form10q.htm

10-Q 1 form10q.htm TRP 033110 FORM 10-Q form10q.htm

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 March 31, 2010

¨ 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)

(713) 584-1000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

þ Yes ¨ No

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

¨ Yes ¨ No

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

Large accelerated filer	¨	Accelerated filer	þ
Non-accelerated filer	¨ (Do not check if a smaller reporting company)	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 þ No

As of May 1, 2010, there were 67,980,596 Common Units and 1,387,360 General Partner Units outstanding.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.			5

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

Consolidated Statements of Operations for the three months ended March 31, 2010 and 2009			6

Consolidated Statements of Comprehensive Income for the three months ended March 31, 2010 and 2009			7

Consolidated Statement of Changes in Owners' Equity for the three months ended March 31, 2010			8

Consolidated Statements of Cash Flows for the three months ended March 31, 2010 and 2009			9

Notes to Consolidated Financial Statements			10

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.			25

Item 3. Quantitative and Qualitative Disclosures About Market Risk.			39

Item 4. Controls and Procedures.			42

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.			43

Item 1A. Risk Factors.			43

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.			43

Item 3. Defaults Upon Senior Securities.			44

Item 4. (Removed and Reserved).			44

Item 5. Other Information.			44

Item 6. Exhibits.			45

SIGNATURES

Signatures			47

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

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

Price Index Definitions

IF-NGPL MC			Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha			Inside FERC Gas Market Report, West Texas Waha
NY-WTI			NYMEX, West Texas Intermediate Crude Oil
OPIS-MB			Oil Price Information Service, Mont Belvieu, Texas

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

Cautionary Statement About Forward-Looking Statements

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

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

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

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

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

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

the level of creditworthiness of counterparties to transactions;

changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment;

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

weather and other natural phenomena;

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

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

the level and success of crude oil and natural gas drilling around our assets and our success in connecting natural gas supplies to our gathering and processing systems and NGL supplies to our logistics and marketing facilities;

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

general economic, market and business conditions; and

the risks described in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2009 (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 in “Item 1A. 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.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS
	March 31,			December 31,
	2010			2009
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	66.2		$	60.4
Trade receivables, net of allowances of $2.0 million and $2.2 million		247.3			328.3
Inventory		25.2			39.3
Assets from risk management activities		32.6			25.8
Other current assets		0.6			1.2
Total current assets		371.9			455.0
Property, plant and equipment, at cost		2,109.0			2,096.8
Accumulated depreciation		(444.1	)		(418.3	)
Property, plant and equipment, net		1,664.9			1,678.5
Long-term assets from risk management activities		14.6			9.1
Investment in unconsolidated affiliate		18.0			18.5
Other long-term assets		18.7			19.8
Total assets	$	2,088.1		$	2,180.9

LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable to third parties	$	123.8		$	164.0
Accounts payable to affiliates		79.8			101.4
Accrued liabilities		108.5			114.2
Liabilities from risk management activities		15.1			16.3
Total current liabilities		327.2			395.9
Long-term debt payable to third parties		747.3			908.4
Long-term liabilities from risk management activities		16.9			28.9
Deferred income taxes		5.5			4.9
Other long-term liabilities		6.6			6.6

Commitments and contingencies (see Note 9)

Owners' equity:
Common unitholders (67,980,596 and 61,639,846 units issued and
outstanding as of March 31, 2010 and December 31, 2009)		965.0			850.5
General partner (1,387,360 and 1,257,957 units issued and
outstanding as of March 31, 2010 and December 31, 2009)		12.6			10.1
Accumulated other comprehensive loss		(6.2	)		(37.8	)
		971.4			822.8
Noncontrolling interest in subsidiary		13.2			13.4
Total owners' equity		984.6			836.2
Total liabilities and owners' equity	$	2,088.1		$	2,180.9

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended
	March 31,
	2010			2009
	(Unaudited)
	(In millions)
Revenues from third parties	$	1,259.3		$	864.4
Revenues from affiliates		87.9			51.6
Total operating revenues		1,347.2			916.0
Costs and expenses:
Product purchases from third parties		922.9			667.8
Product purchases from affiliates		299.8			139.7
Operating expenses from third parties		43.8			42.8
Operating expenses from affiliates		8.8			6.1
Depreciation and amortization expenses		25.8			24.8
General and administrative expenses		16.5			16.1
		1,317.6			897.3
Income from operations		29.6			18.7
Other income (expense):
Interest expense from affiliate		-			(14.8	)
Other interest expense, net		(15.3	)		(9.6	)
Equity in earnings of unconsolidated investment		0.3			0.1
Loss on mark-to-market derivative instruments		(0.4	)		-
Other		-			0.7
		(15.4	)		(23.6	)
Income (loss) before income taxes		14.2			(4.9	)
Income tax expense:
Current		(0.7	)		(0.1	)
Deferred		(0.6	)		(0.4	)
		(1.3	)		(0.5	)
Net income (loss)		12.9			(5.4	)
Less: Net income (loss) attributable to noncontrolling interest		0.3			(0.1	)
Net income (loss) attributable to Targa Resources Partners LP	$	12.6		$	(5.3	)

Net loss attributable to predecessor operations	$	-		$	(3.2	)
Net income attributable to general partner		3.1			1.9
Net income (loss) allocable to limited partners		9.5			(4.0	)
Net income (loss) attributable to Targa Resources Partners LP	$	12.6		$	(5.3	)

Net income (loss) per limited partner unit - basic and diluted	$	0.14		$	(0.09	)
Weighted average limited partner units outstanding - basic and diluted		68.0			46.2

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended
	March 31,
	2010			2009
	(Unaudited)
	(In millions)

Net income (loss)	$	12.9		$	(5.4	)
Other comprehensive income:
Commodity hedges:
Change in fair value		33.7			14.3
Reclassification adjustment for settled periods		3.0			(6.6	)
Interest rate hedges:
Change in fair value		(6.7	)		(3.7	)
Reclassification adjustment for settled periods		1.6			2.5
Foreign currency translation adjustment		-			(0.2	)
Other comprehensive income		31.6			6.3
Comprehensive income		44.5			0.9
Less: Comprehensive income (loss) attributable to noncontrolling interest		0.3			(0.1	)
Comprehensive income attributable to Targa Resources Partners LP	$	44.2		$	1.0

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY

							Accumulated
							Other
	Limited			General			Comprehensive			Noncontrolling
	Partners			Partner			Loss			Interest			Total
	(Unaudited)
	(In millions)
Balance, December 31, 2009	$	850.5		$	10.1		$	(37.8	)	$	13.4		$	836.2
Issuance of common units:
Equity offering		140.1			3.0			-			-			143.1
Distributions to noncontrolling interest		-			-			-			(0.5	)		(0.5	)
Amortization of equity awards		0.1			-			-			-			0.1
Other comprehensive income		-			-			31.6			-			31.6
Net income		9.5			3.1			-			0.3			12.9
Distributions to unitholders		(35.2	)		(3.6	)		-			-			(38.8	)
Balance, March 31, 2010	$	965.0		$	12.6		$	(6.2	)	$	13.2		$	984.6

See notes to consolidated financial statements

TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended
	March 31,
	2010			2009
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income (loss)	$	12.9		$	(5.4	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Amortization in interest expense		1.3			0.6
Amortization in general and administrative expense		0.1			0.1
Depreciation and amortization expense		25.8			24.8
Interest expense on affiliate indebtedness		-			14.8
Accretion of asset retirement obligations		0.1			0.1
Deferred income tax expense		0.6			0.4
Equity in earnings of unconsolidated investment, net of distributions		0.5			(0.1	)
Risk management activities		7.6			18.4
Changes in operating assets and liabilities:
Receivables and other assets		80.1			24.6
Inventory		14.1			36.6
Accounts payable and other liabilities		(66.0	)		(23.4	)
Net cash provided by operating activities		77.1			91.5
Cash flows from investing activities
Outlays for property, plant and equipment		(13.8	)		(20.7	)
Net cash used in investing activities		(13.8	)		(20.7	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		63.9			-
Repayments of credit facility		(225.2	)		-
Proceeds from equity offerings		140.1			-
Distributions to unitholders		(38.8	)		(26.4	)
General partner contributions		3.0			-
Parent distributions		-			(65.7	)
Distributions to noncontrolling interest		(0.5	)		-
Net cash used in financing activities		(57.5	)		(92.1	)
Net change in cash and cash equivalents		5.8			(21.3	)
Cash and cash equivalents, beginning of period		60.4			95.3
Cash and cash equivalents, end of period	$	66.2		$	74.0

See notes to consolidated financial statements

Targa Resources Partners LP

Notes to Consolidated Financial Statements

(Unaudited)

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

Note 1—Organization and Operations

Targa Resources Partners LP is a publicly traded Delaware limited partnership formed by Targa Resources, Inc. (“Targa” or “Parent”). In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. References to “TRP LP” are intended to mean Targa Resources Partners LP, individually, and not on a consolidated basis. Our common units are listed on the New York Stock Exchange under the symbol “NGLS.” Our business operations consist of natural gas gathering and processing and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”). We operate in two divisions: (i) Natural Gas Gathering and Processing (also a segment) and (ii) NGL Logistics and Marketing. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing. See Note 13.

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

On September 24, 2009, we acquired Targa’s interests in Targa Downstream LP, Targa LSNG LP, Targa Downstream GP LLC and Targa LSNG GP LLC (collectively, the “Downstream Business”) in a transaction among entities under common control. See Note 15.

Note 2—Basis of Presentation

These unaudited consolidated financial statements include our accounts and, prior to September 24, 2009, the assets, liabilities and operations of the Downstream Business.

Targa’s conveyance to us of the Downstream Business has been accounted for as a transfer of net assets between entities under common control. We recognize transfers of net assets between entities under common control at Targa’s historical basis in the net assets conveyed. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling of interests method.

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 months ended March 31, 2010 and 2009 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 8. Our financial results for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2010. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report.

We have been allocated certain general and administrative expenses incurred by our Parent in accordance with an Omnibus Agreement. See Note 8.

Note 3—Accounting Policies and Related Matters

Accounting Policy Updates/Revisions

The accounting policies followed by the Company are set forth in Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2009, and are supplemented by the notes to these consolidated financial statements. There have been no significant changes to these policies and it is suggested that these consolidated financial statements be read in conjunction with the consolidated financial statements and notes included in our Annual Report.

Accounting Pronouncements Recently Adopted

In December 2009, the Financial Accounting Standards Board (“FASB”) amended consolidation guidance for variable interest entities (“VIEs”) by issuing Accounting Standards Update (“ASU”) 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”. The new guidance eliminates the scope exception for qualifying special-purpose entities, amends certain guidance for determining whether an entity is a VIE, expands the list of events that trigger reconsideration of whether an entity is a VIE, requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE, requires continuous assessments of whether a company is the primary beneficiary of a VIE, and requires enhanced disclosures about a company’s involvement with a VIE. Prior to adoption, we did not have any interests in a VIE. We adopted the amended guidance on January 1, 2010 and our adoption of this new guidance did not result in any interests being identified as VIEs.

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

Note 4—Property, Plant and Equipment

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

	March 31,			December 31,
	2010			2009
Natural gas gathering systems	$	1,230.6		$	1,225.6
Processing and fractionation facilities		406.3			404.4
Terminalling and natural gas liquids storage facilities		238.8			238.5
Transportation assets		151.8			150.7
Other property, plant and equipment		16.9			16.8
Land		49.8			49.8
Construction in progress		14.8			11.0
		2,109.0			2,096.8
Accumulated depreciation		(444.1	)		(418.3	)
	$	1,664.9		$	1,678.5

Note 5—Debt Obligations

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

	March 31,		December 31,
	2010		2009
Senior secured revolving credit facility, variable rate, due February 2012	$	317.9	$	479.2
Senior unsecured notes, 8¼% fixed rate, due July 2016		209.1		209.1
Senior unsecured notes, 11¼% fixed rate, due July 2017 (1)		220.3		220.1
Total long-term debt	$	747.3	$	908.4
Letters of credit issued	$	76.9	$	69.2

_______

(1)	The carrying amount of the notes includes $11.0 million of unamortized original issue discount as of March 31, 2010.

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations during the three months ended March 31, 2010:

	Range of interest	Weighted average
	rates paid	interest rate paid
Senior secured revolving credit facility	1.2% to 3.5%		1.4%

Compliance with Debt Covenants

As of March 31, 2010, we are in compliance with the covenants contained in our various debt agreements.

Note 6—Partner Equity and Distributions

On January 19, 2010, we completed a public offering of 5,500,000 common units representing limited partner interests in the Partnership (“common units”) under our existing shelf registration statement on Form S-3 at a price of $23.14 per common unit ($22.17 per common unit, net of underwriting discounts), providing net proceeds of $121.9 million. Pursuant to the exercise of the underwriters’ overallotment option, we sold an additional 825,000 common units at $23.14 per common unit, providing net proceeds of $18.3 million. We used the net proceeds from the offering for general partnership purposes, which included reducing borrowings under our senior secured credit facility.

Distributions declared and paid during the three months ended March 31, 2010 and 2009 were as follows:

			Distributions Paid									Distributions
	For the Three		Limited Partners				General Partner					per limited
Date Paid		Months Ended	Common		Subordinated		Incentive		2%	Total		partner unit
			(In millions, except per unit amounts)
2010
February 12, 2010		December 31, 2009		35.2		-		2.8	0.8		38.8		0.5175

2009
February 13, 2009		December 31, 2008		18.0		6.0		1.9	0.5		26.4		0.5175

Subsequent Events. On April 14, 2010, we completed a secondary public offering of 8,500,000 common units owned by Targa LP Inc., a wholly-owned subsidiary of Targa. The Partnership will not receive any of the proceeds from this offering and the number of outstanding common units of the Partnership will remain unchanged. Targa LP, Inc. has granted the underwriters a 30-day option to purchase up to 1,275,000 additional common units.

On April 19, 2010, we announced a cash distribution of $0.5175 per unit on our outstanding common units. The distribution will be paid on May 14, 2010 to unitholders of record on May 7, 2010 for the three months ended March 31, 2010. The total distribution to be paid is $38.8 million.

Note 7—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, as well as changes in interest rates.

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

The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of March 31, 2010, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2010 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGLs 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 sometimes utilize purchased puts (or floors) to hedge 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 realized 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 or sometimes cover the specific expected products. 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, which closely approximate our actual NGL and natural gas delivery points. We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude, which approximate the prices received for condensate.

At March 31, 2010, the notional volumes of our commodity hedges were:

Commodity	Instrument	Unit	2010		2011		2012		2013
Natural Gas	Swaps	MMBtu/d		17,592		15,600		13,600		4,000
NGL	Swaps	Bbl/d		5,602		4,900		3,400		-
NGL	Floors	Bbl/d		-		199		231		-
Condensate	Swaps	Bbl/d		501		350		200		200

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under our senior secured revolving credit facility. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of March 31, 2010, we had borrowings of $317.9 million outstanding under our senior secured revolving credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in accumulated other comprehensive income (“OCI”) until the interest expense on the related debt is recognized in earnings.

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

As of March 31, 2010, affiliates of Goldman Sachs, Barclays Bank and Credit Suisse accounted for 68%, 15% and 10% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Barclays Bank and Credit Suisse are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

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

	Asset Derivatives					Liability Derivatives
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	March 31,		December 31,		Sheet	March 31,		December 31,
	Location	2010		2009		Location	2010		2009
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	31.3	$	24.5	Current liabilities	$	6.1	$	7.8
	Long-term assets		14.1		7.0	Long-term liabilities		10.4		24.2

Interest rate contracts	Current assets		0.3		0.2	Current liabilities		8.3		8.0
	Long-term assets		0.3		1.9	Long-term liabilities		6.5		4.7
Total derivatives designated
as hedging instruments			46.0		33.6			31.3		44.7

Derivatives not designated as hedging instruments
Commodity contracts	Current assets		1.0		1.1	Current liabilities		0.7		0.5
	Long-term assets		0.2		0.2	Long-term liabilities		-		-
Total derivatives not designated
as hedging instruments			1.2		1.3			0.7		0.5

Total derivatives		$	47.2	$	34.9		$	32.0	$	45.2

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those observed in underlying markets. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

Our earnings are also affected by the use of the mark-to-market method of accounting for certain derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of instruments that do not qualify are recorded on the balance sheets and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. Mark-to-market losses of $0.4 million were recorded in 2010. No mark-to-market gains (losses) were recorded during the three months ended March 31, 2009.

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

	Amount of Gain (Loss)						Amount of Gain (Loss)
	Reclassified from OCI into						Reclassified from OCI into
Location of Gain (Loss)	Income (Effective Portion)						Income (Ineffective Portion)
Reclassified from	Three Months Ended March 31,						Three Months Ended March 31,
OCI into Income	2010			2009			2010			2009
Interest expense, net	$	(1.6	)	$	(2.5	)	$	-		$	-
Revenues		(2.9	)		6.2			(0.1	)		0.4
	$	(4.5	)	$	3.7		$	(0.1	)	$	0.4

The following tables reflect the gain (loss) recognized in OCI and income:

	Amount of Gain (Loss)
	Recognized in OCI on
Derivatives in	Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended March 31,
Relationships	2010			2009
Interest rate contracts	$	(6.7	)	$	(3.7	)
Commodity contracts		33.7			14.3
	$	27.0		$	10.6

		Amount of Gain (Loss) Recognized
Derivatives	Location of Gain (Loss)	in Income on Derivatives
Not Designated as	Recognized in Income	Three Months Ended March 31,
Hedging Instruments	on Derivatives	2010			2009
Commodity contracts	Other income (expense)	$	(0.4	)	$	-

As of December 31, 2009, OCI included $28.7 million of unrealized net losses on commodity hedges and $9.3 million of unrealized net losses on interest rate hedges.

As of March 31, 2010, OCI included $7.9 million of unrealized net gains on commodity hedges and $14.3 million of unrealized net losses on interest rate hedges. Deferred net gains of $46.1 million on commodity hedges and deferred net losses of $7.5 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.

During the three months ended March 31, 2010 and 2009, deferred losses of $6.9 million and $18.7 million were reclassified from OCI as a non-cash reduction of revenue. These deferred losses are primarily related to the 2008 termination of certain out-of-the-money natural gas and NGL commodity swaps.

Interest Rate Swaps

As of March 31, 2010, we had $317.9 million outstanding under our credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates we have entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

Period	Fixed Rate		Notional Amount			Fair Value
Remainder of 2010		3.67%	$	300	million	$	(7.8	)
2011		3.52%		300	million		(5.2	)
2012		3.40%		300	million		(2.7	)
2013		3.39%		300	million		0.5
1/1 - 4/24/2014		3.39%		300	million		0.9
						$	(14.3	)

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

See Note 8 and Note 11 for additional disclosures related to derivative instruments and hedging activities.

Note 8—Related Party Transactions

Relationship with Targa

We are a party to various agreements with Targa, our general partner and others that address (i) the reimbursement of costs incurred on our behalf by our general partner, (ii) distribution support to us under certain circumstances, and (iii) our sales of 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
	March 31,
	2010			2009
Sales to affiliates	$	87.9		$	51.6
Purchases from affiliates
Included in product purchases		299.8			139.7
Included in operating expenses		8.8			6.1
Payroll and related costs included in operating expense		12.0			10.5
Parent allocation of general & administrative expense		12.8			13.2
Net change in affiliate receivable		(21.6	)		2.7
Cash distributions to Targa		14.0			8.4

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 months ended March 31, 2010 and 2009, we purchased $6.5 million and $1.4 million of product from Broad Oak.

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 revolving credit facility.

Commodity hedges. We have entered into various commodity derivative transactions with BofA. The following table shows our open commodity derivatives with BofA as of March 31, 2010:

Period

Commodity

Daily Volumes

Average Price

Index

Apr 2010 - Dec 2010

Natural Gas

3,289

MMBtu

7.39

per MMBtu

IF-WAHA

Apr 2010 - Jun 2010

Natural Gas

1,319

MMBtu

8.11

per MMBtu

NY_HH

Apr 2010 - Dec 2010

Condensate

181

Bbl

69.28

per Bbl

NY-WTI

As of March 31, 2010, the aggregate fair value of these open positions was $1.6 million. For the three months ended March 31, 2010 and 2009, we received $0.5 million and $8.5 million from BofA to settle payments due under hedge transactions.

We have entered into several interest rate derivative transactions with BofA. Open positions as of March 31, 2010 consisted of interest rate swaps and interest rate basis swaps expiring on April 24, 2014. As of March 31, 2010, the aggregate fair value of these positions was a liability of $2.5 million. Payments to BofA related to settled portions were $0.5 million and $1.0 million during the three months ended March 31, 2010 and 2009.

Commercial Relationships. During the three months ended March 31, 2009, product sales to BofA which are included in revenues were $0.4 million and natural gas and NGL product purchases were $0.3 million. There were no product sales to, or product purchases from, BofA during 2010.

Note 9—Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

Our environmental liability was not material as of March 31, 2010.

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, 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. On February 23, 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. On April 16, 2010, WTG filed a petition for review with the Texas Supreme Court. If the petition for review is granted, Targa intends to contest the appeal, but can give no assurances regarding the outcome of the proceeding. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

Note 10—Fair Value of Financial Instruments

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

The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows as of the dates indicated:

	March 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Senior unsecured notes, 8¼% fixed rate	$	209.1	$	214.3	$	209.1	$	206.5
Senior unsecured notes, 11¼% fixed rate (1)		220.3		263.7		220.1		253.5

_______

(1)	The carrying amount of the notes includes $11.0 million of unamortized original issue discount as of March 31, 2010.

Note 11—Fair Value Measurements

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3.

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis for the periods indicated. 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.

	March 31, 2010
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	46.6	$	-	$	45.8	$	0.8
Assets from interest rate derivatives		0.6		-		0.6		-
Total assets	$	47.2	$	-	$	46.4	$	0.8
Liabilities from commodity derivative contracts	$	17.2	$	-	$	13.1	$	4.1
Liabilities from interest rate derivatives		14.8		-		14.8		-
Total liabilities	$	32.0	$	-	$	27.9	$	4.1

	December 31, 2009
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	32.8	$	-	$	32.8	$	-
Assets from interest rate derivatives		2.1		-		2.1		-
Total assets	$	34.9	$	-	$	34.9	$	-
Liabilities from commodity derivative contracts	$	32.5	$	-	$	22.4	$	10.1
Liabilities from interest rate derivatives		12.7		-		12.7		-
Total liabilities	$	45.2	$	-	$	35.1	$	10.1

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

	Commodity Derivative Contracts
Balance, December 31, 2009	$	(10.1	)
Unrealized gains included in OCI		7.1
Settlements		(0.3	)
Balance, March 31, 2010	$	(3.3	)

Note 12—Noncontrolling Interest in Subsidiary

The following is a reconciliation of our noncontrolling interest for the three months ended March 31, 2010 and 2009:

	Noncontrolling
	Interest
Balance, December 31, 2008	$	14.1
Net loss		(0.1	)
Balance, March 31, 2009	$	14.0

Balance, December 31, 2009	$	13.4
Distributions to noncontrolling interest		(0.5	)
Net income		0.3
Balance, March 31, 2010	$	13.2

Note 13—Segment Information

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

The Natural Gas Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas. We are also a party to natural gas processing agreements with third party plants.

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

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

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

Eliminations and Other includes amounts related to general and administrative expenses not allocated to segment operations, corporate development, interest expense, income tax expense and the depreciation and cost of equipment used in our headquarters office. Eliminations and Other also includes the elimination of intersegment revenues and expenses.

Our reportable segment information is shown in the following tables:

	Three Months Ended March 31, 2010
	Natural Gas				NGL
	Gathering				Distribution
	and		Logistics		and		Wholesale		Eliminations
	Processing		Assets		Marketing		Marketing		and Other			Total
Revenues	$	137.0	$	23.8	$	721.9	$	376.6	$	-		$	1,259.3
Revenues from affiliates		87.6		0.1		-		0.1		0.1			87.9
Intersegment revenues		152.6		28.1		244.1		47.7		(472.5	)		-
Revenues		377.2		52.0		966.0		424.4		(472.4	)		1,347.2
Product purchases		223.3		-		528.1		171.5		-			922.9
Product purchases from affiliates		85.2		-		214.7		-		(0.1	)		299.8
Intersegment product purchases		14.5		-		213.4		246.1		(474.0	)		-
Product purchases		323.0		-		956.2		417.6		(474.1	)		1,222.7
Operating expenses		13.4		30.2		0.2		-		-			43.8
Operating expenses from affiliates		-		7.1		-		-		1.7			8.8
Operating expenses		13.4		37.3		0.2		-		1.7			52.6
Operating margin	$	40.8	$	14.7	$	9.6	$	6.8	$	-		$	71.9
Other financial information:
Equity in earnings of
unconsolidated investment	$	-	$	0.3	$	-	$	-	$	-		$	0.3
Unconsolidated investments		-		18.0		-		-		-			18.0
Capital expenditures		9.2		3.0		-		-		-			12.2
Revenues by type:
Commodity Sales	$	374.7	$	-	$	959.7	$	423.8	$	(443.6	)	$	1,314.6
Services		2.5		52.0		5.9		0.6		(28.8	)		32.2
Other		-		-		0.4		-		-			0.4
	$	377.2	$	52.0	$	966.0	$	424.4	$	(472.4	)	$	1,347.2

	Three Months Ended March 31, 2009
	Natural Gas				NGL
	Gathering				Distribution
	and		Logistics		and		Wholesale		Eliminations
	Processing		Assets		Marketing		Marketing		and Other			Total
Revenues	$	105.8	$	21.8	$	471.1	$	265.7	$	-		$	864.4
Revenues from affiliates		51.4		-		-		0.2		-			51.6
Intersegment revenues		81.8		22.6		120.4		22.8		(247.6	)		-
Revenues		239.0		44.4		591.5		288.7		(247.6	)		916.0
Product purchases		153.4		-		353.5		160.9		-			667.8
Product purchases from affiliates		35.4		-		104.2		-		0.1			139.7
Intersegment product purchases		5.7		-		118.9		123.5		(248.1	)		-
Product purchases		194.5		-		576.6		284.4		(248.0	)		807.5
Operating expenses		12.9		29.6		0.3		-		-			42.8
Operating expenses from affiliates		-		5.7		-		-		0.4			6.1
Operating expenses		12.9		35.3		0.3		-		0.4			48.9
Operating margin	$	31.6	$	9.1	$	14.6	$	4.3	$	-		$	59.6
Other financial information:
Equity in earnings of
unconsolidated investment	$	-	$	0.1	$	-	$	-	$	-		$	0.1
Unconsolidated investments		-		18.5		-		-		-			18.5
Capital expenditures		7.7		4.7		9.8		0.3		0.1			22.6
Revenues by type:
Commodity sales	$	236.3	$	-	$	586.7	$	287.9	$	(224.6	)	$	886.3
Services		2.7		44.4		4.8		0.3		(23.0	)		29.2
Other		-		-		-		0.5		-			0.5
	$	239.0	$	44.4	$	591.5	$	288.7	$	(247.6	)	$	916.0

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

	Three Months Ended
	March 31,
	2010			2009
Reconciliation of operating margin to net income (loss):
Operating margin	$	71.9		$	59.6
Depreciation and amortization expense		(25.8	)		(24.8	)
General and administrative expense		(16.5	)		(16.1	)
Interest expense, net		(15.3	)		(24.4	)
Income tax expense		(1.3	)		(0.5	)
Other, net		(0.1	)		0.8
Net income (loss)	$	12.9		$	(5.4	)

Note 14—Supplemental Cash Flow Information

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

	Three Months Ended
	March 31,
	2010		2009
Cash:
Interest paid	$	26.7	$	13.4
Non-cash:
Inventory line-fill transferred to property, plant and equipment		-		10.1

Note 15—Acquisition of Downstream Business

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

	Three Months Ended March 31, 2009
	Historical
	Targa									Targa
	Resources			Downstream						Resources
	Partners LP			Business			Adjustments			Partners LP
Revenues	$	239.0		$	764.4		$	(87.4	)	$	916.0
Costs and expenses:
Product purchases		194.5			700.4			(87.4	)		807.5
Operating expenses		12.8			36.1			-			48.9
Depreciation and amortization expense		18.9			5.9			-			24.8
General and administrative expense and other		5.4			10.7			-			16.1
		231.6			753.1			(87.4	)		897.3
Income from operations		7.4			11.3			-			18.7
Other income (expense):
Interest expense		(9.9	)		(14.5	)		-			(24.4	)
Other income		0.7			0.1			-			0.8
Income tax expense		(0.3	)		(0.2	)		-			(0.5	)
Net loss		(2.1	)		(3.3	)		-			(5.4	)
Less: Net income attributable to noncontrolling interest		-			(0.1	)		-			(0.1	)
Net loss attributable to Targa Resources Partners LP	$	(2.1	)	$	(3.2	)	$	-		$	(5.3	)

Note 16—Subsequent Event – Acquisition of Targa Permian and Straddle Assets

On March 31, 2010, we entered into a Purchase and Sale Agreement to acquire Targa’s interests in certain of its natural gas gathering and processing businesses located in West Texas and the Gulf Coast region of Louisiana. These assets include (i) all of the limited partner interests in Targa Midstream Services Limited Partnership, (ii) all of the limited liability company interests in Targa Gas Marketing LLC, (iii) all of the limited and general partner interests in Targa Permian LP, (iv) all of the limited partner interests in Targa Straddle LP and (v) all of the limited liability company interests in Targa Straddle GP LLC, (collectively referred to as “Permian/Straddle”), for aggregate consideration of $420 million, subject to certain adjustments. The Permian/Straddle acquisition and related transactions closed on April 27, 2010, effective April 1, 2010.

As part of the closing of the purchase of the Permian/Straddle assets, our Omnibus Agreement with Targa was amended to extend the commitment of Targa through April 2013 to provide general and administrative and other services to us associated with these assets and any additional assets, operations or businesses that may be sold to us

by Targa, and if Targa and we agree, additional assets, operations or businesses that we may acquire from third parties.

We will account for the Permian/Straddle acquisition as a transfer of net assets between entities under common control, effective April 1, 2010. The Permian/Straddle assets will be recorded based on the amounts recorded in Targa’s consolidated financial statements. GAAP also prescribes that all income statements be revised to include the results attributable to the Permian/Straddle assets as of the date of common control. Accordingly, beginning with its quarterly report for the second quarter of 2010, the Partnership will recast its current and historical financial statements to consolidate the Permian/Straddle assets for periods including and subsequent to October 31, 2005, the date Targa acquired the Permian/Straddle assets.

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

Our Operations

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

Our natural gas gathering and processing assets are located primarily in the Fort Worth Basin in North Texas, the Permian Basin in West Texas and the onshore region of the Louisiana Gulf Coast. Our NGL logistics and marketing assets are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the United States.

Recent Developments

On April 14, 2010, we completed a secondary public offering of 8,500,000 common units owned by Targa LP Inc., a wholly-owned subsidiary of Targa. The Partnership did not receive any of the proceeds from this offering and the number of outstanding common units of the Partnership remained unchanged. Targa LP Inc. granted the underwriters a 30-day option to purchase up to 1,275,000 additional common units.

On April 19, 2010, we announced a cash distribution of $0.5175 per unit on our outstanding common units. The distribution will be paid on May 14, 2010 to unitholders of record on May 7, 2010, for the three months ended March 31, 2010. The total distribution to be paid is $38.8 million.

Recently Issued Pronouncements

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

Results of Operations

The following table and discussion relate to the three months ended March 31, 2010 and 2009 and is a summary of our results of operations for the periods then ended:

	Three Months Ended March 31,
	2010			2009
	(In millions, except
	operating and price data)
Revenues (1)	$	1,347.2		$	916.0
Product purchases		1,222.7			807.5
Operating expenses		52.6			48.9
Depreciation and amortization expense		25.8			24.8
General and administrative expense		16.5			16.1
Income from operations		29.6			18.7
Interest expense, net		(15.3	)		(24.4	)
Other income (expense)		(0.1	)		0.8
Income tax expense		(1.3	)		(0.5	)
Net income (loss)		12.9			(5.4	)
Less: Net income (loss) attributable to noncontrolling interest		0.3			(0.1	)
Net income (loss) attributable to Targa Resources Partners LP	$	12.6		$	(5.3	)

Financial and operating data:
Financial data:
Operating margin (2)	$	71.9		$	59.6
Adjusted EBITDA (3)		62.4			62.6
Distributable cash flow (4)		44.0			36.0
Operating data:
Gathering throughput, MMcf/d (5)		504.4			429.4
Plant natural gas inlet, MMcf/d (6) (7)		478.8			408.1
Gross NGL production, MBbl/d		42.0			41.6
Natural gas sales, BBtu/d (7)		448.8			355.1
NGL sales, MBbl/d		246.7			291.6
Condensate sales, MBbl/d		2.5			2.7
Average realized prices (8):
Natural Gas, $/MMBtu		5.23			4.56
NGL, $/gal		1.16			0.66
Condensate, $/Bbl		75.10			41.14

_______

(1)	Includes business interruption insurance revenues of $0.5 million for 2009.

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

(3)	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.”

(4)	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.”

(5)	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.

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

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

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

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Revenues increased by $431.2 million, or 47%, to $1,347.2 million for 2010 compared to $916.0 million for 2009. Revenues from the sale of natural gas increased by $65.6 million, consisting of increases of $27.2 million due to higher realized prices and $38.4 million due to higher sales volumes. Revenues from the sale of NGL increased by $356.4 million, consisting of an increase of $468.7 million due to higher realized prices, offset by a decrease of $112.3 million due to lower sales volumes. Revenues from the sale of condensate increased by $6.3 million, which is the net of an increase of $7.1 million due to higher realized prices and a decrease of $0.8 million due to lower sales volumes. Non-commodity revenues, which principally include revenues derived from fee-based services and business interruption insurance, increased by $2.9 million.

Our average realized prices for natural gas increased by $0.67 per MMBtu, or 15%, to $5.23 per MMBtu for 2010 compared to $4.56 per MMBtu for 2009. Our average realized prices for NGL increased by $0.50 per gallon, or 76%, to $1.16 per gallon for 2010 compared to $0.66 per gallon for 2009. Our average realized price for condensate increased by $33.96 per barrel, or 83%, to $75.10 per barrel for 2010 compared to $41.14 per barrel for 2009.

Natural gas sales volumes increased by 93.7 BBtu/d, or 26%, to 448.8 BBtu/d for 2010 compared to 355.1 BBtu/d for 2009. NGL sales volumes decreased by 44.9 MBbl/d, or 15%, to 246.7 MBbl/d for 2010 compared to 291.6 MBbl/d for 2009. Condensate sales volumes decreased by 0.2 MBbl/d, or 7%, to 2.5 MBbl/d for 2010 compared to 2.7 MBbl/d for 2009. For information regarding the period to period changes in our commodity sales volumes, see “Results of Operations—By Segment.”

Product purchases increased by $415.2 million, or 51%, to $1,222.7 million for 2010 compared to $807.5 million for 2009. See “Results of Operations—By Segment” for a detailed explanation of the components of the increase.

Operating expenses increased by $3.7 million, or 8%, to $52.6 million for 2010 compared to $48.9 million for 2009. See “Results of Operations—By Segment” for a detailed explanation of the components of the increase.

Depreciation and amortization expense increased by $1.0 million, or 4%, to $25.8 million for 2010 compared to $24.8 million for 2009. The increase is primarily attributable to assets acquired in 2009 that now have a full period of depreciation associated with them.

General and administrative expense increased by $0.4 million, or 2%, to $16.5 million for 2010 compared to $16.1 million for 2009.

Interest expense decreased by $9.1 million, or 37%, to $15.3 million for 2010 compared to $24.4 million for 2009. The decrease is primarily due to lower overall debt. See “Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Results of Operations—By Segment

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

Natural Gas Gathering and Processing Segment

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

	Three Months Ended
	March 31,
	2010			2009
	($ in millions)
Revenues	$	377.2		$	239.0
Product purchases		(323.0	)		(194.5	)
Operating expenses		(13.4	)		(12.9	)
Operating margin (1)	$	40.8		$	31.6
Operating statistics (2):
Gathering throughput, MMcf/d		504.4			429.4
Plant natural gas inlet, MMcf/d		478.8			408.1
Gross NGL production, MBbl/d		42.0			41.6
Natural gas sales, BBtu/d		448.8			355.1
NGL sales, MBbl/d		39.4			37.2
Condensate sales, MBbl/d		2.5			3.4
Average realized prices:
Natural gas, $/MMBtu		5.23			4.56
NGL, $/gal		1.00			0.56
Condensate, $/Bbl		75.10			41.14

_______

(1)	See “Non-GAAP Financial Measures.”

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

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Revenues increased $138.2 million, or 58%, to $377.2 million for 2010 compared to $239.0 million for 2009. The increase was primarily due to an increase attributable to prices of $98.3 million, consisting of increases in natural gas, NGL and condensate revenues of $27.2 million, $63.6 million and $7.5 million; an increase attributable to volumes of $40.1 million, consisting of increases in natural gas and NGL revenues of $38.4 million and $4.7 million, partially offset by a decrease in condensate revenues of $3.0 million and a decrease in fee and other revenues of $0.2 million.

Average realized prices for our sales of natural gas increased by $0.67 per MMBtu, or 15%, to $5.23 per MMBtu during 2010 compared to $4.56 per MMBtu for 2009. Average realized prices for our sales of NGLs increased by $0.44 per gallon, or 79%, to $1.00 per gallon for 2010 compared to $0.56 per gallon for 2009. Average realized prices for our sales of condensate increased by $33.96 per Bbl, or 83%, to $75.10 per Bbl for 2010 compared to $41.14 per Bbl for 2009.

Natural gas sales volume increased by 93.7 BBtu/d or 26%, to 448.8 BBtu/d during 2010 compared to 355.1 BBtu/d for 2009. The increase in natural gas sales is primarily the result of an increase in demand from our industrial customers and an increase in sales of gas purchases from affiliates for resale. NGL sales increased by 2.2 MBbl/d, or 6%, to 39.4 MBbl/d for 2010 compared to 37.2 MBbl/d for 2009. Condensate sales volumes decreased by 0.9 MBbl/d, or 26%, to 2.5 MBbl/d for 2009 compared to 3.4 MBbl/d for 2009.

Product purchases during 2010 were $323.0 million, which increased by $128.5 million or 66%, compared to $194.5 million during 2009. The increase in product purchase cost reflects higher commodity pricing and lower purchases of wellhead volumes.

Operating expenses during 2010 were $13.4 million, which increased by $0.5 million or 4%, compared to $12.9 million during 2009. The increase in operating expenses was primarily the result of an increase in compensation and benefit costs and utilities expenses, partially offset by decreases in system maintenance and repairs and supplies expenses.

Logistics Assets Segment

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

	Three Months Ended
	March 31,
	2010			2009
	($ in millions)
Revenues	$	52.0		$	44.4
Operating expenses		(37.3	)		(35.3	)
Operating margin (1)	$	14.7		$	9.1
Equity in earnings of GCF	$	0.3		$	0.1
Operating statistics:
Fractionation volumes, MBbl/d		209.6			189.7
Treating volumes, MBbl/d (2)		7.6			8.4

_______

(1)	See “Non-GAAP Financial Measures.”

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

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Revenues from fractionation, terminalling and storage, transport and treating increased $7.6 million, or 17%, to $52.0 million for 2010 compared to $44.4 million for 2009. The increase was primarily a result of increased fractionation fees as a result of fee improvement, as well as increased prices for 2010 as compared 2009. Also, many Louisiana area plants were recovering from hurricanes in 2009, resulting in higher throughput in 2010.

Operating expenses increased $2.0 million, or 6%, to $37.3 million for 2010 compared to $35.3 million for 2009. The increase was primarily due to increased fuel costs due to higher natural gas prices and fuel usage.

NGL Distribution and Marketing Services Segment

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

	Three Months Ended
	March 31,
	2010			2009
	($ in millions)
NGL sales revenues	$	959.6		$	586.6
Other revenues		6.4			4.9
		966.0			591.5
Product purchases		(956.2	)		(576.6	)
Operating expenses		(0.2	)		(0.3	)
Operating margin (1)	$	9.6		$	14.6
Operating statistics:
NGL sales, MBbl/d		221.0			252.8
NGL realized price, $/gal		1.15			0.61

_______

(1)	See “Non-GAAP Financial Measures.”

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Revenues increased $374.5 million, or 63%, to $966.0 million for 2010 compared to $591.5 million for 2009. Higher market prices, which were up 89% to $1.15 per gallon in 2010 from $0.61 per gallon for 2009, increased revenue $426.1 million, partially offset by lower sales volumes which decreased revenues by $53.1 million. Other revenues, which consist primarily of non-commodity based service revenue, increased by $1.5 million.

NGL sales decreased 31.8 MBbl/d, or 13%, to 221.0 MBbl/d for 2010 compared to 252.8 MBbl/d for 2009. The decrease in sales volumes is primarily attributable to lower spot sales and reduced-term sales to petrochemical customers.

Product purchases increased $379.6 million, or 66%, to $956.2 million for 2010 compared to $576.6 million for 2009. The net increase comprised a $431.9 million increase from higher average market prices, partially offset by a $52.3 million decrease in purchased volumes.

Wholesale Marketing Segment

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

	Three Months Ended
	March 31,
	2010			2009
	($ in millions)
NGL sales revenues	$	423.8		$	287.9
Other revenues (1)		0.6			0.8
		424.4			288.7
Product purchases		(417.6	)		(284.4	)
Operating margin (2)	$	6.8		$	4.3
Operating statistics:
NGL sales, MBbl/d		79.6			80.6
NGL realized price, $/gal		1.41			0.94

_______

(1)	Includes business interruption insurance revenues of $0.5 million for 2009.

(2)	See “Non-GAAP Financial Measures.”

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Revenues increased $135.7 million, or 47%, to $424.4 million for 2010 compared to $288.7 million for 2009. Higher NGL market prices increased revenue by $139.5 million, offset by lower sales volume which decreased revenue by $3.6 million. The decrease in other revenues is due primarily to a decrease in business interruption insurance proceeds.

Our average realized price for NGL increased $0.47 per gallon, or 50%, to $1.41 per gallon for 2010 compared to $0.94 per gallon for 2009. The increase was primarily due to overall higher market prices. NGL sales volume decreased 1.0 MBbl/d, or 1%, to 79.6 MBbl/d for 2010 compared to 80.6 MBbl/d for 2009. The decrease in volumes is due primarily to the expiration of a refinery purchase agreement, partially offset by increased demand due to colder weather.

Product purchases increased $133.2 million, or 47%, to $417.6 million for 2010 compared to $284.4 million for 2009. Higher NGL market prices increased product purchases by $136.7 million while lower volumes decreased product purchases by $3.5 million. Purchases included a lower of cost or market adjustment of $0.2 million for 2010, compared to $2.0 million for 2009.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet indebtedness obligations, to refinance indebtedness or to meet collateral requirements depends on our ability to generate cash in the future. The ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and ongoing efforts to manage operating costs and maintenance capital expenditures as well as general economic, financial, competitive, legislative, regulatory and other factors. See “Item 1A. Risk Factors” in this Quarterly Report and our Annual Report.

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

markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

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

Crude oil and natural gas prices are also volatile. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2013 (see Note 7 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 fall further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

As of March 31, 2010, we had liquidity of $629.9 million, including $66.2 million of available cash and $563.7 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the lenders in our credit facility. To date, other than a default by Lehman Bank, we have experienced no disruptions in our ability to access funds committed under our credit facility. However, we cannot predict with any certainty the impact to us of any further disruptions in the credit environment.

Our cash generated from operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures, with remaining amounts being distributed in accordance with our distribution policy. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow and borrowings available under our senior secured credit facilities should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, long-term indebtedness obligations, collateral requirements and minimum quarterly cash distributions for at least the next twelve months.

A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of March 31, 2010, our total outstanding letter of credit postings were $76.9 million.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 5 and Note 6 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

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

As of March 31, 2010, we had a positive working capital balance of $44.7 million.

We intend to make minimum quarterly cash distributions to unitholders from available cash, as defined in the partnership agreement. As of March 31, 2010, such minimum amounts payable to non-Targa unitholders total approximately $64.7 million annually.

Contractual Obligations. As of March 31, 2010, except for changes in the ordinary course of our business, our contractual obligations have not changed materially from those reported in our Annual Report.

Cash Flow. Net cash provided by or used in operating activities, investing activities and financing activities for the three months ended March 31, 2010 and 2009 were as follows:

	Three Months Ended
	March 31,
	2010			2009
	(In millions)
Net cash provided by (used in):
Operating activities	$	77.1		$	91.5
Investing activities		(13.8	)		(20.7	)
Financing activities		(57.5	)		(92.1	)

Net cash provided by operating activities decreased by $14.4 million, or 16%, for 2010 compared to 2009, primarily attributable to a decrease in our payables for interest on affiliate indebtedness.

Net cash used in investing activities decreased $6.9 million, or 33%, for 2010 compared 2009, due primarily to lower capital additions during 2010 compared to 2009.

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

	Three Months Ended March 31,
	2010		2009
	(In millions)
Gross additions to property, plant and equipment	$	12.2	$	22.6
Non-cash additions to property, plant and equipment		-		(10.1	)
Change in accruals		1.6		8.2
Cash expenditures	$	13.8	$	20.7

Net cash used in financing activities decreased $34.6 million, or 38%, for 2010 compared to 2009, due primarily to repayments of our credit facility and increased distributions, partially offset by proceeds from borrowings under our credit facility and equity offerings, as well as the acquisition of the Downstream Business from Targa in 2009.

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 2010 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
	March 31,
	2010		2009
	(In millions)
Capital expenditures:
Expansion	$	8.5	$	19.9
Maintenance		3.7		2.7
	$	12.2	$	22.6

Our planned capital expenditures for 2010 are approximately $145 million with maintenance capital expenditures accounting for approximately 25%, including the Permian/Straddle transaction. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that over time we will invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

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

Non-GAAP Financial Measures

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

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

	Three Months Ended
	March 31,
	2010		2009
	(In millions)
Natural Gas Gathering and Processing	$	40.8	$	31.6
Logistics Assets		14.7		9.1
NGL Distribution and Marketing Services		9.6		14.6
Wholesale Marketing		6.8		4.3
	$	71.9	$	59.6

The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the three months ended March 31, 2010 and 2009:

	Three Months Ended
	March 31,
	2010		2009
Reconciliation of net income (loss) attributable to	(In millions)
Targa Resources Partners LP to operating margin:
Net income (loss) attributable to Targa Resources Partners LP	$	12.6	$	(5.3	)
Add:
Depreciation and amortization expense		25.8		24.8
General and administrative expense		16.5		16.1
Interest expense, net		15.3		24.4
Income tax expense		1.3		0.5
Other, net		0.4		(0.9	)
Operating margin	$	71.9	$	59.6

	Three Months Ended
	March 31,
	2010			2009
Reconciliation of net cash provided by operating	(In millions)
activities to Adjusted EBITDA:
Net cash provided by operating activities	$	77.1		$	91.5
Net (income) loss attributable to noncontrolling interest		(0.3	)		0.1
Interest expense, net (1)		14.0			9.0
Current income tax expense		0.7			0.1
Other		(0.9	)		(0.3	)
Changes in operating working capital which used (provided) cash:
Accounts receivable and other		(94.2	)		(61.2	)
Accounts payable and other liabilities		66.0			23.4
Adjusted EBITDA	$	62.4		$	62.6

_______

(1)	Net of amortization of debt issuance costs of $1.3 million and $0.6 million for the three months ended March 31, 2010 and 2009. Excludes interest expense from affiliate.

	Three Months Ended
	March 31,
	2010			2009
Reconciliation of net income (loss) attributable to	(In millions)
Targa Resources Partners LP to Adjusted EBITDA:
Net income (loss) attributable to Targa Resources Partners LP	$	12.6		$	(5.3	)
Add:
Interest expense, net		15.3			24.4
Income tax expense		1.3			0.5
Depreciation and amortization expense		25.8			24.8
Non-cash loss related to mark-to-market derivative instruments		7.6			18.4
Noncontrolling interest adjustment		(0.2	)		(0.2	)
Adjusted EBITDA	$	62.4		$	62.6

	Three Months Ended
	March 31,
	2010			2009
Reconciliation of net income (loss) attributable to	(In millions)
Targa Resources Partners LP to distributable cash flow:
Net income (loss) attributable to Targa Resources Partners LP	$	12.6		$	(5.3	)
Add:
Depreciation and amortization expense		25.8			24.8
Deferred income tax expense		0.6			0.4
Amortization of debt issue costs		1.3			0.6
Non-cash loss related to mark-to-market derivative instruments		7.6			18.4
Maintenance capital expenditures		(3.7	)		(2.7	)
Other		(0.2	)		(0.2	)
Distributable cash flow	$	44.0		$	36.0

Critical Accounting Policies and Estimates

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

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

changes in energy prices;

changes in competition;

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

changes in technology that render an asset obsolete;

changes in expected salvage values; or

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

As of March 31, 2010, the net book value of property, plant and equipment was $2.1 billion and we recorded $25.8 million in depreciation and amortization expense for the three months ended March 31, 2010. The weighted-average life of long-lived assets is approximately 20 years. If the useful lives of these assets were found to be shorter than originally estimated, depreciation and amortization expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result. For example, if the depreciable lives of assets were reduced by 10%, we estimate that depreciation and amortization expense would increase by $2.9 million, which would result in a corresponding reduction in operating income. In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, operating income would decrease by $16.6 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 March 31, 2010, the balance sheet reflects total accounts receivable of $247.3 million, which is due from third-parties. The allowance for doubtful accounts as of March 31, 2010 was $2.0 million.

Exposure to uncollectible accounts receivable relates to the financial health of our counterparties. We and our indirect parent, Targa, have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If an assessment of uncollectibility resulted in a 1% reduction of third-party accounts receivable, operating income would decrease by $2.5 million. There have been no material changes impacting accounts receivable.

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

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

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

The estimated fair value of our commodity derivative financial instruments was $29.4 million as of March 31, 2010, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities, by year, for each counterparty’s traded credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to $0.1 million as of March 31, 2010. If a financial instrument counterparty were to declare bankruptcy, we would be exposed to the loss of fair value of the financial instrument transaction with that counterparty. Ignoring our adjustment for credit risk, if a bankruptcy by a financial instrument counterparty impacted 10% of the fair value of commodity-based financial instruments, we estimate that operating income would decrease by $2.9 million per year.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report.

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

Commodity Price Risk. A majority of 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 a hedge are classified in the same category as the cash flows from the item being hedged. For an in-depth discussion of our hedging strategies, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” in our Annual Report.

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

We have entered into hedging arrangements for a portion of forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). As of March 31, 2010, we had the following hedge arrangements which will settle during the years ending December 31, 2010 through 2013 (except as indicated otherwise, the 2010 volumes reflect daily volumes for the period from April 1, 2010 through December 31, 2010):

Natural Gas

Instrument			Price		MMBtu per day
Type		Index	$/MMBtu		2010		2011		2012		2013		Fair Value
													(In millions)
Swap		IF-NGPL MC		8.78		5,824		-		-		-	$	7.5
Swap		IF-NGPL MC		6.87		-		4,350		-		-		2.7
Swap		IF-NGPL MC		6.82		-		-		4,250		-		1.9
						5,824		4,350		4,250		-

Swap		IF-Waha		6.40		11,767		-		-		-		7.2
Swap		IF-Waha		6.10		-		11,250		-		-		3.6
Swap		IF-Waha		6.28		-		-		9,350		-		2.1
Swap		IF-Waha		5.59		-		-		-		4,000		(0.4	)
						11,767		11,250		9,350		4,000

Total Sales						17,592		15,600		13,600		4,000

Basis Swap	Apr 2010 - May 2011, Rec IF-Columbia Gulf, Pay NYMEX less $0.12, 10,000 MMBtu/d													0.3
Basis Swap	Apr 2010 - May 2011, Rec IF-Columbia Gulf, Pay NYMEX less $0.115, 5,000 MMBtu/d													0.1
Basis Swap	Apr 2010 - May 2011, Rec IF-Columbia Gulf, Pay NYMEX less $0.113, 5,000 MMBtu/d													0.1
Basis Swap	Apr 2010 - May 2011, Rec IF-Columbia Gulf, Pay $6.06, 170 MMBtu/d													(0.1	)
Basis Swap	Apr 2010 - May 2011, Rec IF-Columbia Gulf, Pay $5.65, 56 MMBtu/d													-
													$	25.0

NGLs

Instrument		Price		Barrels per day
Type	Index	$/Gal		2010		2011		2012		2013		Fair Value
												(In millions)
Swap	OPIS-MB		1.15		5,602		-		-		-	$	12.5
Swap	OPIS-MB		0.84		-		4,900		-		-		(3.7	)
Swap	OPIS-MB		0.88		-		-		3,400		-		(2.0	)
Total Swaps					5,602		4,900		3,400		-

Floor	OPIS-MB		1.44		-		199		-		-		1.2
Floor	OPIS-MB		1.43		-		-		231		-		1.5
Total Floors					-		199		231		-

Total Sales					5,602		5,099		3,631		-
												$	9.5

Condensate

Instrument		Price		Barrels per day
Type	Index	$/Bbl		2010		2011		2012		2013		Fair Value
												(In millions)
Swap	NY-WTI		70.62		501		-		-		-	$	(2.0	)
Swap	NY-WTI		76.54		-		350		-		-		(1.2	)
Swap	NY-WTI		72.60		-		-		200		-		(1.0	)
Swap	NY-WTI		74.00		-		-		-		200		(0.9	)
					501		350		200		200

Total Sales					501		350		200		200
												$	(5.1	)

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

We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions. We determine the value of our NGL derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are either readily available in public markets or are quoted by counterparties to these contracts.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate debt under our senior secured revolving credit facility. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of March 31, 2010, we had variable rate borrowings of $317.9 million outstanding under our senior secured revolving credit facility. In an effort to reduce the variability of cash flows, we have entered into various interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by 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 March 31, 2010 we had the following open interest rate swaps:

Period	Fixed Rate		Notional Amount			Fair Value
						(In millions)
Remainder of 2010		3.67%	$	300	million	$	(7.8	)
2011		3.52%		300	million		(5.2	)
2012		3.40%		300	million		(2.7	)
2013		3.39%		300	million		0.5
1/1 - 4/24/2014		3.39%		300	million		0.9
						$	(14.3	)

We have designated all interest rate swaps and interest rate basis swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the swaps are deferred in OCI until interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account interest rate swaps and interest rate basis swaps, would increase annual interest expense by $0.2 million.

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

minimum credit ratings assigned by Standard & Poor’s Ratings Services.

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 information r required to be disclosed 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.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

The information required for this item is provided in Note 9—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, 2009. These risks and uncertainties are not the only ones facing us, and there may be additional matters of which we are unaware, 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:

Recent events in the Gulf of Mexico may result in facility shut-downs and in increased governmental regulation.

On April 20, 2010, the Transocean Deepwater Horizon drilling rig exploded and subsequently sank 130 miles south of New Orleans, Louisiana, and the resulting release of crude oil into the Gulf of Mexico has been declared a Spill of National Significance by the United States Department of Homeland Security. We cannot predict with any certainty the impact of this oil spill, the extent of cleanup activities associated with this spill, or possible changes in regulations that may be enacted in response to this spill, but this event and its aftermath could adversely affect our operations as follows:

Although our operations have not been impacted as of the date of this report, any changes in the path of the oil spill that result in oil reaching our [near shore] [coastal] facilities may require us to shut down the facilities until any impact on our operations can be safely corrected. This may reduce the volume of natural gas that our facilities process, and result in lower mixed NGL volumes for our fractionation business and lower NGL volumes for our NGL logistics and marketing business.

Third party offshore natural gas and NGL production might be reduced as a result of the oil spill and associated cleanup activities which could temporarily reduce the supply of natural gas to our processing facilities, and result in lower mixed NGL volumes for our fractionation business and lower NGL volumes for our NGL logistics and marketing business.

We rely on barge traffic along the Gulf Coast to transport some quantities of propane by barge in the Gulf of Mexico to supply our wholesale propane business. For example, some propane supply to our facilities in Florida is shipped via barge in the Gulf of Mexico. If the oil spill causes commercial sea lanes along the Gulf Coast to close or become subject to restrictions, this business may be interrupted.

Longer term in the aftermath of this oil spill, any additional governmental regulation of the offshore exploration and production industry may negatively impact volumes being gathered and processed by our facilities, and may potentially reduce volumes in our downstream logistics and marketing business.

The shutdown of our facilities or other curtailment of our operations could materially impact our business, financial condition and results of operations.

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

Not applicable.

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. (Removed and Reserved).

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit Index

Exhibit
Number	Description
2.1*	Purchase and Sale Agreement, dated as of March 31, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC and Targa Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 1, 2010 (File No. 001-33303)).
3.1	Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).
3.2	Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
3.3	Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).
3.4	First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).
3.5	Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).
3.6	Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).
4.1**	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.2**	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Gas Marketing LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.3**	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.4**	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Midstream Services Limited Partnership, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.5**	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.6**	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.7**	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.8**	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.9**	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.10**	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.11**	Supplemental Indenture dated April 27, 2010 to Indenture dated June 18, 2008, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.12**	Supplemental Indenture dated April 27, 2010 to Indenture dated July 6, 2009, among Targa Straddle GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
10.1	Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
10.2	First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)).
31.1**	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2**	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Targa Resources Partners LP

(Registrant)

By: Targa Resources GP LLC,

its general partner

By: /s/ John Robert Sparger

John Robert Sparger

Senior Vice President and Chief Accounting Officer

(Authorized signatory and Principal Accounting Officer)

Date: May 6, 2010