UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported)
May 23, 2008 (May 23, 2008)

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		001-33303 (Commission File Number)		65-1295427 (IRS Employer Identification No.)

1000 Louisiana, Suite 4300
Houston, TX 77002
(Address of principal executive office and Zip Code)

(713) 584-1000
(Registrants’ telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o		Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 8.01.		Other Events.

     We are filing the audited consolidated balance sheet of Targa Resources GP LLC as of December 31, 2007, which is included as Exhibit 99.1 to this Current Report on Form 8-K. Targa Resources GP LLC is the general partner of Targa Resources Partners LP.

Item 9.01.		Financial Statements and Exhibits

(d) Exhibits

Exhibit
Number		Description
Exhibit 23.1		Consent of Independent Registered Public Accounting Firm
Exhibit 99.1		Audited Consolidated Balance Sheet of Targa Resources GP LLC as of December 31, 2007

SIGNATURES

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

EXHIBIT INDEX

Exhibit
Number		Description
Exhibit 23.1		Consent of Independent Registered Public Accounting Firm
Exhibit 99.1		Audited Consolidated Balance Sheet of Targa Resources GP LLC as of December 31, 2007

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-149200) of Targa Resources Partners LP of our report dated May 16, 2008 relating to the consolidated balance sheet of Targa Resources GP LLC, which appears in the Current Report on Form 8-K of Targa Resources Partners LP dated May 23, 2008.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
May 23, 2008

Exhibit 99.1

Report of Independent Registered Public Accounting Firm

To the Member of Targa Resources GP LLC:

In our opinion, the accompanying consolidated balance sheet presents fairly, in all material respects, the financial position of Targa Resources GP LLC (the “Company”) at December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

As discussed in Note 7 to the consolidated balance sheet, the Company has engaged in significant transactions with other subsidiaries of its parent company, Targa Resources, Inc., a related party.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
May 16, 2008

TARGA RESOURCES GP LLC
CONSOLIDATED BALANCE SHEET

		December 31,
		2007
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	50,994
Receivables from third parties			59,346
Receivables from affiliated companies			87,547
Inventory			1,624
Assets from risk management activities			8,695
Other			269
Total current assets			208,475
Property, plant and equipment, at cost			1,433,955
Accumulated depreciation			(174,361	)
Property, plant and equipment, net			1,259,594
Debt issue costs			6,588
Long-term assets from risk management activities			3,040
Other long-term assets			2,275
Total assets		$	1,479,972
LIABILITIES AND MEMBER’S EQUITY
Current liabilities:
Accounts payable		$	5,693
Accrued liabilities			142,836
Liabilities from risk management activities			44,003
Total current liabilities			192,532
Long-term debt			626,300
Long-term liabilities from risk management activities			43,109
Other long-term liabilities			3,266
Deferred income tax liability			752
Commitments and contingencies (Note 13)
Limited partners of Targa Resources Partners LP, including Parent			611,476
Member’s equity:
Member interest			4,042
Accumulated other comprehensive loss			(1,505	)
Total member’s equity			2,537
Total liabilities and member’s equity		$	1,479,972

See notes to consolidated balance sheet

TARGA RESOURCES GP LLC
NOTES TO CONSOLIDATED BALANCE SHEET

Note 1—Organization and Operations

     Targa Resources GP LLC is a Delaware single-member limited liability company, formed in October 2006 to own a 2% general partner interest in Targa Resources Partners LP (“Partnership”). Our primary business purpose is to manage the affairs and operations of the Partnership. We are an indirect wholly-owned subsidiary of Targa Resources, Inc. (“Targa”, or “Parent”). In this report, unless the context requires otherwise, references to “we,” “us,” “our,” or “the Company” are intended to mean the business and operations of Targa Resources GP LLC and its consolidated subsidiaries, which include the Partnership and its consolidated subsidiaries. References to “TR GP” are intended to mean and include Targa Resources GP LLC, individually as the general partner of the Partnership, and not on a consolidated basis.

Initial Public Offering

     On February 14, 2007, the Partnership completed its initial public offering (“IPO”) of common units representing limited partner interests in the Partnership. The net proceeds of the IPO were used to pay expenses related to the IPO and the Partnership’s new credit facility and to repay approximately $371.2 million of the Partnership’s outstanding allocated indebtedness. Concurrent with the IPO, Targa contributed its interest in Targa North Texas GP LLC and Targa North Texas LP (collectively the “North Texas System”) to the Partnership. TR GP received a 2% general partnership interest in the Partnership (629,555 general partner units) and incentive distribution rights. Targa received a limited partnership interest in the Partnership represented by 11,528,231 subordinated units, which are subordinated for a period of time to the common units with respect to distribution rights. The common units of the Partnership are listed on The NASDAQ Stock Market LLC under the symbol “NGLS”.

Acquisition of the SAOU and LOU Systems

     On October 24, 2007, the Partnership completed the purchase from Targa of its ownership interests in Targa Texas Field Services LP, (the “SAOU System”), and Targa Louisiana Field Services LLC (the “LOU System”). This acquisition consisted of the SAOU System’s natural gas gathering and processing businesses located in the Permian Basin of west Texas and the LOU System’s natural gas gathering and processing businesses located in southwest Louisiana. The total value of the transaction was approximately $706 million. In addition, the Partnership paid approximately $24.2 million to Targa for the termination of certain hedge transactions. Concurrent with the Partnership’s acquisition, the Partnership sold 13,500,000 common units representing limited partnership interests in the Partnership. Total consideration paid by the Partnership to Targa consisted of cash of approximately $722.5 million and 312,246 general partner units issued to TR GP to allow TR GP to maintain its 2% general partner interest.

     On November 20, 2007, the underwriters exercised their option to purchase an additional 1,800,000 common units. The net proceeds from the underwriters’ exercise were used to reduce borrowings under the Partnership’s credit facility by approximately $47 million. In addition, TR GP made a capital contribution of $1.0 million to maintain its 2% general partner interest.

Note 2—Basis of Presentation

     The Partnership’s acquisition of the SAOU and LOU Systems from Targa has been accounted for as a transfer of assets between entities under common control in accordance with Statement of Financial Accounting Standards (“SFAS”) 141, “Business Combinations.” Targa’s conveyance of the North Texas System to the Partnership in 2007 has also been accounted for as a transfer of assets between entities under common control. Under common control accounting, the SAOU and LOU Systems assets and liabilities are recorded in the Partnership records at the same book value as Targa with the balance of the acquisition proceeds recorded as an adjustment to parent equity.

     We consolidate the accounts of the Partnership and its subsidiaries in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.” We have no independent operations and no material assets outside those of the Partnership. Notwithstanding our consolidation of

the Partnership and its subsidiaries into our Consolidated Balance Sheet pursuant to EITF No. 04-5, we are not liable for, and our assets are not available to satisfy, the obligations of the Partnership and/or its subsidiaries.

     The caption “Limited partners of Targa Resources Partners LP, including Parent” on our December 31, 2007 consolidated balance sheet represents third-party and Targa ownership interests in the Partnership. The following table presents the components of this line item as of December 31, 2007 (In thousands):

Limited partners of Targa Resources Partners LP:
Non-affiliate public unitholders		$	714,888
Targa			(103,412	)
Limited partners of Targa Resources Partners LP, including Parent		$	611,476

Note 3—Accounting Policies

     Asset Retirement Obligations. We account for asset retirement obligations (“AROs”) using SFAS 143, “Accounting for Asset Retirement Obligations,” as interpreted by Financial Interpretation (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” Asset retirement obligations 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, an entity records 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 the entity at either the recorded amount or the entity will recognize a gain or loss on the difference between the recorded amount and the actual settlement cost.

     At December 31, 2007, our aggregate asset retirement obligations totaled $3.3 million.

     Cash and Cash Equivalents. We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

     Concentration of Credit Risk. Financial instruments which potentially subject Targa to concentrations of credit risk consist primarily of trade accounts receivable and derivative instruments. Management believes the risk is limited, as our customers represent a broad and diverse group of energy marketers and end users.

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

     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 on a straight-line basis, which approximates the interest method.

     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.

     Impairment of Long-Lived Assets. Management reviews property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. The carrying amount is deemed not recoverable if it exceeds the undiscounted sum of the cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. If the carrying amount is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors.

     Income Taxes. We follow the guidance in SFAS 109, “Accounting for Income Taxes”, which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

     As part of the process of preparing our consolidated balance sheet, we are required to estimate our income tax liability in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheet.

     We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

     We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no reserve has been established. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.

     Our deferred income tax liability includes the Partnership’s state tax obligations under the revised Texas franchise tax, consisting generally of a 1% tax on the amount by which total revenues exceed cost of goods sold as apportioned to Texas. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

     We adopted the provisions of FIN 48 “Accounting for Uncertainty in Income Taxes” on January 1, 2007. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Based on our evaluation, we have determined that there are no significant uncertain tax positions requiring recognition in our financial statements at the date of adoption or at December 31, 2007. 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 State of Texas jurisdictions, and are open to federal and state income tax examinations for years 2006 forward. Presently, no income tax examinations are underway, and none have been announced. No potential interest or penalties were recognized at December 31, 2007.

     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 at 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.

     Price Risk Management (Hedging). We account for derivative instruments in accordance with SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS 133, 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 member’s equity, 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.

     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 becomes ineffective. 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 probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are reclassified to earnings immediately.

     Our policy is to formally document all relationships between hedging instruments and hedged items, as well as its 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, the Partnership assesses whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Hedge effectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is reclassified to earnings in the current period.

     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
Natural gas gathering systems and processing facilities		15 to 25
Office and miscellaneous equipment		3 to 7

     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. Upon disposition or retirement of property, plant, and equipment, any gain or loss is charged to operations.

     Segment Information. SFAS 131, “Disclosures about Segments of an Enterprise and Related Information,” establishes standards for reporting information about operating segments. We operate in one segment only, the natural gas gathering and processing segment.

     Equity-Based Employee Compensation. We account for awards under the Partnership’s long-term incentive plan utilizing the fair value recognition provisions of SFAS 123R, “Share-Based Payment.” Please see Note 12.

     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 at the date of the 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 tangible and intangible 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.

Recent Accounting Pronouncements

     In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”) which establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The FASB partially deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis while the effective date for nonfinancial and financial assets and liabilities that are recognized on a recurring basis is effective beginning January 1, 2008. We have determined that the adoption of SFAS 157 will not have a material impact on our consolidated balance sheet.

     In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” which is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. SFAS 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. We have determined that our adoption of SFAS 159 will not have a material impact on our consolidated balance sheet.

     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 standard 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. We are currently reviewing this new accounting standard and the impact, if any, it will have on our consolidated balance sheet.

     In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS 141R”). SFAS 141R establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling interest in the acquiree and the goodwill acquired. SFAS 141R also establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. SFAS 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008. We are currently reviewing this new accounting standard and the impact, if any, it will have on our consolidated balance sheet.

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

Note 4—Acquisitions

     On February 14, 2007, the Partnership acquired Targa’s ownership interests in the North Texas System. On October 24, 2007, the Partnership acquired Targa’s ownership interests in the SAOU and LOU Systems. As required by SFAS 141, we accounted for these transactions as transfers of net assets between entities under common control. For combinations of entities under common control, the purchase cost provisions (as they relate to purchase business combinations involving unrelated entities) of SFAS 141 explicitly do not apply; instead the method of accounting prescribed by SFAS 141 for such transfers is similar to the pooling-of-interests method of accounting. Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination (that is, no recognition is made for a purchase premium or discount representing any difference between the cash consideration paid and the book value of the net assets acquired).

Note 5—Partnership Equity and Distributions

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

     Definition of Available Cash. The Partnership’s 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 the Partnership’s business;
	•		comply with applicable law, any of the Partnership’s debt instruments or other agreements; or
	•		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. TR GP is currently entitled to approximately 2% of all quarterly distributions that are made prior to the Partnership’s liquidation. TR GP has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. TR GP’s 2% interest in these distributions will be reduced if the Partnership issues additional units in the future and TR GP does not contribute a proportionate amount of capital to the Partnership to maintain its 2% general partner interest.

     The incentive distribution rights held by TR GP entitles them to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. TR GP’s incentive distribution rights are not reduced if the Partnership issues additional units in the future and TR GP does not contribute a proportionate amount of capital to the Partnership 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. The 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. 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 will end, and the subordinated units will convert to common units, on a one for one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. The earliest date at which the subordination period may end is April 2008.

     Distributions of Available Cash during the Subordination Period. Based on TR GP’s initial 2% ownership percentage, the partnership agreement requires that the Partnership make distributions of Available Cash from its 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 the Partnership distributes 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 the Partnership distributes 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 the Partnership distributes 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 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 (the Second Target Distribution);

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

     Distributions of Available Cash after the Subordination Period. The partnership agreement requires that the Partnership make distributions of Available Cash from its 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.

Note 6—Member’s Equity

     At December 31, 2007, member’s equity consisted of the capital account of Targa GP Inc., an indirect wholly owned subsidiary of Targa and Targa GP Inc.’s proportionate share of the accumulated other comprehensive loss of the Partnership.

Note 7—Related-Party Transactions

     Targa Resources, Inc.

     On February 14, 2007, the Partnership entered into an Omnibus Agreement with Targa, TR GP and others that addressed the reimbursement to Targa for costs incurred on the Partnership’s behalf and indemnification matters. Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described in Note 13, are terminable by Targa at its option if TR GP is removed as the general partner without cause and units held by Targa and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of the Partnership or TR GP as general partner.

     Concurrently with the closing of the acquisition of the SAOU and LOU Systems, the Partnership amended and restated its Omnibus Agreement (as amended and restated, the “Omnibus Agreement”) with Targa, TR GP and others that addresses the reimbursement of Targa for costs incurred on the Partnership’s behalf, competition and indemnification matters. Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, are terminable by Targa at its option if TR GP is removed as general partner without cause and units held by Targa and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of the Partnership or TR GP as general partner.

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 and NGLs.

     NGL and Condensate Purchase Agreement for the North Texas System. During 2007, the Partnership entered into an NGL and high pressure condensate purchase agreement with Targa Liquids Marketing and Trade (“TLMT”) for our North Texas System, which has an initial term of 15 years and will automatically extend for a term of five years, unless the agreement is otherwise terminated by either party, pursuant to which (i) the Partnership is obligated to sell all volumes of NGLs (other than high-pressure condensate) that it owns or controls to TLMT and (ii) the Partnership has the right to sell to TLMT or third parties the volumes of high-pressure condensate that it owns or controls, in each case at a price based on the prevailing market price less transportation, fractionation and certain other fees. Furthermore, either party may elect to terminate the agreement if either party ceases to be an affiliate of Targa.

     NGL Purchase Agreements for the SAOU and LOU Systems. During 2007, the SAOU System entered into an NGL purchase agreement pursuant to which it is obligated to sell all volumes of mixed NGLs, or raw product, that it

owns or controls to TLMT at a price based on either TLMT’s sales price to third parties or the prevailing market price, less transportation, fractionation and certain other fees. The LOU System also has entered into an NGL purchase agreement pursuant to which (i) it has the right to sell to TLMT the volumes of raw product that it owns or controls at a commercially reasonable price agreed by the parties, and (ii) it is obligated to sell all volumes of fractionated NGL components that it owns or controls at a price based on TLMT’s sales price to third parties or the prevailing market price, less transportation, fractionation and certain other fees. Both NGL purchase agreements have an initial term of one year and automatically extend for additional terms of one year, unless the agreements are otherwise terminated by either party.

     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 SAOU and LOU Systems.

Allocations

     Allocation of costs. The employees supporting the Partnership’s 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.

     Other

     Commodity hedges. We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”). Merrill Lynch holds an equity interest in the holding company that indirectly owns us. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas and condensate over periods ending in 2010, and we have agreed to pay MLCI floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with MLCI as of December 31, 2007:

Period		Commodity		Instrument Type		Daily Volumes		Average Price		Index
Jan 2008 — Mar 2008		Natural gas		Swap		1,650 MMBtu		$8.47 per MMBtu		NY-HH
Jan 2008 — Dec 2008		Natural gas		Swap		3,847 MMBtu		8.76 per MMBtu		IF-Waha
Jan 2009 — Dec 2009		Natural gas		Swap		3,556 MMBtu		8.07 per MMBtu		IF-Waha
Jan 2010 — Dec 2010		Natural gas		Swap		3,289 MMBtu		7.39 per MMBtu		IF-Waha
Jan 2008 — Mar 2008		NGL		Swap		470 Bbl		1.39 per gallon		OPIS-MB
Jan 2008 — Dec 2008		NGL		Swap		3,175 Bbl		1.06 per gallon		OPIS-MB
Jan 2009 — Dec 2009		NGL		Swap		3,000 Bbl		0.98 per gallon		OPIS-MB
Jan 2008 — Dec 2008		Condensate		Swap		264 Bbl		72.66 per barrel		NY-WTI
Jan 2009 — Dec 2009		Condensate		Swap		202 Bbl		70.60 per barrel		NY-WTI
Jan 2010 — Dec 2010		Condensate		Swap		181 Bbl		69.28 per barrel		NY-WTI

     At December 31, 2007, the fair value of all these open positions is a liability of $25.6 million.

Note 8—Property, Plant and Equipment

     Property, plant and equipment and accumulated depreciation were as follows as of December 31, 2007 (In thousands):

Gathering and processing systems		$	1,363,791
Other property and equipment			70,164
			1,433,955
Accumulated depreciation			(174,361	)
		$	1,259,594

Note 9—Long-Term Debt

     On February 14, 2007, the Partnership entered into a credit agreement which provides for a five-year $500 million revolving credit facility with a syndicate of financial institutions. The revolving credit facility bears interest at the Partnership’s 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 the Partnership’s total leverage ratio, or LIBOR plus an applicable margin ranging from 1.0% to 2.25% dependent on the Partnership’s total leverage ratio. The Partnership initially borrowed $342.5 million under its credit facility, and concurrently repaid $48.0 million under its 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 the Partnership’s 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 the Partnership. The Partnership’s credit facility is secured by substantially all of its assets. The Partnership’s weighted average interest rate on outstanding borrowings under its credit facility for the period from February 14, 2007 to December 31, 2007 was 6.7%.

     On October 24, 2007, the Partnership 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.

     Concurrent with the acquisition of the SAOU and LOU Systems, the Partnership entered into a Commitment Increase Supplement (the “Supplement”) to its existing five-year $500 million senior secured revolving credit facility to increase the credit facility. The Supplement increased the aggregate commitments under the Credit Agreement by $250 million to an aggregate $750 million. The Partnership paid for its acquisition of the SAOU and LOU Systems with the proceeds from its offering of common units and approximately $378.9 million in incremental borrowings under the increased senior secured revolving credit facility. Substantially all of the assets of the Partnership (North Texas, SAOU and LOU Systems) are currently pledged as collateral on its $750 million credit facility.

     On October 24, 2007, the Partnership 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 the Partnership to request commitments under the Credit Agreement, as supplemented and amended, up to $1 billion.

     The credit agreement restricts the Partnership’s ability to make distributions of available cash to unitholders if it is in any default or an event of default (as defined in the credit agreement) exists. The credit agreement requires the Partnership to maintain a leverage ratio (the ratio of consolidated indebtedness to its consolidated EBITDA, as defined in the credit agreement) of no more than 5.75 to 1.00 on the last day of any fiscal quarter ending on or after September 30, 2007. The credit agreement also requires the Partnership to maintain an interest coverage ratio (the ratio of its consolidated EBITDA to its 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, the Partnership’s 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.

     As of December 31, 2007, the Partnership had approximately $97.8 million available under its revolving credit facility, after giving effect to its outstanding borrowings of $626.3 million and the issuance of $25.9 million of letters of credit.

Note 10—Derivative Instruments and Hedging Activities

     Our OCI balance consists of our proportionate share of the OCI of the Partnership. OCI attributable to the limited partners of the Partnership is included in the caption “Limited partners of Targa Resources Partners LP, including Parent”. At December 31, 2007, our OCI included $1.5 million of unrealized net losses on commodity hedges and a nominal unrealized loss on interest rate hedges. At December 31, 2007, deferred net losses of $0.7 million recorded in OCI are expected to be reclassified to earnings during the next twelve months.

     At December 31, 2007, the Partnership had the following hedge arrangements which will settle during the years ended December 31, 2008 thru 2012:

Natural Gas

Instrument				Avg. Price				MMBtu per day
Type		Index		$/MMBtu				2008				2009				2010				2011				2012				Fair Value
																												(In thousands)
Natural Gas Purchases
Swap		NY-HH			8.34				1,467				—				—				—				—			$	(341	)
									1,467				—				—				—				—				(341	)
Natural Gases Sales
Swap		IF-HSC			8.09				2,328				—				—				—				—				513
Swap		IF-HSC			7.39				—				1,966				—				—				—				(551	)
									2,328				1,966				—				—				—				(38	)
Swap		IF-NGPL MC			8.43				6,964				—				—				—				—				4,475
Swap		IF-NGPL MC			8.02				—				6,256				—				—				—				1,110
Swap		IF-NGPL MC			7.43				—				—				5,685				—				—				(667	)
Swap		IF-NGPL MC			7.34				—				—				—				2,750				—				(387	)
Swap		IF-NGPL MC			7.18				—				—				—				—				2,750				(435	)
									6,964				6,256				5,685				2,750				2,750				4,096
Swap		IF-Waha			8.20				7,389				—				—				—				—				3,000
Swap		IF-Waha			7.61				—				6,936				—				—				—				(618	)
Swap		IF-Waha			7.38				—				—				5,709				—				—				(1,288	)
Swap		IF-Waha			7.36				—				—				—				3,250				—				(709	)
Swap		IF-Waha			7.18				—				—				—				—				3,250				(789	)
									7,389				6,936				5,709				3,250				3,250				(404	)
Total Swaps									16,681				15,158				11,394				6,000				6,000				3,654
Floor		IF-NGPL MC			6.55				1,000				—				—				—				—				218
Floor		IF-NGPL MC			6.55				—				850				—				—				—				171
									1,000				850				—				—				—				389
Floor		IF-Waha			6.85				670				—				—				—				—				140
Floor		IF-Waha			6.55				—				565				—				—				—				93
									670				565				—				—				—				233
Total Floors									1,670				1,415				—				—				—				622
Basis Swap Jan 2008 Rec IF-HH minus $0.01, pay      GD-HH, 403,000 MMBtu																													6
																												$	3,941

NGLs

Instrument				Avg. Price				Barrels per day
Type		Index		$/gal				2008				2009				2010				2011				2012				Fair Value
																												(In thousands)
NGL Sales
Swap		OPIS-MB			1.02				7,127				—				—				—				—			$	(40,051	)
Swap		OPIS-MB			0.96				—				6,248				—				—				—				(20,573	)
Swap		OPIS-MB			0.91				—				—				4,809				—				—				(5,506	)
Swap		OPIS-MB			0.92				—				—				—				3,400				—				(3,210	)
Swap		OPIS-MB			0.92				—				—				—				—				2,700				(2,030	)
									7,127				6,248				4,809				3,400				2,700			$	(71,370	)

Condensate

Instrument				Avg. Price				Barrels per day
Type		Index		$/Bbl				2008				2009				2010				2011				2012				Fair Value
																												(In thousands)
Condensate Sales
Swap		NY-WTI			70.68				384				—				—				—				—			$	(3,013	)
Swap		NY-WTI			69.00				—				322				—				—				—				(2,008	)
Swap		NY-WTI			68.10				—				—				301				—				—				(1,705	)
Total Swaps									384				322				301				—				—				(6,726	)
Floor		NY-WTI			60.50				55				—				—				—				—				2
Floor		NY-WTI			60.00				—				50				—				—				—				9
Total Floors									55				50				—				—				—				11
									439				372				301				—				—			$	(6,715	)

Customer Hedges

Period

Commodity

Instrument Type

Daily Volume

Average Price

Index

Fair Value

(In thousands)

Purchases

Jan 2008 - June 2008

Natural gas

Swap

8,440 MMBtu

7.23 per MMBtu

NY-HH

$

8

Sales

Jan 2008 - June 2008

Natural gas

Fixed price sale

8,440 MMBtu

7.23 per MMBtu

NY-HH

(8

)

$

—

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

     In December 2007, the Partnership entered into interest rate swaps with a notional amount of $200 million. At December 31, 2007, the Partnership had the following open interest rate swaps:

Effective		Expiration		Notional						Fixed
Date		Date		Amount				Index		Rate
12/13/2007		1/24/2011		$	50,000,000			3 Month USD LIBOR			4.0775	%
12/18/2007		1/24/2011		$	50,000,000			3 Month USD LIBOR			4.2100	%
12/21/2007		1/24/2012		$	50,000,000			3 Month USD LIBOR			4.0750	%
12/21/2007		1/24/2012		$	50,000,000			3 Month USD LIBOR			4.0750	%

     These interest rate swaps have each been designated as cash flow hedges of variable rate interest payments on $50 million in borrowings under the Partnership’s revolving credit facility. At December 31, 2007, the fair value of our interest rate swaps was $1.2 million.

Note 11—Income Taxes

     Our deferred income tax assets and liabilities as of December 31, 2007 consist of the following (In thousands):

Deferred tax assets:
Net operating loss		$	487
Deferred tax liabilities:
Investments (1)			(1,239	)
Net deferred tax liability		$	(752	)

Note 12—Share-Based Compensation

     We have adopted a long-term incentive plan (“the Plan”) for employees, consultants and directors of us and our affiliates who perform services for us.

Non-Employee Director Grants

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

Note 13—Commitments and Contingencies

     Our contractual obligations pertain to natural gas pipeline capacity agreements on certain interstate pipelines, operating leases and AROs. Future non-cancelable commitments related to these obligations are presented below.

		Payments due by period
																										2013 &
Contractual Obligations		Total				2008				2009				2010				2011				2012				Thereafter
		(In thousands)
Operating lease obligations		$	142			$	110			$	32			$	—			$	—			$	—			$	—
Capacity payments			16,777				9,201				5,306				1,492				778				—				—
Right of way			4,947				310				269				255				255				252				3,606
Asset retirement obligation			3,263				—				—				—				—				—				3,263
		$	25,129			$	9,621			$	5,607			$	1,747			$	1,033			$	252			$	6,869

     Environmental

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

     Our environmental liability was $0.3 million at December 31, 2007, primarily for ground water assessment and remediation.

     Under the Omnibus Agreement described in Note 7, Targa has indemnified the Partnership for three years from February 14, 2007, against certain potential environmental claims, losses and expenses associated with the operation of the North Texas System and 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 the Partnership’s aggregate losses exceed $250,000. The Partnership has indemnified Targa against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.

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 LLC, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase certain ConocoPhillips assets, 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 and on May 16, 2008 filed it’s appellant’s brief with the 14th Court of Appeals in Houston, Texas. Targa will contest the appeal, but can give no assurances regarding the outcome of the proceeding.

Note 14—Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

     We operate in the midstream energy industry. Its business activities include gathering, transporting and processing of natural gas, NGLs and crude oil. As such, 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 its 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 its financial instrument transactions, management analyzes the counterparty’s financial condition prior to entering into an agreement, establishes credit and/or margin limits and 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 will 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 the Partnership by Targa through the allocation methodology as prescribed in the Omnibus Agreement described in Note 7.

     Under the Omnibus Agreement, Targa has also indemnified the Partnership 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 the Partnership’s aggregate losses exceed $250,000. The Partnership has 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 15—Subsequent Events

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

     On May 15, 2008, we paid a distribution of $0.4175 per common and subordinated unit (approximately $19.9 million, including distribution to the general partner and the holder of the Incentive Distribution Rights) for the first quarter of 2008.