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form8_k.htm

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): Decenber 31, 2008

TARGA RESOURCES PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	001-33303	65-1295427
(State or other jurisdiction	(Commission	(IRS Employer
of incorporation or organization)	File Number)	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))

TABLE OF CONTENTS

Item 8.01. Other Events

Item 9.01. Financial Statements and Exhibits

Item 8.01. Other Events.

We are filing the consolidated balance sheet of Targa Resources GP LLC as of December 31, 2008, 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, 2008

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.

	TARGA RESOURCES PARTNERS LP

	By: Targa Resources GP LLC,
	its general partner

Dated: May 21, 2009	By:	/s/ John Robert Sparger
		John Robert Sparger
		Senior Vice President and Chief Accounting Officer
		(Authorized signatory and Principal Accounting Officer)

TABLE OF CONTENTS

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, 2008

ex23_1.htm

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 March 31, 2009 relating to the consolidated balance sheet of Targa Resources GP LLC, which appears in this Current Report on Form 8-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

May 21, 2009

ex99_1.htm

Exhibit 99.1

Report of Independent Registered Public Accounting Firm

To the Members 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, 2008 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are 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 provides a reasonable basis for our opinion.

As discussed in Note 10 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

March 31, 2009

As generally used in the energy industry and in this report, the identified terms have the following meanings:

Bbl	Barrels (equal to 42 gallons)
Btu	British thermal units, a measure of heating value
Gal	Gallons
MMBtu	Million British thermal units
NGL	Natural gas liquid(s)

Price Index
Definitions

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

TARGA RESOURCES GP LLC
CONSOLIDATED BALANCE SHEET

	December 31, 2008
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	81,768
Receivables from third parties		58,355
Receivables from affiliated companies		22,295
Inventory		987
Assets from risk management activities		91,816
Other current assets		289
Total current assets		255,510

Property, plant and equipment, at cost		1,492,726
Accumulated depreciation		(248,389	)
Property, plant and equipment, net		1,244,337
Debt issue costs		10,524
Long-term assets from risk management activities		68,296
Other assets		2,239
Total assets	$	1,580,906

LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	8,649
Accrued liabilities		86,191
Liabilities from risk management activities		11,664
Total current liabilities		106,504

Long-term debt		696,845
Long term liabilities from risk management activities		9,679
Deferred income taxes		1,959
Other long-term liabilities		3,555
Commitments and contingencies (Note 11)
Limited partners of Targa Resources Partners LP, including Parent		755,367
Member's equity:
Member interest		5,556
Accumulated other comprehensive income		1,441
Total member's equity		6,997
Total liabilities and member's equity	$	1,580,906
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 limited liability company formed in October 2006 to become the general partner of Targa Resources Partners LP. Our sole member is Targa GP Inc., an indirect wholly-owned subsidiary of Targa Resources, Inc. (“Targa”, or “Parent”). Our primary business purpose is to manage the affairs and operations of Targa Resources Partners LP.

Unless the context requires otherwise, references to “we,” “us,” or “our” are intended to mean and include the business and operations of Targa Resources GP LLC, as well as its consolidated subsidiaries, which include Targa Resources Partners LP and its consolidated subsidiaries.

References to “the Partnership” mean the business and operations of Targa Resources Partners LP and its consolidated subsidiaries. The Partnership is a publicly traded Delaware limited partnership, the registered common units of which are listed on The NASDAQ Stock Market LLC under the ticker symbol “NGLS.” References to “TRGP” mean Targa Resources GP, LLC, individually as the general partner of the Partnership, and not on a consolidated basis. TRGP has no independent operations and no material assets outside of its interest in the Partnership.

The Partnership is engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling natural gas liquids (“NGLs”) and NGL products. The Partnership currently operates in the Fort Worth Basin/Bend Arch in North Texas (“North Texas System”), the Permian Basin of West Texas (“SAOU System”) and in Southwest Louisiana (“LOU System”).

Note 2—Basis of Presentation

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.” 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, 2008 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, 2008 (in thousands):

Limited partners of Targa Resources Partners LP:
Non-affiliate public unitholders	$	822,920
Targa		(67,553	)
Limited partners of Targa Resources Partners LP, including Parent	$	755,367

Note 3—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.

As of December 31, 2008, our aggregate AROs totaled $3.5 million and were included in our Consolidated Balance Sheet as a component of other long-term liabilities.

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.

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.

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 an allowance for doubtful accounts may be required. We do not have an allowance for doubtful accounts as of December 31, 2008.

As of December 31, 2008, affiliates of Goldman Sachs, Merrill Lynch and Barclays Bank accounted for 67%, 21% and 11% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Merrill Lynch 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, a division of the McGraw-Hill Companies, Inc.

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.

Income Taxes. We are generally not subject to income taxes, because our income is taxed directly to our sole member and to Targa as our indirect owner. 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. The Partnership is subject to the Texas margin tax. Accordingly, our consolidated deferred tax liability consists of the Partnership’s estimated liability for this tax.

We recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. We have determined that there are no significant uncertain tax positions requiring recognition in our Consolidated Balance Sheet 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.

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 partners’ capital, 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.

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
Other property and 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.

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.

Segment Information. We operate in one segment only, the natural gas gathering and processing segment.

Unit-Based Employee Compensation. We award unit-based compensation 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 8.

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 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 have not yet conclusively determined the impact that our implementation of SFAS 157 will have on our non-financial assets and liabilities; however we do not anticipate it to significantly impact our 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 financial condition, results of operations, or cash flows, we are now required to provide additional disclosures as part of our financial statements. See Note 13.

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, “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 Consolidated Balance Sheet. See Note 9.

Accounting Pronouncements Recently Issued

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. This new accounting standard will only impact how we account for business combinations on a prospective basis.

Note 4—Property, Plant and Equipment

Property, plant, and equipment and accumulated depreciation were as follows as of December 31, 2008 (in thousands):

Natural gas gathering systems	$	1,161,942
Processing and fractionation facilities		237,321
Other property, plant, and equipment		68,003
Construction in progress		25,460
		1,492,726
Accumulated depreciation		(248,389	)
	$	1,244,337

Note 5—Debt Obligations

Our consolidated debt obligations and issued letters of credit were as follows as of December 31, 2008 (in thousands):

Senior unsecured notes, 8¼% fixed rate, due July 1, 2016	$	209,080
Senior secured credit facility, variable rate, due February 14, 2012		487,765
Total long-term debt	$	696,845
Letters of credit issued	$	9,651

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

On October 16, 2008, the Partnership requested a $100 million funding under its credit facility. Lehman Brothers Commercial Bank, a lender under the 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.

During 2008, the Partnership repurchased $40.9 million face amount of its outstanding Notes in open market transactions at an aggregate purchase price of $28.3 million including $1.5 million of accrued interest. The repurchased Notes were retired and are not eligible for re-issue at a later date.

Description of Debt Obligations

Credit Agreement

The Partnership’s credit agreement, as amended, provides for a five-year $850 million credit facility with a syndicate of financial institutions. The 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%, also dependent on the Partnership’s total leverage ratio. The Partnership’s credit facility is secured by substantially all of its assets.

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 total leverage ratio (the Partnership’s ratio of consolidated indebtedness to 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 the Partnership to maintain an interest coverage ratio (the Partnership’s ratio of consolidated EBITDA to 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.

8¼% Senior Notes due 2016

The Notes:

·	are the Partnership’s unsecured senior obligations;

·	rank pari passu in right of payment with the Partnership’s existing and future senior indebtedness, including indebtedness under its credit facility;

·	are senior in right of payment to any of the Partnership’s future subordinated indebtedness; and

·	are unconditionally guaranteed by the Partnership.

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

Interest on the 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.

At any time prior to July 1, 2011, the Partnership may on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes with the net cash proceeds of one or more equity offerings by the Partnership; 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:

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

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

At any time prior to July 1, 2012, the Partnership may also redeem all or a part of the Notes at a redemption price equal to 100% of the principal amount of the 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, the Partnership may redeem all or a part of the 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 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 Notes are subject to a registration rights agreement dated as of June 18, 2008. Under the registration rights agreement, the Partnership is required to file by June 19, 2009 a registration statement with respect to any Notes that are not freely transferable without volume restrictions by holders of the Notes that are not the Partnership’s affiliates. If the Partnership fails to do so, additional interest will accrue on the principal amount of the Notes. The Partnership has determined that the payment of additional interest is not probable. As a result, the Partnership has not recorded a liability for any contingent obligation.

Note 6—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 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 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. TRGP is currently entitled to 2% of all quarterly distributions that the Partnership makes prior to its liquidation. TRGP has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. TRGP’s 2% interest in these distributions will be reduced if the Partnership issues additional units in the future and TRGP does not contribute a proportionate amount of capital to the Partnership to maintain its 2% general partner interest.

As the holder of the Partnership’s incentive distribution rights, TRGP is entitled to receive an increasing share of Available Cash when pre-defined distribution targets are achieved. The incentive distribution rights are not reduced if the Partnership issues additional units in the future and TRGP 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 incentive distribution rights.

Subordinated Units. All of the subordinated units are indirectly held by Targa. 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. 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 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 May 19, 2009.

Distributions of Available Cash during the Subordination Period. Based on TRGP’s 2% ownership percentage, the partnership agreement requires that the Partnership 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 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, 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).

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.

Note 7—Member’s Equity

As of December 31, 2008, member’s equity consisted of the capital account of Targa GP Inc. and its proportionate share of the OCI of the Partnership.

Note 8—Accounting for Unit-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 the Partnership. In general, restricted unit 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. The following table summarizes information regarding our restricted unit awards for the year ended December 31, 2008:

Outstanding at beginning of period		16,000
Granted		16,000
Vested		(5,336	)
Forfeited		-
Outstanding at end of period		26,664
Weighted average grant date fair value per share	$	22.12

Note 9— 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.” As of December 31, 2008, our OCI included $1.8 million of unrealized net gains on commodity hedges and $0.4 million of unrealized net losses on interest rate hedges.

As of December 31, 2008, the Partnership’s commodity hedges 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
												(In thousands)
	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
												(In thousands)
	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

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

(In thousands)

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

)

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 the Partnership to the risk of financial loss in certain circumstances.

Interest Rate Swaps

As of December 31, 2008, the Partnership had $487.8 million outstanding under its credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates the Partnership has entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

Expiration Date	Fixed Rate			Notional Amount	Fair Value
					(In thousands)
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 following schedules reflect the fair values of derivative instruments in our Consolidated Balance Sheet (in thousands):

	Asset Derivatives			Liability Derivatives
		Fair Value as of			Fair Value as of
	Balance Sheet Location	December 31, 2008		Balance Sheet Location	December 31, 2008
Derivatives designated as hedges under Statement 133
Commodity contracts	Current assets	$	88,206	Current liabilities	$	-
	Other assets		68,296	Other liabilities		123

Interest rate contracts	Current assets		-	Current liabilities		8,020
	Other assets		-	Other liabilities		9,556
Total			156,502			17,699

Derivatives not designated as hedges under Statement 133
Commodity contracts	Current assets		3,610	Current liabilities		3,644
	Other assets		-	Other liabilities		-
Total			3,610			3,644

Total derivatives		$	160,112		$	21,343

See also Note 3, Note 10 and Note 13 for additional disclosures related to derivative instruments and hedging activities.

Note 10—Related-Party Transactions

Relationships with Targa

Reimbursement of Operating and General and Administrative Expense. The Omnibus Agreement, as amended, addresses the reimbursement to Targa for costs incurred on the Partnership’s behalf and indemnification matters. Any or all of the provisions of this agreement, other than the indemnification provisions described in Note 11, are terminable by Targa at its option if TRGP is removed without cause and units held by Targa and its affiliates are not voted in favor of that removal.

Under the Omnibus Agreement, the Partnership reimburses 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.

Pursuant to these arrangements, Targa performs centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. The Partnership reimburses Targa for the direct expenses to provide these services as well as other direct expenses it incurs on the Partnership’s 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.

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 the Partnership 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 the Partnership 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 Targa Texas Field Services and Targa Louisiana Field Services.

Allocation of costs. The employees supporting the Partnership’s operations are employees of Targa. Our consolidated balance sheet is affected by costs allocated to the Partnership 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 the Partnership were based on identification of Targa’s resources which directly benefit the Partnership and the Partnership’s proportionate share of costs based on its estimated usage of shared resources and functions. All of the allocations were 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 the Partnership had been operated as a stand-alone entity.

Relationships with Warburg Pincus

Chansoo Joung and Peter Kagan, two of the directors of Targa, are Managing Directors of Warburg Pincus LLC (“Warburg Pincus”) and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom the Partnership buys natural gas and NGL products. Affiliates of Warburg Pincus own a controlling interest in Broad Oak. The Partnership purchased $4.8 million of product from Broad Oak during 2008. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Relationships with Noble Energy, Inc.

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. The Partnership had net purchases of less than $0.1 million of natural gas and NGL products from Noble during 2008. These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Other

Commodity hedges. An affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”) holds an equity interest in Targa Resources Investments Inc., which, through its ownership of Targa, indirectly owns TRGP. The Partnership has entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”) an affiliate of Merrill Lynch. The following table shows the Partnership’s open commodity derivatives with MLCI 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 is $32.0 million. During 2008, the Partnership paid MLCI $9.1 million in commodity derivative settlements.

Note 11—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
	(In thousands)
Capacity payments	$	8,215	$	5,419	$	2,050	$	746	$	-	$	-	$	-
Right-of-way		4,889		348		331		330		319		233		3,328
	$	13,104	$	5,767	$	2,381	$	1,076	$	319	$	233	$	3,328

Environmental

Under the Omnibus Agreement described in Note 10, 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 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. The Partnership has indemnified Targa against environmental liabilities related to the North Texas System arising or occurring after February 14, 2007.

The Partnership’s environmental liabilities not covered by the Omnibus Agreement are for ground water assessment and remediation and were 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, 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. The Partnership is 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.

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

Note 12—Fair Value of Financial Instruments

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

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows as of December 31, 2008 (in thousands):

	Carrying		Fair
	Amount		Value

Credit facility	$	487,765	$	487,765
Senior unsecured notes		209,080		128,333

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

Note 13—Fair Value Measurements

SFAS 157 established a three-tier fair value hierarchy, which prioritized the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other

than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.

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 (in thousands):

	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	$	-

The following table sets forth for the year ended December 31, 2008 a reconciliation of the changes in the fair value of our financial instruments classified as Level 3 in the fair value hierarchy (in thousands):

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

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

Note 14— Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry. Our 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 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 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 the Partnership’s behalf, which provides the Partnership 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 or the Partnership 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 the Partnership, 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 10.

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.