 million, or 53%, for 2009 compared to 2008. The decrease was primarily due to:

· a decrease attributable to commodity prices of $325.2 million, comprising decreases in natural gas, NGL and condensate revenues of $226.4 million, $93.1 million and $5.7 million; partially offset by

· an increase attributable to commodity sales volume of $20.9 million comprising increases in natural gas and condensate revenues of $9.1 million and $19.1 million, partially offset by a decrease in NGL revenues of $7.3 million; and

· a decrease in other revenues of $1.3 million, primarily from miscellaneous processing activities.

Average realized price for natural gas decreased by $5.93 per MMBtu, or 63%, for 2009 compared to 2008. Average realized price for NGLs decreased by $0.73 per gallon, or 50%, for 2009 compared to 2008. Average realized price for condensate decreased by $24.33 per Bbl, or 25%, for 2009 compared to 2008.

Natural gas sales volumes increased by 10.5 BBtu/d, or 3%, for 2009 compared to 2008. NGL sales volumes increased by 3.2 MBbl/d, or 9%, for 2009 compared to 2008. Condensate sales volumes decreased by 0.7 MBbl/d, or 21%, for 2009 compared to 2008. The increase in natural gas sales volumes was primarily the result of an increase in demand from our industrial customers and increased sales under third party contracts.

Product purchases decreased by $299.9 million, or 59%, for the 2009 compared to 2008. The decrease in product purchases reflects lower commodity pricing and purchases of wellhead volumes.

Operating expenses decreased $1.2 million, or 8%, for 2009 compared to 2008. The decrease in operating expenses was primarily the result of a decrease in compensation and benefit costs, system maintenance, chemicals and lubricants expenses and utility expenses, partially offset by an increase in ad valorem taxes.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues decreased by $968.6 million, or 56%, for 2009 compared to 2008. The decrease was primarily due to:

· a decrease attributable to commodity prices of $893.1 million, comprising decreases in natural gas, NGL and condensate revenues of $570.0 million, $290.8 million and $32.2 million;

· a decrease attributable to commodity sales volume of $74.5 million comprising decreases in natural gas and condensate revenues of $74.6 million and $16.4 million, partially offset by increases in NGL revenues of $16.5 million; and

· a decrease in other revenues of $1.0 million, primarily from miscellaneous processing activities.

Average realized price for natural gas decreased by $5.46 per MMBtu, or 59%, for 2009 compared to 2008. Average realized price for NGLs decreased by $0.76 per gallon, or 54%, for 2009 compared to 2008. Average realized price for condensate decreased by $38.72 per Bbl, or 42%, for 2009 compared to 2008.

Natural gas sales volumes decreased by 27.9 BBtu/d, or 7%, for 2009 compared to 2008. Our NGL sales volumes increased by 1.0 MBbl/d, or 3%, for 2009 compared to 2008. Condensate sales volumes decreased by 0.7 MBbl/d, or 21%, for 2009 compared to 2008. The decrease in natural gas sales was primarily the result of a decrease in purchases from affiliates.

Product purchases decreased by $917.0 million, or 61%, for 2009 compared to 2008. The decrease in product purchases reflects lower commodity pricing and purchases of wellhead volumes.

Operating expenses decreased $3.7 million, or 9%, for 2009 compared to for 2008. The decrease was primarily the result of a decrease in compensation and benefit costs, system maintenance expenses, utility expenses, chemical and lubricant expenses.

42

Logistics Assets Segment

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

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	($ in millions)
Revenues from services	$	55.1		$	65.5		$	152.9		$	181.8
Other revenues (1)		(0.1	)		0.1			2.0			0.6
		55.0			65.6			154.9			182.4
Operating expenses		(29.9	)		(49.8	)		(97.7	)		(147.9	)
Operating margin (2)	$	25.1		$	15.8		$	57.2		$	34.5
Equity in earnings of GCF	$	1.4		$	1.1		$	3.2		$	3.0
Operating statistics:
Fractionation volumes, MBbl/d		225.9			207.1			215.4			219.3
Treating volumes, MBbl/d (3)		27.5			20.4			18.5			19.0

____________

(1) Includes business interruption insurance revenue of $0 and $1.9 million for the three and nine months ended September 30, 2009, and $0 and $0.4 million for the three and nine months ended September 30, 2008.

(2) See “Non-GAAP Financial Measures” included in this Item 2.

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

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $10.4 million, or 16%, for 2009 compared to 2008. Although fractionation and treating volumes increased, revenue decreased as the fuel component of the related fees was lower due to lower natural gas prices which also lowered operating expense.

Operating expenses decreased by $19.9 million, or 40%, for 2009 compared to 2008. The decrease was due to lower fuel, utility, equipment rental/maintenance, and barge fees related to lower volumes and decreased fuel and utility rates.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $28.9 million, or 16%, for 2009 compared to 2008. The decrease was primarily due to decreased fractionation and terminalling and storage volumes as a result of damage to certain of our and third party Gulf Coast processing, pipeline and production facilities from Hurricane Ike as well as a lower fuel component of the fractionation fees. In addition, truck and barge volumes were lower for 2009 due to decreased mixed butanes and wholesale activity.

Operating expenses decreased by $50.2 million, or 34%, for 2009 compared to 2008. The decrease was due to lower fuel, utility, equipment rental/maintenance, and barge fees related to lower volumes and decreased fuel and utility rates.

43

NGL Distribution and Marketing Services Segment

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

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	762.4		$	1,654.0		$	2,011.2		$	4,564.4
Other revenues (1)		1.4			0.8			3.6			10.9
		763.8			1,654.8			2,014.8			4,575.3
Product purchases		(755.7	)		(1,679.4	)		(1,982.2	)		(4,558.8	)
Operating expenses		-			(0.3	)		(0.6	)		(1.5	)
Operating margin (2)	$	8.1		$	(24.9	)	$	32.0		$	15.0
Operating statistics:
NGL sales, MBbl/d		244.5			258.1			251.2			257.5
NGL realized price, $/gal		0.81			1.66			0.70			1.54

____________

(1)  Includes business interruption insurance revenue of $0 and $8.6 million for the three and nine months ended September 30, 2008.

 (2) See “Non-GAAP Financial Measures” included in this Item 2.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

NGL sales revenues decreased by $891.6 million, or 54%, for 2009 compared to 2008. The net decrease comprised an $804.4 million decrease from lower average sales prices, which were down 51% during 2009 compared to 2008 and an $87.2 million decrease from lower sales volumes, down 5% during 2009 compared to 2008. The decrease in sales volumes was primarily attributable to a change in contract terms with a large petrochemical customer partially offset by higher plant operational rates and spot sales.

Other revenues, which consist primarily of non-commodity based service revenue, increased by $0.6 million.

Product purchases decreased by $923.7 million, or 55%, for 2009 compared to 2008. The net decrease comprised a $744.1 million decrease from lower average market prices, a $155.5 million decrease from lower purchased volumes and no lower of cost or market adjustment in 2009. Product purchases in 2008 included a $24.1 million lower of cost or market adjustment.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

NGL sales revenues decreased by $2,553.2 million, or 56%, for 2009 compared to 2008. The net decrease comprised a $2,424.9 million decrease from lower average sales prices during 2009 down 55% to $0.70 per gallon from $1.54 per gallon in 2008 and a $128.3 million decrease from lower sales volumes down 2% in 2009 compared to 2008. The decrease in sales volumes was primarily due to reduced sales to petrochemical customers associated with their lower plant operational rates offset by higher spot sales.

Other revenues, decreased by $7.3 million primarily due to $8.6 million in proceeds from business interruption claims received in 2008 partially offset by lower 2008 non-commodity based service revenue of $1.3 million.

Product purchases decreased by $2,576.6 million, or 57%, for 2009 compared to 2008. The net decrease comprised a $2,273.2 million decrease in average commodity prices, a $279.3 million decrease from lower purchase volumes and no lower of cost or market adjustment in 2009. Product purchases in 2008 included a $24.1 million lower of cost or market adjustment.

44

Wholesale Marketing Segment

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

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	141.7		$	320.6		$	559.4		$	1,175.3
Other revenues (1)		0.3			-			1.2			5.9
		142.0			320.6			560.6			1,181.2
Product purchases		(138.7	)		(326.0	)		(549.9	)		(1,168.2	)
Operating margin (2)	$	3.3		$	(5.4	)	$	10.7		$	13.0
Operating statistics:
NGL sales, MBbl/d		41.2			47.0			54.9			60.1
NGL realized price, $/gal		0.89			1.77			0.89			1.70

____________

(1) Includes business interruption insurance revenue of $0 and $0.5 million for the three and nine months ended September 30, 2009, and $0 and $5.9 million for the three and nine months ended September 30, 2008.

(2) See “Non-GAAP Financial Measures” included in this Item 2.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

NGL sales revenues decreased by $178.9 million, or 56%, for 2009 compared to 2008. Lower NGL market prices decreased revenue by $139.2 million and lower sales volumes decreased revenue by an additional $39.6 million. The 5.8 MBbl/d decrease in volumes was primarily due to decreased sales of propane due to the expiration of refinery purchase agreements.

Product purchases decreased by $187.3 million, or 57%, for 2009 compared to 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $142.6 million and $39.6 million as well as a decrease of $5.1 million related to lower of cost or market adjustments in 2009.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

NGL sales revenues decreased by $615.9 million, or 52%, for 2009 compared to 2008. Lower NGL market prices decreased revenue by $510.4 million and lower sales volumes decreased revenue by an additional $105.5 million. The 5.2 MBbl/d decrease in volumes was primarily due to reduced sales of propane as a result of the expiration of sales supply agreements as well as lower butane sales associated with the expiration of a refinery supply agreement.

Product purchases decreased by $618.3 million, or 53%, for 2009 compared to 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $523.3 million and $90.3 million as well as a decrease of $4.7 million related to lower of cost or market adjustments in 2009.

Hurricane Update

Certain of our Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $4.8 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During the nine months ended September 30, 2009, the estimate was reduced by $0.8 million.

During the nine months ended September 30, 2009, expenditures related to the hurricanes included $6.8 million for previously accrued repair costs, and $0.3 million capitalized as improvements.

45

Liquidity and Capital Resources

Our 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 and our Annual Report.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our senior secured credit facility and access to debt and equity capital markets. While the credit markets have improved somewhat, we remain exposed to availability under our revolving credit facility and counterparty risks. In addition, the recent volatility in the debt markets has increased costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and has at times affected 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 substantially all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices which could have a materially adverse effect on our results of operations. We sell a significant portion of 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 and in the case of natural gas have declined significantly during the year. 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 Item 1 of this Quarterly Report). Current 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 reduce further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

At this point, we do not believe our liquidity has been materially affected by the current credit crisis and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the lenders under our senior secured revolving credit facility. To date, other than a default by an affiliate of Lehman Brothers Commercial Bank (“Lehman Bank”) on a borrowing request in October 2008, we have not experienced any material disruptions in our ability to access our senior secured revolving credit facility. However, we cannot predict with any certainty the impact to us of any further disruptions in the credit environment. See “Item 1A. Risk Factors” in our Annual Report.

Historically, cash generated by our operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, borrowings available under our senior secured revolving credit facility and access to capital markets should provide sufficient resources to finance our operations, non-acquisition related capital expenditures and our minimum quarterly cash distributions for at least the next year.

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 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, 2009, our total outstanding letter of credit postings were $58.8 million.

46

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Notes 6 and 9 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

As part of the acquisition of the Downstream Business, Targa has agreed to provide distribution support to us in the form of a reduction in the reimbursement for general and administrative expense if necessary (or make a payment to us, if needed) for a 1.0 times distribution coverage ratio, at the current distribution level of $0.5175 per limited partner unit, subject to maximum support of $8 million in any quarter. The distribution support is in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011.

We may issue equity or debt securities to assist us in meeting our liquidity and capital spending requirements. We have a universal shelf registration statement on file with the SEC that allows us to periodically issue up to $500 million in equity or debt securities. We currently expect to use any proceeds from offerings under this universal shelf registration statement for general partnership purposes or other purposes to be specified in connection with an offering. After taking into account the issuance of common units under this shelf registration in August 2009, we can issue approximately $391.7 million of additional equity or debt securities under this registration statement.

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, 2009, we had working capital of $97.5 million, including a net short-term asset for commodity and interest rate derivatives of $37.6 million. We record the fair value of all derivative instruments on the balance sheet. Our hedge agreements provide for monthly settlement (quarterly for interest rate swaps) based on the differential between the agreement price and published commodity price and interest rate indexes. Cash received from physical sales of commodities and cash paid for interest will be based on actual market prices and interest rates and will generally offset any gains or losses realized on the derivative instruments. Our derivative contracts do not have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date.

Excluding derivatives, our working capital surplus was $59.9 million as of September 30, 2009. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report and our Annual Report and See Part II, Item 1A, Risk Factors in this Quarterly Report.

Contractual Obligations.  As of September 30, 2009, except for changes in the ordinary course of our business, our contractual obligations have not changed materially from those reported in our Annual Report.

Available Credit.  As of September 30, 2009, we had $390 million in capacity available under our senior secured revolving credit facility, after giving effect to $510.5 million in outstanding borrowings, the issuance of $58.8 million of letters of credit and the effect of the Lehman Bank default.

Cash Flow.  Net cash provided by or used in operating activities, investing activities and financing activities for the nine months ended September 30, 2009 and 2008 were as follows:

47

	Nine Months Ended September 30,
	2009			2008
	(In millions)
Net cash provided by (used in):
Operating activities	$	219.9		$	128.6
Investing activities		(46.2	)		(55.2	)
Financing activities		(211.2	)		(94.1	)

Net cash provided by operating activities increased by $91.3 million, or 71%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, primarily attributable to changes in risk management gains (losses).

Net cash used in investing activities decreased $9.0 million, or 16%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 due primarily to lower capital additions during 2009 compared to 2008.

Net cash used in financing activities increased $117.1 million, or 124%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008, due primarily to the acquisition of the Downstream Business from Targa.

Capital Requirements.  The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A portion of the cost of constructing new gathering lines to connect to our gathering system is paid for by the natural gas producer. However, we expect to continue to incur significant expenditures through the remainder of 2009 related to the expansion of our natural gas gathering and processing infrastructure.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
	(In millions)
Capital expenditures:
Expansion	$	5.8	$	9.0	$	25.0	$	31.2
Maintenance		4.7		11.4		12.1		28.5
	$	10.5	$	20.4	$	37.1	$	59.7

Gross additions to property, plant and equipment were $46.8 million for the nine months ended September 30, 2009 including $9.8 million in noncash additions resulting from the reclassification from inventory of working NGL volumes in third-party and Targa owned facilities. Cash flows from investing activities reflect additions of $46.3 million for the same period. The difference was primarily the result of settled accruals, which decreased by $9.1 million during the period.

We estimate that our total capital expenditures for 2009 will be approximately $50 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that

48

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

For a complete discussion of the measures that management uses to evaluate our operations, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate our Operations” in our Annual Report.

Our operating margin by segment and in total was as follows for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009		2008
	(In millions)
Natural Gas Gathering and Processing	$	46.2		$	50.6		$	121.0	$	168.9
Logistics Assets		25.1			15.8			57.2		34.5
NGL Distribution and Marketing Services		8.1			(24.9	)		32.0		15.0
Wholesale Marketing		3.3			(5.4	)		10.7		13.0
Other		(0.6	)		-			-		-
	$	82.1		$	36.1		$	220.9	$	231.4

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, 2009 and 2008:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions)
Reconciliation of net income (loss) attributable to Targa Resources Partners LP to operating margin:
Net income (loss) attributable to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Add:
Depreciation and amortization expense		25.6			24.4			75.5			72.8
General and administrative expense		17.1			19.1			55.5			57.4
Interest expense, net		29.8			25.4			78.8			71.6
Income tax benefit (expense)		(0.2	)		0.6			0.8			1.8
Other, net		(0.2	)		4.9			(3.3	)		(1.8	)
Operating margin	$	82.1		$	36.1		$	220.9		$	231.4

49

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reconciliation of net cash provided by (used in) operating	(In millions)
activities to Adjusted EBITDA:
Net cash provided by (used in) operating activities	$	64.8		$	(168.2	)	$	219.9		$	128.6
Net income attributable to noncontrolling interest		(0.8	)		(0.2	)		(1.1	)		(0.1	)
Termination of commodity derivatives		-			87.4			-			87.4
Interest expense, net (1)		14.8			10.0			32.9			25.7
Other		(3.9	)		(1.2	)		(3.5	)		4.0
Changes in operating working capital which used (provided) cash:
Accounts receivable and other		22.3			(36.4	)		(5.5	)		(160.1	)
Accounts payable and other liabilities		(28.1	)		131.1			(40.9	)		101.2
Adjusted EBITDA	$	69.1		$	22.5		$	201.8		$	186.7

_____________

(1) Net of amortization of debt issuance costs of $1.3 million and $2.5 million for the three and nine months ended September 30, 2009. Net of amortization of debt issuance costs of $0.6 million and $1.5 million for the three and nine months ended September 30, 2008. Excludes interest expense from affiliate.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reconciliation of net income (loss) to Adjusted EBITDA:	(In millions)
Net income (loss) attributable to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Add:
Interest expense, net		29.8			25.4			78.8			71.6
Income tax expense (benefit)		(0.2	)		0.6			0.8			1.8
Depreciation and amortization expense		25.6			24.4			75.5			72.8
Non-cash loss related to derivatives		4.1			10.6			33.8			11.6
Noncontrolling interest adjustment		(0.2	)		(0.2	)		(0.7	)		(0.7	)
Adjusted EBITDA	$	69.1		$	22.5		$	201.8		$	186.7

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reconciliation of net income (loss) attributable to distributable cash flow:	(In millions)
Net income (loss) attributable to Targa Resources Partners LP	$	10.0		$	(38.3	)	$	13.6		$	29.6
Add:
Depreciation and amortization expense		25.6			24.4			75.5			72.8
Deferred income tax expense (benefit)		0.1			0.5			0.8			1.4
Noncash interest expense		15.0			15.4			45.9			45.9
Loss on debt repurchases		1.5			-			1.5			-
Non-cash loss related to derivatives		4.1			10.6			33.8			11.6
Maintenance capital expenditures		(4.7	)		(11.4	)		(12.1	)		(28.5	)
Other		(0.1	)		(0.2	)		(0.4	)		(0.4	)
Distributable cash flow	$	51.5		$	1.0		$	158.6		$	132.4

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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 is 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, 2009, the net book value of property, plant and equipment was $1.7 billion and we recorded $25.6 million and $75.5 million in depreciation and amortization expense for the three and nine months ended September 30, 2009. 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 $8.4 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 $16.9 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, 2009, the balance sheet reflects total accounts receivable of $251.3 million, which is due from third-parties. The allowance for doubtful accounts as of September 30, 2009 was $2.0 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 $2.5 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 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 derivative financial instruments was $40.8 million as of September 30, 2009, 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 $0.3 million as of September 30, 2009. 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 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 $4.1 million.

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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.

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

Commodity Price Risk. A majority of our revenues 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 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 hedges 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 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.

We have entered into hedging arrangements for a portion of forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). As of September 30, 2009, we had the following hedge arrangements which will settle during the years ending December 31, 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from October 1, 2009 through December 31, 2009):

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Natural Gas

Instrument		Avg. Price		MMBtu per day
Type	Index	$/MMBtu		2009		2010		2011		2012		2013		Fair Value
														(In thousands)
Sales
Swap	IF-HSC		7.39		1,966		-		-		-		-	$	500
Swap	IF-NGPL MC		9.18		6,256		-		-		-		-		2,675
Swap	IF-NGPL MC		8.86		-		5,685		-		-		-		6,169
Swap	IF-NGPL MC		7.34		-		-		2,750		-		-		898
Swap	IF-NGPL MC		7.18		-		-		-		2,750		-		605
					6,256		5,685		2,750		2,750		-
Swap	IF-Waha		7.79		9,936		-		-		-		-		2,999
Swap	IF-Waha		6.53		-		11,709		-		-		-		2,630
Swap	IF-Waha		6.10		-		-		11,250		-		-		(1,553	)
Swap	IF-Waha		6.30		-		-		-		7,250		-		(584	)
Swap	IF-Waha		5.59		-		-		-		-		4,000		(1,251	)
					9,936		11,709		11,250		7,250		4,000
Total Swaps					18,158		17,394		14,000		10,000		4,000
Floor	IF-NGPL MC		6.55		850		-		-		-		-		114
Floor	IF-Waha		6.55		565		-		-		-		-		77
Total Floors					1,415		-		-		-		-
Total Sales					19,573		17,394		14,000		10,000		4,000
														$	13,279

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NGLs

Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
														(In thousands)
Sales
Swap	OPIS-MB		1.32		6,248		-		-		-		-	$	10,931
Swap	OPIS-MB		1.23		-		5,209		-		-		-		28,074
Swap	OPIS-MB		0.89		-		-		3,800		-		-		48
Swap	OPIS-MB		0.92		-		-		-		2,700		-		1,071
Total Swaps					6,248		5,209		3,800		2,700		-
Floor	OPIS-MB		1.44		-		-		199		-		-		1,454
Floor	OPIS-MB		1.43		-		-		-		231		-		1,755
Total Floors					-		-		199		231		-
Total Sales					6,248		5,209		3,999		2,931		-
														$	43,333

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Condensate

Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
														(In thousands)
Sales
Swap	NY-WTI		69.00		322		-		-		-		-	$	(61	)
Swap	NY-WTI		68.04		-		401		-		-		-		(913	)
Swap	NY-WTI		71.00		-		-		200		-		-		(446	)
Swap	NY-WTI		72.60		-		-		-		200		-		(449	)
Swap	NY-WTI		74.00		-		-		-		-		200		(459	)
Total Swaps					322		401		200		200		200
Floor	NY-WTI		60.00		50		-		-		-		-		3
Total Floors					50		-		-		-		-
Total Sales					372		401		200		200		200
														$	(2,325	)

55

These contracts may expose us to the risk of financial loss in certain circumstances. 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.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate debt under our senior secured revolving credit facility. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of September 30, 2009, we had variable rate borrowings of $510.5 million outstanding under our senior secured revolving credit facility. In an effort to reduce the variability of cash flows, we have entered into various 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 variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by

56

counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings. The effect of the our interest rate hedges effectively fixes the base rate on $300 million in variable rate borrowings as shown below (in thousands):

Period	Fixed Rate			Notional Amount			Fair Value
							(In thousands)
Remainder of 2009		3.66	%	$	300	million	$	(647	)
2010		3.66	%		300	million		(9,166	)
2011		3.41	%		300	million		(4,566	)
2012		3.39	%		300	million		(913	)
2013		3.39	%		300	million		569
01/01-04/24/2014		3.39	%		300	million		617
							$	(14,106	)

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 $2.1 million.

Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our customers and derivative counterparties.

We monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy. A portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could impact our overall exposure to credit risk since these customers may be impacted by similar economic or other conditions. To help reduce our credit risk, we evaluate our counterparties’ financial condition and, where appropriate, negotiate netting agreements. We generally do not require collateral for our accounts receivable; however, in certain circumstances we will call for prepayment, require automatic debit agreements or obtain collateral to minimize our potential exposure to defaults.

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, 2009, affiliates of Goldman Sachs, BofA and Barclays Bank accounted for 80%, 10% and 7% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, BofA and Barclays Bank are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

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

There has been no change in our internal control over financial reporting during the three months ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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, 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, 2008. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations, as could the following:

A recent determination that emissions of carbon dioxide and other “greenhouse gases” present an endangerment to public health could result in regulatory initiatives that increase our costs of doing business and the costs of our services.

On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other “greenhouse gases” (“GHGs”) presented an endangerment to human health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. Once finalized, EPA’s finding and determination would allow the agency to begin regulating GHG emissions under existing provisions of the Clean Air Act. In late September 2009, EPA announced two sets of proposed regulations in anticipation of finalizing its findings and determination, one rule to reduce emissions of greenhouse gases from motor vehicles and the other to control emissions of greenhouse gases from stationary sources. Although the motor vehicle rules are expected to be adopted in March 2010, it may take EPA several years to adopt and impose regulations limiting emissions of greenhouse gases from stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S., including natural gas liquids fractionators, beginning in 2011 for emissions occurring in 2010. Any limitation imposed by the EPA on GHG emissions from our natural gas–fired compressor stations, processing facilities and fractionators or from the combustion of natural gas or natural gas liquids that we produce could increase our costs of doing business and/or increase the cost and reduce demand for our services.

The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products and services we provide.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA”, which would establish an economy-wide cap-and-trade program in the United States to reduce emissions of “greenhouse gases,” or “GHGs,” including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, covered sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, natural gas and NGLs.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law. President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued

59

each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission obligations. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for our gathering, treating, processing and fractionating services.

Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, with most of the state-level initiatives focused on large sources of GHG emissions, such as coal-fired electric plants. It is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions. ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards. Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our use of derivatives could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

We cannot assure you that the acquisition of the Downstream Business will be beneficial to us.

On September 24, 2009, we purchased the Downstream Business from certain affiliates of Targa. The acquisition of the Downstream Business significantly increased our size and diversifies the businesses and geographic areas in which we operate. Failure to assimilate those assets into our existing assets would adversely affect our financial condition and results of operations.

The acquisition of the Downstream Business involves numerous risks, including:

• a decrease in our liquidity as a result of our use of a significant portion of our borrowing capacity under our senior secured credit facility to finance the acquisition;

• the failure to realize expected profitability or growth; and

• an increase in collateral demands by our counterparties.

We will also be exposed to risks that are commonly associated with any acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. Moreover, the Downstream Business is subject to similar stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as are our existing plants, pipelines and facilities, and thus our operation of those new assets will cause us to incur increased costs to maintain compliance with such laws and regulations. If any of these risks or unanticipated liabilities or costs were to materialize, any desired benefits of

60

the acquisition may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted.

Some of the business conducted by the Downstream Business is seasonal and potentially impacted by weather and some of the Downstream Business’ NGL inventories may be exposed to movements in prices.

While the volumes of raw NGL mix that the Downstream Business fractionates are generally stable on an average annual basis, volumes fractionated and inventory levels required for the Downstream Business may vary on a seasonal basis. For example, the Downstream Business may fractionate lower volumes during the winter months, when more raw NGL mix is fractionated by facilities closer to the field to capture propane for heating purposes and when wells and gathering systems yield less NGLs due to the effect of colder surface temperatures. Conversely, the Downstream Business typically fractionates greater volumes during the summer months, when less raw NGL mix is locally fractionated for heating purposes, when wells and gathering systems yield more NGLs due to warmer surface temperatures and when refineries have excess supply of raw NGL mix due to various regulatory restrictions. This seasonality in demand may cause the Downstream Business’ results of operations to lack predictability on a quarter to quarter basis.

Similarly, weather conditions have a significant impact on the demand for propane because end-users depend on propane principally for heating purposes. Warmer than normal temperatures in one or more regions in which the Downstream Business operates can significantly decrease the total volume of propane we sell. Lack of consumer demand for propane may also adversely affect the retailers with whom the Downstream Business transacts in its wholesale propane marketing operations, exposing the Downstream Business to such retailers’ inability to satisfy their contractual obligations.

The inventories required to operate the Downstream Business in the normal course generally represent a small fraction of the throughput of NGLs. For propane sales, some seasonal inventories are required to meet customer needs in certain markets. Current practice is to forward price a large majority of both of these types of volumes (seasonal and high-turn inventories). Inventories that are forward priced with physical contracts for fixed future prices will not receive higher prices if prices go up. Inventories that are not forward priced are exposed to prices going down, which may result in inventory revaluations that adversely impact our results of operations.

The Downstream Business has significant relationships with Chevron Corporation (“Chevron”), including the Chevron Phillips Chemical Company LLC joint venture ( “CPC”), as purchasers of its NGLs and customers for its marketing and refinery services. In some cases, these agreements are subject to renegotiation and termination rights.

During 2008 and 2007, approximately 25% and 29% of the Downstream Business’ consolidated revenues, and approximately 9% and 12% of its consolidated product purchases, were derived from transactions with Chevron and CPC. Under many of the Downstream Business’ Chevron contracts where it purchases or markets NGLs on Chevron’s behalf, Chevron may elect to terminate the contracts or renegotiate the price terms. The Downstream Business also has an ongoing relationship with CPC for feedstock supply and services provided at Mont Belvieu, Texas and Galena Park, Texas. Agreements associated with this relationship are expected to be renegotiated over time. To the extent Chevron and CPC reduce the volumes of NGLs that they purchases from the Downstream Business or reduce the volumes of NGLs that the Downstream Business markets on its behalf, if any, or to the extent the economic terms of such contracts are changed, the Downstream Business’ revenues could decline.

The Downstream Business may be unable to cause its majority-owned joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.

The Downstream Business participates in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Without the concurrence of joint

61

venture participants with enough voting interests, the Downstream Business may be unable to cause any of our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interest of us or the particular joint venture.

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.

Our interstate common carrier liquids pipeline is regulated by the Federal Energy Regulatory Commission.

As part of the Downstream Business acquired from Targa, we acquired Targa NGL Pipeline Company LLC (“Targa NGL”). Targa NGL is an interstate NGL common carrier subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act, or ICA. Targa NGL owns a twelve-inch (12”) diameter pipeline that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGLs and purity NGL products. Targa NGL also owns an eight-inch (8”) diameter pipeline and a twenty-inch (20”) diameter pipeline each of which run between Mont Belvieu, Texas and Galena Park, Texas. The eight-inch (8”) and the twenty-inch (20”) pipelines are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers. The ICA requires that we maintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits challenges to newly proposed or changed rates and authorizes FERC to suspend the effectiveness of such rates and to investigate such rates to determine whether they are just and reasonable. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation and, in some cases, reparations for the two (2) year period prior to the filing of a complaint.

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

Not applicable.

Item 3.  Defaults Upon Senior Securities

Not applicable.

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

Not applicable.

Item 5.  Other Information

Not applicable.

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Item 6.  Exhibits

Exhibit Index

Exhibit Number	Description
2.1*	Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (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 July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
4.2	Registration Rights Agreement dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
4.3**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary 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 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary 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 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary 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 September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, 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 September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP 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 September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.9**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.10**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.11**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.12**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.13**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.14**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.15**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.16**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.17**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.18**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.19**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.20**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.21**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.22**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.23**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.24**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.25**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.26**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

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10.1	Commitment Increase Supplement, dated July 29, 2009, 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 August 4, 2009 (File No. 001-33303).
10.2	Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating 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 September 24, 2009 (file No. 001-33303)).
10.3	Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.4	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Permian LP (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.5	Specification Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (SE La) (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.6	Raw Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (Versado) (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.7	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (West La) (incorporated by reference to Exhibit 10.6 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (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

64

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 9, 2009

65

Exhibit Index

Exhibit Number	Description
2.1*	Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (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 July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
4.2	Registration Rights Agreement dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).
4.3**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary 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 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary 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 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary 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 September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, 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 September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP 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 September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.9**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.10**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.11**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.12**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.13**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.14**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.15**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.16**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.17**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.18**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.19**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.20**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.21**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.22**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.23**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.24**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.25**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.26**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

66

10.1	Commitment Increase Supplement, dated July 29, 2009, 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 August 4, 2009 (File No. 001-33303).
10.2	Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating 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 September 24, 2009 (file No. 001-33303)).
10.3	Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.4	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Permian LP (incorporated by reference to Exhibit 10.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.5	Specification Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (SE La) (incorporated by reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.6	Raw Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (Versado) (incorporated by reference to Exhibit 10.5 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (file No. 001-33303)).
10.7	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (West La) (incorporated by reference to Exhibit 10.6 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (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