Targa Resources Partners (NGLS-PA) 8-K Financial Statements and Exhibits

Exhibit 99.3

Supplemental Consolidated Financial Statements of Targa Resources Partners LP

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Targa Resources GP LLC, the general partner of the Partnership, is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed 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.

Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

The management of Targa Resources GP LLC has used the framework set forth in the report entitled “Internal Control — Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) to evaluate the effectiveness of the Partnership’s internal control over financial reporting. Based on that evaluation, management has concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2008.

The effectiveness of the Partnerships’ internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on Page 2.

/s/  Rene R. Joyce

Rene R. Joyce

Chief Executive Officer of Targa Resources

GP LLC, the general partner of Targa Resources

Partners LP (Principal Executive Officer)

/s/  Jeffrey J. McParland

Jeffrey J. McParland

Executive Vice President, Chief Financial Officer

of Targa Resources GP LLC, the general partner of

Targa Resources Partners LP

(Principal Financial Officer)

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Report of Independent Registered Public Accounting Firm

Tothe Partners of Targa Resources Partners LP:

In our opinion, theaccompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in partners' capital/net parent investment and of cash flows present fairly, in all material respects, the financial position of Targa Resources Partners LP and its subsidiaries (the "Partnership") at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included inthe accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which was an integrated audit in 2008). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 14 to the consolidated financial statements, the Partnership has engaged in significant transactions with other subsidiaries of its parent company, Targa Resources, Inc., a related party.

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 25, 2009, except with respect to our opinions on the consolidated financial statements and internal control over financial reporting insofar as they relate to the effects of the acquisition of the Downstream Business discussed in Note 2, as to which the date is November 30, 2009

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TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS
	December 31,
	2008			2007
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	95,308		$	64,342
Trade receivables, net of allowances of $2,207 and $943		236,137			733,968
Inventory		72,183			147,591
Assets from risk management activities		91,816			8,695
Other current assets		782			683
Total current assets		496,226			955,279
Property, plant and equipment, at cost		2,036,378			1,936,158
Accumulated depreciation		(317,322	)		(219,737	)
Property, plant and equipment, net		1,719,056			1,716,421
Long-term assets from risk management activities		68,296			3,040
Investment in unconsolidated affiliate		18,465			19,238
Other long-term assets		12,776			8,876
Total assets	$	2,314,819		$	2,702,854
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable to third parties	$	138,745		$	435,118
Accounts payable to affiliates		17,227			65,598
Accrued liabilities		104,112			155,697
Liabilities from risk management activities		11,664			44,003
Total current liabilities		271,748			700,416
Long-term debt payable to third parties		696,845			626,300
Long-term debt payable to Targa Resources, Inc.		773,883			711,267
Long-term liabilities from risk management activities		9,679			43,109
Deferred income taxes		3,337			1,529
Other long-term liabilities		6,239			5,861
Commitments and contingencies (see Note 15)
Owners' equity:
Common unitholders (34,652,000 and 34,636,000 units issued and
outstanding as of December 31, 2008 and 2007)		769,921			770,207
Subordinated unitholders (11,528,231 units issued and outstanding as of
as of December 31, 2008 and 2007)		(85,185	)		(84,999	)
General partner (942,455 and 942,128 units issued and outstanding
as of December 31, 2008 and 2007)		5,556			4,234
Net parent investment		(223,534	)		(15,338	)
Accumulated other comprehensive income (loss)		72,238			(73,250	)
		538,996			600,854
Noncontrolling interest in subsidiary		14,092			13,518
Total owners' equity		553,088			614,372
Total liabilities and owners' equity	$	2,314,819		$	2,702,854
See notes to supplemental consolidated financial statements

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TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF OPERATIONS
	Year Ended December 31,
	2008			2007			2006
	(In thousands, except per unit data)
Revenues from third parties	$	6,983,624		$	6,398,721		$	5,578,236
Revenues from affiliates		489,773			417,425			329,253
Total operating revenues		7,473,397			6,816,146			5,907,489
Costs and expenses:
Product purchases from third parties		5,824,433			5,321,627			4,550,470
Product purchases from affiliates		1,097,640			952,774			928,403
Operating expenses from third parties		195,190			175,129			154,492
Operating expenses from affiliates		58,846			44,530			38,603
Depreciation and amortization expenses		97,837			93,520			90,744
General and administrative expenses		68,641			63,986			57,259
Other		(966	)		(296	)		34
		7,341,621			6,651,270			5,820,005
Income from operations		131,776			164,876			87,484
Other income (expense):
Interest expense from affiliate		(59,255	)		(58,526	)		-
Interest expense allocated from Parent		-			(19,436	)		(127,288	)
Other interest income (expense), net		(37,757	)		(21,392	)		227
Equity in earnings of unconsolidated investment		3,877			3,511			2,754
Gain on debt repurchases		13,061			-			-
Gain (loss) on mark-to-market derivative instruments		(991	)		(30,221	)		16,756
Other		1,378			(1,101	)		(155	)
Income (loss) before income taxes		52,089			37,711			(20,222	)
Income tax expense:
Current		(582	)		(574	)		-
Deferred		(1,808	)		(1,945	)		(3,430	)
		(2,390	)		(2,519	)		(3,430	)
Net income (loss)		49,699			35,192			(23,652	)
Less: Net income attributable to noncontrolling interest		274			112			(630	)
Net income attributable to Targa Resources Partners LP	$	49,425		$	35,080		$	(23,022	)
Net income (loss) attributable to predecessor operations	$	(42,069	)	$	7,014
Net income attributable to general partner		7,049			561
Net income allocable to limited partners		84,445			27,505
Basic and diluted net income per limited partner unit	$	1.83		$	0.81
Basic and diluted weighted average limited partner units outstanding		46,177			34,002
See notes to supplemental consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Net income (loss)	$	49,699		$	35,192		$	(23,652	)
Other comprehensive income (loss):
Commodity hedges:
Change in fair value		130,002			(105,584	)		36,937
Reclassification adjustment for settled periods		33,650			993			(822	)
Related income taxes		-			312			(312	)
Interest rate hedges:
Change in fair value		(19,037	)		(1,689	)		1,838
Reclassification adjustment for settled periods		2,693			(232	)		(708	)
Foreign currency translation adjustment		(1,820	)		1,925			59
Other comprehensive income (loss)		145,488			(104,275	)		36,992
Comprehensive income (loss)		195,187			(69,083	)		13,340
Less: Comprehensive income attributable to
noncontrolling interest		274			112			(630	)
Comprehensive income (loss) attributable to
Targa Resources Partners LP	$	194,913		$	(69,195	)	$	13,970
See notes to supplemental consolidated financial statements

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TARGA RESOURCES PARTNERS LP
SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS
	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Cash flows from operating activities
Net income (loss)	$	49,699		$	35,192		$	(23,652	)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Amortization in interest expense		2,116			1,805			9,095
Amortization in general and administrative expense		280			180			-
Interest expense on affiliate indebtedness		59,255			58,526			-
Depreciation and other amortization expense		97,837			93,520			90,744
Accretion of asset retirement obligations		312			413			311
Deferred income tax expense		1,808			1,945			3,430
Equity in earnings of unconsolidated investments, net
of distributions		773			364			(448	)
Risk management activities		(63,973	)		30,751			(18,297	)
Gain on debt repurchases		(13,061	)		-			-
Gain on sale of assets		(5,917	)		(296	)		34
Changes in operating assets and liabilities:
Receivables and other assets		582,753			(117,096	)		35,073
Inventory		75,408			(28,630	)		35,977
Accounts payable and other liabilities		(494,300	)		191,578			37,594
Net cash provided by operating activities		292,990			268,252			169,861
Cash flows from investing activities
Additions to property, plant and equipment		(86,279	)		(77,545	)		(54,405	)
Other, net		180			787			(156	)
Net cash used in investing activities		(86,099	)		(76,758	)		(54,561	)
Cash flows from financing activities
Proceeds from borrowings under credit facility		185,265			721,300			-
Repayments of credit facility		(323,800	)		(95,000	)		-
Proceeds from issuance of senior notes		250,000			-			-
Repurchases of senior notes		(26,832	)		-			-
Repayment of affiliated indebtedness		-			(665,692	)		-
Proceeds from equity offerings		-			777,471			-
Distributions to unitholders		(90,932	)		(31,221	)		-
General partner contributions		8			-			-
Costs incurred in connection with public offerings		(89	)		(4,640	)		-
Costs incurred in connection with financing arrangements		(7,079	)		(7,491	)		-
Parent distributions		(166,127	)		(847,468	)		(110,690	)
Loan from Parent		3,361			13,024			-
Contribution from noncontrolling interest		300			-			-
Net cash used in financing activities		(175,925	)		(139,717	)		(110,690	)
Net change in cash and cash equivalents		30,966			51,777			4,610
Cash and cash equivalents, beginning of year		64,342			12,565			7,955
Cash and cash equivalents, end of year	$	95,308		$	64,342		$	12,565
See notes to supplemental consolidated financial statements

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TARGA RESOURCES PARTNERS LP
CONSOLIDATED STATEMENT OF CHANGES IN OWNERS' EQUITY
										Accumulated
										Other
	Limited Partners						General			Comprehensive			Net Parent			Noncontrolling
	Common			Subordinated			Partner			Income (Loss)			Investment			Interest			Total
	(In thousands)
Balance, December 31, 2005	$	-		$	-		$	-		$	(5,654	)	$	586,823		$	14,036		$	595,205
Distributions to Parent		-			-			-			-			(214,596	)		-			(214,596	)
Net loss		-			-			-			-			(23,022	)		(630	)		(23,652	)
Other comprehensive income		-			-			-			36,992			-			-			36,992
Balance, December 31, 2006		-			-			-			31,338			349,205			13,406			393,949
Contribution from Parent, net		-			-			-			(313	)		270,529			-			270,216
Book value of net assets transferred under common control		-			(83,715	)		(4,101	)		-			(642,086	)		-			(729,902	)
Issuance of units to public (including underwriter
over-allotment), net of offering and other costs		771,835			-			8,398			-			-			-			780,233
Amortization of equity awards		180			-			-			-			-			-			180
Distributions to unitholders		(20,871	)		(9,726	)		(624	)		-			-			-			(31,221	)
Net income		19,063			8,442			561			-			7,014			112			35,192
Other comprehensive loss		-			-			-			(104,275	)		-			-			(104,275	)
Balance, December 31, 2007		770,207			(84,999	)		4,234			(73,250	)		(15,338	)		13,518			614,372
Contributions		-			-			8			-			-			-			8
Amortization of equity awards		280			-			-			-			-			-			280
Distributions to unitholders		(63,928	)		(21,269	)		(5,735	)		-			-			-			(90,932	)
Distribution to Parent		-			-			-			-			(166,127	)		-			(166,127	)
Contribution from noncontrolling interest		-			-			-			-			-			300			300
Net income (loss)		63,362			21,083			7,049			-			(42,069	)		274			49,699
Other comprehensive income		-			-			-			145,488			-			-			145,488
Balance, December 31, 2008	$	769,921		$	(85,185	)	$	5,556		$	72,238		$	(223,534	)	$	14,092		$	553,088
See notes to supplemental consolidated financial statements

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TARGA RESOURCES PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1—Organization and Operations

Targa Resources Partners LP, together with its subsidiaries, is a publicly traded Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa” or “Parent”). In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. References to “TRP LP” are intended to mean and include Targa Resources Partners LP, individually, and not on a consolidated basis. Our common units are listed on The NASDAQ Stock Market LLC under the symbol “NGLS.” Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids (“NGLs”). See Note 18.

Targa Resources GP LLC is a Delaware single-member limited liability company, formed in October 2006 to own a 2% general partner interest in us. Its primary business purpose is to manage our affairs and operations. Targa Resources GP LLC is an indirect wholly-owned subsidiary of Targa.

On February 14, 2007, we completed an initial public offering (“IPO”) of common units representing limited partner interests in the Partnership. Concurrent with the IPO, Targa conveyed its ownership interests in Targa North Texas GP LLC and Targa North Texas LP (collectively, the “North Texas System”) to us.

On October 24, 2007, Targa conveyed its ownership interests in Targa Texas Field Services LP (the “SAOU System”) and Targa Louisiana Field Services LLC (the “LOU System”) to us. This conveyance consisted of the SAOU System’s natural gas gathering and processing businesses and the LOU System’s natural gas gathering and processing businesses.

On September  24, 2009, we acquired Targa’s interests in Targa Downstream LP, Targa LSNG LP, Targa Downstream GP LLC and Targa LSNG GP LLC (collectively, the “Downstream Business”) in a transaction among entities under common control. See Note 4.

Note 2—Basis of Presentation

The supplemental consolidated financial statements include our accounts and: (i) prior to September 24, 2009 the assets, liabilities and operations of the Downstream Business; (ii) prior to October 24, 2007 the assets, liabilities and operations of the SAOU and LOU Systems as the predecessor entities; and (iii) prior to February 14, 2007 the assets, liabilities and operations of the North Texas System.

Targa’s conveyances to us of the North Texas System, the SAOU and LOU Systems and the Downstream Business have been accounted for as transfers of net assets between entities under common control. We recognize transfers of net assets between entities under common control at Targa’s historical basis in the net assets conveyed. In addition, transfers of net assets between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retroactively adjusted to furnish comparative information similar to the pooling of interests method. The amount of the purchase price in excess of Targa’s basis in the net assets, if any, is recognized as a reduction to net parent investment.

Our supplemental consolidated financial statements and all other financial information included in this report have been retrospectively adjusted to assume that the acquisition of the Downstream Business from Targa by us had occurred at the date when both the Downstream Business and the North Texas System met the accounting requirements for entities under common control (October31, 2005) following the acquisition of the SAOU and LOU Systems. As a result, supplemental financial statements and financial information presented for prior periods in this report have been retrospectively adjusted.

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The retrospective adjustment resulted in all the footnotes and other financial information being updated to reflect the acquisition, including: significant accounting policies (Note 3), conveyance of Downstream Business (Note 4), investment in unconsolidated affiliate (Note 7), debt obligations (Note 9), insurance claims (Note 11), segment information (Note 18), other operating income (Note 19) and supplemental cash flow information (Note 20).

The supplemental consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We refer to the operations, assets and liabilities of the North Texas System, the SAOU and LOU Systems, and the Downstream Business, prior to our acquisition from Targa, collectively as our “predecessors.” The consolidated financial statements of our predecessors have been prepared from the separate records maintained by Targa and may not necessarily be indicative of the conditions that would have existed or the results of operations if our predecessors had been operated as unaffiliated entities. All significant intercompany balances and transactions have been eliminated. Transactions between us and other Targa operations have been identified in the consolidated financial statements as transactions between affiliates.

We have been allocated general and administrative expenses incurred by our Parent in order to present financial statements on a stand-alone basis. See Note 14. All of the allocations are not necessarily indicative of the costs and expenses that would have resulted had we been operated as stand-alone entities.

Note 3—Significant Accounting Policies

Asset retirement obligations (“AROs”). AROs are legal obligations associated with the retirement of tangible long-lived assets that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. The consolidated cost of the asset and the capitalized asset retirement obligation is depreciated using a systematic and rational allocation method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present values of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Upon settlement, AROs will be extinguished by us at either the recorded amount or we will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost.  See Note 8.

Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. See discussion of centralized cash management in Note 14.

Comprehensive Income. Comprehensive income includes net income and other comprehensive income, which includes unrealized gains and losses on derivative instruments that are designated as hedges and currency translation adjustments.

Concentration of Credit Risk. Financial instruments which potentially subject us to concentrations of credit risk consist primarily of trade accounts receivable and commodity derivative instruments.

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

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability to make required payments,

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economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.

The following table presents the activity of our allowance for doubtful accounts for the periods indicated:

	Year Ended December 31,
	2008		2007			2006
Balance at beginning of year	$	943	$	781		$	775
Additions		1,264		242			746
Deductions		-		(80	)		(740	)
Balance at end of year	$	2,207	$	943		$	781

Significant Commercial Relationships. The following table lists the percentage of our combined sales and purchases with Chevron (including the Chevron Phillips Chemical Company LLC joint venture), which accounted for more than 10% of our combined revenues and combined product purchases for the years indicated:

	Year Ended December 31,
	2008			2007			2006
% of revenues		22	%		24	%		29	%
% of product purchases		8	%		11	%		18	%

Commodity Derivative Instruments. As of December 31, 2008, affiliates of Goldman Sachs, Bank of America (“BofA”) and Barclays Bank accounted for 67%, 21% and 11% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, BofA and Barclays Bank are major financial institutions, each possessing investment grade credit ratings, based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.  See Note 13.

Consolidation Policy. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities after the elimination of all material intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling interest.

We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on our equity method investees’ balance sheet in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and charged to interest expense over the term of the related debt.

Environmental Liabilities. Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. See Note 15.

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

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

Income Taxes. We are not subject to federal income taxes. As a result, our earnings or losses for federal income tax purposes are included in the tax returns of our individual partners. In May 2006, Texas adopted a margin tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold, as apportioned to Texas. Accordingly, we have estimated our liability for this tax and it is presently recorded as a deferred tax liability.

We have determined that there are no significant uncertain tax positions requiring recognition in our financial statements as of December 31, 2008. There are no unrecognized tax benefits that, if recognized, would affect the effective rate, and there are no unrecognized tax benefits that are reasonably expected to increase or decrease in the next twelve months. We file tax returns in the United States Federal and several state jurisdictions, and are open to federal and state income tax examinations for years 2007 forward. Presently, no income tax examinations are underway, and none have been announced. No potential interest or penalties were recognized as of December 31, 2008.

Inventory Imbalance. Quantities of natural gas and/or NGLs over-delivered or under-delivered related to operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices as of the time the imbalance was created. Monthly, inventory imbalances receivable are valued at the lower of cost or market; inventory imbalances payable are valued at replacement cost. These imbalances are typically settled in the following month with deliveries of natural gas or NGLs. Certain contracts require cash settlement of imbalances on a current basis. Under these contracts, imbalance cash-outs are recorded as a sale or purchase of natural gas, as appropriate.

Net Income per Limited Partner Unit. Our net income is allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the general partner. Basic and diluted net income per limited partner unit is calculated by dividing limited partners’ interest in net income by the weighted average number of outstanding limited partner units during the period.

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

We compute earnings per unit using the Two-Class Method. The Two-Class Method requires that securities that meet the definition of a participating security 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.

The Two-Class Method does not impact our overall net income or other financial results; however, in periods in which aggregate net income exceeds our aggregate distributions for such period, 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,

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is allocated to the incentive distribution rights of 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 our aggregate distributions for such period, the Two-Class Method does not have any impact on our calculation of earnings per limited partner unit.

The calculation of net income per limited unit for 2006 is not presented as we did not have any outstanding units until we completed our IPO on February 14, 2007. The calculation of basic and diluted net income per common and subordinated unit are the same for all periods presented as distributable cash flow was greater than net income for those periods and distributions to the subordinated unitholders have been equivalent to the distribution to the common unitholders for all quarters.

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

Price Risk Management (Hedging). All derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (“OCI”), a component of net parent investment, and reclassified to earnings when the forecasted transaction occurs. 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.

Our policy is to formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Hedge ineffectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument is terminated or ceases to be highly effective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately. See Notes 13, 14 and 17.

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

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

Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset.

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Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. From time to time, we utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

We may capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is charged to operations.

We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses and the market and business environments to identify indicators that may suggest an asset may not be recoverable.

We evaluate an asset for recoverability by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our supplemental consolidated statements of operations.

Revenue Recognition. Our primary types of sales and service activities reported as operating revenues include:

·      sales of natural gas, NGLs and condensate; and

· natural gas processing, from which we generate revenues through the compression, gathering, treating, and processing of natural gas.

We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured.

For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under percent-of-proceeds contracts, we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index related prices for the natural gas and NGLs. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. Under fee-based contracts, we receive a fee based on throughput volumes.

We generally report revenues gross in our supplemental consolidated statements of operations. Except for fee-based contracts, we act as the principal in the transactions where we receive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership.

Unit-Based Employee Compensation. We award share-based compensation to directors in the form of restricted common units. Compensation expense on restricted common units is measured by the fair value of the award at the date of grant. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. See Note 12.

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Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the supplemental financial statements and the reported amounts of revenues and expenses during the period. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the useful lives of assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from estimated amounts.

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. In February 2008, the FASB issued FASB Staff Position FAS 157-2, “Effective Date of FASB Statement No. 157,” which delayed the effective date of SFAS 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, until January 1, 2009.

We do not anticipate SFAS 157 to significantly impact our supplemental consolidated financial statements. 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 our supplemental financial condition, results of operations, or cash flows, we are now required to provide additional disclosures as part of our supplemental financial statements. See Note 17.

In December 2007, the FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51.” SFAS 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for fiscal periods and interim periods within those fiscal years, beginning on or after December 15, 2008 with retroactive presentation of all years presented. These supplemental financial statements incorporate the retrospective disclosure provisions of SFAS 160.

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, “Accounting for Derivative Instruments and Hedging Activities” 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 as of December 31, 2008 did not impact our supplemental consolidated financial position, results of operations or cash flows. See Note 13.

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

Accounting Pronouncements Recently Issued

In December 2007, FASB issued SFAS 141R, “Business Combinations.” (“SFAS 141R”). SFAS 141R requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the

14

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

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 to Master Limited Partnerships.”  EITF 07-4 provides guidance as to how a master limited partnership (“MLP”) should allocate and present earnings per unit using the two-class method set forth in SFAS 128, “Earnings Per Share” when the MLP’s partnership agreement contains incentive distribution rights.  Under the two-class method, current period earnings are allocated to the partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. Our adoption of EITF 07-4 is not expected to impact our supplemental consolidated financial position, results of operations or cash flows. However, it could potentially reduce our computation of earnings per common and subordinated unit.

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

On April 9, 2009, FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP requires disclosures of fair value for any financial instruments not currently reflected at fair value on the balance sheet for all interim periods. This FSP is effective for interim and annual periods ending after June 15, 2009 and should be applied prospectively. We do not expect any material supplemental financial statement implications relating to the adoption of FSP 107-1.

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

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

Following SFAS 168, FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”). FASB will not consider ASUs as authoritative in their own right. They will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.

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In 2009, FASB has issued ASUs 2009-01 through 2009-11, which either are technical corrections of the Codification and/or do not apply to us.

Note 4—Acquisition of Downstream Business

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

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

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

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

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

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

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The following table presents the impact on our supplemental consolidated financial position at December 31, 2008 and 2007, adjusted for the acquisition of the Downstream Business from Targa.

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

	December 31, 2007
	Historical
	Targa								Targa
	Resources		Downstream						Resources
	Partners LP		Business			Adjustments			Partners LP
Current assets	$	208,475	$	834,351		$	(87,547	)	$	955,279
Property, plant and equipment, net		1,259,594		456,827			-			1,716,421
Other assets		11,903		19,251			-			31,154
Total assets	$	1,479,972	$	1,310,429		$	(87,547	)	$	2,702,854
Current liabilities	$	192,532	$	595,431		$	(87,547	)	$	700,416
Long-term debt		626,300		711,267			-			1,337,567
Other long-term liabilities		46,934		3,565			-			50,499
Owners of Targa Resources Partners LP		614,206		1,986			-			616,192
Net parent investment		-		(15,338	)		-			(15,338	)
Noncontrolling interest in subsidiary		-		13,518			-			13,518
Total owners' equity		614,206		166			-			614,372
Total liabilities and owners' equity	$	1,479,972	$	1,310,429		$	(87,547	)	$	2,702,854

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

	Year Ended December 31, 2008
	Historical
	Targa									Targa
	Resources			Downstream						Resources
	Partners LP			Business			Adjustments			Partners LP
Revenues	$	2,074,118		$	6,172,679		$	(773,400	)	$	7,473,397
Costs and expenses:
Product purchases		1,803,031			5,892,376			(773,334	)		6,922,073
Operating expenses		55,325			198,777			(66	)		254,036
Depreciation and amortization expense		74,274			23,563			-			97,837
General and administrative expense and other		22,454			45,221			-			67,675
		1,955,084			6,159,937			(773,400	)		7,341,621
Income from operations		119,034			12,742			-			131,776
Other income (expense):
Interest expense		(38,274	)		(58,738	)		-			(97,012	)
Other income		12,134			5,191			-			17,325
Income tax expense		(1,400	)		(990	)		-			(2,390	)
Net income (loss)		91,494			(41,795	)		-			49,699
Less: Net income attributable to noncontrolling interest		-			274			-			274
Net income attributable to Targa Resources Partners LP	$	91,494		$	(42,069	)	$	-		$	49,425
Net loss attributable to predecessor operations	$	-		$	(42,069	)	$	-		$	(42,069	)
Net income allocable to partners		91,494			-			-			91,494

	Year Ended December 31, 2007
	Historical
	Targa									Targa
	Resources			Downstream						Resources
	Partners LP			Business			Adjustments			Partners LP
Revenues	$	1,661,469		$	5,767,948		$	(613,271	)	$	6,816,146
Costs and expenses:
Product purchases		1,406,797			5,480,841			(613,237	)		6,274,401
Operating expenses		50,931			168,762			(34	)		219,659
Depreciation and amortization expense		71,756			21,764			-			93,520
General and administrative expense and other		18,631			45,059			-			63,690
		1,548,115			5,716,426			(613,271	)		6,651,270
Income from operations		113,354			51,522			-			164,876
Other income (expense):
Interest expense		(41,434	)		(57,920	)		-			(99,354	)
Other income (expense)		(30,191	)		2,380			-			(27,811	)
Income tax expense		(1,479	)		(1,040	)		-			(2,519	)
Net income (loss)		40,250			(5,058	)		-			35,192
Less: Net income attributable to noncontrolling interest		-			112			-			112
Net income attributable to Targa Resources Partners LP	$	40,250		$	(5,170	)	$	-		$	35,080
Net income (loss) attributable to predecessor operations	$	12,184		$	(5,170	)	$	-		$	7,014
Net income allocable to partners		28,066			-			-			28,066

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	Year Ended December 31, 2006
	Historical
	Targa									Targa
	Resources			Downstream						Resources
	Partners LP			Business			Adjustments			Partners LP
Revenues	$	1,738,525		$	4,632,596		$	(463,632	)	$	5,907,489
Costs and expenses:
Product purchases		1,517,668			4,424,795			(463,590	)		5,478,873
Operating expenses		49,075			144,062			(42	)		193,095
Depreciation and amortization expense		69,957			20,787			-			90,744
General and administrative expense and other		16,063			41,230			-			57,293
		1,652,763			4,630,874			(463,632	)		5,820,005
Income from operations		85,762			1,722			-			87,484
Other income (expense):
Interest expense		(88,025	)		(39,036	)		-			(127,061	)
Other income		16,756			2,599			-			19,355
Income tax expense		(2,926	)		(504	)		-			(3,430	)
Net income (loss)		11,567			(35,219	)		-			(23,652	)
Less: Net loss attributable to noncontrolling interest		-			(630	)		-			(630	)
Net income attributable to Targa Resources Partners LP	$	11,567		$	(34,589	)	$	-		$	(23,022	)

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Note 5—Inventory

Our product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is held during the year to meet anticipated heating season requirements of our customers. Product inventories are valued at the lower of cost or market using the average cost method.

Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases within operating costs and expenses in the period they are recognized, with the related cash impact in the subsequent period. For 2008, 2007 and 2006 we recognized $6.0 million, $0.2 million and $13.1 million to reduce the carrying value of NGL inventory to its net realizable value.

As of December 31, 2008 and 2007, inventory consisted primarily of NGL products of $71.2 million and $147.6 million.

Note 6—Property, Plant and Equipment

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

	December 31,
	2008			2007
Gathering systems	$	1,187,139		$	1,150,971
Processing and fractionation facilities		374,011			360,847
Terminalling and natural gas liquids storage facilities		221,883			213,261
Transportation assets		144,466			135,599
Other property, plant and equipment		14,910			12,100
Land		49,770			49,770
Construction in progress		44,199			13,610
		2,036,378			1,936,158
Accumulated depreciation		(317,322	)		(219,737	)
	$	1,719,056		$	1,716,421

Note 7—Investment in Unconsolidated Affiliate

As of December 31, 2008 and 2007, our unconsolidated investment consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast.

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

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

	Year Ended December 31,
	2008		2007		2006
Equity in earnings	$	3,877	$	3,511	$	2,754
Cash distributions		4,650		3,875		2,306

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Note 8—Asset Retirement Obligations

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

	Year Ended December 31,
	2008			2007		2006
Beginning of period	$	5,857		$	5,412	$	3,040
Liabilities settled		(229	)		-		-
Allocated from Parent		-			-		2,062
Change in cash flow estimate		266			32		(1	)
Accretion expense		312			413		311
End of period	$	6,206		$	5,857	$	5,412

Our asset retirement obligations are included in our supplemental consolidated balance sheets as a component of other long-term liabilities.

Note 9—Debt Obligations

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

	December 31,
	2008		2007
Targa Resources Partners LP:
Senior unsecured notes, 8¼% fixed rate, due July 2016	$	209,080	$	-
Senior secured revolving credit facility, variable rate, due February 2012		487,765		626,300
Targa Downstream LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including
accrued interest of $175,343 and $118,475)		744,020		687,152
Targa LSNG LP:
Note payable to Parent, 10% fixed rate, due December 2011 (including
accrued interest of $4,281 and $1,894)		29,863		24,115
	$	1,470,728	$	1,337,567
Letters of credit issued	$	9,651	$	25,900

On October 16, 2008, we requested a $100 million funding under our credit facility. Lehman Brothers Commercial Bank, a lender under our credit facility, defaulted on its portion of the borrowing request resulting in an actual funding of $97.8 million. As a result of the default, we believe the availability under the credit facility has been effectively reduced by approximately $10.0 million.

Repurchases of Senior Unsecured Notes

During November and December 2008, we repurchased $40.9 million face amount of our outstanding Senior Unsecured Notes in open market transactions at an aggregate purchase price of $28.3 million, including $1.5 million of accrued interest. We recognized a gain of $13.1 million from these transactions. The repurchased Senior Unsecured Notes were retired and are not eligible for re-issue at a later date.

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Information Regarding Variable Interest Rates Paid

The following table shows the range of interest rates paid and weighted average interest rate paid on our variable-rate debt obligations during 2008:

	Range of interest rates paid	Weighted average interest rate paid
Credit facility	1.5% to 6.4%		4.4	%

Affiliated Indebtedness

On January 1, 2007, Targa contributed to us affiliated indebtedness related to the North Texas System of approximately $904.5 million (including accrued interest of $88.3 million computed at 10% per annum). We recorded approximately $9.8 million in interest expense associated with this affiliated debt for the period from January 1, 2007 through February 13, 2007. On February 14, 2007, Targa contributed its interest in Targa North Texas GP LLC and Targa North Texas LP to us.

On January 1, 2007, Targa contributed to us affiliated indebtedness related to the assets of the Downstream Business of approximately $639.7 million (including accrued interest of $61.8 million). During the years ended December 31, 2008 and 2007, additional affiliated indebtedness of $3.4 million and $13.0 million was incurred to fund the construction of its Mont Belvieu, Texas isomerization unit. During 2008 and 2007, we recorded $59.3 million and $58.5 million in interest expense associated with this affiliated debt.

The stated 10% interest rate in the formal debt arrangement was not indicative of prevailing external rates of interest including that incurred under our credit facility which is secured by substantially all of our assets. On a pro forma basis, at prevailing interest rates the affiliated interest expense for the period from January 1, 2007 to February 13, 2007 related to the North Texas System would have been reduced by $3.0 million. The pro forma interest expense adjustment has been calculated by applying the weighted average rate of 6.9% that we incurred under our credit facility to the affiliate debt balance for the period from January 1, 2007 to February 13, 2007. On a pro forma basis, at prevailing interest rates the affiliated interest expense for the years ended December 31, 2008 and 2007 related to the Downstream business would have been reduced by $15.9 million and $10.2 million. The pro forma interest expense adjustment has been calculated by applying the weighted average rates of 7.3% and 8.3% that Targa incurred under its credit facility to the affiliate debt balance for the periods indicated.

Allocated Indebtedness

On October 24, 2007, we completed the acquisition of the SAOU and LOU Systems from Targa. As part of the acquisition of the SAOU and LOU Systems, the allocated indebtedness was settled with Targa through an adjustment to parent equity and the collateralization of the assets was released.

Credit Agreement

On February 14, 2007, we entered into a credit agreement which provided for a five-year $500 million credit facility with a syndicate of financial institutions. The credit facility bears interest at our option, at the higher of the lender’s prime rate or the federal funds rate plus 0.5%, plus an applicable margin ranging from 0% to 1.25% dependent on our total leverage ratio, or LIBOR plus an applicable margin ranging from 1.0% to 2.25% dependent on our total leverage ratio. We initially borrowed $342.5 million under our credit facility, and concurrently repaid $48.0 million under our credit facility with the proceeds from the 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units. The net proceeds of $294.5 million from this borrowing, together with approximately $371.2 million of available cash from the IPO (after payment of offering and debt issue costs and necessary operating cash reserve balances), were used to repay approximately $665.7 million of affiliate indebtedness. In connection with our IPO, the guarantee of indebtedness from the entity holding the North Texas System was terminated, the related collateral interest was released and the remaining affiliate indebtedness was retired and treated as a capital contribution to us. Our credit facility is secured by substantially all of our assets.

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Concurrent with the acquisition of the SAOU and LOU Systems, we entered into a Commitment Increase Supplement to our existing credit facility, which increased the aggregate commitments under the Credit Agreement by $250 million to an aggregate $750 million. We paid for our acquisition of the SAOU and LOU Systems with the proceeds from our offering of common units and approximately $378.9 million in incremental borrowings under the increased credit facility. Substantially all of our assets (North Texas, SAOU and LOU Systems) are currently pledged as collateral on our credit facility.

On October 24, 2007, we entered into the First Amendment to Credit Agreement (the “Amendment”). The Amendment increased by $250 million the maximum amount of increases to the aggregate commitments that may be requested by us. The Amendment allows us to request commitments under the credit agreement, as supplemented and amended, up to $1 billion.

On June 18, 2008, we increased the commitments under our credit facility by $100 million, bringing the total commitments under our credit facility to $850 million. We may request additional commitments under our credit facility of up to $150 million, which would increase the total commitments under our credit facility to $1 billion.

The credit agreement restricts our ability to make distributions of available cash to unitholders if we are in any default or an event of default (as defined in the credit agreement) exists. The credit agreement requires us to maintain a leverage ratio (the ratio of consolidated indebtedness to our consolidated EBITDA, as defined in the credit agreement) of no more than 5.50 to 1.00 on the last day of any fiscal quarter. The credit agreement also requires us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, as defined in the credit agreement) of no less than 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination. In addition, the credit agreement contains various covenants that may limit, among other things, our ability to:

· incur indebtedness;

· grant liens; and

· engage in transactions with affiliates.

The credit facility matures on February 14, 2012, at which time all unpaid principal and interest is due.

8¼% Senior Notes due 2016

On June 18, 2008, we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 8¼% senior notes due 2016 (the “8¼% Notes”). Proceeds from the 8¼% Notes were used to repay borrowings under our credit facility.

The 8¼% Notes:

· are our unsecured senior obligations;

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

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

· are unconditionally guaranteed by us.

The 8¼% Notes are effectively subordinated to all secured indebtedness under our credit agreement, which is secured by substantially all of our assets, to the extent of the value of the collateral securing that indebtedness.

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Interest on the 8¼% Notes accrues at the rate of 8¼% per annum and is payable semi-annually in arrears on January 1 and July 1, commencing on January 1, 2009. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.

Prior to July 1, 2011, we may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 8¼% Notes with the net cash proceeds of one or more equity offerings by us at a redemption price of 108.25% of the principal amount, plus accrued and unpaid interest and liquidated damages, if any, to the redemption date provided that:

(1) at least 65% of the aggregate principal amount of the 8¼% Notes (excluding 8¼% Notes held by us) remains outstanding immediately after the occurrence of such redemption; and

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

At any time prior to July 1, 2012, we may also redeem all or a part of the 8¼% Notes at a redemption price equal to 100% of the principal amount of the 8¼% Notes redeemed plus the applicable premium as defined in the indenture agreement as of, and accrued and unpaid interest and liquidated damages, if any, to the date of redemption.

On or after July 1, 2012, we may redeem all or a part of the 8¼% Notes at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest and liquidated damages, if any, on the 8¼% Notes redeemed, if redeemed during the twelve-month period beginning on July 1 of each year indicated below:

Year	Percentage
2012		104.125	%
2013		102.063	%
2014 and thereafter		100.000	%

The 8¼% Notes are subject to a registration rights agreement dated as of June 18, 2008. Under the registration rights agreement, we are required to file by June 19, 2009 a registration statement with respect to any 8¼% Notes that are not freely transferable without volume restrictions by holders of the 8¼% Notes that are not our affiliates. If we fail to do so, additional interest will accrue on the principal amount of the 8¼% Notes. We have determined that the payment of additional interest is not probable. As a result, we have not recorded a liability for any contingent obligation. Any subsequent accrual of a liability under this registration rights agreement will be charged to earnings as interest expense.

Compliance with Debt Covenants

As of December 31, 2008, the Partnership was in full compliance with the covenants contained in its various debt agreements.

Note 10—Partnership Equity and Distributions

General. The partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (defined below) to unitholders of record on the applicable record date, as determined by the general partner.

Definition of Available Cash. Available Cash, for any quarter, consists of all cash and cash equivalents on hand on the date of determination of available cash for that quarter: less the amount of cash reserves established by the general partner to:

· provide for the proper conduct of our business;

· comply with applicable law, any of our debt instruments or other agreements; or

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· provide funds for distributions to the unitholders and to the general partner for any one or more of the next four quarters.

General Partner Interest and Incentive Distribution Rights. The general partner is currently entitled to approximately 2% of all quarterly distributions that we make prior to our liquidation. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s 2% interest in these distributions will be reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.

The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. The general partner’s incentive distribution rights are not reduced if we issue additional units in the future and the general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Please read “Distributions of Available Cash during the Subordination Period” and “Distributions of Available Cash after the Subordination Period” below for more details about the distribution targets and their impact on the general partner’s incentive distribution rights.

Subordinated Units. All of the subordinated units are indirectly held by Targa. Our partnership agreement provides that, during the subordination period, the common units have the right to receive distributions of Available Cash each quarter in an amount equal to $0.3375 per common unit, or the “Minimum Quarterly Distribution,” plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period ended, and all 11,528,231 subordinated units converted to common units, on a one for one basis, on May 19, 2009.

Distributions of Available Cash during the Subordination Period. Based on the general partner’s initial 2% ownership percentage, the partnership agreement requires that we make distributions of Available Cash from operating surplus for any quarter during the subordination period in the following manner:

· first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the Minimum Quarterly Distribution for that quarter;

· second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the Minimum Quarterly Distribution on the common units for any prior quarters during the subordination period;

· third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the Minimum Quarterly Distribution for that quarter;

· fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.3881 per unit for that quarter (the First Target Distribution);

· fifth, 85% to all unitholders, 2% to the general partner and 13% to the holders of the Incentive Distribution Rights, pro rata, until each unitholder receives a total of $0.4219 per unit for that quarter (the Second Target Distribution);

· sixth, 75% to all unitholders, 2% to the general partner and 23% to the holders of the Incentive Distribution Rights, pro rata, until each unitholder receives a total of $0.50625 per unit for that quarter (the Third Target Distribution); and

· thereafter, 50% to all unitholders, 2% to the general partner and 48% to the holders of the Incentive Distribution Rights, pro rata, (the Fourth Target Distribution).

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Distributions of Available Cash after the Subordination Period. The partnership agreement requires that we make distributions of Available Cash from operating surplus for any quarter after the subordination period in the following manner:

· first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.3881 per unit for that quarter;

· second, 85% to all unitholders, pro rata, 2% to the general partner and 13% to the holders of the Incentive Distribution Rights, until each unitholder receives a total of $0.4219 per unit for that quarter;

· third, 75% to all unitholders, pro rata, 2% to the general partner and 23% to the holders of the Incentive Distribution Rights, until each unitholder receives a total of $0.50625 per unit for that quarter; and

· thereafter, 50% to all unitholders, pro rata, 2% to the general partner and 48% to the holders of the Incentive Distribution Rights.

The following table shows the amount of cash distributions we paid to date:

		Distributions Paid										Distributions
	For the Three	Common		Subordinated		General Partner						per limited
Date Paid	Months Ended	Units		Units		Incentive			2%	Total		partner unit
		(In thousands, except per unit amounts)
February 13, 2009	December 31, 2008	$	17,949	$	5,966	$	1,933	$	528	$	26,376	$	0.51750
November 14, 2008	September 30, 2008		17,934		5,966		1,931		527		26,358		0.51750
August 14, 2008	June 30, 2008		17,759		5,908		1,711		518		25,896		0.51250
May 15, 2008	March 31, 2008		14,467		4,813		208		398		19,886		0.41750
February 14, 2008	December 31, 2007		13,768		4,582		66		376		18,792		0.39750
November 14, 2007	September 30, 2007		11,082		3,891		-		305		15,278		0.33750
August 14, 2007	June 30, 2007		6,526		3,890		-		212		10,628		0.33750
May 15, 2007	March 31, 2007		3,263		1,945		-		107		5,315		0.16875

Note 11—Insurance Claims

We recognize income from business interruption insurance in our combined statements of operations as a component of revenues from third parties in the period that a proof of loss is executed and submitted to the insurers for payment. For 2008, 2007 and 2006 income from business interruption insurance resulting from the effects of Hurricanes Katrina and Rita was $18.1 million, $4.6 million and $7.0 million. In addition, we received $0.6 million during 2008 as a result of fire damage claims at certain plants in our wholesale marketing segment.

Hurricanes Gustav and Ike

In September 2008, certain of our facilities in Louisiana and Texas sustained damage and had disruption to their operations from Hurricanes Gustav and Ike.

We estimate the cost associated with our interest for repairs to the impacted facilities to be approximately $17.4 million. We believe that we have adequate insurance coverage (subject to customary deductibles, limits and sub-limits) to cover the respective facility repair costs and to offset the majority of the associated lost profits as a result of the hurricanes. The property damage deductibles under our insurance coverage will reduce our ultimate property damage insurance recoveries by approximately $3.3 million. We will have additional out of pocket costs associated with improvements (e.g., elevating critical equipment) that may not be covered by insurance.

During 2008 we recorded a loss provision of $4.9 million for our estimated out-of-pocket cleanup and repair

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costs related to these two hurricanes, after estimated insurance proceeds. As of December 31, 2008, expenditures related to the hurricanes totaled $5.5 million.

Note 12—Accounting for Unit-Based Compensation

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

During 2008 and 2007, our general partner awarded 2,000 restricted common units in the Partnership to each of the general partner’s and Targa Resources Investments Inc.’s (“Targa Investments”) non-management 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.

	Year Ended December 31,
	2008			2007		2006
Outstanding at beginning of year		16,000			-		-
Granted		16,000			16,000		-
Vested		(5,336	)		-		-
Forfeited		-			-		-
Outstanding at end of year		26,664			16,000		-
Weighted average grant date fair value per share	$	22.12		$	21.00	$	-

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. During 2008 and 2007, we recognized compensation expense of $0.3 million and $0.2 million related to these awards. We estimate that the remaining fair value of $0.2 million will be recognized in expense over approximately one year.

Note 13—Derivative Instruments and Hedging Activities

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

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

The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2008, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may

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

We have tailored our hedges to generally match the NGL product composition and the NGL and natural gas delivery points to those of our physical equity volumes. Our NGL hedges cover baskets of ethane, propane, normal butane, iso-butane and natural gasoline based upon our expected equity NGL composition. We believe this strategy avoids uncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Additionally, our NGL hedges are based on published index prices for delivery at Mont Belvieu and our natural gas hedges are based on published index prices for delivery at Columbia Gulf, Houston Ship Channel, Mid-Continent and Waha, which closely approximate our actual NGL and natural gas delivery points. We hedge a portion of our condensate sales using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light, sweet crude.

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of our variable rate debt under our credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of December 31, 2008, we had borrowings of approximately $487.8 million outstanding under our revolving credit facility. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings.

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

As of December 31, 2008, affiliates of Goldman Sachs, BofA and Barclays Bank accounted for 67%, 21% and 11% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, BofA and Barclays Bank are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

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

	Asset Derivatives					Liability Derivatives
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	December 31,				Sheet	December 31,
	Location	2008		2007		Location	2008		2007
Derivatives designated as hedging instruments under SFAS 133
Commodity contracts	Current assets	$	88,206	$	8,410	Current liabilities	$	-	$	43,461
	Other assets		68,296		3,040	Other liabilities		123		42,134
Interest rate contracts	Current assets		-		-	Current liabilities		8,020		257
	Other assets		-		-	Other liabilities		9,556		975
Total derivatives designated
as hedging instruments			156,502		11,450			17,699		86,827
Derivatives not designated as hedging instruments under SFAS 133
Commodity contracts	Current assets		3,610		285	Current liabilities		3,644		285
	Other assets		-		-	Other liabilities		-		-
Total derivatives not designated
as hedging instruments			3,610		285			3,644		285
Total derivatives		$	160,112	$	11,735		$	21,343	$	87,112

	Gain (Loss)									Amount of Gain (Loss)
Derivatives in	Recognized in OCI on									Reclassified from OCI into
SFAS 133	Derivatives (Effective Portion)								Location of Gain (Loss)	Income (Effective Portion)
Cash Flow Hedging	Year Ended December 31,								Reclassified from	Year Ended December 31,
Relationships	2008			2007			2006		OCI into Income	2008			2007			2006
Interest rate contracts	$	(19,037	)	$	(1,689	)	$	1,267	Interest expense, net	$	(2,693	)	$	232		$	-
Commodity contracts		130,002			(105,583	)		36,937	Revenues		(33,650	)		(993	)		822
	$	110,965		$	(107,272	)	$	38,204		$	(36,343	)	$	(761	)	$	822

Derivatives Not		Amount of Gain (Loss) Recognized
Designated as Hedging	Location of Gain (Loss)	in Income on Derivatives
Instruments Under	Recognized in Income	Year Ended December 31,
SFAS 133	on Derivatives	2008			2007			2006
Commodity contracts	Other income (expense)	$	(991	)	$	(30,221	)	$	16,756

As of December 31, 2008, OCI included $89.6 million of unrealized net gains on commodity hedges. As of December 31, 2007, OCI included $74.0 million of unrealized net losses on commodity hedges.

For 2008, 2007 and 2006 deferred net losses on commodity hedges of $33.7 million, $1.0 million and $0.9 million were reclassified from OCI to revenues. There were no adjustments for hedge ineffectiveness for 2008, 2007 or 2006.

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As of December 31, 2008 and 2007, OCI also included $17.6 million and $1.2 million of unrealized losses on interest rate hedges.

For 2008, 2007 and 2006, deferred net gain (losses) on interest rate hedges of $2.7 million, ($0.2) million and ($0.5) million were reclassified from OCI to net interest expense. There were no adjustments for hedge ineffectiveness for 2008, 2007 or 2006.

As of December 31, 2008, deferred net gains (losses) of $50.0 million on commodity hedges and ($8.0) million on interest rate hedges recorded in OCI are expected to be reclassified to expense during the next twelve months.

In May 2008 we entered into certain NGL derivative contracts with Lehman Brothers Commodity Services Inc., a subsidiary of Lehman Brothers Holdings Inc. (“Lehman”). Due to Lehman’s bankruptcy filing, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, we discontinued hedge accounting treatment for these contracts as of July 1, 2008. Deferred losses of $0.1 million and $0.3 million will be reclassified from OCI to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. During 2008, we recognized a non-cash mark-to-market loss on derivatives of $1.0 million to adjust the fair value of the Lehman derivative contracts to zero. On October 22, 2008, we terminated the Lehman derivative contracts.

In July 2008, we paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, these swaps were designated as hedges in accordance with SFAS 133. Deferred losses will be reclassified from OCI as a non-cash reduction of revenue when the hedged forecasted sales transaction occurs. During 2008, deferred losses of $20.8 million related to the terminated swaps were reclassified from OCI as a non-cash reduction to revenue. We also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps through 2010.

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As of December 31, 2008, our commodity derivatives that have been designated as cash flow hedges were as follows:

Natural Gas

		Avg. Price		MMBtu per day
Instrument Type	Index	$/MMBtu		2009		2010		2011		2012		Fair Value
Natural Gas Sales
Swap	IF-HSC		7.39		1,966		-		-		-	$	1,159
					1,966		-		-		-
Swap	IF-NGPL MC		9.18		6,256		-		-		-		9,466
Swap	IF-NGPL MC		8.86		-		5,685		-		-		5,129
Swap	IF-NGPL MC		7.34		-		-		2,750		-		843
Swap	IF-NGPL MC		7.18		-		-		-		2,750		738
					6,256		5,685		2,750		2,750
Swap	IF-Waha		8.73		6,936		-		-		-		8,627
Swap	IF-Waha		7.52		-		5,709		-		-		2,294
Swap	IF-Waha		7.36		-		-		3,250		-		886
Swap	IF-Waha		7.18		-		-		-		3,250		708
					6,936		5,709		3,250		3,250
Total Swaps					15,158		11,394		6,000		6,000
Floor	IF-NGPL MC		6.55		850		-		-		-		574
					850		-		-		-
Floor	IF-Waha		6.55		565		-		-		-		326
					565		-		-		-
Total Floors					1,415		-		-		-
Total Sales					16,573		11,394		6,000		6,000
												$	30,750

NGL

		Avg. Price		Barrels per day
Instrument Type	Index	$/gal		2009		2010		2011		2012		Fair Value
NGL Sales
Swap	OPIS-MB		1.32		6,248		-		-		-	$	66,137
Swap	OPIS-MB		1.27		-		4,809		-		-		39,122
Swap	OPIS-MB		0.92		-		-		3,400		-		8,288
Swap	OPIS-MB		0.92		-		-		-		2,700		6,018
Total Swaps					6,248		4,809		3,400		2,700
Floor	OPIS-MB		1.44		-		-		199		-		1,807
Floor	OPIS-MB		1.43		-		-		-		231		1,932
Total Floors					-		-		199		231
Total Sales					6,248		4,809		3,599		2,931
												$	123,304

31

Condensate

		Avg. Price		Barrels per day
Instrument Type	Index	$/Bbl		2009		2010		2011		2012		Fair Value
Condensate Sales
Swap	NY-WTI		69.00		322		-		-		-	$	1,655
Swap	NY-WTI		68.10		-		301		-		-		431
Total Swaps					322		301		-		-
Floor	NY-WTI		60.00		50		-		-		-		239
Total Floors					50		-		-		-
Total Sales					372		301		-		-
												$	2,325

As of December 31, 2008, we had the following commodity derivative contracts directly related to fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market through earnings:

Instrument

��

Period

Commodity

Type

Daily Volume

Average Price

Index

Fair Value

Purchases

Jan 2009 - Dec 2009

Natural gas

Swap

6,005

MMBtu

$

7.50

per MMBtu

NY-HH

$

(3,644

)

Jan 2010 - Jun 2010

Natural gas

Swap

1,304

MMBtu

8.03

per MMBtu

NY-HH

(113

)

Sales

Jan 2009 - Dec 2009

Natural gas

Fixed price sale

6,005

MMBtu

7.50

per MMBtu

NY-HH

3,610

Jan 2010 - Jun 2010

Natural gas

Fixed price sale

1,304

MMBtu

8.03

per MMBtu

NY-HH

113

$

(34

)

Our earnings are also affected by use of the mark-to-market method of accounting for derivative financial instruments that do not qualify for hedge accounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earnings (i.e., using the “mark-to-market” method) rather than being deferred until the anticipated transaction affects earnings. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatility due to changes in the underlying commodity price indices. During 2008, 2007 and 2006, we recorded mark-to-market gains (losses) of ($1.0) million, ($30.2) million and $16.8 million.

Interest Rate Swaps

As of December 31, 2008, we had $487.8 million outstanding under our credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in

32

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

				Notional	Fair
Expiration Date	Fixed Rate			Amount	Value
January 24, 2011		4.00	%	$100 million	$	(5,282	)
January 24, 2012		3.75	%	200 million		(12,294	)
					$	(17,576	)

All interest rate swaps and interest rate basis swaps have been designated as cash flow hedges of variable rate interest payments on $50 million in borrowings under our credit facility.

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 and interest rates based on those observed in underlying markets. These contracts may expose us to the risk of financial loss in certain circumstances.

See also Notes 3, 14 and 17 for additional disclosures related to derivative instruments and hedging activities.

Note 14—Related-Party Transactions

Targa Resources, Inc.

On February 14, 2007, we entered into an Omnibus Agreement with Targa, our general partner and others that addressed the reimbursement of our general partner for costs incurred on our behalf and indemnification matters. Any or all of the provisions of this agreement, other than the indemnification provisions described in Note 15, are terminable by Targa at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will terminate in the event of a change of control of us or our general partner.

Concurrently with the closing of the acquisition of the SAOU and LOU Systems and the Downstream Business, we amended and restated our Omnibus Agreement (as amended and restated) with Targa, our general partner and others that addresses the reimbursement of our general partner for costs incurred on our behalf, competition and indemnification matters.

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

Reimbursement of Operating and General and Administrative Expense

Under the Omnibus Agreement, we reimburse Targa for the payment of certain operating expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for our benefit. With respect to the North Texas System, we reimburse Targa for the following expenses:

· general and administrative expenses, which are capped at $5 million annually for three years, subject to increases based on increases in the Consumer Price Index and subject to further increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses with the concurrence of our conflicts committee; thereafter, our general partner will determine the general and administrative expenses to be allocated to us in accordance with our partnership agreement; and

· operations and certain direct general and administrative expenses, which are not subject to the $5 million cap for general and administrative expenses.

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With respect to the SAOU and LOU Systems and the Downstream Business, we will reimburse Targa for the following expenses:

· general and administrative expenses, which are not capped, allocated to the SAOU and LOU Systems and the Downstream Business according to Targa’s allocation practice; and

· operating and certain direct expenses, which are not capped.

Pursuant to these arrangements, Targa performs centralized corporate functions for us, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. We reimburse Targa for the direct expenses to provide these services as well as other direct expenses it incurs on our behalf, such as compensation of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.

Contracts with Affiliates

Sales to and purchases from affiliates. We routinely conduct business with other subsidiaries of Targa. The related party transactions result primarily from purchases and sales of natural gas. Prior to February 14, 2007, all of our expenditures were paid through Targa, resulting in intercompany transactions. Prior to February 14, 2007, settlement of these inter-company transactions was through adjustments to partners’ capital accounts. After the conveyance of the assets of the North Texas System, the SAOU and LOU Systems, and the Downstream Business, all intercompany transactions were settled in cash.

Natural Gas Purchase Agreements. During 2007, the North Texas, SAOU and LOU Systems entered into natural gas purchase agreements at a price based on Targa Gas Marketing LLC’s (“TGM”) sale price for such natural gas, less TGM’s costs and expenses associated therewith. These agreements have an initial term of 15 years and automatically extend for a term of five years, unless the agreements are otherwise terminated by either party. Furthermore, either party may elect to terminate the agreements if either party ceases to be an affiliate of Targa. In addition, Targa manages the SAOU and LOU Systems’ natural gas sales to third parties under contracts that remain in the name of the Targa Texas Field Services and Targa Louisiana Field Services.

NGL Product Purchase Agreements. On September 24, 2009, Targa Liquids Marketing and Trade, a Delaware general partnership and indirectly, wholly-owned subsidiary of the Partnership (“Targa Liquids”), entered into product purchase agreements with Targa Midstream Services Limited Partnership, a Delaware limited partnership and indirectly wholly-owned subsidiary of Targa (“TMSLP”), and Targa Permian LP, a Delaware limited partnership and indirectly, wholly-owned subsidiary of Targa (“Targa Permian”), pursuant to which Targa Liquids will purchase all volumes of NGLs that are owned or controlled by TMSLP and Targa Permian and not otherwise committed for sale to a third party, at a price based on the prevailing market price less transportation, fractionation and certain other fees. The product purchase agreements will have an initial term of 15 years and will automatically extend for a term of five years. Furthermore, either party may elect to terminate the agreement if either party ceases to be an affiliate of Targa. Each product purchase agreement is effective as of September 1, 2009.

Allocations

Allocation of costs. The employees supporting our operations are employees of Targa. Our financial statements include costs allocated to us by Targa for centralized general and administrative services performed by Targa, as well as depreciation of assets utilized by Targa’s centralized general and administrative functions. Costs allocated to us were based on identification of Targa’s resources which directly benefit us and our proportionate share of costs based on our estimated usage of shared resources and functions. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operated as a stand-alone entity. Prior to the initial IPO and the subsequent acquisition of the SAOU and LOU Systems these allocations were not settled in cash, but were settled through an adjustment to partners’ capital accounts. Effective February 14, 2007, all of the North Texas System’s allocations were settled monthly in cash. Effective October 23, 2007, all of the SAOU and LOU Systems’ allocations were settled monthly in cash.

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Allocations of long-term debt, debt issue costs, interest rate swaps and interest expense. Prior to January 1, 2007, our financial statements included long-term debt, debt issue costs, interest rate swaps and interest expense allocated from Targa. The allocations were calculated in a manner similar to Targa’s purchase price allocation related to its acquisition of the SAOU and LOU Systems and the Downstream Business, and were based on the fair value of acquired tangible assets plus related net working capital and unconsolidated equity interests. These allocations were not settled in cash. Settlement of these allocations occurred through adjustments to partners’ capital. The allocated debt, debt issue costs and interest rate swaps for the North Texas System and the Downstream Business, were settled through a deemed partner contributions of $846.3 million and $478.7 million on January 1, 2007. On October 23, 2007, The allocated debt, debt issue costs and interest rate swaps related to the SAOU and LOU Systems were settled through a deemed partner contribution of $179.6 million.

The following table summarizes the sales to and purchases from affiliates of Targa, payments made or received by Targa on behalf of us and allocations of costs from Targa which were settled through adjustments to partners’ capital prior to the contribution of the North Texas System and the Downstream Business by Targa and the acquisition of the SAOU and LOU Systems from Targa. Management believes these transactions are executed on terms that are fair and reasonable.

	Year Ended December 31,
	2008			2007			2006
Sales to affiliates	$	489,773		$	417,425		$	329,253
Purchases from affiliates:
Included in product purchases		1,097,640			952,774			928,403
Included in operating expenses		58,846			44,530			38,603
Payments made to our Parent		(1,658,240	)		(911,581	)		(997,068	)
Parent allocation of interest expense		-			19,436			127,288
Parent allocation of general and administrative expense		61,723			60,393			56,516
Net change in affiliate payable		48,371			23,478			(26,192	)

Centralized Cash Management

Prior to the conveyance of the assets of the North Texas, SAOU and LOU Systems and the Downstream Business to us, the excess cash from these subsidiaries was held in separate bank accounts and swept to a centralized account under Targa. Beginning with the contribution of these systems to us, their bank accounts have been maintained under a separate 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 us were $0.5 million. For the SAOU and LOU Systems for the period from January 1, 2007 through October 23, 2007, deemed net capital distributions from us were $133.6 million.

For the Downstream Business, deemed net capital distributions of cash to (from) Targa were $166.1 million, $(26.0) million and $58.8 million for 2008, 2007 and 2006.

Transactions with GCF

For the years 2008, 2007 and 2006, transactions with GCF which were included in revenues totaled $0.5 million, $4.5 million and $1.4 million. For the same periods, transactions included in costs and expenses were $3.5 million, $3.3 million and $3.3 million.

Relationships with Warburg Pincus

Chansoo Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of Warburg Pincus and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products.

35

Affiliates of Warburg Pincus own a controlling interest in Broad Oak. We purchased $4.8 million of product from Broad Oak during 2008. We had no commercial transactions prior to 2008 with Broad Oak. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationships with Noble Energy

Chris Tong, one of the directors of Targa, is a Senior Vice President and Chief Financial Officer of Noble Energy, Inc. (“Noble”) from whom we buy certain commodity products. We had net purchases of less than $0.1 million, $0.1 million and $1.7 million of natural gas and NGL products from Noble during 2008, 2007 and 2006. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationship with Bank of America

An affiliate of BofA is an equity investor in Targa Investments, which indirectly owns our general partner. We have executed NGL sales and purchase transactions on the spot market with BofA. For the years 2008, 2007 and 2006, sales to BofA which were included in revenues totaled $4.4 million, $18.1 million and $12.4 million. For the same periods, purchases from BofA were $0.8 million, $9.4 million and $11.2 million.

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

Commodity hedges. We have entered into various commodity derivative transactions with BofA. The following table shows our open commodity derivatives with BofA as of December 31, 2008:

		Instrument
Period	Commodity	Type	Daily Volumes			Average Price			Index
Jan 2009 - Dec 2009	Natural gas	Swap		3,556	MMBtu	$	8.07	per MMBtu	IF-Waha
Jan 2009 - Dec 2009	Natural gas	Swap		575	MMBtu		7.83	per MMBtu	NY-HH
Jan 2010 - Dec 2010	Natural gas	Swap		3,289	MMBtu		7.39	per MMBtu	IF-Waha
Jan 2010 - Dec 2010	Natural gas	Swap		247	MMBtu		8.17	per MMBtu	NY-HH
Jan 2009 - Dec 2009	NGL	Swap		3,000	Bbl		1.18	per gallon	OPIS-MB
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

As of December 31, 2008, the fair value of these open positions was $32.0 million. During 2008, 2007 and 2006, we paid to (received from) BofA $9.1 million, $1.9 million and $(4.2) million in commodity derivative settlements.

Note 15—Commitments and Contingencies

Future non-cancelable commitments related to certain contractual obligations are presented below:

	Payments Due by Period
	Total		2009		2010		2011		2012		2013		Thereafter
Operating leases (1)	$	53,942	$	10,258	$	8,874	$	6,655	$	6,196	$	5,436	$	16,523
Capacity payments		8,215		5,419		2,050		746		-		-		-
Right of way		7,406		532		484		458		447		359		5,126
Asset retirement obligations		6,206		-		-		6		-		-		6,200
	$	75,769	$	16,209	$	11,408	$	7,865	$	6,643	$	5,795	$	27,849

________

(1) Operating lease obligations include minimum lease payment obligations associated with site leases, railcar leases and office space leases.

36

The following table summarizes total expenses related to operating lease obligations, capacity payments and right-of-way payments for each of the years indicated:

	2008		2007		2006
Operating lease obligations	$	11,273	$	13,057	$	6,762
Capacity payments		3,051		2,878		778
Right-of-way payments		2,183		1,355		1,029

Environmental

Under the Omnibus Agreement described in Note 14, Targa has indemnified us for three years from February 14, 2007 against certain potential environmental claims, losses and expenses associated with the operation of the North Texas System occurring before such date that were not reserved on the books of the North Texas System. Targa’s maximum liability for this indemnification obligation will not exceed $10.0 million and Targa will not have any obligation under this indemnification until our aggregate losses exceed $250,000. We have indemnified Targa against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.

Our environmental liabilities not covered by the Omnibus Agreement are for ground water assessment and remediation and was less than $0.1 million as of December 31, 2008.

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 alleges that Targa and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal. On February 3, 2009, the parties presented oral arguments and the appeal is pending before the 14th Court of Appeals in Houston, Texas. We are contesting WTG’s appeal, but can give no assurances regarding the outcome of the proceeding. Targa has agreed to indemnify us for any claim or liability arising out of the WTG suit.

We are not a party to any other legal proceedings other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business.

Note 16—Fair Value of Financial Instruments

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

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

37

The carrying value of the senior secured revolving credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt. The carrying value of the notes payable to Parent approximates their fair value as they were settled at their stated amount on September 24, 2009. The carrying amounts and fair values of our other financial instruments are as follows as of the dates indicated:

	As of December 31,
	2008				2007
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Credit facility	$	487,765	$	487,765	$	626,300	$	626,300
Senior unsecured notes		209,080		128,333		-		-
Notes payable to Parent:
Targa Downstream LP		744,020		744,020		687,152		687,152
Targa LSNG LP		29,863		29,863		24,115		24,115

Note 17—Fair Value Measurements

A three-tier fair value hierarchy, which prioritizes the significant inputs used in measuring fair value is used to record assets and liabilities. 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.

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 following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	160,112	$	-	$	36,808	$	123,304
Assets from interest rate derivatives		-		-		-		-
Total assets	$	160,112	$	-	$	36,808	$	123,304
Liabilities from commodity derivative contracts	$	3,767	$	-	$	3,767	$	-
Liabilities from interest rate derivatives		17,576		-		17,576		-
Total liabilities	$	21,343	$	-	$	21,343	$	-

38

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

	Commodity Derivative Contracts
Balance, December 31, 2007	$	(71,370	)
Total gains (losses) realized/unrealized:
Included in loss on mark-to-market derivatives (1)		(991	)
Included in OCI		100,068
Purchases		2,866
Terminations		77,792
Settlements		14,939
Balance, December 31, 2008	$	123,304

________

(1) No unrealized gains or losses were reported relating to assets and liabilities still held as of December 31, 2008.

Note 18—Segment Information

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

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

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

The NGL Distribution and Marketing segment markets our own natural gas liquids production and purchased natural gas liquids products in selected United States markets. We also had the right to purchase or market substantially all of Chevron’s natural gas liquids pursuant to a Master Natural Gas Liquids Purchase Agreement.

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

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

39

Our reportable segment information is shown in the following tables:

	Year Ended December 31, 2008
	Natural Gas					NGL
	Gathering					Distribution
	and		Logistics			and			Wholesale		Eliminations
	Processing		Assets			Marketing			Marketing		and Other			Total
Revenues from third parties	$	848,725	$	106,016		$	4,613,423		$	1,415,460	$	-		$	6,983,624
Revenues from affiliates		489,113		-			(62	)		722		-			489,773
Intersegment revenues		736,280		131,995			571,358			43,865		(1,483,498	)		-
Revenues		2,074,118		238,011			5,184,719			1,460,047		(1,483,498	)		7,473,397
Product purchases from third parties		1,479,061		(101	)		3,445,263			900,210		-			5,824,433
Product purchases from affiliates		286,917		-			808,556			2,167		-			1,097,640
Intersegment product purchases		37,053		101			910,621			544,513		(1,492,288	)		-
Product purchases		1,803,031		-			5,164,440			1,446,890		(1,492,288	)		6,922,073
Operating expenses from third parties		55,259		138,125			1,746			60		-			195,190
Operating expenses from affiliates		66		49,990			-			-		8,790			58,846
Operating expenses		55,325		188,115			1,746			60		8,790			254,036
Operating margin	$	215,762	$	49,896		$	18,533		$	13,097	$	-		$	297,288
Other financial information:
Equity in earnings of
unconsolidated investments	$	-	$	3,877		$	-		$	-	$	-		$	3,877
Identifiable assets		1,580,906		498,189			142,349			115,670		(22,295	)		2,314,819
Unconsolidated investments		-		18,465			-			-		-			18,465
Capital expenditures		54,758		41,460			-			-		-			96,218
Revenues by type:
Commodity sales	$	2,063,724	$	60		$	5,172,168		$	1,453,130	$	(1,349,199	)	$	7,339,883
Services		10,350		235,398			2,961			408		(134,299	)		114,818
Business interruption/other		44		2,553			9,590			6,509		-			18,696
	$	2,074,118	$	238,011		$	5,184,719		$	1,460,047	$	(1,483,498	)	$	7,473,397

40

	Year Ended December 31, 2007
	Natural Gas					NGL
	Gathering					Distribution
	and		Logistics			and			Wholesale		Eliminations
	Processing		Assets			Marketing			Marketing		and Other			Total
Revenues from third parties	$	630,773	$	83,129		$	4,419,636		$	1,265,183	$	-		$	6,398,721
Revenues from affiliates		420,030		-			(3,320	)		715		-			417,425
Intersegment revenues		610,666		111,968			479,498			30,107		(1,232,239	)		-
Revenues		1,661,469		195,097			4,895,814			1,296,005		(1,232,239	)		6,816,146
Product purchases from third parties		1,215,733		-			3,322,534			783,360		-			5,321,627
Product purchases from affiliates		188,494		-			764,105			175		-			952,774
Intersegment product purchases		2,570		-			752,183			489,532		(1,244,285	)		-
Product purchases		1,406,797		-			4,838,822			1,273,067		(1,244,285	)		6,274,401
Operating expenses from third parties		50,897		122,639			1,562			31		-			175,129
Operating expenses from affiliates		34		32,473			(23	)		-		12,046			44,530
Operating expenses		50,931		155,112			1,539			31		12,046			219,659
Operating margin	$	203,741	$	39,985		$	55,453		$	22,907	$	-		$	322,086
Other financial information:
Equity in earnings of
unconsolidated investments	$	-	$	3,511		$	-		$	-	$	-		$	3,511
Identifiable assets		1,479,972		482,190			588,505			239,734		(87,547	)		2,702,854
Unconsolidated investments		-		19,238			-			-		-			19,238
Capital expenditures		43,947		35,179			-			-		-			79,126
Revenues by type:
Commodity sales	$	1,652,415	$	45		$	4,889,339		$	1,294,599	$	(1,118,313	)	$	6,718,085
Services		7,223		195,081			2,643			580		(113,926	)		91,601
Business interruption/other		1,831		(29	)		3,832			826		-			6,460
	$	1,661,469	$	195,097		$	4,895,814		$	1,296,005	$	(1,232,239	)	$	6,816,146

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	Year Ended December 31, 2006
	Natural Gas					NGL
	Gathering					Distribution
	and		Logistics			and		Wholesale			Eliminations
	Processing		Assets			Marketing		Marketing			and Other			Total
Revenues from third parties	$	951,936	$	63,429		$	3,315,535	$	1,247,336		$	-		$	5,578,236
Revenues from affiliates		324,945		-			3,442		866			-			329,253
Intersegment revenues		461,644		114,700			419,792		62,240			(1,058,376	)		-
Revenues		1,738,525		178,129			3,738,769		1,310,442			(1,058,376	)		5,907,489
Product purchases from third parties		1,194,751		3			2,496,448		859,268			-			4,550,470
Product purchases from affiliates		320,971		-			612,617		(5,185	)		-			928,403
Intersegment product purchases		1,946		(3	)		617,056		445,831			(1,064,830	)		-
Product purchases		1,517,668		-			3,726,121		1,299,914			(1,064,830	)		5,478,873
Operating expenses from third parties		49,033		103,405			2,044		10			-			154,492
Operating expenses from affiliates		42		32,107			-		-			6,454			38,603
Operating expenses		49,075		135,512			2,044		10			6,454			193,095
Operating margin	$	171,782	$	42,617		$	10,604	$	10,518		$	-		$	235,521
Other financial information:
Equity in earnings of
unconsolidated investments	$	-	$	2,754		$	-	$	-		$	-		$	2,754
Identifiable assets		1,416,371		479,819			346,805		158,018			-			2,401,013
Unconsolidated investments		-		19,602			-		-			-			19,602
Capital expenditures		32,576		23,167			-		-			-			55,743
Revenues by type:
Commodity sales	$	1,725,161	$	-		$	3,730,172	$	1,302,287		$	(943,695	)	$	5,813,925
Services		13,031		177,744			3,092		7,059			(114,681	)		86,245
Business interruption/other		333		385			5,505		1,096			-			7,319
	$	1,738,525	$	178,129		$	3,738,769	$	1,310,442		$	(1,058,376	)	$	5,907,489

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

	Year Ended December 31,
	2008			2007			2006
Reconciliation of operating margin to net income (loss):
Operating margin	$	297,288		$	322,086		$	235,521
Depreciation and amortization expense		(97,837	)		(93,520	)		(90,744	)
General and administrative expense		(68,641	)		(63,986	)		(57,259	)
Interest expense, net		(97,012	)		(99,354	)		(127,061	)
Income tax expense		(2,390	)		(2,519	)		(3,430	)
Other, net		18,291			(27,515	)		19,321
Net income (loss)	$	49,699		$	35,192		$	(23,652	)

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Note 19—Other Operating Income

Our other operating (income) expense consists of the following items for the periods indicated:

	Year Ended December 31,
	2008			2007			2006
Casualty loss adjustment (see Note 11)	$	4,951		$	-		$	-
Loss (gain) on sale of assets		(5,917	)		(296	)		34
	$	(966	)	$	(296	)	$	34

Note 20—Supplemental Cash Flow Information

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

	Year Ended December 31,
	2008		2007			2006
Net settlement of allocated indebtedness and debt issue costs	$	-	$	941,518		$	330
Net contribution of affiliated receivables		-		184,462			-
Noncash long-term debt allocation of payments from Parent		-		(419,277	)		3,238
Interest paid		29,271		15,453			-
Debt issue costs allocated from Parent		-		(9,726	)		6,054
Like-kind exchange of property, plant and equipment		5,813		-			-
Assets allocated to Parent, net		-		-			75,226

Note 21—Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry. Our business activities include gathering, transporting, processing and fractionating of natural gas, NGLs and crude oil. Our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of natural gas, NGLs and crude oil transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and crude oil handled by our facilities.

A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.

Counterparty Risk with Respect to Financial Instruments

Where we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and

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monitors the appropriateness of these limits on an ongoing basis. Generally, management does not require collateral and does not anticipate nonperformance by our counterparties.

Casualty or Other Risks

Targa maintains coverage in various insurance programs on our behalf, which provides us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations.

Management believes that Targa has adequate insurance coverage, although insurance may not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, Targa may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations.

A portion of the insurance costs described above is allocated to us by Targa through the allocation methodology as prescribed in the Omnibus Agreement described in Note 14.

Under the Omnibus Agreement, Targa has also indemnified us for losses attributable to rights-of-way, certain consents or governmental permits, pre-closing litigation relating to the North Texas System and income taxes attributable to pre-closing operations that were not reserved on the books of the North Texas System as of February 14, 2007. Targa does not have any obligation under these indemnifications until our aggregate losses exceed $250,000. We have indemnified Targa for all losses attributable to the post-closing operations of the North Texas System. Targa’s obligations under this additional indemnification will survive for three years from February 14, 2007, except that the indemnification for income tax liabilities will terminate upon the expiration of the applicable statutes of limitations.

Note 22—Selected Quarterly Financial Data (Unaudited)

Our supplemental results of operations by quarter for the years ended December 31, 2008 and 2007, as adjusted to reflect the consideration of common control accounting as discussed in Note 2, were as follows:

	First		Second		Third			Fourth
	Quarter		Quarter		Quarter			Quarter		Total
	(In thousands, except per unit amounts)
Year Ended December 31, 2008:
Revenues	$	2,079,458	$	2,120,192	$	2,214,851		$	1,058,896	$	7,473,397
Operating income		45,184		67,860		(7,530	)		26,262		131,776
Net income attributable to partners		24,935		28,206		14,692			23,661		91,494
Net income per limited partner unit--basic and diluted	$	0.50	$	0.54	$	0.31		$	0.48	$	1.83
Year Ended December 31, 2007:
Revenues	$	1,328,540	$	1,505,084	$	1,746,971		$	2,235,551	$	6,816,146
Operating income		37,216		23,976		38,092			65,592		164,876
Net income (loss) attributable to partners		2,153		4,040		3,869			18,004		28,066
Net income per limited partner unit--basic and diluted	$	0.07	$	0.13	$	0.12		$	0.42	$	0.81

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The following tables reconcile the previously reported amounts to those shown above:

	Historical										Historical
	Targa Resources		Downstream					Targa Resources			Targa Resources		Downstream						Targa Resources
	Partners LP		Business		Adjustments			Partners LP			Partners LP		Business			Adjustments			Partners LP
	(In thousands, except per unit amounts)									(In thousands, except per unit amounts)
	First Quarter 2008										Second Quarter 2008
Revenues	$	512,069	$	1,769,795	$	(202,406	)	$	2,079,458		$	630,520	$	1,729,321		$	(239,649	)	$	2,120,192
Operating income		33,974		11,186		24			45,184			36,525		31,335			-			67,860
Net income attributable to partners		24,935		-		-			24,935			28,206		-			-			28,206
Net income per limited partner unit--basic and diluted	$	0.50		-		-		$	0.50		$	0.54		-			-		$	0.54
	First Quarter 2007										Second Quarter 2007
Revenues	$	348,781	$	1,086,667	$	(106,908	)	$	1,328,540		$	433,615	$	1,213,678		$	(142,209	)	$	1,505,084
Operating income		20,739		16,477		-			37,216			28,183		(4,207	)		-			23,976
Net income (loss) attributable to partners		2,153		-		-			2,153			4,040		-			-			4,040
Net income per limited partner unit--basic and diluted	$	0.07		-		-		$	0.07		$	0.13		-			-		$	0.13

	Historical											Historical
	Targa Resources		Downstream						Targa Resources			Targa Resources		Downstream					Targa Resources
	Partners LP		Business			Adjustments			Partners LP			Partners LP		Business		Adjustments			Partners LP
	(In thousands, except per unit amounts)											(In thousands, except per unit amounts)
	Third Quarter 2008											Fourth Quarter 2008
Revenues	$	578,747	$	1,868,916		$	(232,812	)	$	2,214,851		$	352,782	$	804,647	$	(98,533	)	$	1,058,896
Operating income		26,815		(34,345	)		-			(7,530	)		21,720		4,542		-			26,262
Net income attributable to partners		14,692		-			-			14,692			23,661		-		-			23,661
Net income per limited partner unit--basic and diluted	$	0.31		-			-		$	0.31		$	0.48		-		-		$	0.48
	Third Quarter 2007											Fourth Quarter 2007
Revenues	$	405,038	$	1,502,186		$	(160,253	)	$	1,746,971		$	474,035	$	1,965,445	$	(203,929	)	$	2,235,551
Operating income		29,965		8,127			-			38,092			34,467		31,125		-			65,592
Net income (loss) attributable to partners		3,869		-			-			3,869			18,004		-		-			18,004
Net income per limited partner unit--basic and diluted	$	0.12		-			-		$	0.12		$	0.42		-		-		$	0.42

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