Targa Resources Partners (NGLS-PA) 10-Q 2009 Q2 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 June 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 46,212,231 Common Units and 943,108 General Partner Units outstanding as of August 1, 2009.

PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	4
	Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008	5
	Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended
	June 30, 2009 and 2008	6
	Consolidated Statement of Changes in Partners’ Capital for the six months ended June 30, 2009
	and 2008	7
	Consolidated Statements of Cash Flows for the six months ended June 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	25
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	34
Item 4.	Controls and Procedures	39
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3.	Defaults Upon Senior Securities	41
Item 4.	Submission of Matters to a Vote of Security Holders	41
Item 5.	Other Information	41
Item 6.	Exhibits	42
SIGNATURES		44

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
Btu	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.

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

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

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

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

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

· the level of creditworthiness of counterparties to transactions;

2

· 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 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 elsewhere in this Quarterly Report on Form 10-Q 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.

3

PART I — FINANCIAL INFORMATION

Item 1.  Financial Statements

TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
	June 30,			December 31,
	2009			2008
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	37,861		$	81,768
Receivables from third parties		32,844			58,355
Receivables from affiliated companies		42,258			22,295
Inventory		2,092			987
Assets from risk management activities		65,950			91,816
Other current assets		411			289
Total current assets		181,416			255,510
Property, plant and equipment, at cost		1,508,368			1,492,726
Accumulated depreciation		(286,107	)		(248,389	)
Property, plant and equipment, net		1,222,261			1,244,337
Long-term assets from risk management activities		34,426			68,296
Other assets		12,670			12,763
Total assets	$	1,450,773		$	1,580,906
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable	$	3,861		$	8,649
Accrued liabilities		77,079			86,191
Liabilities from risk management activities		12,156			11,664
Total current liabilities		93,096			106,504
Long-term debt		656,845			696,845
Long term liabilities from risk management activities		11,540			9,679
Deferred income taxes		2,559			1,959
Other long-term liabilities		3,709			3,555
Commitments and contingencies (see Note 11)
Partners' capital:
Common unitholders (46,212,231 and 34,652,000 units issued and
outstanding as of  June 30, 2009 and December 31, 2008)		637,573			769,921
Subordinated unitholders (11,528,231 units issued and outstanding as of
December 31, 2008)		-			(85,185	)
General partner (943,108 and 942,455 units issued and outstanding as of
June 30, 2009 and December 31, 2008)		4,595			5,556
Accumulated other comprehensive income		40,856			72,072
Total partners' capital		683,024			762,364
Total liabilities and partners' capital	$	1,450,773		$	1,580,906
See notes to consolidated financial statements

4

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Unaudited)
	(In thousands, except per unit amounts)
Revenues from third parties	$	97,593		$	243,138		$	203,425		$	438,210
Revenues from affiliates		143,070			387,382			276,272			704,379
Total operating revenues		240,663			630,520			479,697			1,142,589
Costs and expenses:
Product purchases from third parties		144,052			478,890			297,478			854,515
Product purchases from affiliates		41,549			76,269			82,687			142,794
Operating expenses		11,907			14,701			24,810			27,271
Depreciation and amortization expense		18,972			18,421			37,850			36,669
General and administrative expense		7,544			5,715			12,865			10,916
Casualty loss adjustment		(13	)		-			(13	)		-
Gain on sale of assets		-			(1	)		-			(75	)
		224,011			593,995			455,677			1,072,090
Income from operations		16,652			36,525			24,020			70,499
Other income (expense):
Interest expense, net		(9,774	)		(7,976	)		(19,698	)		(16,694	)
Other (see Note 14)		-			20			726			36
Income before income taxes		6,878			28,569			5,048			53,841
Deferred income tax expense		(300	)		(363	)		(600	)		(700	)
Net income		6,578			28,206			4,448			53,141
Net income attributable to general partner		2,066			3,384			3,956			5,230
Net income available to limited partners	$	4,512		$	24,822		$	492		$	47,911
Basic and diluted net income per limited partner unit	$	0.10		$	0.54		$	0.01		$	1.04
Basic and diluted average limited partner units
outstanding		46,212			46,180			46,209			46,173
See notes to consolidated financial statements

5

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Unaudited)
	(In thousands)
Net income	$	6,578		$	28,206		$	4,448		$	53,141
Other comprehensive loss:
Commodity hedges:
Change in fair value		(35,164	)		(168,452	)		(20,910	)		(220,236	)
Reclassification adjustment for settled periods		(13,291	)		19,714			(19,902	)		29,711
Interest rate hedges:
Change in fair value		8,209			9,165			4,474			(270	)
Reclassification adjustment for settled periods		2,600			848			5,122			615
Other comprehensive loss		(37,646	)		(138,725	)		(31,216	)		(190,180	)
Comprehensive loss	$	(31,068	)	$	(110,519	)	$	(26,768	)	$	(137,039	)
See notes to consolidated financial statements

6

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' CAPITAL
	Partners' Capital									Accumulated
										Other
	Limited Partners						General			Comprehensive
	Common			Subordinated			Partner			Income			Total
	(Unaudited)
	(In thousands)
Balance, December 31, 2008	$	769,921		$	(85,185	)	$	5,556		$	72,072		$	762,364
Contributions		-			-			5			-			5
Amortization of equity awards		174			-			-			-			174
Other comprehensive loss		-			-			-			(31,216	)		(31,216	)
Conversion of subordinated units
to common units (see Note 4)		(97,624	)		97,624			-			-			-
Net income (loss)		1,000			(508	)		3,956			-			4,448
Distributions to unitholders		(35,898	)		(11,931	)		(4,922	)		-			(52,751	)
Balance, June 30, 2009	$	637,573		$	-		$	4,595		$	40,856		$	683,024
See notes to consolidated financial statements

7

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Six Months Ended June 30,
	2009			2008
	(Unaudited)
	(In thousands)
Cash flows from operating activities
Net income	$	4,448		$	53,141
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization in interest expense		1,193			857
Amortization in general and administrative expense		174			119
Depreciation and other amortization expense		37,850			36,669
Accretion of asset retirement obligations		164			72
Deferred income tax expense		600			700
Risk management activities		29,726			1,011
Gain on sale of assets		-			(75	)
Changes in operating assets and liabilities:
Receivables and other assets		5,581			(48,313	)
Inventory		(1,105	)		(726	)
Accounts payable and other liabilities		(6,204	)		55,907
Net cash provided by operating activities		72,427			99,362
Cash flows from investing activities
Additions to property, plant and equipment		(23,450	)		(17,586	)
Other, net		(32	)		(4,150	)
Net cash used in investing activities		(23,482	)		(21,736	)
Cash flows from financing activities
Repayments on credit facility		(40,000	)		(301,300	)
Proceeds from issuance of senior notes		-			250,000
Distributions to unitholders		(52,751	)		(38,678	)
General partner contributions		5			8
Costs incurred in connection with public offerings		(106	)		(72	)
Costs incurred in connection with financing arrangements		-			(6,590	)
Net cash used in financing activities		(92,852	)		(96,632	)
Net change in cash and cash equivalents		(43,907	)		(19,006	)
Cash and cash equivalents, beginning of period		81,768			50,994
Cash and cash equivalents, end of period	$	37,861		$	31,988
See notes to consolidated financial statements

8

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, together with its subsidiaries (“we,” “us,” “our” or the “Partnership”), is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa”), a leading provider of midstream natural gas and NGL services in the United States, to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling natural gas liquids (“NGLs”) and NGL products. We currently operate in the Fort Worth Basin/Bend Arch in North Texas (the “Fort Worth Basin”), the Permian Basin of West Texas and in Southwest Louisiana.

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 six months ended June 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 6). Our financial results for the three and six months ended June 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 on Form 10-Q should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008.

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 June 30, 2009, up until the issuance of the financial statements, which occurred on August 5, 2009. See Notes 5, 8 and 15.

Note 2—Accounting Policies and Related Matters

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.

Accounting Pronouncements Recently Adopted

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 applies to other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS 157 was initially effective as of January 1, 2008, but in February 2008, FASB delayed the effective date for applying this standard 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

9

November 15, 2008. We adopted SFAS 157 as of January 1, 2008 for 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 10.

On October 10, 2008, FASB issued FASB Staff Position (“FSP”) FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active.” FSP FAS 157-3 clarifies the application of SFAS 157 in a market that is not active and provides factors to take into consideration when determining the fair value of an asset in an inactive market. FSP FAS 157-3 was effective upon issuance, including prior periods for which financial statements have not been issued. FSP FAS 157-3 did not have a material impact on our financial statements.

   In December 2007, FASB issued SFAS 141R, “Business Combinations.” SFAS 141R 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. SFAS 141R also establishes principles and requirements for how an acquirer recognizes any noncontrolling interest in the acquiree and the goodwill acquired in a business combination. SFAS 141R 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, SFAS 141R 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.

On April 1, 2009, FASB issued FSP FAS 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies.” FSP FAS 141R-1 amends and clarifies SFAS 141R to address 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 FSP 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 FSP.

In December 2007, FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51.” SFAS 160 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 distinguishes between the interest of the parent and the interests of noncontrolling owners. SFAS 160 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 SFAS 160 as of January 1, 2009. The adoption of SFAS 160 did not have a material impact on our financial statements.

We adopted FASB Emerging Issues Task Force (“EITF”) 07-4, “Application of the Two - Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnership” on January 1, 2009. Our adoption of EITF 07-4 required us to retrospectively adjust our earnings per unit calculation as described in Net Income per Limited Partner Unit above.

We adopted FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payments Transactions are Participating Securities” on January 1, 2009. Upon adoption, we were required to retrospectively adjust our earnings per unit data to conform to the provisions of FSP EITF 03-6-1. The adoption of FSP EITF 03-6-1 resulted in us recognizing unvested unit-based payment awards as participating units in our basic earnings per unit calculation.

On April 9, 2009, FASB issued FSP FAS 157-4, “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.” FSP FAS 157-4 relates to 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 FSP

10

FAS 157-4 as of June 30, 2009. There have been no material financial statement implications relating to our adoption of FSP FAS 157-4.

On April 9, 2009, FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP 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 this FSP as of June 30, 2009. There have been no material financial statement implications relating to the adoption of this FSP. See Note 12.

In May 28, 2009, FASB issued SFAS 165, “Subsequent Events”. SFAS 165 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. SFAS 165 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. SFAS 165 is effective for interim and annual periods ended after June 15, 2009 and should be applied prospectively. The adoption of SFAS 165 did not have a material impact on our financial statements.

Accounting Pronouncements Recently Issued

In June 2009, FASB issued SFAS 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162.” SFAS 168 establishes the FASB Accounting Standards Codification (“Codification”) as the source of authoritative U.S. GAAP recognized by FASB 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. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. On the effective date, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative.

Following SFAS 168, 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.

On June 30, 2009, FASB issued ASU 2009-1, “Topic 105—Generally Accepted Accounting Principles—amendments based on—Statement of Financial Accounting Standards No. 168—The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” ASU 2009-1 amends the Codification for the issuance of SFAS 168.

On June 30, 2009, FASB issued ASU 2009-2, “Omnibus Update—Amendments to Various Topics for Technical Corrections.” The technical corrections in ASU 2009-2 are not expected to impact our financial statements.

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 SFAS 141-R and SFAS 160. We do not anticipate that the adoption of this SAB will have a material impact on our consolidated financial statements.

11

Note 3—Property, Plant and Equipment

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

	June 30,			December 31,
	2009			2008
Natural gas gathering systems	$	1,200,931		$	1,161,942
Processing and fractionation facilities		246,304			237,321
Other property, plant, and equipment		50,137			68,003
Construction in progress		10,996			25,460
		1,508,368			1,492,726
Accumulated depreciation		(286,107	)		(248,389	)
	$	1,222,261		$	1,244,337

Additions to property, plant and equipment were $15.6 million, net of $0.1 million of retirements, for the six months ended June 30, 2009. Cash flows from investing activities reflect additions of $23.5 million for the same period. The difference is the result of settled accruals, which decreased by $7.8 million during the period.

Note 4—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 will have no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.

Note 5—Partner Distributions

Distributions declared and paid during the six months ended June 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
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
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

Subsequent Event. On July 20, 2009, we announced a cash distribution of $0.5175 per unit on our outstanding common units. The distribution will be paid on August 14, 2009 to unitholders of record on August 5, 2009, for the period April 1, 2009 through June 30, 2009. The total distribution to be paid is $26.4 million, with $18.0 million to be paid to our non-affiliated common unitholders and $6.0 million, $0.5 million and $1.9 million to be paid to our general partner for its common unit ownership, general partner interest and incentive distribution rights.

12

Note 6—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) our sales of certain NGLs and NGL products to, and purchases from, Targa; and (iii) our sales of our natural gas to, and purchases from, Targa.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Sales to affiliates	$	143,070	$	387,382	$	276,272	$	704,379
Purchases from affiliates		41,549		76,269		82,687		142,794
Allocations of general & administrative
expenses under Omnibus Agreement		4,594		4,236		9,197		8,098
Net change in affliate receivable		4,969		4,558		19,963		19,820

Relationship with Bank of America

An affiliate of Bank of America (“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 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 June 30, 2009:

Period	Commodity	Daily Volumes			Average Price			Index
Jul 2009 - Dec 2009	Natural gas		3,556	MMBtu	$	8.07	per MMBtu	IF-Waha
Jul 2009 - Dec 2009	Natural gas		652	MMBtu		8.06	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
Jul 2009 - Dec 2009	NGL		3,000	Bbl		1.18	per gallon	OPIS-MB
Jul 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 June 30, 2009, the aggregate fair value of these open positions was $12.7 million. For the three and six months ended June 30, 2009, we received $7.4 million and $15.9 million from BofA to settle payments due under hedge transactions. For the three and six months ended June 30, 2008, we paid BofA $7.4 million and $11.7 million to settle payments due under hedge transactions.

We have entered into several interest rate derivative transactions with BofA. Open positions as of June 30, 2009 consisted of interest rate swaps and interest rate basis swaps expiring on April 24, 2014. As of June 30, 2009, the aggregate fair value of these positions was a liability of $3.6 million. Payments to BofA related to settled portions were $0.6 million and $1.6 million for the three and six months ended June 30, 2009.

13

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 six months ended June 30, 2009, we purchased $1.7 million and $3.1 million of product from Broad Oak. During the three and six months ended June 30, 2008, we purchased $1.2 million of product from Broad Oak.

Note 7—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.

Note 8—Long-Term Debt

Our consolidated debt obligations consisted of the following as of the dates indicated:

	June 30,		December 31,
	2009		2008
Senior unsecured notes, 8¼% fixed rate, due July 1, 2016	$	209,080	$	209,080
Senior secured credit facility, variable rate, due February 14, 2012		447,765		487,765
Total long-term debt	$	656,845	$	696,845
Letters of credit issued	$	13,370	$	9,651

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations during the six months ended June 30, 2009:

	Range of interest rates paid	Weighted average interest rate paid
Credit facility	1.3% to 4.5%	1.9%

Subsequent Events.

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 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 credit facility;

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

· are unconditionally guaranteed by us.

14

The 11¼% Notes are effectively subordinated to all secured 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.

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 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 agreement 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, the Partnership is 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.

Commitment Increase

On July 29, 2009, we executed a Commitment Increase Supplement (the “Supplement”) to our existing senior secured credit facility. The 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, which would increase the total commitments under our credit facility to $1 billion.

Note 9—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

15

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 June 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 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 our variable rate debt under our credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of June 30, 2009, we had borrowings of approximately $447.8 million outstanding under our 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 June 30, 2009, affiliates of Goldman Sachs, BofA and Barclays Bank accounted for 77%, 14% and 6% 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.

16

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

	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	June 30,		December 31,		Sheet	June 30,		December 31,
	Location	2009		2008		Location	2009		2008
Derivatives designated as
hedging instruments under
SFAS 133
Commodity contracts	Current assets	$	61,259	$	88,206	Current liabilities	$	628	$	-
	Other assets		34,426		68,296	Other liabiliites		9,239		123
Interest rate contracts	Current assets		1,709		-	Current liabilities		8,535		8,020
	Other assets		-		-	Other liabiliites		2,301		9,556
Total			97,394		156,502			20,703		17,699
Derivatives not designated as
hedging instruments under
SFAS 133
Commodity contracts	Current assets		2,982		3,610	Current liabilities		2,993		3,644
	Other assets		-		-	Other liabiliites		-		-
Total			2,982		3,610			2,993		3,644
Total derivatives		$	100,376	$	160,112		$	23,696	$	21,343

	Amount of Gain (Loss)
Derivatives in	Recognized in OCI on
SFAS 133	Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended June 30,
Relationships	2009			2008
Interest rate contracts	$	8,209		$	9,165
Commodity contracts		(35,164	)		(168,452	)
	$	(26,955	)	$	(159,287	)
	Amount of Gain (Loss)
Derivatives in	Recognized in OCI on
SFAS 133	Derivatives (Effective Portion)
Cash Flow Hedging	Six Months Ended June 30,
Relationships		2009			2008
Interest rate contracts	$	4,474		$	(270	)
Commodity contracts		(20,910	)		(220,236	)
	$	(16,436	)	$	(220,506	)

17

	Amount of Gain (Loss)						Amount of Gain (Loss)
Location of Gain (Loss)	Reclassified from OCI to						Recognized in Income on
Reclassified from	Income (Effective Portion)						Derivatives (Ineffective Portion)
Accumulated OCI	Three Months Ended June 30,						Three Months Ended June 30,
into Income	2009			2008			2009			2008
Interest expense, net	$	(2,600	)	$	(848	)	$	-		$	-
Revenues		13,664			(19,714	)		(373	)		-
	$	11,064		$	(20,562	)	$	(373	)	$	-
	Amount of Gain (Loss)						Amount of Gain (Loss)
Location of Gain (Loss)	Reclassified from OCI to						Recognized in Income on
Reclassified from	Income (Effective Portion)						Derivatives (Ineffective Portion)
Accumulated OCI	Six Months Ended June 30,						Six Months Ended June 30,
into Income		2009			2008			2009			2008
Interest expense, net	$	(5,122	)	$	(615	)	$	-		$	-
Revenues		19,903			(29,711	)		-			-
	$	14,781		$	(30,326	)	$	-		$	-

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 June 30, 2009, OCI consisted of $48.8 million of unrealized net gains on commodity hedges and $8.0 million of unrealized net losses on interest rate hedges. Deferred net gains of $38.3 million on commodity hedges and deferred net losses of $6.8 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.

18

As of June 30, 2009, we had the following commodity 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 July 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		-		-		-		-	$	1,155
					1,966		-		-		-		-
Swap	IF-NGPL MC		9.18		6,256		-		-		-		-		6,109
Swap	IF-NGPL MC		8.86		-		5,685		-		-		-		6,655
Swap	IF-NGPL MC		7.34		-		-		2,750		-		-		866
Swap	IF-NGPL MC		7.18		-		-		-		2,750		-		466
					6,256		5,685		2,750		2,750		-
Swap	IF-Waha		7.79		9,936		-		-		-		-		7,115
Swap	IF-Waha		6.53		-		11,709		-		-		-		4,020
Swap	IF-Waha		6.10		-		-		11,250		-		-		(973	)
Swap	IF-Waha		6.30		-		-		-		7,250		-		(821	)
Swap	IF-Waha		5.59		-		-		-		-		4,000		(1,536	)
					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		-		-		-		-		435
					850		-		-		-		-
Floor	IF-Waha		6.55		565		-		-		-		-		285
					565		-		-		-		-
Total Floors					1,415		-		-		-		-
Total Sales					19,573		17,394		14,000		10,000		4,000
Basis swap Jul 09-May 2011 Rec IF-CGT, Pay NYMEX less $0.11, 20,000 MMBtu/d															(668	)
Fuel cost swap Jul 2009-May2011 Rec IF-CGT, Pay $5.96, 226 MMbtu/d															46
														$	23,154

19

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		-		-		-		-	$	24,428
Swap	OPIS-MB		1.27		-		4,809		-		-		-		30,359
Swap	OPIS-MB		0.92		-		-		3,400		-		-		1,844
Swap	OPIS-MB		0.92		-		-		-		2,700		-		545
Total Swaps					6,248		4,809		3,400		2,700		-
Floor	OPIS-MB		1.44		-		-		199		-		-		3,937
Floor	OPIS-MB		1.43		-		-		-		231		-		4,242
Total Floors					-		-		199		231		-
Total Sales					6,248		4,809		3,599		2,931		-
														$	65,355

Condensate

Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		69.00		322		-		-		-		-	$	(149	)
Swap	NY-WTI		68.04		-		401		-		-		-		(1,048	)
Swap	NY-WTI		71.00		-		-		200		-		-		(508	)
Swap	NY-WTI		72.60		-		-		-		200		-		(506	)
Swap	NY-WTI		74.00		-		-		-		-		200		(495	)
Total Swaps					322		401		200		200		200
Floor	NY-WTI		60.00		50		-		-		-		-		15
Total Floors					50		-		-		-		-
Total Sales					372		401		200		200		200
														$	(2,691	)

20

Customer Hedges

As of June 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 Mkt Price

Index

Fair Value

(In thousands)

Purchases

Jan 2009 - Dec 2009

Natural gas

Swap

8,380

MMBtu

5.70

per MMBtu

NY-HH

$

(2,448

)

Jan 2010 - Jun 2010

Natural gas

Swap

663

MMBtu

8.03

per MMBtu

NY-HH

(264

)

Sales

Jan 2009 - Dec 2009

Natural gas

Fixed price sale

8,380

MMBtu

5.70

per MMBtu

NY-HH

2,439

Jan 2010 - Jun 2010

Natural gas

Fixed price sale

663

MMBtu

8.03

per MMBtu

NY-HH

262

$

(11

)

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		3.68%	$	300	million	$	(4,668	)
2010		3.67%		300	million		(6,703	)
2011		3.48%		300	million		(2,048	)
2012		3.40%		300	million		1,050
2013		3.39%		300	million		2,318
01/01-4/24/2014		3.39%		300	million		924
						$	(9,127	)

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 Note 6 and Note 10 for additional disclosures related to derivative instruments and hedging activities.

Note 10—Fair Value Measurements

We classify our 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 June 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.

21

	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	98,667	$	-	$	31,987	$	66,680
Assets from interest rate derivatives		1,709		-		1,709		-
Total assets	$	100,376	$	-	$	33,696	$	66,680
Liabilities from commodity derivative contracts	$	12,860	$	-	$	11,535	$	1,325
Liabilities from interest rate derivatives		10,836		-		10,836		-
Total liabilities	$	23,696	$	-	$	22,371	$	1,325

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 losses included in OCI		(26,557	)
Settlements		(31,392	)
Balance, June 30, 2009	$	65,355

No unrealized gains or losses related to assets and liabilities still held as of June 30, 2009 were included in our consolidated statement of operations.

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

Note 11—Commitments and Contingencies

Environmental

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

We do not have a reserve for environmental expenses as of June 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.

22

Note 12—Fair Value of Financial Instruments

The estimated fair values of our 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 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:

	June 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior unsecured notes, 8¼% fixed rate		209,080		176,673		209,080		128,333

Note 13—Accounting for Unit-Based Compensation

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

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

Non-Employee Director Grants

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 six months ended June 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.

23

Note 14—Sale of Bankruptcy Claim

In 2008, we terminated certain derivative contracts with Lehman Brothers Commodity Services, Inc. and filed a claim with the United States Bankruptcy Court. During the first quarter of 2009, we sold our bankruptcy claim for $0.7 million and recognized the proceeds as other income in our consolidated statement of operations.

Note 15—Subsequent Event

On July 27, 2009, we agreed to acquire Targa’s natural gas liquids business (the “Downstream Business”) for $530 million. As part of the transaction, Targa 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 for a 1.0 times distribution coverage ratio, at the current $0.5175 per limited partner unit, subject to maximum support of $8 million in any quarter. The distribution support will be in effect for the nine-quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011.

Consideration to Targa will include 25% of the transaction value in newly issued common and general partner units of the Partnership. The remaining 75%, or approximately $397.5 million, will be in cash, funded through borrowings under our senior secured credit facility.

The equity consideration to Targa will consist of 8,527,615 common units and 174,033 general partner units valued at $15.227 per unit (calculated using the volume weighted-average trading price for the 10-day period through and including July 17, 2009) and equal to 25% of the transaction value, or $132.5 million.

For additional subsequent event disclosures, see Notes 1, 5 and 8.

24

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. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products. We currently operate in the Fort Worth Basin/Bend Arch in North Texas, the Permian Basin in West Texas and in Southwest Louisiana.

We are owned 98% by our limited partners and 2% by our general partner, Targa Resources GP LLC, an indirect, wholly-owned subsidiary of Targa. In addition, Targa owns 11,528,231 common units, representing a 24.5% limited partner interest in us, through its indirect wholly-owned subsidiaries, Targa GP Inc. and Targa LP Inc. Our limited partner common units are publicly traded on The NASDAQ Stock Market LLC under the symbol “NGLS.”

Our Operations

We sell the majority of our processed natural gas, NGLs and high-pressure condensate to Targa at market-based rates pursuant to natural gas, NGL and condensate purchase agreements. Low-pressure condensate is sold to third parties. For a more complete description of these arrangements, see “Item 13. Certain Relationships and Related Transactions, and Director Independence” in our Annual Report.

Recently Issued Pronouncements

See Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

25

Results of Operations

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

[Missing Graphic Reference]	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(In millions, except operating and price data)
Revenues	$	240.7		$	630.5		$	479.7		$	1,142.6
Product purchases		185.6			555.2			380.1			997.3
Operating expenses		11.9			14.7			24.8			27.3
Depreciation and amortization expense		19.0			18.4			37.9			36.7
General and administrative expense		7.6			5.7			12.9			10.9
Gain on sale of assets		-			-			-			(0.1	)
Income from operations		16.6			36.5			24.0			70.5
Interest expense, net		(9.8	)		(8.0	)		(19.7	)		(16.7	)
Deferred income tax expense		(0.3	)		(0.3	)		(0.6	)		(0.7	)
Other		0.1			-			0.7			-
Net income	$	6.6		$	28.2		$	4.4		$	53.1
Financial and operating data:
Financial data:
Operating margin (1)	$	43.2		$	60.6		$	74.8		$	118.0
Adjusted EBITDA (2)		46.9			55.4			92.3			108.2
Distributable cash flow (3)		35.6			40.5			69.1			80.6
Operating data:
Gathering throughput, MMcf/d (4)
LOU System		189.5			194.2			167.7			195.2
SAOU System		99.4			99.2			100.6			98.5
North Texas System		186.4			170.5			184.2			169.8
		475.3			463.9			452.5			463.5
Plant natural gas inlet, MMcf/d (5)(6)
LOU System		181.9			182.9			161.4			184.0
SAOU System		93.0			91.9			92.2			91.1
North Texas System		179.8			164.2			178.0			163.3
		454.7			439.0			431.6			438.4
Gross NGL production, MBbl/d
LOU System		9.0			10.2			8.3			10.5
SAOU System		14.3			14.4			14.3			14.3
North Texas System		20.9			19.1			20.3			19.3
		44.2			43.7			42.9			44.1
Natural gas sales, BBtu/d (6)		378.3			410.0			366.8			414.2
NGL sales, MBbl/d		39.8			39.1			38.5			38.5
Condensate sales, MBbl/d		3.1			3.7			3.2			3.7
Average realized prices:
Natural Gas, $/MMBtu		3.55			10.47			4.03			9.22
NGL, $/gal		0.66			1.35			0.61			1.29
Condensate, $/ Bbl		53.40			101.11			46.98			93.38

26

_____________

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

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

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

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

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

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

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

Our revenues decreased by $389.8 million, or 62%, to $240.7 million for 2009 compared to $630.5 million for 2008. The decrease is primarily due to:

· a decrease attributable to commodity prices of $356.9 million, comprising decreases in natural gas, NGL and condensate revenues of $238.1 million, $105.5 million and $13.3 million;

· a decrease attributable to commodity sales volume of $32.7 million comprising decreases in natural gas and condensate revenues of $30.2 million and $6.1 million, partially offset by an increase in NGL revenues of $3.6 million; and

· a decrease in other revenues of $0.2 million, primarily from miscellaneous processing activities.

Our average realized price for natural gas decreased by $6.92 per MMBtu, or 66%, to $3.55 per MMBtu for 2009 compared to $10.47 per MMBtu for 2008. Our average realized price for NGLs decreased by $0.69 per gallon, or 51%, to $0.66 per gallon for 2009 compared to $1.35 per gallon for 2008. Our average realized price for condensate decreased by $47.71 per barrel, or 47%, to $53.40 per barrel for 2009 compared to $101.11 per barrel for 2008.

Our natural gas sales volumes decreased by 31.7BBtu/d, or 8%, to 378.3 BBtu/d for 2009 compared to 410.0 BBtu/d for 2008. The decrease in natural gas sales is primarily the result of a decrease in purchases from affiliates for resale.

Our NGL sales volumes increased by 0.7 MBbl/d, or 2%, to 39.8 MBbl/d for 2009 compared to 39.1 MBbl/d for 2008.

Our condensate sales volumes decreased by 0.6 MBbl/d, or 16%, to 3.1 MBbl/d for 2009 compared to 3.7 MBbl/d for 2008.

Our product purchases decreased by $369.6 million, or 67%, to $185.6 million for 2009 compared to $555.2 million for 2008. The decrease in product purchase cost reflects lower commodity pricing and purchases of wellhead volumes.

Our operating expenses decreased by $2.8 million, or 19%, to $11.9 million for 2009 compared to $14.7 million for 2008. The decrease in operating expenses primarily resulted from a decrease in system maintenance and utility expenses.

27

Our general and administrative expenses increased by $1.9 million, or 33%, to $7.6 million for 2009 compared to $5.7 million for 2008. This is primarily due to $2.1 million in transaction costs in 2009. 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 $1.8 million, or 23%, to $9.8 million for 2009 compared to $8.0 million for 2008. The increase is primarily due to the issuance in June 2008 of our 8¼% Senior Notes due 2016 (the “8¼% Notes”).

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Our revenues decreased by $662.9 million, or 58%, to $479.7 million for 2009 compared to $1,142.6 million for 2008. The decrease is primarily due to:

· a decrease attributable to commodity prices of $569.5 million, comprising decreases in natural gas, NGL and condensate revenues of $344.3 million, $198.0 million and $27.2 million;

· a decrease attributable to commodity sales volume of $93.8 million comprising decreases in natural gas, NGL and condensate revenues of $83.0 million, $2.3 million and $8.5 million; and

· an increase in other revenues of $0.4 million, primarily from miscellaneous processing activities.

Our average realized price for natural gas decreased by $5.19 per MMBtu, or 56%, to $4.03 per MMBtu for 2009 compared to $9.22 per MMBtu for 2008. Our average realized price for NGLs decreased by $0.68 per gallon, or 51%, to $0.61 per gallon for 2009 compared to $1.29 per gallon for 2008. Our average realized price for condensate decreased by $46.40 per barrel, or 50%, to $46.98 per barrel for 2009 compared to $93.38 per barrel for 2008.

Our natural gas sales volumes decreased by 47.4BBtu/d, or 11%, to 366.8 BBtu/d for 2009 compared to 414.2 Btu/d for 2008. The decrease in natural gas sales is 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 were flat at 38.5 MBbl/d for both 2009 and 2008.

Our condensate sales volumes decreased by 0.5 MBbl/d, or 14%, to 3.2 MBbl/d for 2009 compared to 3.7 MBbl/d for 2008.

Our product purchases decreased by $617.2 million, or 62%, to $380.1 million for 2009 compared to $997.3 million for 2008. The decrease in product purchase cost reflects lower commodity pricing and purchases of wellhead volumes.

Our operating expenses decreased by $2.5 million, or 9%, to $24.8 million for 2009 compared to $27.3 million for 2008. The decrease in operating expenses was primarily the result of a decrease in system maintenance expenses.

Our general and administrative expenses increased by $2.0 million, or 18%, to $12.9 million for 2009 compared to $10.9 million for 2008. This is primarily due to $2.1 million in transaction costs in 2009. 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 $3.0 million, or 18%, to $19.7 million for 2009 compared to $16.7 million for 2008. The increase is primarily due to the issuance of our 8¼% Notes.

Liquidity and Capital Resources

Our ability to finance our operations, including to fund capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements depends on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and our ongoing

28

efforts to manage operating costs and maintenance capital expenditures. See “Item 1A.  Risk Factors” in this Quarterly Report and in our Annual Report.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a senior secured credit facility with both uncommitted and committed availability and access to both the debt and equity capital markets. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit crisis includes our senior secured credit facility, cash investments and counterparty performance risks. Continued volatility in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

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 operations. We sell a significant portion of our natural gas and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil and natural gas prices are also volatile and 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 9 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report). The 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 decrease further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

At this point, we do not believe our liquidity has been materially affected by the current credit crisis and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the capital markets. Additionally, we will continue to monitor events and circumstances surrounding each of our lenders under our senior secured 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 credit facility. However, we cannot predict with any certainty the impact to us of any further disruptions in the credit environment.

Historically, cash generated from our operations has been sufficient to finance our operating expenditures and fund most of our maintenance and expansion capital expenditures, with remaining amounts being distributed to our unitholders.

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

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Notes 5 and 8 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Working Capital.  Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital

29

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 June 30, 2009, we had working capital of $88.3 million, including a net short-term asset for commodity and interest rate derivatives of $53.8 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 $34.5 million as of June 30, 2009. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report and our Annual Report.

Contractual Obligations.  As of June 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 June 30, 2009, we had approximately $378 million in capacity available under our senior secured credit facility, after giving effect to $447.8 million in outstanding borrowings, the issuance of $13.4 million of letters of credit and the effect of the Lehman Bank default.

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.

Cash Flow.  Net cash provided by or used in operating activities, investing activities and financing activities for the six months ended June 31, 2009 and 2008 were as follows:

	Six Months Ended June 30,
	2009			2008
	(In millions)
Net cash provided by (used in):
Operating activities	$	72.4		$	99.4
Investing activities		(23.5	)		(21.7	)
Financing activities		(92.9	)		(96.6	)

Net cash provided by operating activities decreased by $27.0 million, or 27%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008, primarily attributable to the net of a $48.8 million decrease in net income, a $28.7 million increase in risk management activities net assets and a decrease of $8.4 million of net operating assets during the respective periods.

Net cash used in investing activities for the six months ended June 30, 2009 increased $1.8 million, or 8%, compared to the six months ended June 30, 2008 due primarily to an increase in cash payments for additions to property, plant and equipment.

30

Net cash used in financing activities decreased $3.7 million, or 4%, for the six months ended June 30, 2009 compared to the six months ended June 30, 2008, due primarily to a lack of financing arrangement costs incurred in the current period versus the prior period.

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 June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Capital expenditures:
Expansion	$	5.9	$	3.1	$	11.0	$	6.1
Maintenance		2.1		7.4		4.7		11.8
	$	8.0	$	10.5	$	15.7	$	17.9

Gross additions to property, plant and equipment were $15.7 million for the six months ended June 30, 2009. Cash flows from investing activities reflect additions of $23.5 million for the same period. The difference is the result of settled accruals, which decreased by $7.8 million during the period.

We estimate that our total capital expenditures for 2009 will be approximately $40 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that we will invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

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

Non-GAAP Financial Measures

For a complete discussion of the measures that management uses to evaluate our operations, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate our Operations” in our Annual Report on Form 10-K for the year ended December 31, 2008. The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the three and six months ended June 30, 2009 and 2008:

31

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Reconciliation of net cash provided by operating activities	(In millions)
to Adjusted EBITDA:
Net cash provided by operating activities	$	50.4		$	46.6		$	72.4		$	99.4
Interest expense, net (1)		9.2			7.5			18.5			15.8
Changes in operating working capital which used (provided) cash:
Accounts receivable and other		1.6			43.4			(4.8	)		48.9
Accounts payable and other liabilities		(14.3	)		(42.1	)		6.2			(55.9	)
Adjusted EBITDA	$	46.9		$	55.4		$	92.3		$	108.2

_____________

(1) Net of amortization of debt issuance costs of $0.6 million and $1.2 million for the three and six months ended June 30, 2009. Net of amortization of debt issuance costs of $0.5 million and $0.9 million for the three and six months ended June 30, 2008.

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Reconciliation of net income to Adjusted EBITDA:	(In millions)
Net income	$	6.6	$	28.2	$	4.4	$	53.1
Add:
Interest expense, net		9.8		8.0		19.7		16.7
Deferred income tax expense		0.3		0.3		0.6		0.7
Depreciation and amortization expense		19.0		18.4		37.9		36.7
Non-cash loss related to derivatives		11.2		0.5		29.7		1.0
Adjusted EBITDA	$	46.9	$	55.4	$	92.3	$	108.2

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Reconciliation of net income to operating margin:
Net income	$	6.6	$	28.2	$	4.4	$	53.1
Add:
Depreciation and amortization expense		19.0		18.4		37.9		36.7
Deferred income tax expense		0.3		0.3		0.6		0.7
Interest expense, net		9.8		8.0		19.7		16.7
General and administrative and other expense		7.5		5.7		12.2		10.8
Operating margin	$	43.2	$	60.6	$	74.8	$	118.0

32

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Reconciliation of net income to distributable cash flow:	(In millions)
Net income	$	6.6		$	28.2		$	4.4		$	53.1
Add:
Depreciation and amortization expense		19.0			18.4			37.9			36.7
Deferred income tax expense		0.3			0.3			0.6			0.7
Amortization in interest expense		0.6			0.5			1.2			0.9
Non-cash loss related to derivatives		11.2			0.5			29.7			1.0
Maintenance capital expenditures		(2.1	)		(7.4	)		(4.7	)		(11.8	)
Distributable cash flow	$	35.6		$	40.5		$	69.1		$	80.6

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. Our 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 our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our 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 June 30, 2009, the net book value of our property, plant and equipments was $1.2 billion and we recorded $37.9 million in depreciation and amortization expense for the six months ended June 30, 2009. The weighted-average life of our 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 and amortizable lives of our 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 our operating income.  In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, our operating income would decrease by $12.2 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 June 30, 2009, our balance sheet reflects total accounts receivable of approximately $75.1 million of which $32.8 million is due from third-parties and $42.3 million is due from affiliates.  We do not have an allowance for doubtful accounts as of June 30, 2009.

33

Our 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 our third-party accounts receivable, our operating income would decrease by $0.4 million.  There have been no material changes impacting accounts receivable.

Price Risk Management (Hedging). Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our 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 our 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 $76.7 million as of June 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 $2.8 million as of June 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 our operating income would decrease by $7.2 million.

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 our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs (including the impact of reduced commodity prices on oil and gas drilling levels), changes in interest rates, as well as nonperformance risk by our 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

34

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.

35

We have entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). As of June 30, 2009, we had the following open commodity derivative positions which will settle during 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from July 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		-		-		-		-	$	1,155
					1,966		-		-		-		-
Swap	IF-NGPL MC		9.18		6,256		-		-		-		-		6,109
Swap	IF-NGPL MC		8.86		-		5,685		-		-		-		6,655
Swap	IF-NGPL MC		7.34		-		-		2,750		-		-		866
Swap	IF-NGPL MC		7.18		-		-		-		2,750		-		466
					6,256		5,685		2,750		2,750		-
Swap	IF-Waha		7.79		9,936		-		-		-		-		7,115
Swap	IF-Waha		6.53		-		11,709		-		-		-		4,020
Swap	IF-Waha		6.10		-		-		11,250		-		-		(973	)
Swap	IF-Waha		6.30		-		-		-		7,250		-		(821	)
Swap	IF-Waha		5.59		-		-		-		-		4,000		(1,536	)
					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		-		-		-		-		435
					850		-		-		-		-
Floor	IF-Waha		6.55		565		-		-		-		-		285
					565		-		-		-		-
Total Floors					1,415		-		-		-		-
Total Sales					19,573		17,394		14,000		10,000		4,000
Basis swap Jul 09-May 2011 Rec IF-CGT, Pay NYMEX less $0.11, 20,000 MMBtu/d															(668	)
Fuel cost swap Jul 2009-May2011 Rec IF-CGT, Pay $5.96, 226 MMbtu/d															46
														$	23,154

36

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		-		-		-		-	$	24,428
Swap	OPIS-MB		1.27		-		4,809		-		-		-		30,359
Swap	OPIS-MB		0.92		-		-		3,400		-		-		1,844
Swap	OPIS-MB		0.92		-		-		-		2,700		-		545
Total Swaps					6,248		4,809		3,400		2,700		-
Floor	OPIS-MB		1.44		-		-		199		-		-		3,937
Floor	OPIS-MB		1.43		-		-		-		231		-		4,242
Total Floors					-		-		199		231		-
Total Sales					6,248		4,809		3,599		2,931		-
														$	65,355

Condensate

Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		69.00		322		-		-		-		-	$	(149	)
Swap	NY-WTI		68.04		-		401		-		-		-		(1,048	)
Swap	NY-WTI		71.00		-		-		200		-		-		(508	)
Swap	NY-WTI		72.60		-		-		-		200		-		(506	)
Swap	NY-WTI		74.00		-		-		-		-		200		(495	)
Total Swaps					322		401		200		200		200
Floor	NY-WTI		60.00		50		-		-		-		-		15
Total Floors					50		-		-		-		-
Total Sales					372		401		200		200		200
														$	(2,691	)

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate debt under our credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of June 30, 2009, we had borrowings of approximately $447.8 million outstanding under our 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 OCI until the interest expense on the related debt is recognized in earnings.

As of June 30, 2009, we had $447.8 million outstanding under our senior secured credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable

37

to changes in market interest rates we have entered into interest rate swaps and basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

Period	Fixed Rate		Notional Amount			Fair Value
Remainder of 2009		3.68%	$	300	million	$	(4,668	)
2010		3.67%		300	million		(6,703	)
2011		3.48%		300	million		(2,048	)
2012		3.40%		300	million		1,050
2013		3.39%		300	million		2,318
01/01-4/24/2014		3.39%		300	million		924
						$	(9,127	)

We have designated all interest rate swaps and interest rate basis swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the swaps are deferred in OCI until interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account our interest rate swaps and interest rate basis swaps, would increase our annual interest expense by $1.5 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 June 30, 2009, affiliates of Goldman Sachs, BofA and Barclays Bank accounted for 77%, 14% and 6% 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.

38

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 June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

39

PART II — OTHER INFORMATION

Item 1.  Legal Proceedings

The information required for this item is provided in Note 11—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 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.  The finding and determination allows the EPA to begin regulating GHG emissions under existing provisions of the Clean Air Act.  Any limitation imposed by the EPA on GHG emissions from our natural gas–fired compressor stations and processing facilities 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.  In addition, the U.S. Congress and various states are currently considering legislation that may impose national or regional caps on GHG emissions and may require major sources of GHG emissions to purchase “allowances” that would permit such sources to continue to emit GHGs.  Such legislation could require us to obtain allowances to offset emissions of GHGs that result from the combustion of natural gas or natural gas liquids we produce.  As an alternative to a “cap and trade” program, it is possible that Congress or individual states could implement carbon tax programs.  Any such regulatory initiatives adopted by EPA or legislation adopted by Congress or the states could increase our costs of doing business and/or increase the cost and reduce demand for our services.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for oil and natural gas products.

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.  The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States.  GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes.  ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050.  Under ACESA, most 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, and natural gas.

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 each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission

40

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, compressing, treating, processing and fractionating services.

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 trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

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.

41

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	Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
4.2	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)).
4.3	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)).
10.1	Purchase Agreement dated as of June 30, 2009 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and Barclays Capital Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).

42

10.2	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).
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

43

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 autho

Targa Resources Partners  (Registrant)

By: Targa Resources GP LLC,

its general partner

By: /s/ John Robert Sparger e

John Robert Sparger

Senior Vice President and

Chief Accounting Officer

(Authorized signatory and

Principal Accounting Officer)

Date: August 5, 2009

44

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	Specimen Unit Certificate representing common units (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
4.2	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)).
4.3	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)).
10.1	Purchase Agreement dated as of June 30, 2009 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and Barclays Capital Inc., as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 6, 2009 (File No. 001-33303)).

45

10.2	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).
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