Targa Resources Partners LP - FORM 10-Q

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EX-4.4 - EXHIBIT 4.4 - Targa Resources Partners LP	ex4_4.htm
EX-4.6 - EXHIBIT 4.6 - Targa Resources Partners LP	ex4_6.htm
EX-4.7 - EXHIBIT 4.7 - Targa Resources Partners LP	ex4_7.htm
EX-4.5 - EXHIBIT 4.5 - Targa Resources Partners LP	ex4_5.htm
EX-32.2 - EXHIBIT 32.2 - Targa Resources Partners LP	ex32_2.htm
EX-31.1 - EXHIBIT 31.1 - Targa Resources Partners LP	ex31_1.htm
EX-31.2 - EXHIBIT 31.2 - Targa Resources Partners LP	ex31_2.htm
EX-32.1 - EXHIBIT 32.1 - Targa Resources Partners LP	ex32_1.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, 2011

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission File Number: 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

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

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

(713) 584-1000

(Registrant’s telephone number, including area code)

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

Large accelerated filer R

Accelerated filer £

Non-accelerated filer £

Smaller reporting company £

(Do not check if a smaller reporting company)

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

Act). Yes £ No R.

As of May 4, 2011, there were 84,756,009 Common Units and 1,729,715 General Partner Units outstanding.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.	4

Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010	4

Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010	5

Consolidated Statements of Comprehensive Income for the three months ended March 31, 2011 and 2010	6

Consolidated Statement of Changes in Owners' Equity for the three months ended March 31, 2011	7

Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010	8

Notes to Consolidated Financial Statements	9

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.	21

Item 3. Quantitative and Qualitative Disclosures About Market Risk.	36

Item 4. Controls and Procedures.	39

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.	40

Item 1A. Risk Factors.	40

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.	40

Item 3. Defaults Upon Senior Securities.	40

Item 4. (Removed and Reserved.)	40

Item 5. Other Information.	40

Item 6. Exhibits.	40

SIGNATURES

Signatures	42

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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Targa Resources Partners LP’s (together with its subsidiaries, “we”, “us”, “our” or the “Partnership”) 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.” 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. Known risks and uncertainties include, but are not limited to, the risks set forth in “Part II-Other Information, Item 1A. Risk Factors” of this Quarterly Report on form 10-Q (“Quarterly Report”), as well as the following risks and uncertainties:

·	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 (“NGL”) 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 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 elsewhere in “Part II–Other Information, Item 1A. Risk Factors” of this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2010 (“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 “Part II–Other Information, Item 1A. Risk Factors” in this Quarterly Report and in our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

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As generally used in the energy industry and in this Quarterly Report the identified terms have the following meanings:

Bbl	Barrels (equal to 42 gallons)
Btu	British thermal units, a measure of heating value
BBtu	Billion British thermal units
/d	Per day
gal	Gallons
LPG	Liquefied petroleum gas
MBbl	Thousand barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
NYMEX	New York Mercantile Exchange

Price Index
Definitions
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB	Inside FERC Gas Market Report, Permian Basin
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

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

TARGA RESOURCES PARTNERS LP
CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2011			2010
	(Unaudited)
	(In millions)
ASSETS
Current assets:
Cash and cash equivalents	$	63.6		$	76.3
Trade receivables, net of allowances of $7.4 million and $7.7 million		444.1			466.1
Inventory		5.1			50.3
Assets from risk management activities		19.6			25.2
Other current assets		1.0			2.9
Total current assets		533.4			620.8
Property, plant and equipment, at cost		3,377.1			3,299.5
Accumulated depreciation		(847.0	)		(804.3	)
Property, plant and equipment, net		2,530.1			2,495.2
Long-term assets from risk management activities		14.9			18.9
Investment in unconsolidated affiliate		21.3			15.2
Other long-term assets		41.0			36.3
Total assets	$	3,140.7		$	3,186.4

LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable to third parties	$	190.4		$	250.5
Accounts payable to Targa Resources Corp.		43.7			51.4
Accrued liabilities		273.2			273.7
Liabilities from risk management activities		56.1			34.2
Total current liabilities		563.4			609.8
Long-term debt		1,179.1			1,445.4
Long-term liabilities from risk management activities		55.5			32.8
Deferred income taxes		9.1			8.7
Other long-term liabilities		42.1			40.6

Commitments and contingencies (see Note 11)

Owners' equity:
Common unitholders (84,756,009 and 75,545,409 units issued and
outstanding as of March 31, 2011 and December 31, 2010)		1,219.6			935.3
General partner (1,729,715 and 1,541,744 units issued and
outstanding as of March 31, 2011 and December 31, 2010)		22.2			15.1
Accumulated other comprehensive income (loss)		(84.6	)		(30.6	)
		1,157.2			919.8
Noncontrolling interests in subsidiaries		134.3			129.3
Total owners' equity		1,291.5			1,049.1
Total liabilities and owners' equity	$	3,140.7		$	3,186.4

See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended March 31,
	2011			2010
	(Unaudited)
	(In millions, except per unit amounts)
Revenues	$	1,614.5		$	1,483.8
Costs and expenses:
Product purchases		1,400.6			1,297.9
Operating expenses		65.9			62.2
Depreciation and amortization expenses		42.7			42.0
General and administrative expenses		31.8			25.0
Income from operations		73.5			56.7
Other income (expense):
Interest expense from affiliate		-			(13.5	)
Interest expense allocated from Parent		-			(2.1	)
Other interest expense, net		(27.5	)		(15.4	)
Equity in earnings of unconsolidated investment		1.7			0.3
Gain on mark-to-market derivative instruments		-			25.4
Other		(0.2	)		-
Income before income taxes		47.5			51.4
Income tax expense:
Current		(1.4	)		(0.8	)
Deferred		(0.4	)		(0.7	)
		(1.8	)		(1.5	)
Net income		45.7			49.9
Less: Net income attributable to noncontrolling interests		7.9			7.3
Net income attributable to Targa Resources Partners LP	$	37.8		$	42.6

Net income attributable to predecessor operations	$	-		$	30.1
Net income attributable to general partner		7.6			3.1
Net income attributable to limited partners		30.2			9.4
Net income attributable to Targa Resources Partners LP	$	37.8		$	42.6

Net income per limited partner unit - basic and diluted	$	0.37		$	0.14
Weighted average limited partner units outstanding - basic and diluted		82.3			68.0


See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended March 31,
	2011			2010
	(Unaudited)
	(In millions)
Net income	$	45.7		$	49.9
Other comprehensive income:
Commodity hedging contracts:
Change in fair value		(61.3	)		33.6
Settlements reclassified to revenues		4.6			3.0
Interest rate hedges:
Change in fair value		0.2			(6.7	)
Settlements reclassified to interest expense, net		2.5			1.6
Other comprehensive income (loss)		(54.0	)		31.5
Comprehensive income (loss)		(8.3	)		81.4
Less: Comprehensive income attributable to
noncontrolling interests		7.9			7.3
Comprehensive income (loss) attributable to
Targa Resources Partners LP	$	(16.2	)	$	74.1

See notes to consolidated financial statements

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

								Accumulated
		Limited						Other
		Partners			General			Comprehensive			Noncontrolling
		Common			Partner			Income (Loss)			Interests			Total
	(Unaudited)
	(In millions)
Balance, December 31, 2010		$	935.3		$	15.1		$	(30.6	)	$	129.3		$	1,049.1
Proceeds from equity offerings			298.1			6.3									304.4
Contributions from Targa Resources Corp.			2.2			0.3									2.5
Distributions to noncontrolling interests												(3.5	)		(3.5	)
Contributions from noncontrolling interests												0.6			0.6
Amortization of equity awards			0.2												0.2
Other comprehensive loss									(54.0	)					(54.0	)
Net income			30.2			7.6						7.9			45.7
Distributions to unitholders			(46.4	)		(7.1	)								(53.5	)
Balance, March 31, 2011		$	1,219.6		$	22.2		$	(84.6	)	$	134.3		$	1,291.5

See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
	2011			2010
	(Unaudited)
	(In millions)
Cash flows from operating activities
Net income	$	45.7		$	49.9
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense		1.8			1.2
Compensation on equity grants		0.2			0.1
Interest expense on affiliate and allocated indebtedness		-			15.6
Depreciation and other amortization expense		42.7			42.0
Accretion of asset retirement obligations		0.9			0.8
Deferred income tax expense		0.4			0.7
Equity in earnings of unconsolidated investment, net of distributions		(1.7	)		0.4
Risk management activities		0.2			(18.6	)
Changes in operating assets and liabilities:
Receivables and other assets		24.0			73.3
Inventory		47.3			14.2
Accounts payable and other liabilities		(62.9	)		(59.2	)
Net cash provided by operating activities		98.6			120.4
Cash flows from investing activities
Outlays for property, plant and equipment		(55.5	)		(18.9	)
Business Acquisition		(29.0	)		-
Investment in unconsolidated affiliate		(4.4	)		-
Net cash used in investing activities		(88.9	)		(18.9	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		268.0			63.9
Repayments of credit facility		(832.0	)		(225.2	)
Proceeds from issuance of senior notes		325.0			-
Cash paid on note exchange		(27.7	)		-
Proceeds from equity offerings		304.4			143.1
Distributions to unitholders		(53.5	)		(38.8	)
Costs incurred in connection with financing arrangements		(6.2	)		-
Contributions from parent		2.5			-
Distributions under common control		-			(17.8	)
Contributions from noncontrolling interests		0.6			-
Distributions to noncontrolling interests		(3.5	)		(1.9	)
Net cash used in financing activities		(22.4	)		(76.7	)
Net change in cash and cash equivalents		(12.7	)		24.8
Cash and cash equivalents, beginning of period		76.3			90.9
Cash and cash equivalents, end of period	$	63.6		$	115.7

See notes to consolidated financial statements

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TARGA RESOURCES PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. 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 in October, 2006 by Targa Resources Corp. (“Targa” or “Parent”). Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange under the symbol “NGLS.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis.

Targa Resources GP LLC is a Delaware limited liability company, formed by Targa in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa. As of March 31, 2011, Targa and its subsidiaries own a 15.5% interest in us in the form of 1,729,715 general partner units, incentive distribution rights (IDR’s) and 11,645,659 common units.

We acquired Targa’s ownership interests in the following assets, liabilities and operations on the dates indicated:

·	February 2007 – North Texas System;

·	October 2007 – San Angelo (“SAOU”) and Louisiana (“LOU”);

·	September 2009 – Downstream Business;

·	April 2010 – Permian Business and Straddle Assets (See Note 4);

·	August 2010 – Versado (See Note 4); and

·	September 2010 – Venice Operations (See Note 4).

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

Allocation of costs. The employees supporting our operations are employees of Targa. Our financial statements include the direct costs of employees deployed to our operating units, as well an allocation of costs associated with our usage of Targa centralized general and administrative services and related administrative assets.

Our Operations

We are engaged in the business of gathering, compressing, treating, processing and selling natural gas, storing, fractionating, treating, transporting and selling NGLs and NGL products and storing and terminaling refined petroleum products and crude oil. See Note 13 for an analysis of our operations by segment.

Note 2 — Basis of Presentation

We have prepared these unaudited consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. While we derived the year-end balance sheet data from audited financial statements, this interim report does not include all disclosures required by GAAP for annual periods. The unaudited consolidated financial statements for the three months ended March 31, 2011 and 2010 include all adjustments which we believe are necessary for a fair presentation of the results for interim periods.

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Our financial results for the three months ended March 31, 2011 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2011. 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 for the year ended December 31, 2010.

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

Note 3 — Significant Accounting Policies

Accounting Policy Updates/Revisions

The accounting policies followed by the Partnership 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, 2010. There have been no significant changes to these policies during the three months ended March 31, 2011.

Note 4 — Acquisitions under Common Control

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

On August 25, 2010, we acquired Targa’s 63% equity interest in Versado Gas Processors L.L.C. (“Versado”), effective August 1, 2010, for $247.2 million in the form of $244.7 million in cash and $2.5 million in partnership interests represented by 89,813 common units and 1,833 general partner units. This consideration was used to repay $247.2 million of affiliated indebtedness. Targa contributed the remaining $205.8 million of affiliate indebtedness as a capital contribution. Under the terms of the Versado acquisition purchase and sale agreement, Targa will reimburse us for future maintenance capital expenditures required pursuant to the New Mexico Environmental Department (“NMED”) settlement agreement, of which our share is currently estimated to be $21.0 million, including $6.7 million that has been incurred as of March 31, 2011.

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

These acquisitions have been accounted for as acquisitions under common control, resulting in the retrospective adjustment of our prior results.

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Note 5 — Property, Plant and Equipment

	March 31,		December 31,		Estimated useful lives
	2011		2010		(In years)
Natural gas gathering systems	$	1,651.6	$	1,630.9	5 to 20
Processing and fractionation facilities		967.8		961.9	5 to 25
Terminaling and storage facilities (1)		276.4		244.7	5 to 25
Transportation assets		276.4		275.6	10 to 25
Other property, plant and equipment		48.4		46.8	3 to 25
Land		51.9		51.2
Construction in progress		104.6		88.4
	$	3,377.1	$	3,299.5

___________

(1)	Includes the March 15, 2011 acquisition of a refined petroleum products and crude oil storage facility, for which we paid $29.0 million.

Note 6 — Debt Obligations

	March 31,			December 31,
	2011			2010
Senior secured revolving credit facility, variable rate, due July 2015	$	201.3		$	765.3
Senior unsecured notes, 8¼% fixed rate, due July 2016		209.1			209.1
Senior unsecured notes, 11¼% fixed rate, due July 2017		72.7			231.3
Unamortized discounts		(3.1	)		(10.3	)
Senior unsecured notes, 7⅞% fixed rate, due October 2018		250.0			250.0
Senior unsecured notes, 6⅞% fixed rate, due February 2021		483.6			-
Unamortized discounts		(34.5	)		-
	$	1,179.1		$	1,445.4

Letters of credit issued	$	113.6		$	101.3

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, 2011:

	Range of Interest Rates Paid		Weighted Average Interest Rate Paid
Senior secured revolving credit facility	2.7% to 3.1%		3.0%

Compliance with Debt Covenants

As of March 31, 2011, we are in compliance with the covenants contained in our various debt agreements.

Senior Secured Credit Facility

As of March 31, 2011, availability under our senior secured credit facility was $785.1 million, after giving effect to $113.6 million in outstanding letters of credit.

6⅞% Senior Notes of the Partnership

On February 2, 2011, we closed a private placement of $325 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (the “6⅞% Notes”). The net proceeds of this offering were $319.0 million after deducting expenses of the offering. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility and for general partnership purposes.

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On February 4, 2011, we exchanged an additional $158.6 million principal amount of 6⅞% Notes plus payments of $28.6 million including $0.9 million of accrued interest for $158.6 million aggregate principal amount of our 11¼% Senior Notes due 2017 (the “11¼% Notes”). The holders of the exchanged notes are subject to the provisions of the 6⅞% Notes described below. The debt covenants related to the remaining $72.7 million of face value of our 11¼% Notes were removed as we received sufficient consents in connection with the exchange offer to amend the indenture. This exchange was accounted for as a debt modification whereby the financial effects of the exchange will be recognized over the term of the new debt issue.

The 6⅞% Notes are unsecured senior obligations that rank pari passu in right of payment with existing and future senior indebtedness, including indebtedness under our credit facility. They are senior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by certain of our subsidiaries. These notes are effectively subordinated to all secured indebtedness under our credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.

Interest on the 6⅞% Notes accrues at the rate of 6⅞% per annum and is payable semi-annually in arrears on February 1 and August 1, commencing on August 1, 2011.

We may redeem 35% of the aggregate principal amount of the 6⅞% Notes at any time prior to February 1, 2014, with the net cash proceeds of one or more equity offerings. We must pay a redemption price of 106.875% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:

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

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

We may also redeem all or part of the 6⅞% Notes on or after August 1, 2016 at the redemption prices set forth below plus accrued and unpaid interest and liquidated damages, if any, on the notes redeemed, if redeemed during the twelve-month period beginning on August 1 of each year indicated below:

Year		Percentage
2016		103.44%
2017		102.29%
2018		101.15%
2019 and thereafter		100.00%

Note 7 — Partnership Equity and Distributions

On January 24, 2011, we completed a public offering of 8,000,000 common units under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011, we issued an additional 1,200,000 common units, providing net proceeds of $38.8 million. In addition, Targa contributed $6.3 million to us for 187,755 general partner units to maintain its 2% general partner interest in us.

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Distributions for the three months ended March 31, 2011 and 2010 were as follows:

		Distributions
	For the Three	Limited Partners		General Partner						Distributions per limited
Date Paid	Months Ended	Common		Incentive			2%	Total		partner unit
		(In millions, except per unit amounts)
May 13, 2011 (1)	March 31, 2011	$	47.3	$	6.8	$	1.1	$	55.2	$	0.5575
February 14, 2011	December 31, 2010		46.4		6.0		1.1		53.5		0.5475
May 14, 2010	March 31, 2010		35.2		2.8		0.8		38.8		0.5175
February 12, 2010	December 31, 2009		35.2		2.8		0.8		38.8		0.5175

__________

(1) To be paid on May 13, 2011

Subsequent Event. On April 11, 2011, we announced a cash distribution of $0.5575 per unit on our outstanding common units for the three months ended March 31, 2011. The distribution to be paid is $40.8 million to our third-party limited partners, and $6.5 million, $6.8 million and $1.1 million to Targa for its ownership of common units, incentive distribution rights and its 2% general partner interest in us.

Note 8 — Derivative Instruments and Hedging Activities

Commodity Hedges

The primary purpose of our commodity risk management activities is to hedge the 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, we have hedged the commodity price associated with a portion of our expected natural gas and NGL equity volumes through 2013 and condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (floors).

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

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

Hedge ineffectiveness has been immaterial for all periods.

At March 31, 2011, the notional volumes of our commodity hedges were:

Commodity	Instrument	Unit	2011	2012	2013	2014
Natural Gas	Swaps	MMBtu/d	38,470	31,790	17,089	-
NGL	Swaps	Bbl/d	10,118	8,611	4,150	-
NGL	Floors	Bbl/d	253	294	-	-
Condensate	Swaps	Bbl/d	1,630	1,460	1,595	700

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Interest Rate Swaps

As of March 31, 2011, we had $201.3 million outstanding under our credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, we have entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300.0 million as shown below:

Period	Fixed Rate		Notional Amount		Fair Value
Remainder of 2011		3.52%	$	300	$	(7.3	)
2012		3.40%		300		(5.9	)
2013		3.39%		300		(3.6	)
1/1/2014 - 4/24/2014		3.39%		300		(0.6	)
					$	(17.4	)

Derivative Instruments Not Designated as Hedging Instruments

All interest rate swaps and interest rate basis swaps had been designated as cash flow hedges of variable rate interest payments on borrowings under our credit facility until February 11, 2011, when we de-designated $125.0 million notional principal of fixed interest rate swaps and $25.0 million notional principal of interest rate basis swaps. There is an immaterial impact to earnings in the first quarter of 2011 as a result of the de-designation. The de-designated swaps will receive mark-to-market treatment, with changes in fair value recorded immediately to interest expense. We de-designated the swaps as our borrowings under our credit facility reduced below $300.0 million, which is the total notional amount of our fixed interest rate swaps.

We frequently enter into derivative instruments to manage location basis differentials. We do not account for these derivatives as hedges and we record changes in fair value in Other Income (Expense).

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

	Derivative Assets					Derivative Liabilities
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	March 31,		December 31,		Sheet	March 31,		December 31,
	Location	2011		2010		Location	2011		2010
Derivatives designated as hedging instruments
Commodity contracts	Current assets	$	19.1	$	24.8	Current liabilities	$	48.0	$	25.5
	Long-term assets		14.9		18.9	Long-term liabilities		45.9		20.5
Interest rate contracts	Current assets		-		-	Current liabilities		4.3		7.8
	Long-term assets		-		-	Long-term liabilities		5.1		12.3
Total derivatives designated as hedging instruments		$	34.0	$	43.7		$	103.3	$	66.1

Derivatives not designated as hedging instruments
Commodity contracts	Current assets	$	0.5	$	0.4	Current liabilities	$	0.3	$	0.9
	Long-term assets		-		-	Long-term liabilities		-		-
Interest rate contracts	Current assets		-		-	Current liabilities		3.5		-
	Long-term assets		-		-	Long-term liabilities		4.5		-
Total derivatives not designated as hedging instruments		$	0.5	$	0.4		$	8.3	$	0.9
Total derivatives		$	34.5	$	44.1		$	111.6	$	67.0

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

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The following tables reflect amounts recorded in other comprehensive income (“OCI”) and amounts reclassified from OCI to revenue and expense:

	Gain (Loss)
	Recognized in OCI on
Derivatives in	Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended March 31,
Relationships	2011			2010
Interest rate contracts	$	0.2		$	(6.7	)
Commodity contracts		(61.3	)		33.6
	$	(61.1	)	$	26.9

	Loss Reclassified from OCI into
	Income (Effective Portion)
	Three Months Ended March 31,
Location of Loss		2011			2010
Interest expense, net	$	(2.5	)	$	(1.6	)
Revenues		(4.6	)		(3.0	)
	$	(7.1	)	$	(4.6	)

Our earnings are also affected by the use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction settles. 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. During the three months ended March 31, 2011 and 2010, we recorded the following mark-to-market gains:


		Gain Recognized in Income on Derivatives
Derivatives Not Designated as Hedging Instruments	Location of Gain Recognized in Income on Derivatives	Three Months Ended March 31,
Derivatives Not Designated as Hedging Instruments	Location of Gain Recognized in Income on Derivatives	2011		2010
Commodity contracts	Other income	$	-	$	25.4

The following table shows the unrealized losses included in accumulated other comprehensive income (loss) (“OCI”):

	March 31,			December 31,
	2011			2010
Unrealized net losses on commodity hedges	$	(67.3	)	$	(10.5	)
Unrealized net losses on interest rate hedges	$	(17.4	)	$	(20.1	)

As of March 31, 2011, deferred net losses of $31.0 million on commodity hedges and $7.8 million on interest rate swaps recorded in OCI are expected to be reclassified to revenue and interest expense during the next twelve months.

In July 2008, we and Targa paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. We and Targa also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps. Prior to the terminations, these swaps were designated as hedges. During the three months ended March 31, 2011 and 2010, deferred gains (losses) of $0.2 million and $(6.9) million related to the terminated swaps were reclassified from OCI as a non-cash addition (reduction) to revenue.

See Note 3 and Note 9 for additional disclosures related to derivative instruments and hedging activities.

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Note 9 — Fair Value Measurements

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

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

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

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

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain counterparties. We determine the value of our derivative contracts using 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.

Contracts classified as Level 3 are valued using price inputs available from public markets to the extent that the markets are liquid for the relevant settlement periods.

The following tables present the fair value of our financial assets and liabilities according to the fair value hierarchy. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels:

	March 31, 2011
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	34.5	$	-	$	34.5	$	-
Total assets	$	34.5	$	-	$	34.5	$	-
Liabilities from commodity derivative contracts	$	94.2	$	-	$	63.8	$	30.4
Liabilities from interest rate derivatives		17.4		-		17.4		-
Total liabilities	$	111.6	$	-	$	81.2	$	30.4

	December 31, 2010
	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	44.1	$	-	$	43.9	$	0.2
Total assets	$	44.1	$	-	$	43.9	$	0.2
Liabilities from commodity derivative contracts	$	46.9	$	-	$	35.1	$	11.8
Liabilities from interest rate derivatives		20.1		-		20.1		-
Total liabilities	$	67.0	$	-	$	55.2	$	11.8

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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, 2010	$	(11.6	)
Unrealized losses included in OCI		(20.0	)
Settlements included in Net Income		1.2
Balance, March 31, 2011	$	(30.4	)

There have been no transfers of derivative assets or liabilities between the three levels of the fair value hierarchy during the three months ended March 31, 2011.

We designated all Level 3 derivative instruments as cash flow hedges, and, as such, all changes in their fair value are reflected in other comprehensive income. Therefore, there are no unrealized gains or losses reflected in revenues or other income (expense) with respect to Level 3 derivative instruments.

Note 10 — Fair Value of Financial Instruments

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

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

The carrying value of our 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 as of the dates indicated in the following table:

	March 31,						December 31,
	2011						2010
	Carrying			Fair			Carrying			Fair
	Amount			Value			Amount			Value
Senior unsecured notes, 8¼% fixed rate		$	209.1		$	222.8		$	209.1		$	219.4
Senior unsecured notes, 11¼% fixed rate			69.6			85.0			231.3			265.0
Senior unsecured notes, 7⅞% fixed rate			250.0			262.0			250.0			259.7
Senior unsecured notes, 6⅞% fixed rate			449.1			481.5		NA			NA

Note 11 — Commitments and Contingencies

Environmental

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

Our environmental liability at March 31, 2011 and December 31, 2010 was $1.6 million. Our March 31, 2011 liability consisted of $0.1 million for gathering system leaks and $1.5 million for ground water assessment and remediation.

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In May 2007, the NMED alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants, which are operated by us and owned by Versado, were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005.

In January 2010, Versado settled the alleged violations with NMED for a penalty of approximately $1.5 million. As part of the settlement, Versado agreed to install two acid gas injection wells, additional emission control equipment and monitoring equipment. We estimate the total cost to complete these projects to be approximately $33.4 million, of which our portion of the cost is projected to be $21.0 million. As of March 31, 2011, $10.7 million has been paid by Versado ($6.7 million by us).

Under the terms of the Versado acquisition purchase and sale agreement between Targa and us, Targa is obligated to reimburse us for maintenance capital expenditures required pursuant to the NMED settlement agreement.

Legal Proceedings

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

On December 8, 2005, WTG Gas Processing, L.P. (“WTG”) filed suit in the 333rd District Court of Harris County, Texas (the “District Court”) against several defendants, including Targa and two other Targa entities and private equity funds affiliated with Warburg Pincus LLC (“Warburg Pincus”), seeking damages. 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 SAOU from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. In October 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. In February 2010, the 14th Court of Appeals affirmed the District Court’s final judgment in favor of defendants in its entirety. In January 2011, the Texas Supreme Court denied WTG’s petition for review of the lower court’s judgment and in March 2011, the Texas Supreme Court denied WTG’s motion for rehearing of the Court’s denial to review WTG’s appeal. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

Note 12 — Supplemental Cash Flow Information

Supplemental cash flow information was as follows for the periods indicated:

	Three Months Ended March 31,
	2011				2010
Interest paid		$	29.1			$	26.8
Taxes paid			0.3				0.1
Non-cash adjustment to line-fill			(2.1	)			-

Note 13 — Segment Information

We report our operations in two divisions: (i) Natural Gas Gathering and Processing, consisting of two reportable segments – (a) Field Gathering and Processing and (b) Coastal Gathering and Processing; and (ii) Logistics and Marketing consisting of two reportable segments – (a) Logistics Assets and (b) Marketing and Distribution. The financial results of our hedging activities are reported in Other.

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

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Our Logistics and Marketing division is also referred to as our Downstream Business. Downstream includes all the activities necessary to convert raw natural gas liquids into NGL products and provides certain value added services such as storage, terminaling, transportation, distribution and marketing of NGLs, crude and refined products. It also includes certain natural gas supply and marketing activities in support of our other businesses.

The Logistics Assets segment is involved in transporting, storing, and fractionating mixed NGLs; storing, terminaling, and transporting finished NGLs; and storing and terminaling crude and refined products. These assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing segments and are predominantly located in Mont Belvieu, Texas and Southwestern Louisiana. This segment includes the activities associated with the recent acquisition of a refined petroleum products and crude oil storage and terminaling facility.

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

Other contains the results of our derivative and hedging transactions. Eliminations of inter-segment transactions are reflected in the eliminations column.

Our reportable segment information is shown in the following tables:

Three Months Ended March 31, 2011
	Field		Coastal
	Gathering		Gathering				Marketing					Corporate
	and		and		Logistics		and					and
	Processing		Processing		Assets		Distribution		Other			Eliminations			Total
Revenues	$	52.0	$	84.0	$	23.2	$	1,459.7	$	(4.4	)	$	-		$	1,614.5
Intersegment revenues		299.7		217.4		19.1		112.3		-			(648.5	)		-
Revenues	$	351.7	$	301.4	$	42.3	$	1,572.0	$	(4.4	)	$	(648.5	)	$	1,614.5
Operating margin	$	61.1	$	36.3	$	22.3	$	32.7	$	(4.4	)	$	-		$	148.0
Other financial information:
Total assets	$	1,641.8	$	431.3	$	506.6	$	458.7	$	34.5		$	67.8		$	3,140.7
Capital expenditures	$	31.8	$	1.4	$	45.2	$	0.1	$	-		$	-		$	78.5

Three Months Ended March 31, 2010
	Field		Coastal
	Gathering		Gathering				Marketing					Corporate
	and		and		Logistics		and					and
	Processing		Processing		Assets		Distribution		Other			Eliminations			Total
Revenues	$	55.1	$	133.6	$	16.7	$	1,281.4	$	(3.0	)	$	-		$	1,483.8
Intersegment revenues		292.0		204.9		21.0		138.7		-			(656.6	)		-
Revenues	$	347.1	$	338.5	$	37.7	$	1,420.1	$	(3.0	)	$	(656.6	)	$	1,483.8
Operating margin	$	68.3	$	27.5	$	11.2	$	19.7	$	(3.0	)	$	-		$	123.7
Other financial information:
Total assets	$	1,667.4	$	487.6	$	415.4	$	350.2	$	70.3		$	95.8		$	3,086.7
Capital expenditures	$	12.6	$	2.8	$	3.0	$	-	$	-		$	-		$	18.4

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

	Three Months Ended March 31,
	2011			2010
Natural gas sales	$	248.1		$	312.9
NGL sales		1,302.8			1,112.2
Condensate sales		21.5			25.3
Fractionating and treating fees		11.0			13.0
Storage and terminaling fees		13.9			9.5
Transportation fees		10.7			7.3
Gas processing fees		7.2			7.1
Hedge settlements		(4.4	)		(3.0	)
Other		3.7			(0.5	)
	$	1,614.5		$	1,483.8

The following table is a reconciliation of operating margin to net income for each period presented:

	Three Months Ended March 31,
	2011			2010
Reconciliation of operating margin to net income:
Operating margin	$	148.0		$	123.7
Depreciation and amortization expense		(42.7	)		(42.0	)
General and administrative expense		(31.8	)		(25.0	)
Interest expense, net		(27.5	)		(31.0	)
Income tax expense		(1.8	)		(1.5	)
Other, net		1.5			25.7
Net income	$	45.7		$	49.9

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2010, as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q.

Overview

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

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

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

·	February 2007 – North Texas System;

·	October 2007 – San Angelo (“SAOU”) and Louisiana (“LOU”);

·	September 2009 – Downstream Business;

·	April 2010 – Permian Business and Straddle Assets;

·	August 2010 – Versado; and

·	September 2010 – Venice Operations.

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

Our Operations

We are engaged in the business of gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating, transporting and selling NGLs and NGL products; and storing and terminaling refined petroleum products and crude oil.

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Other contains the results of our derivative and hedging transactions.

Recent Developments

On January 24, 2011, we completed a public offering of 8,000,000 common units under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011 we issued an additional 1,200,000 common units, providing net proceeds of $38.8 million. In addition, our general partner contributed $6.3 million to us for 187,755 general partner units to maintain its 2% general partner interest in us. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility.

On February 2, 2011, we closed a private placement of $325.0 million in aggregate principal amount of 6⅞% Senior Notes due 2021 (the “6⅞% Notes”). The net proceeds of this offering were $319.0 million after deducting expenses of the offering. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility.

On February 4, 2011, we exchanged an additional $158.6 million principal amount of our 6⅞% Notes plus payments of $28.6 million, including $0.9 million of accrued interest, for $158.6 million aggregate principal amount of our 11¼% Senior Notes due 2017 (the “11¼% Notes”). The debt covenants related to the remaining $72.7 million of face value of our 11¼% Notes were removed as we received sufficient consents in connection with the exchange offer to amend the indenture. This exchange was accounted for as a debt modification whereby the financial effects of the exchange will be recognized over the term of the new debt issue.

On March 15, 2011, we broadened our Logistics Assets segment portfolio with the acquisition of a refined petroleum products and crude oil storage and terminaling facility (the "Terminal") in Channelview, Texas on Carpenter's Bayou along the Houston Ship Channel for $29.0 million. The Terminal can handle multiple grades of blend stocks, products and crude and has potential for on-site expansion, as well as integration with our other logistics operations. The transaction was paid entirely with cash funded through borrowings under our senior secured revolving credit facility.

Recent Accounting Pronouncements

None.

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How We Evaluate Our Operations

Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the natural gas, NGLs and condensate we sell, and the costs associated with conducting our operations, including the costs of wellhead natural gas and mixed NGLs that we purchase as well as operating and general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas and NGLs and the volumes of natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services and changes in our customer mix.

Our management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses and (3) the following non-GAAP measures — gross margin, operating margin, adjusted EBITDA and distributable cash flow.

Throughput Volumes, Facility Efficiencies and Fuel Consumption. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production as well as by capturing natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Business’ fractionation facilities. We fractionate NGLs generated by our gathering and processing plants as well as by contracting for mixed NGL supply from third-party gathering or fractionation facilities.

In addition, we seek to increase operating margins by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes of natural gas received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business’ facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor the fuel consumption and recoveries of the facilities. Similar tracking is performed for our logistics assets. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.

Operating Expenses. Operating expenses are costs associated with the operation of a specific asset. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses generally remain relatively stable and independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.

Gross Margin. Gross margin is defined as revenues less purchases. It is impacted by volumes and commodity prices as well as by our contract mix and hedging program. We define Natural Gas Gathering and Processing gross margin as total operating revenues from the sales of natural gas and NGLs plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases. Logistics Assets gross margin consists primarily of service fee revenue. Gross margin for Marketing and Distribution equals total revenue from service fees and NGL sales, less cost of sales, which consists primarily of NGL purchases, transportation costs and changes in inventory valuation. The gross margin impacts of cash flow hedge settlements are reported in Other.

Operating Margin. Operating margin is an important performance measure of the core profitability of our operations. We define operating margin as gross margin less operating expenses. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.

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Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is net income. Gross margin and operating margin are not alternatives to GAAP net income, and have important limitations as analytical tools. You should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definition of gross margin and operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by us and by external users of our financial statements, including investors and commercial banks to assess:

·	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

·	our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

·	the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

Adjusted EBITDA. We define Adjusted EBITDA as net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others.

The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into its decision-making processes.

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

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

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

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

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Consolidated Results of Operations

Our management uses a variety of financial and operational measurements to analyze our performance, including gross margin, operating margin, plant inlet, gross NGL production, adjusted EBITDA and distributable cash flow, among others.

The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2011 and 2010 (in millions, except operating and price amounts):

	Three Months Ended March 31,						2011 vs. 2010
	2011			2010			$ Change			% Change
Revenues	$	1,614.5		$	1,483.8		$	130.7			9%
Product purchases		1,400.6			1,297.9			102.7			8%
Gross margin (1)		213.9			185.9			28.0			15%
Operating expenses		65.9			62.2			3.7			6%
Operating margin (2)		148.0			123.7			24.3			20%
Depreciation and amortization expenses		42.7			42.0			0.7			2%
General and administrative expenses		31.8			25.0			6.8			27%
Income from operations		73.5			56.7			16.8			30%
Interest expense, net		(27.5	)		(31.0	)		3.5			11%
Equity in earnings of unconsolidated investments		1.7			0.3			1.4			467%
Gain (loss) on mark-to-market derivative instruments		-			25.4			(25.4	)		(100%	)
Other		(0.2	)		-			(0.2	)		-
Income tax expense		(1.8	)		(1.5	)		(0.3	)		(20%	)
Net income		45.7			49.9			(4.2	)		(8%	)
Less: Net income attributable to noncontrolling interests		7.9			7.3			0.6			8%
Net income (loss) attributable to Targa Resources Partners LP	$	37.8		$	42.6		$	(4.8	)		(11%	)
Financial and operating data:
Financial data:
Adjusted EBITDA (3)	$	107.4		$	97.5		$	9.9			10%
Distributable cash flow (4)		72.1			76.4			(4.3	)		(6%	)
Operating data:
Plant natural gas inlet, MMcf/d (5)(6)		2,168.6			2,331.6			(163.0	)		(7%	)
Gross NGL production, MBbl/d		119.1			118.7			0.4		NM
Natural gas sales, BBtu/d (6)		682.2			664.5			17.7			3%
NGL sales, MBbl/d		275.6			252.9			22.7			9%
Condensate sales, MBbl/d		2.6			3.7			(1.1	)		(30%	)

__________

(1)	Gross margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

(2)	Operating margin is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

(3)

Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization, gains or losses on debt repurchases and non-cash risk management activities related to derivative instruments. This is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

(4)

Distributable cash flow is net income attributable to Targa Resources Partners LP plus depreciation and amortization, deferred taxes and amortization of debt issue costs included in interest expense, adjusted for losses (gains) on mark-to-market derivative contracts and debt repurchases, less maintenance capital expenditures (net of any reimbursements of project costs). This is a non-GAAP financial measure and is discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations” and “Non-GAAP Financial Measures.”

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

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

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

Consolidated revenues (including the impacts of hedging) increased due to higher net impact of realized commodity prices ($19.8 million), higher NGL and natural gas sales volumes ($107.9 million) and higher fee-based and other revenues ($10.2 million), partially offset by lower condensate sales volumes ($7.2 million).

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Consolidated operating margin increased $24.3 million, reflecting higher gross margin partially offset by increased operating expenses. The increase in consolidated gross margin reflects higher revenues of $130.7 million partially offset by increases in product purchase costs of $102.7 million. The increase in consolidated operating expenses of $3.7 million primarily reflects increased compensation and benefits and fuel, utilities and catalyst costs.

See “Results of Operations—By Segment” for additional information regarding changes in the components of operating margin on a disaggregated basis.

The increase in depreciation and amortization expenses of $0.7 million reflects $2.0 million of depreciation expense related to new assets placed in service since the first quarter of 2010 less the $1.3 million impact of assets that have become fully depreciated.

General and administrative expenses increased $6.8 million reflecting higher allocations by Targa for salaries, burden and incentive compensation.

The decrease in interest expense was primarily due to a lower level of borrowings, partially offset by a higher effective interest rate.

See “—Liquidity and Capital Resources” for information regarding our outstanding debt obligations.

Mark-to-market gain decreased $25.4 million. This variance is attributable to the accounting treatment of commodity hedges related to the Permian and Versado acquisitions during 2010. Under common control accounting, these hedges did not qualify for hedge accounting treatment for predecessor periods prior to our acquisition of the assets. Therefore, changes in fair value for these instruments were recorded in earnings. These derivative instruments were designated as hedges as of the date of these acquisitions, and therefore changes in value subsequent to those dates are recorded in other comprehensive income until the underlying transactions settle. We did not have mark-to-market gains on these derivatives during the first quarter of 2011, and will not have future mark-to-market gains or losses unless the hedges are de-designated.

Results of Operations—By Segment

Our operating margin by reportable segment is:

		Field		Coastal
		Gathering		Gathering				Marketing
		and		and		Logistics		and
		Processing		Processing		Assets		Distribution		Other			Total
	(In millions)
Three Months Ended March 31, 2011		$	61.1	$	36.3	$	22.3	$	32.7	$	(4.4	)	$	148.0
Three Months Ended March 31, 2010			68.3		27.5		11.2		19.7		(3.0	)		123.7

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Natural Gas Gathering and Processing Segments

Field Gathering and Processing

	Three Months Ended March 31,				2011 vs. 2010
	2011		2010		$ Change			% Change
	($ in millions)
Gross margin	$	87.9	$	90.1	$	(2.2	)		(2%	)
Operating expenses		26.8		21.8		5.0			23%
Operating margin	$	61.1	$	68.3	$	(7.2	)		(11%	)
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2)		572.8		576.5		(3.7	)		(1%	)
Gross NGL production, MBbl/d		69.5		69.3		0.2		NM
Natural gas sales, BBtu/d (2),(3)		263.1		253.5		9.6			4%
NGL sales, MBbl/d (3)		56.4		55.2		1.2			2%
Condensate sales, MBbl/d (3)		2.3		2.5		(0.2	)		(8%	)
Average realized prices (4):
Natural gas, $/MMBtu		3.81		5.17		(1.36	)		(26%	)
NGL, $/gal		1.11		1.00		0.11			11%
Condensate, $/Bbl		91.04		76.04		15.00			20%

________

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

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

(3)	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 quarter and the denominator is the number of calendar days during the quarter.

(4)	Average realized prices exclude the impact of hedging activities.

Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010

The $2.2 million decrease in gross margin for 2011 was primarily due to lower natural gas sales prices ($32.1 million), lower condensate sales volumes ($1.5 million) and higher product purchases ($6.7 million), partially offset by higher NGL and condensate sales prices ($28.2 million), higher natural gas and NGL sales volumes ($9.1 million) and higher fee based and other revenues ($1.0 million). Plant inlet volumes were essentially flat, with the impact of volumes associated with new well connects at the North Texas and SAOU systems offset by volume decreases due to severe cold weather in January and February 2011 and operational outages combined with production declines at the Partnership’s Versado system. The increased natural gas and NGL sales volumes were due primarily to higher NGL content in supply from new well connects and slightly lower plant recoveries offsetting the impact of lower plant inlet volumes.

The $5.0 million increase in operating expenses was primarily due to higher fuel, utilities and catalyst costs ($1.6 million), higher system maintenance expenses ($1.4 million) driven by severe cold weather and operational outages, as well as higher compensation and benefit costs ($1.0 million), and higher contract and professional service expenses ($1.0 million).

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Coastal Gathering and Processing

	Three Months Ended March 31,				2011 vs. 2010
	2011		2010		$ Change			% Change
	($ in millions)
Gross margin	$	46.5	$	37.4	$	9.1			24%
Operating expenses		10.2		9.9		0.3			3%
Operating margin	$	36.3	$	27.5	$	8.8			32%
Operating statistics:
Plant natural gas inlet, MMcf/d (1),(2),(3)		1,595.8		1,755.1		(159.3	)		(9%	)
Gross NGL production, MBbl/d		49.6		49.4		0.2		NM
Natural gas sales, Bbtu/d (3),(4)		254.2		313.9		(59.7	)		(19%	)
NGL sales, MBbl/d (4)		43.5		43.4		0.1		NM
Condensate sales, MBbl/d (4)		0.3		1.2		(0.9	)		(75%	)
Average realized prices (5):
Natural gas, $/MMBtu		4.15		5.26		(1.11	)		(21%	)
NGL, $/gal		1.21		1.09		0.12			11%
Condensate, $/Bbl		92.23		77.28		14.95			19%

__________

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

(2)	The majority of our Coastal Straddle plant volumes are gathered on third-party offshore pipeline systems and delivered to the plant inlets.

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

(4)	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 quarter and the denominator is the number of calendar days during the quarter.

(5)	Average realized prices exclude the impact of hedging activities.

Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010

The $9.1 million increase in gross margin for the three months ended March 31, 2011 is primarily due to an increase in NGL and condensate sales prices ($20.3 million), an increase in NGL sales volumes ($0.6 million), an increase in fee-based and other revenues ($1.5 million) and a decrease in commodity sales purchases ($46.3 million), partially offset by a decrease in natural gas sales prices ($25.5 million) and a decrease in natural gas and condensate sales volumes ($34.1 million). The decreases in plant inlet volumes were largely attributable to a decline in traditional wellhead and offshore supply volumes but higher liquids pricing more than offset the volume declines resulting in higher operating margin.

Operating expenses were flat.

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Logistics and Marketing Segments

Logistics Assets

	Three Months Ended March 31,				2011 vs. 2010
	2011		2010		$ Change			% Change
	($ in millions)
Gross margin	$	42.3	$	37.6	$	4.7			13%
Operating expenses		20.0		26.4		(6.4	)		(24%	)
Operating margin	$	22.3	$	11.2	$	11.1			99%
Operating statistics: (1)
Fractionation volumes, MBbl/d		209.3		209.6		(0.3	)	NM
Treating volumes, MBbl/d		10.2		7.6		2.6			34%

________

(1)	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 quarter and the denominator is the number of calendar days during the quarter.

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

The $4.7 million increase in gross margin reflects higher terminaling and storage revenue ($4.9 million) at our Mont Belvieu and Galena Park terminals. The increase in terminaling revenue at our Mont Belvieu terminal is primarily due to supply services to petrochemical customers. At our Galena Park terminal, the increase is due to expanded LPG export services. The acquisition of the Channelview Terminal also contributed to the higher terminaling and storage revenues.

The $6.4 million decrease in operating expenses was primarily due to a favorable system product gain/loss ($2.6 million), lower natural gas price for fuel to fractionators ($1.7 million) and less cost associated with fractionation maintenance.

Marketing and Distribution

	Three Months Ended March 31,				2011 vs. 2010
	2011		2010		$ Change			% Change
	($ in millions)
Gross margin	$	44.6	$	30.9	$	13.7			44%
Operating expenses		11.9		11.2		0.7			6%
Operating margin	$	32.7	$	19.7	$	13.0			66%
Operating statistics: (1)
Natural gas sales, BBtu/d		664.3		609.3		55.0			9%
NGL sales, MBbl/d		272.4		246.4		26.0			11%
Average realized prices:
Natural gas, $/MMBtu		4.07		5.23		(1.16	)		(22%	)
NGL realized price, $/gal		1.28		1.20		0.08			7%

________

(1)	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 quarter and the denominator is the number of calendar days during the quarter.

Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010

The $13.7 million increase in gross margin was due to higher NGL volumes ($118.0 million) and natural gas volumes ($25.9 million), higher NGL prices ($76.4 million) offset by lower natural gas prices ($69.7 million), and higher fee-based and other revenues ($1.2 million), offset by increased product purchases ($138.2 million). Factors contributing to higher operating margins in the first quarter of 2011 included increased west coast propane sales and increased export sales.

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Other

	Three Months Ended March 31,						2011 vs. 2010
	2011			2010			$ Change			% Change
	($ in millions)
Gross margin	$	(4.4	)	$	(3.0	)	$	(1.4	)		46.7%
Operating margin	$	(4.4	)	$	(3.0	)	$	(1.4	)		46.7%

Other contains the financial effects of our hedging program on profitability. 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. We have hedged the commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes by entering into derivative financial instruments. As such, these hedge positions will enhance our margins in periods of falling prices and decrease our margins in periods of rising prices.

The following table provides a breakdown of our hedge results by product:

		Three Months Ended March 31,
		2011			2010				$ Change
	(In millions)
Natural Gas		$	6.2			$	1.1		$	5.1
NGL			(8.9	)			(3.7	)		(5.2	)
Crude			(1.7	)			(0.4	)		(1.3	)
		$	(4.4	)		$	(3.0	)	$	(1.4	)

Liquidity and Capital Resources

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

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our senior secured credit facility, the issuance of additional common units and access to debt markets. The capital markets continue to experience volatility. Many financial institutions have had liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to current credit conditions includes our credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

We continue to evaluate 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.

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Crude oil and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas and NGL equity volumes through 2013 and our condensate equity volumes through 2014 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. See “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.” The current market conditions may also impact our ability to enter into future commodity derivative contracts. A significant reduction in commodity prices could reduce our operating margins and cash flow from operations to the extent that such operating margins and cash flows derive from the portion of equity volumes that are not hedged.

We have experienced significant liability increases in the fair value of our commodity derivative instruments during the first quarter of 2011 compared to the year ended December 31, 2010. This change is attributable to increasing commodity prices amplified by higher volumes being hedged during the first quarter of 2011 compared to the volumes hedged as of December 31, 2010. During the first quarter of 2011, we entered into new derivatives that increased our hedged daily volumes of natural gas by 26,149 MMBtu, NGLs by 4,219 barrels and condensate by 1,835 barrels. The contracts extend to 2013 for natural gas and NGLs, and 2014 for condensate. We designated the new derivatives as cash flow hedges. Therefore, the impact to earnings as a result of the fair value changes is immaterial for the first quarter of 2011 as these changes are recorded in other comprehensive income until the underlying hedged transactions settle.

As of March 31, 2011, our liquidity of $848.7 million consisted of $63.6 million of available cash and $785.1 million of available borrowings under our credit facility. We will continue to monitor our liquidity and the credit markets. Additionally, we continue to monitor events and circumstances surrounding each of the lenders in our credit facility.

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

A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status, as assigned to us by Moody’s Investors Service, Inc. and Standard & Poor’s Corporation, and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. At March 31, 2011, our total outstanding letter of credit postings were $113.6 million.

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 by our customers or paid to our suppliers can 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. We believe our cash flows provided by operating activities will be sufficient to meet our operating requirements for the next twelve months.

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Cash Flow

The following table and discussion summarize our consolidated cash flow provided by or used in operating activities, investing activities and financing activities for the periods indicated:

		Three Months Ended March 31,						2011 vs. 2010
		2011			2010			$ Change			% Change
	(In millions)
Net cash provided by (used in):
Operating activities		$	98.6		$	120.4		$	(21.8	)		(18%	)
Investing activities			(88.9	)		(18.9	)		(70.0	)		(370%	)
Financing activities			(22.4	)		(76.7	)		54.3			71%

Operating Activities

The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash charges as presented in the Consolidated Statements of Cash Flows included in our historical consolidated financial statements and related notes included in this Quarterly Report and changes in working capital as discussed above under “—Liquidity and Capital Resources—Working Capital.”

The $21.8 million decrease in net cash provided by operating activities in three months ended March 31, 2011 compared to 2010 was primarily due to the following:

·	a decrease in the change of operating assets and liabilities of $19.9 million, driven by lower receivable, inventory and payable balances in 2011;

·	a $15.7 million decrease in affiliate interest for the three months ended March 31, 2011, as no affiliate debt existed after the dropdown of asset to us from Targa in 2010; and

·	a $2.1 million negative change in net earnings of unconsolidated investments, driven by no distributions from unconsolidated affiliates in the first quarter of 2011 as excess operating cash flow is being used for expansion projects.

Please see “—Results of Operations—Three Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010” for a discussion of material items that impacted our net income.

Investing Activities

Net cash used in investing activities increased by $70.0 million for the three months ended March 31, 2011 compared to 2010. The increase was primarily driven by the Partnership’s acquisition of the Channelview Terminal for $29.0 million and a $25.1 million increase in Partnership expansion capital projects in gathering and processing and in fractionation. We also invested $4.4 million of equity contributions associated with the expansion at Gulf Coast Fractionators.

Financing Activities

Net cash used in financing activities decreased by $54.3 million for the three months ended March 31, 2011 compared to 2010. The decrease in net cash used in financing activities was driven by two primary factors: distributions and changes in our equity offerings and financing activities. For the three months ended March 31, 2011 compared to 2010, distributions increased by $14.7 million. Net proceeds from public offerings, issuance of senior notes and borrowings under our credit facility less repayments on our credit facility changed from net repayments of $18.2 million for the three months ended March 31, 2010 to net proceeds of $31.5 million for the three months ended March 31, 2011.

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Our primary financing activities that occurred during the first quarter of 2011 were:

On January 24, 2011, we completed a public offering of 8,000,000 common units in us under an existing shelf registration statement on Form S-3 at a price of $33.67 per common unit ($32.41 per common unit, net of underwriting discounts), providing net proceeds of $259.3 million. Pursuant to the exercise of the underwriters’ overallotment option, on February 3, 2011 we issued an additional 1,200,000 common units, providing net proceeds of approximately $38.8 million. In addition, our general partner contributed $6.3 million to us for 187,755 general partner units to maintain its 2% general partner interest in us. We used the net proceeds from the offering to reduce borrowings under our senior secured credit facility.

·	On February 2, 2011, we closed a private placement of $325.0 million in aggregate principal amount of our 6⅞% Senior Notes due 2021resulting in net proceeds of $319.0 million.

·	On February 4, 2011, we exchanged an additional $158.6 million principal amount of our 6⅞% Notes for $158.6 million aggregate principal amount of our 11¼% Notes. In conjunction with the exchange we paid a cash premium of $28.6 million including $0.9 million of accrued interest.

Distributions to our Unitholders

Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 6 and Note 7 of the notes to Consolidated Financial Statements included in this Quarterly Report.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). As of March 31, 2011, such annual minimum amounts would have been approximately $101.0 million. In every quarter since the fourth quarter of 2007, we have paid quarterly distributions greater than the minimum quarterly distribution rate. The quarterly distribution per limited partner unit paid in February 2011 for the fourth quarter of 2010 was $0.5475 per limited partner unit.

The following table shows the distributions for 2011 and 2010:

		Distributions								Distributions
	For the Three	Limited Partners		General Partner						per limited
Date Paid	Months Ended	Common		Incentive			2%	Total		partner unit
		(In millions, except per unit amounts)
May 13, 2011 (1)	March 31, 2011	$	47.3	$	6.8	$	1.1	$	55.2	$	0.5575
February 14, 2011	December 31, 2010		46.4		6.0		1.1		53.5		0.5475
November 12, 2010	September 30, 2010		40.6		4.6		0.9		46.1		0.5375
August 13, 2010	June 30, 2010		35.9		3.5		0.8		40.2		0.5275
May 14, 2010	March 31, 2010		35.2		2.8		0.8		38.8		0.5175
February 12, 2010	December 31, 2009		35.2		2.8		0.8		38.8		0.5175

__________

(1)	To be paid on May 13, 2011

The distribution for the three months ended March 31, 2011 was announced on April 11, 2011. Amounts paid under the distribution will be $40.8 million to our third-party limited partners, and $6.5 million, $6.8 million and $1.1 million to Targa for its ownership of common units, incentive distribution rights and its 2% general partner interest in us.

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Capital Requirements

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

		Three Months Ended March 31,
		2011		2010
	(In millions)
Gross additions to property, plant and equipment		$	78.5	$	18.4
Change in accruals			6.0		0.5
Cash expenditures		$	84.5	$	18.9

The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to our gathering system is generally paid for by the natural gas producer. However, we expect to make significant expenditures during the next year for the construction of additional natural gas gathering and processing infrastructure and to enhance the value of our natural gas logistics and marketing assets.

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,
		2011		2010
Capital expenditures:	(In millions)
Expansion		$	65.7		$	11.6
Maintenance			12.8			6.8
		$	78.5		$	18.4

We estimate that our total capital expenditures for 2011 will be approximately $285.0 million gross and $250.0 million net of non-controlling interest share and reimbursements. We also estimate that of the $250.0 million net capital expenditures, approximately 20-25% will be for maintenance. 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 common units and debt offerings.

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Non-GAAP Financial Measures

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, 2011 and 2010:

	Three Months Ended March 31,
	2011			2010
Reconciliation of gross margin and operating margin to net income (loss):	(In millions)
Gross margin	$	213.9		$	185.9
Operating expenses		(65.9	)		(62.2	)
Operating margin		148.0			123.7
Depreciation and amortization expenses		(42.7	)		(42.0	)
General and administrative expenses		(31.8	)		(25.0	)
Interest expense, net		(27.5	)		(31.0	)
Income tax expense		(1.8	)		(1.5	)
Other, net		1.5			25.7
Net income	$	45.7		$	49.9

	Three Months Ended March 31,
	2011			2010
	(In millions)
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	98.6		$	120.4
Net income attributable to noncontrolling interests		(7.9	)		(7.3	)
Interest expense, net (1)		25.7			14.2
Current income tax expense		1.4			0.8
Other (2)		(2.0	)		(2.5	)
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		(71.3	)		(87.4	)
Accounts payable and other liabilities		62.9			59.3
Adjusted EBITDA	$	107.4		$	97.5

_________

(1)	Net of amortization of debt issuance costs, discount and premium included in interest expense of $1.8 million and $1.2 million for the three months ended March 31, 2011 and 2010. Excludes affiliate and allocated interest expense.

(2)	Includes equity earnings from unconsolidated investments – net of distributions, accretion expense associated with asset retirement obligations, amortization of stock based compensation and gain (loss) on sale of assets.

	Three Months Ended March 31,
	2011			2010
	(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income attributable to Targa Resources Partners LP	$	37.8		$	42.6
Add:
Interest expense, net (1)		27.5			31.0
Income tax expense		1.8			1.5
Depreciation and amortization expenses		42.7			42.0
Risk management activities		0.2			(17.2	)
Noncontrolling interests adjustment		(2.6	)		(2.4	)
Adjusted EBITDA	$	107.4		$	97.5

________

(1)	Includes affiliate and allocated interest expense.

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	Three Months Ended March 31,
	2011			2010
	(In millions)
Reconciliation of net income attributable to Targa Resources Partners LP to distributable cash flow:
Net income attributable to Targa Resources Partners LP	$	37.8		$	42.6
Affiliate and allocated interest expense		-			15.6
Depreciation and amortization expenses		42.7			42.0
Deferred income tax expense		0.4			0.7
Amortization in interest expense		1.8			1.2
Risk management activities		0.2			(17.2	)
Maintenance capital expenditures		(12.8	)		(6.8	)
Other (1)		2.0			(1.7	)
Distributable cash flow	$	72.1		$	76.4

_______

(1)	Includes reimbursements of certain environmental maintenance capital expenditures by Targa and the non-controlling interest portion of maintenance capital expenditures and depreciation expense.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report. There have been no material changes to these policies and estimates during the three months ended March 31, 2011.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Commodity Price Risk. A 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 hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. For an in-depth discussion of our hedging strategies, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk” in our Annual Report.

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 specific NGL products based upon our expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our NGL hedges’ fair values are based on published index prices for delivery at Mont Belvieu through 2013, except for the price of isobutane in 2012, which is based on the ending 2011 pricing. Our natural gas hedges fair values are based on published index prices for delivery at WAHA, Permian Basin and Mid-Continent, which closely approximate the actual NGL and natural gas delivery points. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

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These 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. Absent new federal regulations resulting from Dodd-Frank Wall Street Reform and Consumer Protection Act, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.

For all periods presented we entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). During the three months ended March 31, 2011 and 2010, our operating revenues were decreased by net hedge adjustments on commodity derivative contracts of $4.4 million and $3.0 million.

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As of March 31, 2011, we had the following hedge arrangements which will settle during the years ending December 31, 2011 through 2014 (except as indicated otherwise, the 2011 volumes reflect daily volumes for the period from April 1, 2011 through December 31, 2011):

Natural Gas
Instrument		Price		MMBtu per day
Type	Index	$/MMBtu		2011		2012		2013		Fair Value
										(In millions)
Swap	IF-WAHA		6.29		23,750					$	12.2
Swap	IF-WAHA		6.61				14,850				9.6
Swap	IF-WAHA		5.28						7,230		0.3
Total Swaps					23,750		14,850		7,230
Swap	IF-PB		4.58		6,565						0.5
Swap	IF-PB		4.98				10,200				0.7
Swap	IF-PB		5.23						7,084		0.3
Total Swaps					6,565		10,200		7,084
Swap	IF-NGPL MC		5.66		8,155						2.9
Swap	IF-NGPL MC		6.03				6,740				3.1
Swap	IF-NGPL MC		4.89						2,775		(0.2	)
Total Swaps					8,155		6,740		2,775
Total Sales					38,470		31,790		17,089
Natural Gas Basis Swaps
Basis Swaps	Various Indexes, Maturities January 2011-Dec 2012										0.2
										$	29.6

NGL
Instrument		Price		Barrels per day
Type	Index	$/Gal		2011		2012		2013		Fair Value
										(In millions)
Swap	OPIS-MB		0.92		10,118					$	(30.8	)
Swap	OPIS-MB		0.91				8,611				(21.3	)
Swap	OPIS-MB		0.98						4,150		(9.5	)
Total Swaps					10,118		8,611		4,150
Floor	OPIS-MB		1.44		253						0.2
Floor	OPIS-MB		1.43				294				0.7
Total Floors					253		294		-
Total Sales					10,371		8,905		4,150
										$	(60.7	)

Condensate
Instrument		Price		Barrels per day
Type	Index	$/Bbl		2011		2012		2013		2014			Fair Value
													(In millions)
Swap	NY-WTI		86.31		1,630								$	(9.7	)
Swap	NY-WTI		88.60				1,460							(9.4	)
Swap	NY-WTI		91.49						1,595					(6.7	)
Swap	NY-WTI		90.03								700			(2.8	)
Total Sales					1,630		1,460		1,595		700
													$	(28.6	)

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.

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 readily available in public markets. For the NGL contracts that have inputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those NGL contracts which we are unable to obtain quoted prices for the full term of the commodity swap and options, the NGL valuations are classified as Level 3 within the fair value hierarchy.

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, 2011, we had variable rate borrowings of $201.3 million outstanding. 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, 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 for those contracts designated as hedging instruments.

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As of March 31, 2011, we had the following open interest rate swaps:

Period	Fixed Rate		Notional Amount		Fair Value
			($ in millions)
Remainder of 2011		3.52%	$	300	$	(7.3	)
2012		3.40%		300		(5.9	)
2013		3.39%		300		(3.6	)
1/1/2014 - 4/24/2014		3.39%		300		(0.6	)
					$	(17.4	)

A hypothetical change of 100 basis points in the underlying interest rate of our variable rate debt, after taking into account our interest rate swaps, would impact our annual interest expense by $1.0 million.

Counterparty Risk – Credit and Concentration

Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivative instruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) of each counterparty at the reporting date. Should the creditworthiness of one or more of the 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, 2011, affiliates of Barclays PLC (“Barclays”), Credit Suisse Group AG (“Credit Suisse”) and BP PLC (“BP”) accounted for 67%, 11% and 11% of our counterparty credit exposure related to commodity derivative instruments. Barclays and Credit Suisse are major financial institutions and BP is a major oil and gas company. These entities possess investment grade credit ratings based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s Corporation.

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

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2011, our disclosure controls and procedures were designed at the reasonable assurance level and, as of the end of the period covered by this report, our disclosure controls and procedures are effective at the reasonable assurance level to provide that information required to be disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and (ii) accumulated and communicated to management, including our principal executive officer and principal financial officer, to allow for timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

The information required for this item is provided in Note 11 – Commitments and Contingencies, under the heading “Legal Proceedings” included in the Notes to Consolidated Financial Statements included under Part I, Item 1 of this Quarterly Report, which is incorporated by reference into this item.

Item 1A. Risk Factors.

For an in-depth discussion of our risk factors, see “Item 1A. Risk Factors” in our Annual Report. All of these risks and uncertainties could adversely affect our business, financial condition and/or 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 Number		Description

3.1		Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).

3.2		Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

3.3		Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).

3.4		First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).

3.5		Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).

3.6		Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

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4.1		Indenture dated February 2, 2011 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).

4.2		First Supplemental Indenture dated February 2, 2011 to Indenture dated July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).

4.3		Registration Rights Agreement dated February 2, 2011 among the Issuers, the Guarantors, Deutsche Bank Securities Inc., as representative of the several initial purchasers, and the Dealer Managers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).

4.4**		Supplemental Indenture dated April 8, 2011 to Indenture dated June 18, 2008, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.5**		Supplemental Indenture dated April 8, 2011 to Indenture dated July 6, 2009, among Targa Terminals LLC, 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 8, 2011 to Indenture dated August 13, 2010, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.7**		Supplemental Indenture dated April 8, 2011 to Indenture dated February 2, 2011, among Targa Terminals 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		Purchase Agreement dated January 19, 2011 by and among the Issuers, the Guarantors and Deutsche Bank Securities Inc., as representative of the several Initial Purchasers (incorporated by reference to Exhibit 1.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 24, 2011 (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.

**		Filed herewith

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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/ Matthew J. Meloy

Matthew J. Meloy

Senior Vice President, Chief Financial Officer and Treasurer

(Authorized Officer and Principal Financial Officer)

Date: May 6, 2011

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Exhibit Index

Exhibit Number		Description

3.1		Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’s Registration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)).

3.2		Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

3.3		Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)).

3.4		First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.1 to Targa Resources Partners LP’s current report on Form 8-K filed February 16, 2007 (File No. 001-33303)).

3.5		Amendment No. 1, dated May 13, 2008, to the First Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 14, 2008 (File No. 001-33303)).

3.6		Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’s Registration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)).

4.1		Indenture dated February 2, 2011 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee thereto (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).

4.2		First Supplemental Indenture dated February 2, 2011 to Indenture dated July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors and U.S. Bank National Association (incorporated by reference to Exhibit 4.3 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).

4.3		Registration Rights Agreement dated February 2, 2011 among the Issuers, the Guarantors, Deutsche Bank Securities Inc., as representative of the several initial purchasers, and the Dealer Managers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed February 2, 2011 (File No. 001-33303)).

4.4**		Supplemental Indenture dated April 8, 2011 to Indenture dated June 18, 2008, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

4.5**		Supplemental Indenture dated April 8, 2011 to Indenture dated July 6, 2009, among Targa Terminals LLC, 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 8, 2011 to Indenture dated August 13, 2010, among Targa Terminals LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

Table of Contents

4.7**		Supplemental Indenture dated April 8, 2011 to Indenture dated February 2, 2011, among Targa Terminals 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		Purchase Agreement dated January 19, 2011 by and among the Issuers, the Guarantors and Deutsche Bank Securities Inc., as representative of the several Initial Purchasers (incorporated by reference to Exhibit 1.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 24, 2011 (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.

**		Filed herewith

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