Targa Resources Partners (NGLS-PA) 8-K Other Events

Exhibit 99.1

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

Bbl	Barrels
Btu	British thermal units, a measure of heating value
gal	Gallons
MMBtu	Million British thermal units
NGL(s)	Natural gas liquid(s)
Price Index Definitions
IF-CGT	Inside FERC Gas Market Report, Columbia Gulf Transmission, Louisiana
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

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TARGA RESOURCES GP LLC
CONSOLIDATED BALANCE SHEET
	September 30, 2009
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	57,766
Receivables from third parties		251,332
Inventory		42,251
Assets from risk management activities		48,472
Other current assets		509
Total current assets		400,330
Property, plant and equipment, at cost		2,083,138
Accumulated depreciation		(392,752	)
Property, plant and equipment, net		1,690,386
Long-term assets from risk management activities		18,860
Investment in unconsolidated affiliate		17,811
Other assets		20,931
Total assets	$	2,148,318
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable to third parties	$	123,648
Accounts payable to affiliates		84,549
Accrued liabilities		83,730
Liabilities from risk management activities		10,903
Total current liabilities		302,830
Long-term debt payable to third parties		939,424
Long-term liabilities from risk management activities		15,645
Deferred income taxes		3,559
Other long-term liabilities		6,501
Commitments and contingencies (Note 12)
Equity:
Member's interest		9,804
Accumulated other comprehensive income		187
Total member's equity		9,991
Noncontrolling interest		870,368
Total equity		880,359
Total liabilities and  equity	$	2,148,318
See notes to consolidated balance sheet

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Targa Resources GP LLC

Notes to Consolidated Balance Sheet

(Unaudited)

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

Note 1—Organization and Operations

Targa Resources 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.

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

This unaudited consolidated balance sheet has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information. Accordingly, it does not contain all of the information and footnotes required by GAAP for complete financial statements. The unaudited consolidated balance sheet as of September 30, 2009 includes all adjustments, both normal and recurring, which are, in the opinion of management, necessary for the fair statement of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Transactions between us and other Targa operations have been identified in the unaudited consolidated balance sheet as transactions between affiliates. See Note 14. This unaudited consolidated balance sheet should be read in conjunction with our consolidated balance sheet and notes thereto as of December 31, 2008.

Note 2—Basis of Presentation

We consolidate the accounts of the Partnership and its subsidiaries into our consolidated balance sheet. Notwithstanding this consolidation, we are not liable for, and our assets are not available to satisfy, the obligations of the Partnership and/or its subsidiaries.

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

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

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

The NGL Distribution and Marketing segment markets our own natural gas liquids production and purchased natural gas liquids products in selected United States markets.

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

In preparing the accompanying unaudited consolidated balance sheet, we have reviewed events that have occurred after September 30, 2009, up until December 7, 2009, the date of issuance.

Note 3—Accounting Policies and Related Matters

Accounting Policy Updates/Revisions

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

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

Noncontrolling Interest. Noncontrolling interest represents third party ownership in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third party investor’s interest shown as noncontrolling interest.

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

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

Accounting Pronouncements Recently Adopted

On July 1, 2009, the Financial Accounting Standards Board (“FASB”) issuance of Statement of Financial Accounting Standards (“SFAS”) 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162.” established the FASB Accounting Standards Codification (“Codification” or “ASC”) as the source of authoritative GAAP recognized to be

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applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. On the effective date, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification has become non-authoritative.

Following the issuance of the Codification, FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”). FASB will not consider ASUs as authoritative in their own right. They will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.

Fair Value Measurements

In September 2006, FASB issued SFAS 157 (ASC 820), “Fair Value Measurements.” ASC 820 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 applies to other accounting pronouncements that require or permit fair value measurements, and accordingly, does not require any new fair value measurements. The guidance in ASC 820 was initially effective as of January 1, 2008, but in February 2008, FASB delayed the effective date for applying the guidance to nonfinancial assets and nonfinancial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis, until periods beginning after November 15, 2008. We adopted the guidance in ASC 820 as of January 1, 2008 with respect to financial assets and liabilities within its scope and the impact was not material to our consolidated balance sheet. As of January 1, 2009, nonfinancial assets and nonfinancial liabilities were also required to be measured at fair value. The adoption of these additional provisions did not have a material impact on our consolidated balance sheet. See Note 11.

In April 2009, FASB issued FASB Staff Position ("FSP") FAS 157-4 (ASC 820), “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.” This update to ASC 820 provides guidance for determining fair values when there is no active market or where the price inputs being used represent distressed sales. Specifically, it reaffirms the need to use judgment to ascertain if a formerly active market has become inactive and in determining fair values when markets have become inactive. We adopted the guidance as of June 30, 2009. There have been no material consolidated balance sheet implications relating to our adoption of the guidance.

In April 2009, FASB issued FSP FAS 107-1 and APB 28-1 (ASC 270), “Interim Disclosures about Fair Value of Financial Instruments.” ASC 270 requires disclosures of fair value for any financial instruments not currently reflected at fair value on the balance sheet for all interim periods. We adopted the updated provisions of ASC 270 as of June 30, 2009. There have been no material consolidated balance sheet implications relating to this adoption. See Note 13.

Business Combinations

In December 2007, FASB issued SFAS 141R (ASC 805), “Business Combinations.” ASC 805 requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed and requires the acquirer to disclose certain information related to the nature and financial effect of the business combination. ASC 805 also establishes principles and requirements for how an acquirer recognizes any noncontrolling interest in the acquiree and the goodwill acquired in a business combination. ASC 805 was effective on a prospective basis for business combinations for which the acquisition date is on or after January 1, 2009. For any business combination that takes place subsequent to January 1, 2009, ASC 805 may have a material impact on our consolidated balance sheet. The nature and extent of any such impact will depend upon the terms and conditions of the transaction.

In April 2009, FASB issued FSP FAS 141R-1 (ASC 805), “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies.” This update to ASC 805 amends and clarifies

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application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This update is effective for assets and liabilities arising from contingencies in business combinations for which the acquisition date is on or after January 1, 2009. There have been no material consolidated balance sheet implications relating to the adoption of this update.

Other

In December 2007, FASB issued SFAS 160 (ASC 810), “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51.” ASC 810 requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated statement of financial position, to clearly identify consolidated net income attributable to the parent and to the noncontrolling interest on the face of the consolidated statement of income, and to provide sufficient disclosure that clearly identifies and distinguishes between the interest of the parent and the interests of noncontrolling owners. ASC 810 also establishes accounting and reporting standards for changes in a parent’s ownership interest and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. We adopted ASC 810 as of January 1, 2009. As a result, additional disclosures have been provided.

In March 2008, the FASB’s Emerging Issues Task Force (“EITF”) reached a consensus on EITF 07-4 (ASC 260), “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships.” ASC 260 provides guidance as to how a master limited partnership (“MLP”) should allocate and present earnings per unit using the two-class method when the MLP’s partnership agreement contains incentive distribution rights. Under the two-class method, current period earnings are allocated to the partners according to the distribution formula for available cash set forth in the MLP’s partnership agreement. Our adoption of this guidance on January 1, 2009, did not impact our consolidated balance sheet.

In May 2009, FASB issued SFAS 165 (ASC 855), “Subsequent Events.” ASC 855 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. ASC 855 sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. ASC 855 is effective for interim and annual periods ended after June 15, 2009 and should be applied prospectively. The adoption of ASC 855 did not have a material impact to our consolidated balance sheet.

The FASB has issued ASUs 2009-01 through 2009-15, which are either technical corrections of the Codification and/or do not apply to us.

In June 2009, the SEC Staff issued Staff Accounting Bulletin (“SAB”) 112. SAB 112 amends or rescinds portions of the SEC staff’s interpretive guidance included in the Staff Accounting Bulletin Series in order to make the relevant interpretive guidance consistent with ASC 805 and ASC 810. The adoption of SAB 112 did not have a material impact on our consolidated balance sheet.

Note 4—Acquisition of Downstream Business

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

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

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

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

Note 5—Property, Plant and Equipment

Property, plant, and equipment and accumulated depreciation were as follows as of September30, 2009:

Natural gas gathering systems	$	1,216,457
Processing and fractionation facilities		403,038
Terminalling and natural gas liquids storage facilities		236,978
Transportation assets		150,658
Other property, plant, and equipment		16,410
Land		49,770
Construction in progress		9,827
		2,083,138
Accumulated depreciation		(392,752	)
	$	1,690,386

Note 6—Investment in Unconsolidated Affiliate

As of September 30, 2009 our unconsolidated investment consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast.

Our equity in the net assets of GCF exceeded our acquisition date investment account by $5.2 million.

Note 7—Long-Term Debt

Our consolidated debt obligations consisted of the following as of September 30, 2009:

Senior secured revolving credit facility, variable rate, due February 2012	$	510,483
Senior unsecured notes, 8¼% fixed rate, due July 2016		209,080
Senior unsecured notes, 11¼% fixed rate, due July 2017 (1)		219,861
Total long-term debt	$	939,424
Letters of credit issued	$	58,844

_____________

(1) The carrying amount of the notes includes $11.4 million of unamortized original

 issue discount.

11¼% Senior Unsecured Notes due July 15, 2017

On July 6, 2009, the Partnership completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of 11¼% senior notes due 2017 (the “11¼% Notes”). The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. Proceeds from the 11¼% Notes were used to repay borrowings under the Partnership’s credit facility.

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The 11¼% 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 11¼% 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 11¼% Notes accrues at the rate of 11¼% per annum and is payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2010. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.

At any time prior to July 15, 2012, the Partnership may on any one or more occasions redeem up to 35% of the aggregate principal amount of the 11¼% Notes with the net cash proceeds of certain equity offerings by the Partnership at a redemption price of 111.25% of the principal amount, plus accrued and unpaid interest to the redemption date, provided that:

(1) at least 65% of the aggregate principal amount of the 11¼% Notes (excluding 11¼% Notes held by the Partnership) remains outstanding immediately after the occurrence of such redemption; and

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

Prior to July 15, 2013, the Partnership may also redeem all or a part of the 11¼% Notes at a redemption price equal to 100% of the principal amount of the 11¼% Notes redeemed plus the applicable premium as defined in the indenture agreement as of, and accrued and unpaid interest to, the date of redemption.

On or after July 15, 2013, the Partnership may redeem all or a part of the 11¼% Notes at the redemption prices set forth below (expressed as percentages of principal amount) plus accrued and unpaid interest on the 11¼% Notes redeemed, if redeemed during the twelve-month period beginning on July 15 of each year indicated below:

Year	Percentage
2013		105.625%
2014		102.813%
2015 and thereafter		100.000%

The 11¼% Notes are subject to a registration rights agreement dated as of July 6, 2009. Under the registration rights agreement, the Partnership is required to file by July 9, 2010 a registration statement with respect to any 11¼% Notes that are not freely transferable without volume restrictions by holders of the 11¼% 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 11¼% 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. Any subsequent accrual of a liability under this registration rights agreement will be charged to earnings as interest expense.

11¼% Notes Repurchases

During the third quarter of 2009, we repurchased $18.7 million face value ($17.8 million carrying value, net of issue discount) of our 1¼% Notes for $18.9 million plus accrued interest of $0.3 million.

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Commitment Increase

On July 29, 2009, the Partnership executed a Commitment Increase Supplement (the “Supplement”) to the Partnership’s existing senior secured credit facility. The Supplement increased the commitments under the Partnership’s credit facility by $127.5 million, bringing the total commitments to $977.5 million. The Partnership may request additional commitments under its credit facility of up to $22.5 million, which would increase the total commitments under the credit facility to $1 billion.

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-years 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 nine months ended September 30, 2009:

Outstanding at beginning of period		26,664
Granted		32,000
Vested		(10,672	)
Outstanding at end of period		47,992
Weighted average grant date fair value per share	$	12.88

Note 9—Equity

As of September 30, 2009, member’s equity consisted of the capital account of Targa GP Inc. and its proportionate share of the accumulated other comprehensive income (“OCI”) of the Partnership.

Noncontrolling interest represents third-party and Targa ownership interests in the Partnership. As of September 30, 2009, the components of noncontrolling interest were:

Non-affiliate public unitholders	$	840,324
Targa Resources, Inc.		20,870
Accumulated other comprehensive income		9,174
Noncontrolling interest	$	870,368

Unit Offering

On August 12, 2009, the Partnership completed a unit offering under its shelf registration statement of 6.9 million common units representing limited partner interests in the Partnership at a price of $15.70 per common unit. Net proceeds generated by the offering were $105.3 million, after deducting underwriting discounts, commissions and estimated offering expenses, and including TRGP’s proportionate capital contribution of $2.2 million. The proceeds were used to reduce borrowings of the Partnership’s credit facility by $103.5 million.

Units Issued Relating to Acquisition

On September 24, 2009, the Partnership acquired Targa’s interests in the Downstream Business for $530 million. Consideration to Targa comprised $397.5 million in cash and the issuance to Targa of 174,033 general partner units and 8,527,615 common units. See Note 4.

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Note 10—Derivative Instruments and Hedging Activities

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

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

The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2009, the Partnership hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, the Partnership typically receives an agreed upon fixed price for a specified notional quantity of natural gas or NGL and it pays the hedge counterparty a floating price for that same quantity based upon published index prices. Since the Partnership receives from its customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than the Partnership’s expected natural gas and NGL equity volumes. The Partnership utilizes purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. The Partnership’s commodity hedges may expose us to the risk of financial loss in certain circumstances. The Partnership’s hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise above the prices at which the Partnership has hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

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

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under the Partnership’s senior secured revolving credit facility. To the extent that interest rates increase, interest expense for the Partnership’s revolving debt will also increase. As of September 30, 2009, the Partnership had borrowings of $510.5 million outstanding under its senior secured revolving credit facility. In an effort to reduce the variability of its cash flows, the Partnership entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of the Partnership’s variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period. The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheet. Accordingly, unrealized gains and losses relating to our portion of the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings.

Credit Risk. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to the Partnership at the reporting date. At such times, these outstanding

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instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of the Partnership’s counterparties decline, its ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

As of September 30, 2009, affiliates of Goldman Sachs, Bank of America (“BofA”) and Barclays Bank accounted for 81%, 10% and 7% of our exposure related to the Partnership’s counterparties regarding credit commodity derivative instruments. Goldman Sachs, BofA and Barclays Bank are major financial institutions, each possessing investment grade credit ratings based upon minimum credit ratings assigned by Standard & Poor’s Ratings Services.

The following schedules reflect the fair values of derivative instruments in our consolidated balance sheet:

	Asset Derivatives			Liability Derivatives
	Balance	Fair Value as of		Balance	Fair Value as of
	Sheet	September 30,		Sheet	September 30,
	Location	2009		Location	2009
Derivatives designated as hedging instruments under ASC 815
Commodity contracts	Current assets	$	46,508	Current liabilities	$	1,383
	Long term assets		18,575	Long term liabilities		9,415
Interest rate contracts	Current assets		-	Current liabilities		7,876
	Long term assets		-	Long term liabilities		6,230
Total derivatives designated
as hedging instruments			65,083			24,904
Derivatives not designated as hedging instruments under ASC 815
Commodity contracts	Current assets		1,964	Current liabilities		1,644
	Long term assets		285	Long term liabilities		-
Total derivatives not designated
as hedging instruments			2,249			1,644
Total derivatives		$	67,332		$	26,548

As of September 30, 2009, TRGP’s proportionate share of OCI consisted of $0.4 million of unrealized net gains on commodity hedges and $0.2 million of unrealized net losses on interest rate hedges.

The fair value of our derivative instruments, depending on the type of instrument, are determined by the use of present value methods and standard option valuation models with assumptions about commodity price risk and interest rate risk based on those observed in underlying markets.

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As of September 30, 2009, the Partnership had the following commodity derivative arrangements which will settle during the years ending December 31, 2009 through 2013 (except as indicated otherwise, the 2009 volumes reflect daily volumes for the period from October 1, 2009 through December 31, 2009):

Natural Gas

Instrument		Avg. Price		MMBtu per day
Type	Index	$/MMBtu		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	IF-HSC		7.39		1,966		-		-		-		-	$	500
Swap	IF-NGPL MC		9.18		6,256		-		-		-		-		2,675
Swap	IF-NGPL MC		8.86		-		5,685		-		-		-		6,169
Swap	IF-NGPL MC		7.34		-		-		2,750		-		-		898
Swap	IF-NGPL MC		7.18		-		-		-		2,750		-		605
					6,256		5,685		2,750		2,750		-
Swap	IF-Waha		7.79		9,936		-		-		-		-		2,999
Swap	IF-Waha		6.53		-		11,709		-		-		-		2,630
Swap	IF-Waha		6.10		-		-		11,250		-		-		(1,553	)
Swap	IF-Waha		6.30		-		-		-		7,250		-		(584	)
Swap	IF-Waha		5.59		-		-		-		-		4,000		(1,251	)
					9,936		11,709		11,250		7,250		4,000
Total Swaps					18,158		17,394		14,000		10,000		4,000
Floor	IF-NGPL MC		6.55		850		-		-		-		-		114
Floor	IF-Waha		6.55		565		-		-		-		-		77
Total Floors					1,415		-		-		-		-
Total Sales					19,573		17,394		14,000		10,000		4,000
Basis Swap Oct 09-May 2011, Rec IF-CGT, Pay NYMEX less $0.11, 20,000 MMBtu/d															586
Fuel cost swap Oct 2009-May2011, Rec IF-CGT, Pay $5.96, 226 MMbtu/d															18
														$	13,883

12

NGLs

Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	OPIS-MB		1.32		6,248		-		-		-		-	$	10,931
Swap	OPIS-MB		1.23		-		5,209		-		-		-		28,074
Swap	OPIS-MB		0.89		-		-		3,800		-		-		48
Swap	OPIS-MB		0.92		-		-		-		2,700		-		1,071
Total Swaps					6,248		5,209		3,800		2,700		-
Floor	OPIS-MB		1.44		-		-		199		-		-		1,454
Floor	OPIS-MB		1.43		-		-		-		231		-		1,755
Total Floors					-		-		199		231		-
Total Sales					6,248		5,209		3,999		2,931		-
														$	43,333

Condensate

Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013			Fair Value
Sales
Swap	NY-WTI		69.00		322		-		-		-		-		$	(61	)
Swap	NY-WTI		68.04		-		401		-		-		-	��		(913	)
Swap	NY-WTI		71.00		-		-		200		-		-			(446	)
Swap	NY-WTI		72.60		-		-		-		200		-			(449	)
Swap	NY-WTI		74.00		-		-		-		-		200			(459	)
Total Swaps					322		401		200		200		200
Floor	NY-WTI		60.00		50		-		-		-		-			3
Total Floors					50		-		-		-		-
Total Sales					372		401		200		200		200
															$	(2,325	)

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Customer Hedges

As of September 30, 2009, the Partnership had the following commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements, which have been marked to market through earnings:

Period

Commodity

Instrument Type

Daily Volume

Average Price

Index

Fair Value

Purchases

Oct 2009 - Dec 2009

Natural gas

Swap

2,935

MMBtu

$

9.15

per MMBtu

NY-HH

$

(1,189

)

Jan 2010 - Jun 2010

Natural gas

Swap

663

MMBtu

8.03

per MMBtu

NY-HH

(247

)

Sales

Oct 2009 - Dec 2009

Natural gas

Fixed price sale

2,935

MMBtu

9.15

per MMBtu

NY-HH

1,188

Jan 2010 - Jun 2010

Natural gas

Fixed price sale

663

MMBtu

8.03

per MMBtu

NY-HH

247

$

(1

)

Interest Rate Hedges

The Partnership’s consolidated variable rate indebtedness accrues interest at a base rate plus an applicable margin. The Partnership’s interest rate hedges effectively fix the base rate on the indicated notional amount of borrowings for the indicated periods:

Period	Fixed Rate			Notional Amount			Fair Value
Remainder of 2009		3.66	%	$	300	million	$	(647	)
2010		3.66	%		300	million		(9,166	)
2011		3.41	%		300	million		(4,566	)
2012		3.39	%		300	million		(913	)
2013		3.39	%		300	million		569
01/01-4/24/2014		3.39	%		300	million		617
							$	(14,106	)

We have designated all interest rate swaps and interest rate basis swaps as cash flow hedges.

See Notes 11 and 14 for additional disclosures related to derivative instruments and hedging activities.

Note 11—Fair Value Measurements

We classify our assets and liabilities measured at fair value on a recurring and nonrecurring basis using a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market data exists, therefore requiring us to develop our own assumptions.

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 September 30, 2009. 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.

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	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	67,332	$	-	$	67,332	$	-
Total assets	$	67,332	$	-	$	67,332	$	-
Liabilities from commodity derivative contracts	$	12,442	$	-	$	12,442	$	-
Liabilities from interest rate derivatives		14,106		-		14,106		-
Total liabilities	$	26,548	$	-	$	26,548	$	-

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

	Commodity Derivative Contracts
Balance, December 31, 2008	$	123,304
Unrealized gains (losses) included in OCI		(26,557	)
Settlements		(31,392	)
Transfers out of Level 3		(65,355	)
Balance, September 30, 2009	$	-

During the third quarter of 2009, we reclassified our NGL derivative contracts from Level 3 (unobservable inputs in which little or no market data exists) to Level 2 as we were able to obtain directly observable inputs other than quoted prices in active markets.

Our nonfinancial assets and liabilities measured at fair value on a nonrecurring basis as of September 30, 2009 were not significant.

Note 12—Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Environmental reserves do not reflect management’s assessment of 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.

We do not have a reserve for environmental expenses as of September 30, 2009.

Legal Proceeding

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

15

Note 13—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 value of the credit facility approximates its fair value, as its interest rate is based on prevailing market rates. The fair value of the senior unsecured notes is based on quoted market prices based on trades of such debt.

The carrying 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 consolidated balance sheet are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows as of September 30, 2009:

	Carrying		Fair
	Amount		Value
Senior unsecured notes, 8¼% fixed rate	$	209,080	$	193,922
Senior unsecured notes, 11¼% fixed rate (1)		219,861		242,266

______________

(1) The carrying amount of the notes includes $11.4 million of unamortized

original issue discount as of September 30, 2009.

Note 14—Related Party Transactions

Relationship with Targa

We are a party to various agreements with Targa and others that address (i) the reimbursement of costs incurred on the Partnership’s behalf by TRGP, (ii) our sales of certain NGLs and NGL products to, and purchases from, Targa; and (iii) our sales of our natural gas to, and purchases from, Targa.

Relationship with Bank of America

An affiliate of BofA is an equity investor in Targa Resources Investments Inc., which indirectly owns TRGP.

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

Commodity hedges. We have entered into various commodity derivative transactions with BofA. The following table shows our open commodity derivatives with BofA as of September 30, 2009:

Period	Commodity	Daily Volumes			Average Price			Index
Oct 2009 - Dec 2009	Natural gas		3,556	MMBtu	$	8.07	per MMBtu	IF-Waha
Oct 2009 - Dec 2009	Natural gas		652	MMBtu		8.35	per MMBtu	NY-HH
Jan 2010 - Dec 2010	Natural gas		3,289	MMBtu		7.39	per MMBtu	IF-Waha
Jan 2010 - Jun 2010	Natural gas		497	MMBtu		8.17	per MMBtu	NY-HH
Oct 2009 - Dec 2009	NGL		3,000	Bbl		1.18	per gallon	OPIS-MB
Oct 2009 - Dec 2009	Condensate		202	Bbl		70.60	per barrel	NY-WTI
Jan 2010 - Dec 2010	Condensate		181	Bbl		69.28	per barrel	NY-WTI

As of September 30, 2009, the aggregate fair value of these open positions was $6.0 million.

16

We have entered into several interest rate derivative transactions with BofA. Open positions as of September 30, 2009 consisted of interest rate swaps and interest rate basis swaps expiring on April 24, 2014. As of September 30, 2009, the aggregate fair value of these positions was a liability of $2.7 million.

Relationship with Warburg Pincus LLC

Two of the directors of Targa are Managing Directors of Warburg Pincus LLC and are also directors of Broad Oak Energy, Inc. (“Broad Oak”) from whom we buy natural gas and NGL products. Affiliates of Warburg Pincus LLC own a controlling interest in Broad Oak. As of September 30, 2009, our payable balance with Broad Oak was $0.8 million.

Note 15—Segment Information

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

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

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

The NGL Distribution and Marketing segment markets our own natural gas liquids production and purchased natural gas liquids products in selected United States markets.

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

The “Eliminations and Other” column in the following tables includes corporate level consolidation adjustments as of and for the nine months ended September 30, 2009:

	Natural Gas Gathering and Processing		Logistics Assets		NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other		Total
Identifiable assets	$	1,309,344	$	490,481	$	234,716	$	70,630	$	43,147	$	2,148,318
Unconsolidated investments		-		17,811		-		-		-		17,811
Capital expenditures		21,341		15,853		-		-		-		37,194

17