SEC Filing | Targa Resources Corp.

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e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended March 31, 2008
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission File Number 001-33303

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)


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

Registrant’s telephone number, including area code:

(713) 584-1000

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

Indicate by check mark whether the registrant 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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes o No þ

There were 34,652,000 Common Units, 11,528,231 Subordinated Units and 942,455 General Partner Units outstanding as of May 1, 2008.


PART I — FINANCIAL INFORMATION
	Item 1.	Financial Statements	4
		Consolidated Balance Sheets at March 31, 2008 and December 31, 2007	4
		Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007	5
		Consolidated Statements of Comprehensive Loss for the three months ended March 31, 2008 and 2007	6
		Consolidated Statement of Changes in Partners’ Capital for the three months ended March 31, 2008	7
		Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and 2007	8
		Notes to Consolidated Financial Statements	9
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 3.	Quantitative and Qualitative Disclosures about Market Risk	26
	Item 4T.	Controls and Procedures	29
PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings	29
	Item 1A.	Risk Factors	30
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 3.	Defaults Upon Senior Securities	30
	Item 4.	Submission of Matters to a Vote of Security Holders	30
	Item 5.	Other Information	30
	Item 6.	Exhibits	30
SIGNATURES			31
Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership
Certification of CEO Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

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


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


Price Index
Definitions

GD-HH		Henry Hub Gas Daily average
IF-HH		Inside FERC Gas Market Report, Henry Hub
IF-HSC		Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC		Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha		Inside FERC Gas Market Report, West Texas Waha
NY-HH		NYMEX, Henry Hub Natural Gas
NY-WTI		NYMEX, West Texas Intermediate Crude Oil
OPIS-MB		Oil Price Information Service, Mont Belvieu, Texas

Cautionary Statement About Forward-Looking Statements

This Quarterly Report contains “forward-looking statements” as defined in Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this Quarterly Report are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our future financial position, business strategy, future capital and other expenditures, plans and objectives of management for future operations. You can typically identify forward-looking statements by the use of forward-looking words such as “may,” “potential,” “project,” “plan,” “believe,” “expect,” “anticipate,” “intend,” “estimate” or similar expressions or variations on such expressions. Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors, known and unknown, which could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties, many of which are beyond our control, include, but are not limited to:


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

	•	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;

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

	•	changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment or the gathering and processing industry;

	•	the timing and extent of changes in natural gas, NGL and 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;

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

	•	the level and success of natural gas drilling around our assets, and our success in connecting natural gas supplies to our gathering and processing systems;

	•	general economic, market and business conditions; and

	•	the risks described in our Annual Report on Form 10-K for the year ended December 31, 2007.

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. 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.

Forward-looking statements contained in this Quarterly Report and all subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this cautionary statement.

PART I — FINANCIAL INFORMATION


Item 1.	*Financial Statements*

TARGA RESOURCES PARTNERS LP

CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
	2008			2007
	(Unaudited)
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	23,441		$	50,994
Receivables from third parties		80,003			59,346
Receivables from affiliated companies		72,285			87,547
Inventory		1,869			1,624
Assets from risk management activities		1,403			8,695
Other		155			269

Total current assets		179,156			208,475
Property, plant and equipment, at cost		1,445,568			1,433,955
Accumulated depreciation		(192,541	)		(174,361	)

Property, plant and equipment, net		1,253,027			1,259,594
Debt issue costs		6,186			6,588
Long-term assets from risk management activities		192			3,040
Other long-term assets		2,243			2,275

Total assets	$	1,440,804		$	1,479,972


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	4,557		$	5,693
Accrued liabilities		157,856			142,836
Liabilities from risk management activities		55,498			44,003

Total current liabilities		217,911			192,532

Long-term debt		576,300			626,300
Long-term liabilities from risk management activities		73,407			43,109
Other long-term liabilities		3,355			3,266
Deferred income tax liability		896			559
Commitments and contingencies (Note 9)
Partners’ capital:
Common unitholders (34,652,000 and 34,636,000 units issued and outstanding at March 31, 2008 and December 31, 2007, respectively)		773,802			770,207
Subordinated unitholders (11,528,231units issued and outstanding at March 31, 2008 and December 31, 2007, respectively)		(83,814	)		(84,999	)
General partner (942,455 and 942,128 units issued and outstanding at March 31, 2008 and December 31, 2007, respectively)		5,638			4,234
Accumulated other comprehensive loss		(126,691	)		(75,236	)

Total partners’ capital		568,935			614,206

Total liabilities and partners’ capital	$	1,440,804		$	1,479,972

See notes to unaudited consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2008			2007
	(Unaudited)
	(In thousands, except per unit amounts)

Revenues from third parties	$	195,072		$	140,190
Revenues from affiliates		316,997			208,591

Total operating revenues		512,069			348,781
Costs and expenses:
Product purchases from third parties		375,625			254,154
Product purchases from affiliates		66,525			40,344
Operating expenses		12,570			12,152
Depreciation and amortization expense		18,248			18,038
General and administrative expense		5,201			3,354
Gain on sale of assets		(74	)		—

		478,095			328,042

Income from operations		33,974			20,739
Other expense:
Interest expense, net		8,718			2,705
Interest expense allocated from Parent		—			13,443
Loss on mark-to-market derivative instruments		—			14,880
Other		(16	)		(21	)

Income (loss) before income taxes		25,272			(10,268	)
Deferred income tax expense		337			359

Net income (loss)		24,935			(10,627	)
Less net loss attributable to predecessor operations		—			(12,780	)

Net income allocable to partners		24,935			2,153
Net income attributable to general partner interests		1,846			43

Net income available to common and subordinated unitholders	$	23,089		$	2,110

Basic net income per common and subordinated unit	$	0.50		$	0.07

Diluted net income per common and subordinated unit	$	0.50		$	0.07

Basic average number of common and subordinated units outstanding		46,151			30,848
Diluted average number of common and subordinated units outstanding		46,158			30,851

See notes to unaudited consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2008			2007
	(Unaudited)
	(In thousands)

Net income (loss)	$	24,935		$	(10,627	)
Other comprehensive loss:
Commodity hedges:
Change in fair value of commodity hedges		(51,784	)		(25,895	)
Reclassification adjustment for settled periods		9,997			(3,996	)
Related income taxes		—			303
Interest rate swaps:
Change in fair value of interest rate swaps		(9,435	)		(575	)
Reclassification adjustment for settled periods		(233	)		—

Other comprehensive loss		(51,455	)		(30,163	)

Comprehensive loss	$	(26,520	)	$	(40,790	)

See notes to unaudited consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL


	Accumulated
	Other			Partners’ Capital
	Comprehensive			Limited Partners						General
	Loss			Common			Subordinated			Partner			Total
							(Unaudited)
							(In thousands)

Balance at December 31, 2007	$	(75,236	)	$	770,207		$	(84,999	)	$	4,234		$	614,206
Amortization of equity awards		—			41			—			—			41
Other comprehensive loss		(51,455	)		—			—			—			(51,455	)
Net income		—			17,322			5,767			1,846			24,935
Distributions		—			(13,768	)		(4,582	)		(442	)		(18,792	)

Balance at March 31, 2008	$	(126,691	)	$	773,802		$	(83,814	)	$	5,638		$	568,935

See notes to unaudited consolidated financial statements

TARGA RESOURCES PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2008			2007
	(Unaudited)
	(In thousands)

Cash flows from operating activities
Net income (loss)	$	24,935		$	(10,627	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities Depreciation		18,216			18,007
Accretion of asset retirement obligations		60			182
Amortization		475			740
Gain on sale of assets		(74	)		—
Deferred income tax expense		337			359
Risk management activities		478			15,173
Changes in operating assets and liabilities:
Accounts receivable		(5,395	)		17,195
Inventory		(245	)		(101	)
Other		116			1
Accounts payable		(1,136	)		2,759
Accrued liabilities		15,020			(97	)

Net cash provided by operating activities		52,787			43,591

Cash flows from investing activities
Purchases of property, plant and equipment		(7,381	)		(11,918	)
Other		(4,167	)		1

Net cash used in investing activities		(11,548	)		(11,917	)

Cash flows from financing activities
Proceeds from equity offerings		—			380,768
Costs incurred in connection with public offerings		—			(3,710	)
Distributions		(18,792	)		—
Proceeds from borrowings under credit facility		—			342,500
Costs incurred in connection with financing arrangements		—			(4,082	)
Repayments of loans:
Affiliated		—			(665,692	)
Credit facility		(50,000	)		(48,000	)
Deemed parent distributions		—			(13,123	)

Net cash used in financing activities		(68,792	)		(11,339	)

Net change in cash and cash equivalents		(27,553	)		20,335
Cash and cash equivalents, beginning of period		50,994			—

Cash and cash equivalents, end of period	$	23,441		$	20,335

Supplemental cash flow information:
Net settlement of allocated indebtedness and debt issue costs	$	—		$	238,679
Net contribution of affiliated receivables		—			38,856

See notes to unaudited consolidated financial statements

Targa Resources Partners LP

Notes to Consolidated Financial Statements


Note 1 —	Organization and Operations

Targa Resources Partners LP (“we”, “us”, “our” or the “Partnership”) is a publicly traded Delaware limited partnership. Our common units are listed on The NASDAQ Stock Market LLC under the symbol “NGLS”. We were formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”), a leading provider of midstream natural gas and NGL services in the United States, to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling natural gas liquids (“NGLs”) and NGL products. We currently operate in the Fort Worth Basin/Bend Arch in North Texas (the “North Texas system”), the Permian Basin in West Texas (the “SAOU system”) and in Southwest Louisiana (the “LOU system”).


Note 2 —	Basis of Presentation

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. The unaudited consolidated financial statements for the three month periods ended March 31, 2008 and 2007 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair presentation of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Transactions between us and other Targa operations have been identified in the unaudited consolidated financial statements as transactions between affiliates (see Note 5). Our results of operations for the quarter ended March 31, 2007 were adjusted to reflect the consideration of common control accounting and change in predecessor entities as discussed in Notes 4 and 15 in our Annual Report on Form 10-K for the year ended December 31, 2007. Our financial results for the three months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the full year ended December 31, 2008. These unaudited consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.


Note 3 —	Accounting Pronouncements

Accounting Pronouncements Recently Adopted.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements.” SFAS 157 establishes a framework for measuring fair value and expands disclosures about fair value measurements. The FASB partially deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We adopted SFAS 157 with respect to financial assets and liabilities that are recognized on a recurring basis on January 1, 2008. Although the adoption of SFAS 157 did not materially impact its financial condition, results of operations, or cash flow, the Company is now required to provide additional disclosures as part of its financial statements.

SFAS 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are either readily available in public markets or are quoted by counterparties to these contracts. In situations where we obtain inputs via quotes from our counterparties, we verify the reasonableness of these quotes via similar quotes from another source for each date for which financial statements are presented. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3. The price quotes for the Level 3 inputs are provided by a counterparty with whom we regularly transact business.

The fair value of our financial instruments at March 31, 2008 was:


	Total		Level 1		Level 2		Level 3
	(In thousands)

Assets from commodity derivative contracts	$	1,595	$	—	$	1,595	$	—

Total assets	$	1,595	$	—	$	1,595	$	—

Liabilities from commodity derivative contracts	$	118,005	$	—	$	27,440	$	90,565
Liabilities from interest rate swaps		10,900		—		10,900		—

Total liabilities	$	128,905	$	—	$	38,340	$	90,565

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


	Commodity
	Derivative
	Contracts
	(In thousands)

Beginning balance, January 1, 2008	$	(71,370	)
Losses included in other comprehensive income		(30,738	)
Settlements		11,543
Transfers in/out of Level 3		—

Ending balance, March 31, 2008	$	(90,565	)

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115.” SFAS 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. Our adoption of SFAS 159 on January 1, 2008 did not have a material impact on our consolidated financial statements.

Accounting Pronouncements Recently Issued

In March 2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus on EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” EITF 07-4 improves the comparability of earnings per unit calculations for master limited partnerships (“MLPs”) with incentive distribution rights (“IDRs”) in accordance with Statement 128 and its related interpretations. Under EITF 07-4, when an MLP’s current-period earnings are in excess of cash distributions and the IDRs are a separate limited partner interest, undistributed earnings should be allocated to the general partner (“GP”), limited partners (“LPs”) and IDR holder utilizing the contractual terms of the

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

partnership agreement. The distribution formula for available cash specified in the partnership agreement contractually mandates the way in which earnings are distributed.

Additionally, EITF 07-4 requires an MLP to reflect its contractual obligation to make distributions as of the end of the current reporting period. Therefore, an MLP would reduce (increase) income (loss) from continuing operations (or net income or loss) for the current reporting period by the amount of available cash that has been or will be distributed to the GP, LPs, and IDR holder for that current reporting period. If distributions to the IDR holder are contractually limited to available cash as defined in the partnership agreement, then the specified threshold for the current reporting period would be the holder’s share of available cash that has been or will be distributed to the IDR holder for that current reporting period.

EITF 07-4 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Earlier application is not permitted. Our adoption of EITF 07-4 will not impact our consolidated financial position, results of operations or cash flows. We are currently evaluating the effect this pronouncement will have on our present computation of earnings per unit.

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early adoption is encouraged. Our adoption of SFAS 161 will not impact our consolidated financial position, results of operations or cash flows.


Note 4 —	Net Income per Limited Partner Unit and Distributions

Our net income is allocated to the general partner and the limited partners, including the holders of the subordinated units, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner.

Securities that meet the definition of a participating security are required to be considered for inclusion in the computation of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a particular period.

These required disclosures do not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds the First Target Distribution Level, it will have the impact of reducing net income per limited partner unit. This result occurs as a larger portion of our aggregate earnings, as if distributed, is allocated to the incentive distribution rights held by the general partner, even though we make distributions on the basis of Available Cash and not earnings. In periods in which our aggregate net income does not exceed the First Target Distribution Level, there is no impact on our calculation of earnings per limited partner unit. During the three months ended March 31, 2008, our aggregate net income per limited partner unit was greater than the First Target Distribution level, and as a result we allocated $1.3 million in additional earnings to the general partner. During the three months ended March 31, 2007, our aggregate net income per limited partner unit was less than the First Target Distribution, and as a result there was no impact on our calculation of earnings per limited partner unit.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income, less pro forma general partner incentive distributions as described above, by the weighted-average number of outstanding limited partner units during the period.

On February 14, 2008, we paid a distribution of $0.3975 per common and subordinated unit (approximately $18.8 million, including distributions to the general partner and the holder of the incentive distributions rights) for the fourth quarter of 2007.

The following table illustrates our calculation of net income per limited and subordinated partner unit for the three months ended March 31, 2008 and 2007:


	Three Months		Three Months
	Ended		Ended
	March 31,		March 31,
	2008		2007
	(In thousands)

Net income (loss)	$	24,935	$	(10,627	)
Less: Net loss attributable to predeccessor operations		—		(12,780	)

Net income allocable to partners		24,935		2,153
Net income attributable to general partner interests		1,846		43

Net income available to common and subordinated unitholders	$	23,089	$	2,110

Basic net income per common and subordinated unit	$	0.50	$	0.07

Diluted net income per common and subordinated unit	$	0.50	$	0.07

Basic average number of common and subordinated units outstanding		46,151		30,848
Restrictive equivalents		7		3

Diluted average number of common and subordinated unts outstanding		46,158		30,851


Note 5 —	Related-Party Transactions

Targa Resources, Inc.

We are a party to various agreements with Targa, our general partner and others that address (i) the reimbursement of our general partner for costs incurred on our behalf, (ii) our sales of certain NGLs and NGL products to Targa; and (iii) our sales of our natural gas to Targa.

The following table summarizes the sales to and purchases from affiliates of Targa, payments made or received by Targa on behalf of the Partnership and allocations of costs from Targa which were settled through

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

adjustments to partners’ capital. Management believes these transactions are executed on terms that are fair and reasonable.


	Three Months		Three Months
	Ended		Ended
	March 31, 2008		March 31, 2007
	(In thousands)

Sales to affiliates	$	316,997	$	208,591
Purchases from affiliates		66,525		40,344
Allocations of general & administrative expenses — pre IPO		—		2,478
Allocations of general & administrative expenses under Omnibus Agreement		3,862		876
Allocated interest		—		13,443
Payments made by Parent on our behalf		—		90,018
Net change in affiliate receivable		15,262		28,639

Centralized Cash Management

Prior to the contribution of the North Texas, SAOU and LOU Systems to us, the excess cash from these subsidiaries was held in separate bank accounts and swept to a centralized account under Targa. After the contribution of these systems, their bank accounts are maintained under the Partnership’s seperate centralized cash management system.

For the North Texas System, prior to February 14, 2007, cash distributions are deemed to have occurred through partners’ capital and are reflected as an adjustment to partners’ capital. For the period from January 1, 2007 through February 13, 2007, deemed net capital distributions from the Partnership were $0.5 million.

For the SAOU and LOU Systems, for the period from January 1, 2007 though March 31, 2007, deemed net capital distributions from the Partnership were $12.6 million.

Other

Commodity hedges. We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”). Merrill Lynch holds an equity interest in the holding company that indirectly owns our general partner. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas and condensate over periods ending in 2010, and we have agreed to pay MLCI floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with MLCI as of March 31, 2008:

Period

Commodity

Instrument Type

Daily Volumes

Average Price

Index

Apr 2008 — Dec 2008

Natural gas

Swap

3,847

MMBtu

8.76

per MMBtu

IF-Waha

Jan 2009 — Dec 2009

Natural gas

Swap

3,556

MMBtu

8.07

per MMBtu

IF-Waha

Jan 2010 — Dec 2010

Natural gas

Swap

3,289

MMBtu

7.39

per MMBtu

IF-Waha

Apr 2008 — Dec 2008

NGL

Swap

3,175

Bbl

1.06

per gallon

OPIS-MB

Jan 2009 — Dec 2009

NGL

Swap

3,000

Bbl

0.98

per gallon

OPIS-MB

Apr 2008 — Dec 2008

Condensate

Swap

264

Bbl

72.66

per barrel

NY-WTI

Jan 2009 — Dec 2009

Condensate

Swap

202

Bbl

70.60

per barrel

NY-WTI

Jan 2010 — Dec 2010

Condensate

Swap

181

Bbl

69.28

per barrel

NY-WTI

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

At March 31, 2008, the fair value of these open positions is a liability of $30.2 million. For the three months ended March 31, 2008 and 2007, we paid MLCI $4.1 million and $0.7 million to settle payments due under hedge transactions.


Note 6 —	Long-Term Debt

The outstanding borrowings, issued letters of credit and available borrowings under our credit facility as of the dates shown below were:


	March 31,		December 31,
	2008		2007
	(In thousands)

Outstanding borrowings under Credit Facility	$	576,300	$	626,300
Letters of Credit issued		38,450		25,900
Available borrowings under Credit Facility		135,250		97,800

Our weighted average interest rate on outstanding borrowings under our credit facility for the quarter ended March 31, 2008 was 5.6%.


Note 7 —	Derivative Instruments and Hedging Activities

At March 31, 2008 and December 31, 2007, accumulated other comprehensive income (loss) (“OCI”) included $115.8 million and $74.0 million of unrealized net losses, respectively, on commodity hedges.

For the quarters ended March 31, 2008 and 2007, deferred net gains (losses) on commodity hedges of ($10.0) million and $4.0 million were reclassified from OCI to revenues, respectively. There were no adjustments for hedge ineffectiveness for the quarters ended March 31, 2008 or 2007.

At March 31, 2008 and December 31, 2007, OCI also included $10.9 million and $1.2 million of unrealized losses, respectively, on interest rate hedges. For the quarter ended March 31, 2008, unrealized gains on interest rate hedges of $0.2 million were reclassified from OCI to interest expense. There were no adjustments for hedge ineffectiveness for the quarters ended March 31, 2008 or 2007.

At March 31, 2008, deferred net losses of $50.0 million on commodity hedges and $5.0 million on interest rate hedges recorded in OCI are expected to be reclassified to expense during the next twelve months.

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

At March 31, 2008, we had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from April 1, 2008 through December 31, 2008):

Natural Gas


		Avg. Price		MMBtu per Day
Instrument Type	Index	$/MMBtu		2008		2009		2010		2011		2012		Fair Value
														(In thousands)

Natural Gas Purchases
Swap	NY-HH		8.42		1,552		—		—		—		—	$	775

					1,552		—		—		—		—		775

Natural Gas Sales
Swap	IF-HSC		8.09		2,328		—		—		—		—		(1,235	)
Swap	IF-HSC		7.39		—		1,966		—		—		—		(1,420	)

					2,328		1,966		—		—		—		(2,655	)

Swap	IF-NGPL MC		8.43		6,964		—		—		—		—		(1,182	)
Swap	IF-NGPL MC		8.02		—		6,256		—		—		—		(1,352	)
Swap	IF-NGPL MC		7.43		—		—		5,685		—		—		(1,538	)
Swap	IF-NGPL MC		7.34		—		—		—		2,750		—		(713	)
Swap	IF-NGPL MC		7.18		—		—		—		—		2,750		(820	)

					6,964		6,256		5,685		2,750		2,750		(5,605	)

Swap	IF-Waha		8.20		7,389		—		—		—		—		(2,754	)
Swap	IF-Waha		7.61		—		6,936		—		—		—		(3,339	)
Swap	IF-Waha		7.38		—		—		5,709		—		—		(2,017	)
Swap	IF-Waha		7.36		—		—		—		3,250		—		(848	)
Swap	IF-Waha		7.18		—		—		—		—		3,250		(976	)

					7,389		6,936		5,709		3,250		3,250		(9,934	)

Total Swaps					16,681		15,158		11,394		6,000		6,000		(18,194	)

Floor	IF-NGPL MC		6.55		1,000		—		—		—		—		115
Floor	IF-NGPL MC		6.55		—		850		—		—		—		25

					1,000		850		—		—		—		140

Floor	IF-Waha		6.85		670		—		—		—		—		75
Floor	IF-Waha		6.55		—		565		—		—		—		7

					670		565		—		—		—		82

Total Floors					1,670		1,415		—		—		—		222

Basis Swap Apr 2008 Rec GD-HH, pay IF-HH, 120,000 MMBtu															—

														$	(17,197	)

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

NGLs


			Avg. Price		Barrels per Day
Instrument Type	Index		$/gal		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

NGL Sales
Swap		OPIS-MB		1.02		7,110		—		—		—		—	$	(29,293	)
Swap		OPIS-MB		0.96		—		6,248		—		—		—		(27,281	)
Swap		OPIS-MB		0.91		—		—		4,809		—		—		(15,978	)
Swap		OPIS-MB		0.92		—		—		—		3,400		—		(10,417	)
Swap		OPIS-MB		0.92		—		—		—		—		2,700		(7,596	)

						7,110		6,248		4,809		3,400		2,700	$	(90,565	)

Condensate


			Avg. Price		Barrels per Day
Instrument Type	Index		$/Bbl		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

Condensate Sales
Swap		NY-WTI		68.34		384		—		—		—		—	$	(3,016	)
Swap		NY-WTI		69.00		—		322		—		—		—		(3,002	)
Swap		NY-WTI		68.10		—		—		301		—		—		(2,641	)

Total Swaps						384		322		301		—		—		(8,659	)

Floor		NY-WTI		60.50		55		—		—		—		—		21
Floor		NY-WTI		60.00		—		50		—		—		—		(10	)

Total Floors						55		50		—		—		—		11

						439		372		301		—		—	$	(8,648	)

Customer Hedges

Period

Commodity

Instrument Type

Daily Volume

Average Price

Index

Fair Value

(In thousands)

Purchases

Apr 2008 — June 2008

Natural gas

Swap

14,176 MMBtu

$9.22 per MMBtu

NY-HH

545

Sales

Apr 2008 — June 2008

Natural gas

Fixed price sale

14,176 MMBtu

$9.22 per MMBtu

NY-HH

(545

)

—

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

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

In December 2007, we entered into interest rate swaps with a notional amount of $200 million. In January 2008, we entered into interest rate swaps for an additional notional amount of $100 million At March 31, 2008, we had the following open interest rate swaps:


Effective Date		Expiration Date		Notional Amount		Index		Fixed Rate

	12/13/2007		1/24/2011	$	50,000,000		3 Month USD LIBOR	4.0775%
	12/18/2007		1/24/2011	$	50,000,000		3 Month USD LIBOR	4.2100%
	12/21/2007		1/24/2012	$	50,000,000		3 Month USD LIBOR	4.0750%
	12/21/2007		1/24/2012	$	50,000,000		3 Month USD LIBOR	4.0750%
	1/9/2008		1/24/2012	$	50,000,000		3 Month USD LIBOR	3.6990%
	1/11/2008		1/24/2012	$	50,000,000		3 Month USD LIBOR	3.6400%

Each of these interest rate swaps has been designated as a cash flow hedge of variable rate interest payments on $50 million in borrowings under our revolving credit facility. At March 31, 2008, the fair value of our interest rate swaps was a liability of $10.9 million.


Note 8 —	Income Taxes

We are not a taxable entity for United States Federal income tax purposes. Taxes on our net income are generally borne by our unitholders through allocations of taxable income pursuant to the partnership agreement. In May 2006, Texas substantially revised its tax rules and imposed a new tax based on modified gross margin, beginning in 2007. For the three months ended March 31, 2008 and 2007, our provisions for income taxes of $0.3 million and $0.4 million, respectively, are applicable to state tax obligations under the Texas Margin Tax.

In accordance with FASB Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position, results of operations or cash flows.


Note 9 —	Commitments and Contingencies

Environmental

For environmental matters, the Partnership records liabilities when remedial efforts are probable and the costs are reasonably estimated in accordance with the American Institute of Certified Public Accountants Statement of Position 96-1, “Environmental Remediation Liabilities.” Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. This liability was transferred as part of the assets contributed to us at the time of our initial public offering.

Our environmental liability was $0.3 million at March 31, 2008, primarily for ground water assessment and remediation.

Litigation

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc., and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit

Targa Resources Partners LP

Notes to Consolidated Financial Statements — (Continued)

alleges that Targa and private equity funds affiliated with Warburg Pincus LLC, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU system from ConocoPhillips, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal, and on May 6, 2008 filed it’s appellant’s brief with the 14th Court of Appeals in Houston, Texas. Targa will contest the appeal, but can give no assurances regarding the outcome of the proceeding.

Note 10 — Share-Based Compensation

Our general partner has adopted a long-term incentive plan (“the Plan”) for employees, consultants and directors of the general partner and its affiliates who perform services for us. We account for awards under the Plan utilizing the fair value recognition provisions of SFAS 123R, “Share-Based Payment.”

Non-Employee Director Grants

On March 25, 2008, our general partner made equity-based awards of 16,000 restricted common units of the Partnership (2,000 restricted common units in the Partnership to each of the Partnership’s non-management directors and to each of Targa Resources Investments Inc.’s independent directors) under the Plan. The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date.

Compensation expense on the restricted common units is recognized on a straight-line basis over the vesting period. The fair value of an award of restricted common units is measured on the grant date using the market price of a common unit on such date. For the quarter ended March 31, 2008 and for the period of commencement of Partnership operations (February 14, 2007) through March 31, 2007, we recognized compensation expense of approximately $41,000 and $16,000 related to equity-based awards, respectively. We estimate that the remaining fair value of $480,000 will be recognized in expense over the next 23-36 months.


Note 11 —	Subsequent Event

On April 22, 2008, our general partner approved a quarterly distribution of available cash of $0.4175 per common and subordinated unit (approximately $19.9 million, including distributions to the general partner and the holder of the incentive distributions rights), for the quarter ended March 31, 2008, payable on May 15, 2008 to unitholders of record as of the close of business on May 5, 2008.


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

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Form 10-Q and in our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Overview

We are a Delaware limited partnership formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products. We currently operate in the Fort Worth Basin in North Texas, the Permian Basin in West Texas and in Southwest Louisiana.

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

Our Operations

We sell the majority of our processed natural gas, NGLs and high pressure condensate to Targa at market-based rates pursuant to natural gas, NGL and condensate purchase agreements. Low-pressure condensate is sold to third parties. For a more complete description of these arrangements, please see “Item 13. Certain Relationships and Related Transactions and Director Independence” and “Item 1. Business — Market Access” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Critical Accounting Policies and Estimates

There have been no significant changes to our critical accounting policies and estimates since December 31, 2007. For a more complete description of our critical accounting polices and estimates, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Accounting Pronouncements

On January 1, 2008, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 157. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 3 of the Notes to Unaudited Consolidated Financial Statements for information regarding fair value disclosures pertaining to our financial assets and liabilities.

The accounting standard-setting bodies have recently issued the following accounting guidelines that will or may affect our future financial statements:


	•	EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.”

	•	SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.”

For additional information regarding these recent accounting developments and others that may affect our future financial statements, see Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Results of Operations

The following table and discussion relate to the three months ended March 31, 2008 and 2007 and is a summary of our results of operations for the periods then ended:


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2008			2007
	(In millions of dollars, except operating and price data)

Revenues	$	512.1		$	348.8
Product purchases		442.2			294.5
Operating expense, excluding DD&A		12.6			12.2
Depreciation and amortization expense		18.2			18.0
General and administrative expense		5.2			3.3

Income from operations		33.9			20.8
Interest expense, net		8.7			2.7
Interest expense, allocated from Parent		—			13.4
Loss on mark-to-market derivative instruments		—			14.9
Deferred income tax expense(1)		0.3			0.4

Net income(loss)	$	24.9		$	(10.6	)

Financial data:
Operating margin(2)	$	57.3		$	42.1
Adjusted EBITDA(3)	$	52.6		$	39.1
Operating data:
Gathering throughput, MMcf/d(4)		457.1			425.1
Plant natural gas inlet, MMcf/d(5)(6)		437.7			397.8
Gross NGL production, MBbl/d		43.6			39.0
Natural gas sales, BBtu/d(6)		418.4			380.2
NGL sales, MBbl/d		38.0			33.0
Condensate sales, MBbl/d		3.7			3.4
Natural Gas, per MMBtu
Average realized sales price	$	7.96		$	6.68
Impact of hedging		0.06			0.08

Average realized price	$	8.02		$	6.76

NGL, per gal
Average realized sales price	$	1.29		$	0.81
Impact of hedging		(0.08	)		—

Average realized price	$	1.21		$	0.81

Condensate, per Bbl
Average realized sales price	$	87.45		$	50.93
Impact of hedging		(1.86	)		1.85

Average realized price	$	85.59		$	52.78


(1)		In May 2006, Texas adopted a margin tax, comprising a 1% tax on the amount by which total revenue exceeds cost of goods sold as apportioned to Texas. The amount presented represents our estimated liability for this tax.


(2)		Operating margin is total operating revenues less product purchases and operating expense. Please see “Non-GAAP Financial Measures” included in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

(3)		Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash loss related to derivative instruments. Please see “Non-GAAP Financial Measures” included in Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

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

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

Three Months Ended March 31, 2008 Compared to Three Months Ended March 31, 2007

Revenues increased $163.3 million, or 47%, to $512.1 million for the three months ended March 31, 2008 compared to $348.8 million for the three months ended March 31, 2007. The increase is primarily due to:


	•	An increase attributable to commodity sales volume of $44.3 million comprising increases in natural gas, NGL and condensate revenues of $26.1 million, $16.7 million and $1.5 million, respectively;

	•	An increase attributable to commodity prices of $116.3 million, comprising increases in natural gas, NGL and condensate revenues of $47.8 million, $57.4 million and $11.1 million, respectively; and

	•	An increase in other revenue of $2.7 million, primarily from miscellaneous processing activities.

Average realized prices for natural gas increased by $1.26 per MMBtu, or 19%, to $8.02 per MMBtu ($0.02 decrease per MMBtu related to hedge settlements) for the three months ended March 31, 2008 compared to $6.76 per MMBtu for the three months ended March 31, 2007. The average realized price for NGLs increased by $0.40 per gallon, or 49%, to $1.21 per gallon ($0.08 decrease per gallon related to hedge settlements) for the three months ended March 31, 2008 compared to $0.81 per gallon for the three months ended March 31, 2007. The average realized price for condensate increased by $32.81 per barrel, or 62%, to $85.59 per barrel ($3.71 decrease per barrel related to hedge settlements) for the three months ended March 31, 2008 compared to $52.78 per barrel for the three months ended March 31, 2007.

Natural gas sales volumes increased by 38.2 BBtu/d, or 10%, to 418.4 BBtu/d for the three months ended March 31, 2008 compared to 380.2 BBtu/d for the three months ended March 31, 2007. Sales volume increases were attributable to increased demand by our industrial customers, as well as sales of additional natural gas purchase from affiliates, partially offset by increases in residue take-in-kind volumes.

NGL sales volumes increased by 5.0 MBbl/d, or 15%, to 38.0 MBbl/d for the three months ended March 31, 2008 compared to 33.0 MBbl/d for the three months ended March 31, 2007. The increase was primarily due to increased NGL recoveries of 4.6 MBbl/d from higher inlet volumes of 39.9 MMcf/d. Contractual linefill requirements after the termination of a prior sales contract reduced volumes available for sale by approximately 0.8 MBbl/d.

Product purchases increased by $147.7 million, or 50%, to $442.2 million for the three months ended March 31, 2008 compared to $294.5 million for the three months ended March 31, 2007. The increase in product purchases was due primarily to increased purchases to meet industrial market demands, an increase in plant natural gas inlet volumes and higher product purchase prices.

Operating expenses increased by $0.4 million, or 3%, to $12.6 million for the three months ended March 31, 2008 compared to $12.2 million for the three months ended March 31, 2007. The increase in operating expenses was primarily the result of increased compensation and benefit costs.

General and administrative expenses increased by $1.9 million, or 58%, to $5.2 million for the three months ended March 31, 2008 compared to $3.3 million for the three months ended March 31, 2007. The

increase primarily consisted of increases of $0.5 million in professional services fees and a $1.2 million increase in the allocation of corporate level expenses which were higher during the three months ended March 31, 2008. For additional information regarding our allocation of general and administrative costs, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our Annual Report on Form 10-K for the year ended December 31, 2007.

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 or to meet our collateral requirements depends on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for natural gas and NGLs, operating costs and maintenance capital expenditures. Please see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Historically, our cash generated from operations has been sufficient to finance our operating expenditures and maintenance and expansion capital expenditures, with remaining amounts being distributed to Targa, during its period of ownership and to our unitholders since Targa’s contribution of assets to us and our acquisition of assets from Targa. Our sources of liquidity include:


	•	cash generated from operations;

	•	borrowings under our credit facility;

	•	issuance of additional partnership units; and

	•	debt offerings.

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

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs. Historically, we have relied on internally generated cash flows for these purposes. On February 14, 2008, a cash distribution of $0.3975 per common and subordinated unit ($1.59 per common unit on an annualized basis) was paid for the fourth quarter of 2007. On April 23, 2008, a cash distribution of $0.4175 per common and subordinated unit ($1.67 per common unit on an annualized basis) was declared for the first quarter of 2008.

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

At March 31, 2008, we had a working capital deficit of $38.8 million, including a net short-term liability for commodity and interest rate derivatives was $54.1 million. In accordance with SFAS 133 “Accounting for Derivative Instruments and Hedging Activities”, we record the fair value of all derivative instruments on the balance sheet. Our hedge agreements provide for monthly settlement (quarterly for interest rate swaps) based

on the differential between the agreement price and published commodity price and interest rate indexes. Cash received from physical sales of commodities and cash paid for interest will be based on actual market prices and interest rates and will generally offset any gains or losses realized on the derivative instruments. Our derivative contracts do not have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. Excluding derivatives our working capital surplus was $15.3 million.

Cash Flow. Net cash provided by or used in operating activities, investing activities and financing activities for the three months ended March 31, 2008 and 2007 were as follows:


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2008			2007
	(In millions)

Net cash provided by operating activities	$	52.8		$	43.6
Net cash used in investing activities		(11.5	)		(11.9	)
Net cash used in financing activities		(68.8	)		(11.3	)

Operating Activities. Net cash provided by operating activities increased by $9.2 million, or 21%, for the three months ended March 31, 2008 compared to the three months ended March 31, 2007. This increase is primarily attributable to an increase in our net income, adjusted for non-cash charges related to risk management activities and other non-cash charges, as presented in the combined statements of cash flows.

Investing Activities. Net cash used in investing activities for the three months ended March 31, 2008 decreased $0.4 million, or 3%, compared to the three months ended March 31, 2007. Purchases of property, plant and equipment during the three months ended March 31, 2008 versus the three months ended March 31, 2007 were down due to the timing of expansion capital projects. Other investing activities for the three months ended March 31, 2008 included approximately $4.1 million for contractually obligated linefill on a third party owned pipeline.

Financing Activities. Net cash used in financing activities for the three months ended March 31, 2008 increased by $57.5 million compared to the three months ended March 31, 2007. This increase is primarily due to distributions to unitholders of $18.8 million and the repayment of $50 million on our credit facility that occurred during the three months ended March 31, 2008, compared to transactions during the three months ended March 31, 2007 associated with the completion of our IPO, the establishment of our credit facility, deemed parent contributions prior to the IPO and the contribution of the North Texas System to us, which were offset by payments of debt, offering costs, and debt issuance costs related to our credit facility.

Contractual Obligations. There were no material changes to our contractual obligations other than the repayment of $50 million under our credit facility during the three months ended March 31, 2008.

Available Credit. As of March 31, 2008, we had approximately $135.3 million in capacity available under our credit agreement, after giving effect to outstanding borrowings of $576.3 million and the issuance of $38.5 million of letters of credit.

Capital Requirements. 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 continue to incur significant expenditures throughout 2008 related to the expansion of our natural gas gathering and processing infrastructure.

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

Expansion expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues.


	Three Months		Three Months
	Ended		Ended
	March 31,		March 31,
	2008		2007
	(In millions)

Capital expenditures:
Expansion	$	3.0	$	7.0
Maintenance		4.4		4.9

	$	7.4	$	11.9

We estimate that our total capital expenditures for 2008 will be approximately $60 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that we will invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

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

Non-GAAP Financial Measures

For a complete discussion of the measures that management uses to evaluate our operations, please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate our Operations” in our Annual Report on Form 10-K for the year ended December 31, 2007. 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, 2008 and 2007:


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2008			2007
	(In millions)

Reconciliation of “Adjusted EBITDA” to net cash provided by operating activities:
Net cash provided by operating activities	$	52.8		$	43.6
Allocated interest expense from parent(1)		—			12.7
Interest expense, net(1)		8.3			2.7
Changes in operating working capital which used (provided) cash:
Accounts receivable		5.4			(17.2	)
Accounts payable		1.1			(2.8	)
Accrued liabilities		(15.0	)		0.1

Adjusted EBITDA	$	52.6		$	39.1

Reconciliation of “Adjusted EBITDA” to net income (loss):
Net income (loss)	$	24.9		$	(10.6	)
Add:
Allocated interest expense, net		—			13.4
Interest expense, net		8.7			2.7
Deferred income tax expense		0.3			0.4
Depreciation and amortization expense		18.2			18.0
Risk Management Activities		0.5			15.2

Adjusted EBITDA	$	52.6		$	39.1


	Three Months		Three Months
	Ended		Ended
	March 31,		March 31,
	2008		2007
	(In millions)

Reconciliation of “operating margin” to net income (loss):
Net income (loss)	$	24.9	$	(10.6	)
Add:
Depreciation and amortization expense		18.2		18.0
Deferred income tax expense		0.3		0.4
Allocated interest expense, net		—		13.4
Interest expense, net		8.7		2.7
Non-cash loss related to derivative instruments		—		14.9
General and administrative expense		5.2		3.3

Operating margin	$	57.3	$	42.1


(1)		-Net of amortization of debt issuance costs of $0.4 million for the three months ended March 31, 2008 and $0.7 million for the three months ended March 31, 2007.


	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2008			2007(a)
	(In millions)

Reconciliation of “Distributable cash flow” to net income (loss):
Net income (loss)	$	24.9		$	(10.6	)
Depreciation and amortization expense		18.2			18.0
Deferred income tax expense		0.3			0.4
Amortization of debt issue costs		0.4			0.7
Loss on mark-to-market derivative contracts		—			14.9
Maintenance capital expenditures		(4.4	)		(4.9	)

Distributable cash flow	$	39.4		$	18.5


(a)		Distributable cash flow for the quarter ended March 31, 2007 reflects allocated interest from parent of $13.4 million.

Below is a reconciliation of net income (loss) as reported and distributable cash flow which excludes the results of operations of the North Texas System and the SAOU and LOU Systems prior to their ownership by the Partnership.


	For the Three Months Ended March 31, 2007
				Pre-Acquisition
				SAOU-LOU			North Texas			Post
				Jan 1, 2007 to			Jan 1, 2007 to			Acquisition
	TRP LP			March 31, 2007			Feb 13, 2007			TRP LP
	(In millions)

Net income (loss)	$	(10.6	)	$	(5.9	)	$	(6.9	)	$	2.2
Depreciation and amortization expense		18.0			3.8			6.9			7.3
Deferred income tax expense		0.4			—			—			0.4
Amortization of debt issue costs		0.7			0.6			—			0.1
Loss on mark-to-market derivative instruments		14.9			14.9			—			—
Maintenance capital expenditures		(4.9	)		(2.2	)		(1.5	)		(1.2	)

Distributable Cash Flow	$	18.5		$	11.2		$	(1.5	)	$	8.8


Item 3.	*Quantitative and Qualitative Disclosures about Market Risk*

For an in-depth discussion of market risks, please see “Item 7A. Quantitative and Qualitative Disclosure about Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.

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, please see “Item 7A. Quantitative and Qualitative Disclosure about Market Risk — Commodity Price Risk” in our Annual Report on Form 10-K for the year ended December 31, 2007.

For the three months ended March 31, 2008, our operating revenues were decreased by net hedge settlements of $10.0 million. During 2007 and 2006, 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). At March 31, 2008, we had the following open commodity derivative positions (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from April 1, 2008 through December 31, 2008):

Natural Gas


		Avg. Price		MMBtu per day
Instrument Type	Index	$/MMBtu		2008		2009		2010		2011		2012		Fair Value
														(In thousands)

Natural Gas Purchases
Swap	NY-HH		8.42		1,552		—		—		—		—	$	775

					1,552		—		—		—		—		775

Natural Gas Sales
Swap	IF-HSC		8.09		2,328		—		—		—		—		(1,235	)
Swap	IF-HSC		7.39		—		1,966		—		—		—		(1,420	)

					2,328		1,966		—		—		—		(2,655	)

Swap	IF-NGPL MC		8.43		6,964		—		—		—		—		(1,182	)
Swap	IF-NGPL MC		8.02		—		6,256		—		—		—		(1,352	)
Swap	IF-NGPL MC		7.43		—		—		5,685		—		—		(1,538	)
Swap	IF-NGPL MC		7.34		—		—		—		2,750		—		(713	)
Swap	IF-NGPL MC		7.18		—		—		—		—		2,750		(820	)

					6,964		6,256		5,685		2,750		2,750		(5,605	)

Swap	IF-Waha		8.20		7,389		—		—		—		—		(2,754	)
Swap	IF-Waha		7.61		—		6,936		—		—		—		(3,339	)
Swap	IF-Waha		7.38		—		—		5,709		—		—		(2,017	)
Swap	IF-Waha		7.36		—		—		—		3,250		—		(848	)
Swap	IF-Waha		7.18		—		—		—		—		3,250		(976	)

					7,389		6,936		5,709		3,250		3,250		(9,934	)

Total Swaps					16,681		15,158		11,394		6,000		6,000		(18,194	)

Floor	IF-NGPL MC		6.55		1,000		—		—		—		—		115
Floor	IF-NGPL MC		6.55		—		850		—		—		—		25

					1,000		850		—		—		—		140

Floor	IF-Waha		6.85		670		—		—		—		—		75
Floor	IF-Waha		6.55		—		565		—		—		—		7

					670		565		—		—		—		82

Total Floors					1,670		1,415		—		—		—		222

Basis Swap Apr 2008 Rec GD-HH, pay IF-HH, 120,000 MMBtu															—

														$	(17,197	)

NGLs


			Avg. Price		Barrels per day
Instrument Type	Index		$/gal		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

NGL Sales
Swap		OPIS-MB		1.02		7,110		—		—		—		—	$	(29,293	)
Swap		OPIS-MB		0.96		—		6,248		—		—		—		(27,281	)
Swap		OPIS-MB		0.91		—		—		4,809		—		—		(15,978	)
Swap		OPIS-MB		0.92		—		—		—		3,400		—		(10,417	)
Swap		OPIS-MB		0.92		—		—		—		—		2,700		(7,596	)

						7,110		6,248		4,809		3,400		2,700	$	(90,565	)

Condensate


			Avg. Price		Barrels per day
Instrument Type	Index		$/Bbl		2008		2009		2010		2011		2012		Fair Value
															(In thousands)

Condensate Sales
Swap		NY-WTI		68.34		384		—		—		—		—	$	(3,016	)
Swap		NY-WTI		69.00		—		322		—		—		—		(3,002	)
Swap		NY-WTI		68.10		—		—		301		—		—		(2,641	)

Total Swaps						384		322		301		—		—		(8,659	)

Floor		NY-WTI		60.50		55		—		—		—		—		21
Floor		NY-WTI		60.00		—		50		—		—		—		(10	)

Total Floors						55		50		—		—		—		11

						439		372		301		—		—	$	(8,648	)

Customer Hedges

Period

Commodity

Instrument Type

Daily Volume

Average Price

Index

Fair Value

(In thousands)

Purchases

Apr 2008 — June 2008

Natural gas

Swap

14,176 MMBtu

$9.22 per MMBtu

NY-HH

545

Sales

Apr 2008 — June 2008

Natural gas

Fixed price sale

14,176 MMBtu

$9.22 per MMBtu

NY-HH

(545

)

—

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.

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of variable rate debt under our credit facility. To the extent that interest rates increase, interest expense on our revolving debt will also increase. As of March 31, 2008, there were borrowings of approximately $576.3 million outstanding under our $750 million credit facility. Because of the interest rate risk on our credit facility, in addition to the $200 million in interest

rate swaps that we had at December 31, 2007, we entered into an additional $100 million in interest rate swaps during the first quarter of 2008 to reduce this risk, as shown below:

Trade Date

Term

From

Fixed Rate

Notional Amount

(In thousands)

01/07/08

4 years

01/09/08

1/24/12

3.699

50,000

01/09/08

4 years

01/11/08

1/24/12

3.64

50,000

Each swap fixes the three month LIBOR rate at the indicated rates for the specified amounts of related debt outstanding over the term of each swap agreement. The fair value of our outstanding interest rate swaps was a liability of $10.9 million at March 31, 2008. We have designated all interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account our interest rate swaps, would increase our annual interest expense by $2.8 million.

Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We operate under the Targa credit policy and closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with this credit policy. In addition to third party contracts, we have entered into several agreements with Targa. For example, we are party to natural gas, NGL and condensate purchase agreements pursuant to which Targa purchases the majority of our natural gas, NGLs and high-pressure condensate. In addition, we are also a party to an omnibus agreement with Targa which addresses, among other things, the provision of general and administrative and operating services to us. Any material nonperformance under the omnibus and purchase agreements by Targa could materially and adversely impact our ability to operate and make distributions to our unitholders.


Item 4T.	*Controls and Procedures*

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective at a reasonable assurance level to provide reasonable assurance that all material information relating to us required to be included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. There has been no change in our internal controls over financial reporting during the three months ended March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


Item 1.	*Legal Proceedings*

The information required for this item is provided in Note 9, Commitments and Contingencies, under the heading “Litigation” included in the notes to the consolidated financial statements included under Part I, Item 1, which is incorporated by reference into this item.


Item 1A.	*Risk Factors*

For an in-depth discussion of our risk factors, please see “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. There have been no material changes to the risk factors included in “Item 1A” of our Annual Report on Form 10-K for the year ended December 31, 2007.


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

Not applicable.


Item 3.	*Defaults Upon Senior Securities*

Not applicable.


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

Not applicable.


Item 5.	*Other Information*

Amendment to Partnership Agreement

On May 13, 2008, the Partnership amended its First Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) to modify the mechanism by which the capital accounts of all partners are maintained when the general partner’s incentive distribution rights are valued when calculating the enterprise value of the Partnership in the event of a follow-on offering of common units. The amendment is effective as of January 1, 2008. Amendment No. 1 to the Partnership Agreement is filed as Exhibit 3.5 to this quarterly report.


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/A 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.
	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)).
	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

SIGNATURES

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

Targa Resources Partners LP

(Registrant)

By: Targa Resources GP LLC,
its general partner


	By:	/s/ John Robert Sparger

John Robert Sparger

Senior Vice President and Chief Accounting Officer

(Authorized signatory and Principal Accounting Officer)

Date: May 14, 2008

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/A 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.
	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)).
	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

exv3w5

Exhibit 3.5

AMENDMENT NO. 1 TO

FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

TARGA RESOURCES PARTNERS LP

This Amendment No. 1 (this “Amendment No. 1”) to the First Amended and Restated Agreement of Limited Partnership (as amended, the “Partnership Agreement”) of Targa Resources Partners LP (the “Partnership”) is hereby adopted by Targa Resources GP LLC, a Delaware limited liability company (the “General Partner”), as general partner of the Partnership. Capitalized terms used but not defined herein are used as defined in the Partnership Agreement.

WHEREAS, the General Partner desires to amend the Partnership Agreement to make certain adjustments to certain allocation provisions and the definitions related thereto, which adjustments shall be effective in accordance with Section 761(c) of the Code as of January 1, 2008; and

WHEREAS, acting pursuant to the power and authority granted to it under Section 13.1(d) of the Partnership Agreement, the General Partner has determined that the following amendment to the Partnership Agreement does not require the approval of any Limited Partner.

NOW THEREFORE, the General Partner does hereby amend the Partnership Agreement as follows:

Section 1. Amendment.

(a) Section 1.1 is hereby amended to add or amend and restate the following definitions:

(i) “Disposed of Adjusted Property” has the meaning assigned to such term in Section 6.1(d)(xii)(B).

(ii) “Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Partnership (a) after the Liquidation Date or (b) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group). The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

(iii) “Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the

- 1 -

Partnership (a) after the Liquidation Date or (b) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group). The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.5(b) and shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

(b) Section 5.5(d) is hereby amended and restated in its entirety as follows:

(i) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the General Partner’s Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Accounts of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1(c) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1(c) in the same manner as any item of gain or loss actually recognized following an event giving rise to the dissolution of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents)

- 2 -

immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Corrective and Other Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) Except as provided in Section 6.1(d)(xii)(B), in the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof) with respect to any Partnership property, the General Partner shall allocate such Additional Book Basis Derivative Items (1) to (aa) the holders of Incentive Distribution Rights and (bb) the General Partner in the same manner that the Unrealized Gain or Unrealized Loss attributable to such property is allocated pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii) and (2) to all Unitholders, Pro Rata, to the extent that the Unrealized Gain or Unrealized Loss attributable to such property is allocated to any Unitholders pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii).

(B) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof or an allocation of Net Termination Gain or Net Termination Loss pursuant to Section 6.1(c) hereof) as a result of a sale or other taxable disposition of any Partnership asset that is an Adjusted Property (“Disposed of Adjusted Property”), the General Partner shall allocate (1) additional items of income and gain (aa) away from the holders of Incentive Distribution Rights and the General Partner and (bb) to the Unitholders, or (2) additional items of deduction and loss (aa) away from the Unitholders and (bb) to the holders of Incentive Distribution Rights and the General Partner, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. For this purpose, the Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under this Agreement (e.g., Additional Book Basis Derivative Items taken into account in computing cost of goods sold would reduce the amount of book income otherwise available for allocation among the Partners). Any allocation made pursuant to this

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Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(C) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(D) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii).

Section 2. General Authority. The appropriate officers of the General Partner are hereby authorized to make such further clarifying and conforming changes to the Partnership Agreement as they deem necessary or appropriate, and to interpret the Partnership Agreement, to give effect to the intent and purpose of this Amendment No. 1.

Section 3. Ratification of Partnership Agreement. Except as expressly modified and amended herein, all of the terms and conditions of the Partnership Agreement shall remain in full force and effect.

Section 4. Governing Law. This Amendment No. 1 will be governed by and construed in accordance with the laws of the State of Delaware.

IN WITNESS WHEREOF, the General Partner has executed this Amendment No. 1 as of May 13, 2008.


		GENERAL PARTNER:

		TARGA RESOURCES GP LLC

		By:		/s/ Rene R. Joyce

		Name:		Rene R. Joyce
		Title:		Chief Executive Officer

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exv31w1

Exhibit 31.1

Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002

I, Rene R. Joyce, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended March 31, 2008 of Targa Resources Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-(f))for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	By:	/s/ Rene R. Joyce

Name: Rene R. Joyce


	Title:	Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

Date: May 14, 2008

exv31w2

Exhibit 31.2

Certification Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002

I, Jeffrey J. McParland, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended March 31, 2008 of Targa Resources Partners LP;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


	By:	/s/ Jeffrey J. McParland

Name: Jeffrey J. McParland


	Title:	Executive Vice President and Chief Financial Officer

of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Financial Officer)

Date: May 14, 2008

exv32w1

Exhibit 32.1

CERTIFICATION OF CEO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2008 of Targa Resources Partners LP (the “Partnership”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Rene R. Joyce, as Chief Executive Officer of Targa Resources GP LLC., hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.


	By:	/s/ Rene R. Joyce

Name: Rene R. Joyce


	Title:	Chief Executive Officer of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Executive Officer)

Date: May 14, 2008

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

exv32w2

Exhibit 32.2

CERTIFICATION OF CFO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended March 31, 2008 of Targa Resources Partners LP (the “Partnership”) as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Jeffrey J. McParland, as Chief Financial Officer of Targa Resources GP LLC, hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.


	By:	/s/ Jeffrey J. McParland

Name: Jeffrey J. McParland


	Title:	Executive Vice President and Chief Financial Officer

of Targa Resources GP LLC,

the general partner of Targa Resources Partners LP

(Principal Financial Officer)

Date: May 14, 2008

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