TRI Resources (NGLS) 10-Q 2009 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

Or

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

  For the transition period from                      to                     

Commission File Number 333-147066

TARGA RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	74-3117058
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1000 Louisiana, Suite 4300, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code:

(713) 584-1000

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes o    No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨    Accelerated filer ¨    Non-accelerated filer þ    Smaller reporting company ¨

                     (Do not check if a smaller reporting company)

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

PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008	4
	Consolidated Statements of Operations for the three and nine months ended September 30, 2009 and 2008	5
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	58
Item 4T.	Controls and Procedures	65
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	66
Item 1A.	Risk Factors	66
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 3.	Defaults Upon Senior Securities	67
Item 4.	Submission of Matters to a Vote of Security Holders	67
Item 5.	Other Information	67
Item 6.	Exhibits	68
SIGNATURES		71

1

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

Bbl	Barrels
BBtu	Billion British thermal units, a measure of heating value
/d	Per day
gal	Gallons
MBbl	Thousand barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
Price Index
Definitions
HH-GD	Henry Hub-Gas Daily
IF-CGT	Inside FERC Gas Market Report, Columbia Gulf Transmission, Louisiana
IF-HH	Inside FERC Gas Market Report, Henry Hub
IF-HSC	Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-PB	Inside FERC Gas Market Report, Permian Basin
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

As used in this Quarterly Report, unless the context otherwise requires, “Targa,” “we,” “us,” “our,” and similar terms refer to Targa Resources, Inc., together with its consolidated subsidiaries, including our publicly traded master limited partnership, Targa Resources Partners LP, which we refer to in this Quarterly Report as the “Partnership.”

Cautionary Statement About Forward-Looking Statements

Our reports, filings and other public announcements may from time to time contain statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.

All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.

These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed or implied in the forward-looking statements include known and unknown risks. These risks and uncertainties, many of which are beyond our control, include, but are not limited to the risks set forth in “Item 1A. Risk Factors” as well as the following:

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

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

• our success in risk management activities, including the use of derivative financial instruments to hedge commodity and interest rate risks;

2

• the level of creditworthiness of counterparties to transactions;

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

• the timing and extent of changes in natural gas, natural gas liquids and other commodity prices, interest rates and demand for our services;

• weather and other natural phenomena;

• industry changes, including the impact of consolidations and changes in competition;

• our ability to obtain necessary licenses, permits and other approvals;

• the level and success of crude oil and natural gas drilling around our assets and our success in connecting natural gas supplies to our gathering and processing systems and NGL supplies to our logistics and marketing facilities;

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

• general economic, market and business conditions; and

• the risks described in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2008 (“the Annual Report”).

Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and, therefore, we cannot assure you that the forward-looking statements included in this Quarterly Report will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading Risk Factors in this Quarterly Report and our Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

TARGA RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
	September 30,			December 31,
	2009			2008
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	187,927		$	362,769
Trade receivables, net of allowances of $9,122 and $9,380		303,332			303,904
Inventory		40,830			68,519
Assets from risk management activities		58,531			112,341
Other current assets		27,858			9,615
Total current assets		618,478			857,148
Property, plant and equipment, at cost		3,167,224			3,093,264
Accumulated depreciation		(603,355	)		(475,895	)
Property, plant and equipment, net		2,563,869			2,617,369
Long-term assets from risk management activities		28,087			89,774
Investment in debt obligations of Targa Resources Investments Inc.		62,191			10,953
Other assets		58,893			73,333
Total assets	$	3,331,518		$	3,648,577
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	148,260		$	153,756
Accrued liabilities		244,057			253,384
Current maturities of debt		12,500			12,500
Liabilities from risk management activities		18,331			11,664
Deferred income taxes		14,231			36,240
Total current liabilities		437,379			467,544
Long-term debt, less current maturities		1,242,224			1,552,440
Long-term liabilities from risk management activities		24,440			9,679
Deferred income taxes		52,042			40,027
Other long-term liabilities		59,817			49,638
Commitments and contingencies (see Note 15)
Stockholders' equity:
Targa Resources, Inc. stockholder's equity:
Common stock ($0.001 par value, 1,000 shares authorized, issued,
and outstanding at September 30, 2009 and December 31, 2008, collateral
for Targa Resources Investments Inc. debt)		-			-
Additional paid-in capital		420,314			420,067
Retained earnings		141,126			127,640
Accumulated other comprehensive income		3,027			31,934
Total Targa Resources, Inc. stockholder's equity		564,467			579,641
Noncontrolling interest in subsidiaries		951,149			949,608
Total stockholders' equity		1,515,616			1,529,249
Total liabilities and stockholders' equity	$	3,331,518		$	3,648,577
See notes to consolidated financial statements

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TARGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(Unaudited)
	(In thousands)
Revenues	$	1,121,477		$	2,352,987		$	3,127,020		$	6,818,606
Costs and expenses:
Product purchases		932,121			2,176,830			2,606,905			6,201,360
Operating expenses		63,506			73,583			182,673			208,390
Depreciation and amortization expenses		44,255			41,086			127,908			118,028
General and administrative expenses		31,429			26,679			83,478			78,696
Other (see Note 19)		(3	)		17,886			1,804			13,441
		1,071,308			2,336,064			3,002,768			6,619,915
Income from operations		50,169			16,923			124,252			198,691
Other income (expense):
Interest expense, net		(29,386	)		(24,599	)		(77,138	)		(73,844	)
Equity in earnings of unconsolidated investments		1,417			2,534			3,221			13,189
Loss on debt repurchases (See Note 8)		(1,483	)		-			(1,483	)		-
Loss on early debt extinguishment (See Note 8)		(14,808	)		-			(14,808	)		-
Gain on insurance claims (see Note 12)		-			-			-			18,566
Gain (loss) on mark-to-market derivative instruments		805			(1,311	)		805			(1,311	)
Other income		564			-			1,568			-
Income (loss) before income taxes		7,278			(6,453	)		36,417			155,291
Income tax (expense) benefit:
Current		(212	)		1,053			(328	)		(184	)
Deferred		1,409			8,829			(4,880	)		(30,225	)
		1,197			9,882			(5,208	)		(30,409	)
Net income		8,475			3,429			31,209			124,882
Less: Net income attributable to noncontrolling interest		11,068			24,309			17,723			81,148
Net income (loss) attributable to Targa Resources, Inc.	$	(2,593	)	$	(20,880	)	$	13,486		$	43,734
See notes to consolidated financial statements

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TARGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Nine Months Ended
	September 30,
	2009			2008
	(Unaudited)
	(In thousands)
Cash flows from operating activities
Net income	$	31,209		$	124,882
Adjustments to reconcile net income to net cash provided
by operating activities:
Amortization in interest expense		5,052			5,899
Interest income on paid-in-kind investment		(2,209	)		(165	)
Amortization in general and other administrative expense		710			1,179
Depreciation and amortization expense		126,382			118,028
Accretion of asset retirement obligations		2,200			1,189
Deferred income tax expense		4,880			30,225
Equity in earnings of unconsolidated investments, net of distributions		654			(10,476	)
Risk management activities		35,129			(76,754	)
Gain on sale of assets		(41	)		(4,458	)
Loss on debt repurchases		1,483			-
Loss on early debt extinguishment		14,808			-
Gain on property damage insurance settlement (See Note 12)		-			(18,566	)
Asset impairment charges		1,526			5,112
Changes in operating assets and liabilities:
Accounts receivable and other assets		(33,788	)		268,581
Inventory		17,912			22,412
Accounts payable and other liabilities		3,171			(204,547	)
Net cash provided by operating activities		209,078			262,541
Cash flows from investing activities
Additions to property, plant and equipment		(74,874	)		(93,848	)
Acquisitions, net of cash acquired		-			(124,938	)
Proceeds from property insurance		23,800			48,294
Investment in debt obligations of Targa Resources Investments Inc.		(39,296	)		(16,400	)
Other		366			581
Net cash used in investing activities		(90,004	)		(186,311	)
Cash flows from financing activities
Repayments of senior secured debt		(456,875	)		(9,375	)
Repayments of senior secured credit facility		(95,920	)		-
Senior secured credit facility of the Partnership:
Borrowings		397,618			87,500
Repayments		(374,900	)		(323,800	)
Repurchases of senior notes of the Partnership		(18,882	)		-
Proceeds from issuance of senior notes of the Partnership		237,433			250,000
Distributions to noncontrolling interest		(73,746	)		(75,039	)
Contributions from noncontrolling interest		104,242			-
Distribution to Targa Resources Investments Inc.		(214	)		(52,774	)
Costs incurred in connection with financing arrangements		(12,672	)		(7,202	)
Net cash used in financing activities		(293,916	)		(130,690	)
Net change in cash and cash equivalents		(174,842	)		(54,460	)
Cash and cash equivalents, beginning of period		362,769			177,949
Cash and cash equivalents, end of period	$	187,927		$	123,489
See notes to consolidated financial statements

6

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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 Basis of Presentation

Targa Resources, Inc. is a Delaware corporation formed on February 26, 2004. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intended to mean the consolidated business and operations of Targa Resources, Inc.

We are a second-tier, wholly owned subsidiary of our parent holding company, Targa Resources Investments Inc. (“Targa Investments”). The only significant asset of Targa Investments is its ownership of 100% of the outstanding capital stock of an intermediate holding company, whose sole asset is its ownership of 100% of our outstanding capital stock, which consists of one thousand shares of common stock.

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. The unaudited consolidated financial statements for the three and nine months ended September 30, 2009 and 2008 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair statement of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Our financial results for the three and nine months ended September 30, 2009 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2009. These unaudited consolidated financial statements and other information included in this Quarterly Report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report for the year ended December 31, 2008.

We currently own approximately 33.9% of Targa Resources Partners LP (the “Partnership”), including our 2% general partner interest. Targa Resources GP LLC, the general partner of the Partnership, is wholly owned by us. The Partnership is consolidated within our financial statements under the presumption of control in accordance with GAAP.

The noncontrolling interest in our consolidated balance sheets consists primarily of the investment by partners other than Targa Resources, Inc., including those partners’ share of the net income, distributions and accumulated other comprehensive income (loss) of the Partnership. Noncontrolling interest in net income on our consolidated statements of operations consists primarily of those partners’ share of the net income of the Partnership.

In preparing the accompanying unaudited consolidated financial statements, the Company has reviewed, as determined necessary by the Company, events that have occurred after September 30, 2009, up until the issuance of the financial statements, which occurred on November 9, 2009. See Notes 4 and 13.

Note 2—Out of Period Adjustments

We recorded adjustments related to prior periods which decreased our income before income taxes for the three and nine month periods ended September 30, 2009 by $4.5 million and $5.4 million, recorded as loss on early extinguishment of debt.  The adjustments consisted of $6.3 million and $7.2 million in the respective periods related to debt issue costs that should have been expensed during 2007, and $1.8 million and $1.8 million in the respective periods of revenue which should have been recorded during 2006.

Had these adjustments been previously recorded in their appropriate periods, net income (loss) attributable to Targa for the three and nine month periods ended September 30, 2009 would have increased by $2.8 million and $3.4 million.

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After evaluating the quantitative and qualitative aspects of these errors, we concluded that our previously issued financial statements were not materially misstated and the effect of recognizing these adjustments during the third quarter of 2009 on full year 2009 are not expected to be material.

Note 3—Accounting Policies and Related Matters

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 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 financial statements. 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 financial statements. See Note 14.

In March 2009, FASB released Proposed Staff Position SFAS 157-e (ASC 820), “Determining Whether a Market Is Not Active and a Transaction Is Not Distressed.”  This proposal provides additional guidance in determining whether a market for a financial asset is not active and a transaction is not distressed for fair value measurement purposes as defined in ASC 820. This guidance is effective for interim periods ending after June 15, 2009, but early adoption is permitted for interim periods ending after March 15, 2009.  We adopted this guidance as of April 1, 2009. This guidance did not have a significant impact on our financial statements.

In March 2009, FASB issued Proposed Staff Position SFAS 115-a, SFAS 124-a, and EITF 99-20-b (ASC 320), “Recognition and Presentation of Other-Than-Temporary Impairments.”  This update to ASC 320 provides guidance in determining whether impairments in debt securities are other than temporary, and modifies the presentation and disclosures surrounding such instruments.  This guidance is effective for interim periods ending after June 15, 2009, but early adoption is permitted for interim periods ending after March 15, 2009.  We adopted the provisions of this guidance as of April 1, 2009. Our adoption did not have a significant impact on our financial statements.

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 financial statement 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 financial statement implications relating to this adoption. See Note 16.

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 financial statements. 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 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 financial statement 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, previously presented amounts have been conformed to the required presentation and additional disclosures have been provided.

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 on our financial statements.

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 financial statements.

Note 4—Partnership Units and Related Matters

Under the terms of the Partnership’s amended and restated partnership agreement, all 11,528,231 of our subordinated units converted to common units on a one-for-one basis on May 19, 2009.

The following table lists the Partnership’s distributions declared and paid in the nine months ended September 30, 2009 and 2008:

		Distributions Paid										Distributions
	For the Three	Limited Partners				General Partner						per limited
Date Paid	Months Ended	Common		Subordinated		Incentive			2%	Total		partner unit
		(In thousands, except per unit amounts)
2009
August 14, 2009	June 30, 2009	$	23,915	$	-	$	1,933	$	528	$	26,376	$	0.5175
May 15, 2009	March 31, 2009		17,949		5,966		1,933		528		26,376		0.5175
February 13, 2009	December 31, 2008		17,949		5,965		1,933		528		26,375		0.5175
2008
August 14, 2008	June 30, 2008		17,759		5,908		1,711		518		25,896		0.5125
May 15, 2008	March 31, 2008		14,467		4,813		208		398		19,886		0.4175
February 14, 2008	December 31, 2007		13,768		4,582		66		376		18,792		0.3975

Public Offering of Common Units. 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 of the offering were $105.3 million, after deducting underwriting discounts, commissions and estimated offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. The Partnership used a portion of the proceeds to repay $103.5 million of outstanding borrowings under its senior secured revolving credit facility.

Sale of Downstream Business.On September 24, 2009, the Partnership acquired our interests in Targa Downstream GP LLC, Targa LSNG GP LLC, Targa Downstream LP and Targa LSNG LP (collectively, the “Downstream Business”) for $530 million. Total consideration paid by the Partnership to us consisted of $397.5 million in cash and the issuance to us of 174,033 general partner units of the Partnership and 8,527,615 common units of the Partnership. We continue to consolidate the Partnership due to our ability to exercise significant control over the Partnership through our general partner interest.

Subsequent Event. On October 19, 2009, the Partnership announced a cash distribution of $0.5175 per unit on its outstanding common units. The distribution will be paid on November 13, 2009 to unitholders of record on November 4, 2009, for the three months ended September 30, 2009. The total distribution to be paid is $35.2 million, with  $21.5 million paid to the Partnership’s non-affiliated common unitholders and $10.4 million, $0.7 million and $2.6 million to be paid to us in respect of our common units, general partner interest and incentive distribution rights.

8

Note 5—Investment in Debt Securities of Targa Investments

During the nine months ended September 30, 2009, we paid $39.3 million to acquire $64.5 million face value of Targa Investments’ outstanding variable rate indebtedness. As of September 30, 2009, we have acquired in total $84.3 million of the outstanding principal amount of Targa Investments’ variable rate indebtedness for $55.7 million, including accrued interest.

The stated maturity date of the indebtedness is February 2015, and as of September 30, 2009, the variable rate was 5.2%. We have classified this investment as an available-for-sale security. During the three and nine months ended September 30, 2009, we recognized unrealized gains (losses) of ($2.0) million and $7.6 million in accumulated comprehensive income (“OCI”), based on an indicative valuation supplied by a bank. As of September 30, 2009, OCI included $0.9 million ($0.6 million, net of tax) of net unrealized gains related to our investment in Targa Investments’ debt.

As of September 30, 2009, the fair value and unrealized gains (losses) on our investment in Targa Investments’ debt were:

Held Less Than				Held Twelve Months
Twelve Months				or Greater					Total
Fair		Unrealized		Fair		Unrealized			Fair		Unrealized
Value		Gain (Loss)		Value		Gain (Loss)			Value (1)		Gain (Loss)
$	43,276	$	3,980	$	13,295	$	(3,105	)	$	56,571	$	875

____________

(1) Excludes $3.2 million of interest paid-in-kind and $2.5 million of discount amortization.

Note 6—Unconsolidated Investment

Our unconsolidated investment as of September 30, 2009 and December 31, 2008 consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast.

The following table shows our unconsolidated investment in GCF at the dates indicated:

September 30,		December 31,
2009		2008
$	17,811	$	18,465

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

Prior to July 31, 2008 our unconsolidated investment also included a 22.8959% ownership interest in Venice Energy Services Company, LLC (“VESCO”), a venture that operates a natural gas liquids processing and extraction facility. On July 31, 2008, we acquired an additional 53.8577% interest, giving us effective control. We have consolidated the operations of VESCO in our financial results effective August 1, 2008.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Equity in earnings of:
VESCO (1) (2)	$	-	$	1,432	$	-	$	10,161
GCF		1,417		1,102		3,221		3,028
	$	1,417	$	2,534	$	3,221	$	13,189
Cash distributions:
GCF	$	3,100	$	1,938	$	3,875	$	2,713

____________

(1) Includes our equity earnings through July 31, 2008.

(2) Includes business interruption insurance claims of $0 and $4.1 million for the three and nine months ended September 30, 2008.

Note 7—Income Tax Expense

Our implementation of SFAS 160 (ASC 810) had a significant impact on our presentation of income tax expense. Whereas in prior years our consolidated income before income taxes was presented after the deduction of minority interest expense, the new income statement format required under this standard presents this expense (now called “net income attributable to noncontrolling interest”) after the presentation of income tax expense. Because our non-wholly owned consolidated subsidiaries are limited liability companies and limited partnerships that are generally not subject to entity level taxation, income tax expense has not been provided on net income attributable to noncontrolling interest. As a result, our effective tax rate is lower even though the determination of our total provision for income taxes has not changed.

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Note 8—Long-Term Debt

Our consolidated debt obligations consisted of the following as of the dates indicated:

	September 30,			December 31,
	2009			2008
Long-term debt:
Obligations of Targa:
Senior secured term loan facility, variable rate, due October 2012	$	65,300		$	522,175
Senior unsecured notes, 8½% fixed rate, due November 2013		250,000			250,000
Senior secured revolving credit facility, variable rate, due October 2011		-			95,920
Obligations of the Partnership: (1)
Senior secured revolving credit facility, variable rate, due February 2012		510,483			487,765
Senior unsecured notes, 8¼% fixed rate, due July 2016		209,080			209,080
Senior unsecured notes, 11¼% fixed rate, due July 2017 (2)		219,861			-
Total debt		1,254,724			1,564,940
Current maturities of debt		(12,500	)		(12,500	)
Total long-term debt	$	1,242,224		$	1,552,440
Irrevocable standby letters of credit:
Letters of credit outstanding under senior secured synthetic letter of credit facility (3)	$	38,099		$	114,019
Letters of credit outstanding under senior secured revolving credit
facility of the Partnership		58,844			9,651
	$	96,943		$	123,670

____________

(1) We consolidate the debt of the Partnership with that of our own; however, the Partnership’s debt is non-recourse to Targa.

(2) The carrying amount of the notes includes $11.4 million of unamortized original issue discount as of September 30, 2009.

(3) The $50 million senior secured synthetic letter of credit facility terminates in October 2012.

Information Regarding Variable Interest Rates Paid

The following table shows the range of interest rates paid and weighted average interest rates paid on our significant consolidated variable-rate debt obligations during the nine months ended September 30, 2009:

	Range of interest rates paid	Weighted average interest rate paid
Senior secured term loan facility	2.2% to 6.0%		3.6	%
Senior secured revolving credit facility	2.1% to 3.5%		3.1	%
Senior secured revolving credit facility of the Partnership	1.2% to 4.5%		1.8	%

Senior Secured Term Loan Facility

During the third quarter we repaid substantially all of our senior secured term loan facility and recognized a $14.8 million loss on early debt extinguishment consisting of the write-off of debt issue costs related to the facility. In addition, the loss includes an out of period adjustment related to prepayments made during 2007. See Note 2.

Senior Secured Synthetic Letter of Credit Facility

During the third quarter 2009, we elected to reduce the commitments under the senior secured synthetic letter of credit facility from $300 million to $50 million.

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11¼% Senior Unsecured Notes of the Partnership 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.

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 senior secured revolving 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 indebtedness under the Partnership’s credit agreement, which is secured by substantially all of its 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 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 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,

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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, the Partnership repurchased $18.7 million face value ($17.8 million carrying value, net of issue discount) of its 11¼% Notes for $18.9 million plus accrued interest of $0.3 million. The Partnership recognized a loss on the debt repurchases of $1.5 million, including $0.4 million in debt issue costs associated with the repurchased notes.

Commitment Increase by the Partnership

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

Note 9—Asset Retirement Obligations

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

	Nine Months Ended
	September 30, 2009
Beginning of period	$	33,985
Change in cash flow estimate (1)		(2,853	)
Accretion expense		2,200
End of period	$	33,332

____________

(1) Results primarily from a reassessment of the estimated abandonment dates of certain of our offshore natural gas gathering systems.

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Note 10—Changes in Stockholders’ Equity

The following tables reflect the reconciliation at the beginning and the end of the period of the carrying amount of total equity, the components of equity attributable to Targa Resources, Inc. and equity attributable to noncontrolling interest:

						Accumulated
						Other			Additional
				Retained		Comprehensive			Paid-in			Noncontrolling
Nine Months Ended September 30, 2009	Total			Earnings		Income			Capital			Interest
Balance, December 31, 2008	$	1,529,249		$	127,640	$	31,934		$	420,067		$	949,608
Contributions		104,242			-		-			-			104,242
Distributions		(73,960	)		-		-			(214	)		(73,746	)
Amortization of equity awards		710			-		-			461			249
Tax expense on vesting of common stock		-			-		-			-			-
Subtotal		1,560,241			127,640		31,934			420,314			980,353
Comprehensive income (loss):
Net income		31,209			13,486		-			-			17,723
Other comprehensive income (loss):
Change in fair value:
Commodity hedging contracts		(43,683	)		-		(16,496	)		-			(27,187	)
Interest rate swaps		(7,825	)		-		(7,084	)		-			(741	)
Available for sale securities		7,575			-		7,575			-			-
Reclassification adjustment for settled periods:
Commodity hedging contracts		(59,112	)		-		(34,930	)		-			(24,182	)
Interest rate swaps		12,337			-		7,154			-			5,183
Related income taxes		14,874			-		14,874			-			-
Total comprehensive income (loss)		(44,625	)		13,486		(28,907	)		-			(29,204	)
Balance, September 30, 2009	$	1,515,616		$	141,126	$	3,027		$	420,314		$	951,149

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						Accumulated
						Other			Additional
				Retained		Comprehensive			Paid-in			Noncontrolling
Nine Months Ended September 30, 2008	Total			Earnings		Loss			Capital			Interest
Balance, December 31, 2007	$	1,307,530		$	74,736	$	(56,116	)	$	473,784		$	815,126
VESCO Acquisition		41,856			-		-			-			41,856
Distributions		(127,813	)		-		-			(52,774	)		(75,039	)
Amortization of equity awards		1,179			-		-			979			200
Tax expense on vesting of common stock		(526	)		-		-			(526	)		-
Subtotal		1,222,226			74,736		(56,116	)		421,463			782,143
Comprehensive income (loss):
Net income		124,882			43,734		-			-			81,148
Other comprehensive income (loss):
Change in fair value:
Commodity hedging contracts		(50,530	)		-		(24,622	)		-			(25,908	)
Interest rate swaps		(1,976	)		-		(523	)		-			(1,453	)
Available for sale securities		(2,065	)		-		(2,065	)		-			-
Reclassification adjustment for settled periods:
Commodity hedging contracts		87,704			-		51,157			-			36,547
Interest rate swaps		1,485			-		393			-			1,092
Foreign currency translation adjustment		(477	)		-		(477	)		-			-
Related income taxes		(7,375	)		-		(7,375	)		-			-
Total comprehensive income (loss)		151,648			43,734		16,488			-			91,426
Balance, September 30, 2008	$	1,373,874		$	118,470	$	(39,628	)	$	421,463		$	873,569

Note 11—Stock and Other Compensation Plans

Stock Option Plans

Share-based compensation cost related to stock options included in general and administrative expense for the three and nine months ended September 30, 2009 was $0.1 million. Share-based compensation cost related to stock options included in general and administrative expense for the three and nine months ended September 30, 2008 was less than $0.1 million and $0.2 million. As of September 30, 2009, our remaining unamortized compensation cost related to stock options was $0.2 million, which is expected to be recognized over a weighted-average period of approximately three months.

Non-vested (Restricted) Common Stock

Share-based compensation cost related to restricted stock included in general and administrative expense for the three and nine months ended September 30, 2009 was $0.1 million and $0.3 million. Share-based compensation cost related to restricted stock included in general and administrative expense for the three and nine months ended September 30, 2008 was $0.2 million and $0.8 million. As of September 30, 2009, our remaining unamortized compensation cost related to restricted stock was $0.1 million, which is expected to be recognized over a weighted-average period of approximately two months.

Incentive Plans related to the Partnership’s Common Units

Non-Employee Director Grants. In January 2009, the general partner of the Partnership awarded 32,000 restricted common units of the Partnership (4,000 restricted common units to each of the Partnership’s non-management directors and to each of Targa Investments’ independent directors).

Compensation expense on the restricted common units is recognized on a straight-line basis over the vesting period. The fair value of an award of restricted common units is measured on the grant date using the market price of a common unit on such date. For the three and nine months ended September 30, 2009, we recognized compensation expense of $0 and $0.2 million related to these awards. The remaining fair value of $0.3 million will be recognized in expense over a weighted average period of approximately one year. For the three and nine months ended September 30, 2008, we recognized compensation expense of $0.1 million and $0.2 million related to these awards.

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Performance Units.  There were 536,100 performance units awarded during the nine months ended September 30, 2009, under Targa Investments’ long-term incentive plan. Upon vesting, each performance unit will entitle the awardee to a cash payment equal to the then value of a Partnership common unit, including distribution equivalent rights. Vesting of performance units is based on the total return per common unit of the Partnership through the end of the performance period, relative to the total return of a defined peer group.

As of September 30, 2009, the aggregate fair value of performance units expected to vest was $29.4 million. For the three and nine months ended September 30, 2009, we recognized compensation expense related to the performance units of $4.6 million and $6.4 million. The weighted average recognition period for the remaining unrecognized compensation cost is approximately two years. For the three and nine months ended September 30, 2008, we recognized compensation expense related to the performance units of ($0.2) million and $0.7 million.

Note 12—Insurance Claims

Certain of our Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During the nine months ended September 30, 2009, the estimate was reduced by $3.7 million.

During the three and nine months ended September 30, 2009, expenditures related to the hurricanes included $3.7 million and $32.8 million for previously accrued repair costs, and $0.5 million and $7.8 million capitalized as improvements.

Our initial purchase price allocation for the DMS acquisition in October 2005 included an $81.1 million receivable for insurance claims related to expenditures to repair pre-acquisition property damage caused by Hurricanes Katrina and Rita in 2005. During the nine months ended September 30, 2008, our cumulative receipts exceeded such amount and accordingly, we recognized a gain of $18.6 million.

During the three and nine months ended September 30, 2009 and 2008, we recognized revenue from business interruption insurance receipts of:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Included in revenues
Natural Gas Gathering and Processing (1)	$	2,900	$	749	$	5,474	$	3,289
Logistics Assets		-		-		1,926		441
NGL Distribution and Marketing		-		-		-		8,602
Wholesale Marketing (2)		-		-		500		5,920
	$	2,900	$	749	$	7,900	$	18,252
Included in equity in earnings of unconsolidated investments
Natural Gas Gathering and Processing	$	-	$	-	$	-	$	4,108
	$	2,900	$	749	$	7,900	$	22,360

____________

(1) Includes $0.7 million for the three and nine months ended September 30, 2008 in non-hurricane business interruption insurance revenue in our natural gas gathering and processing segment.

(2) Includes $0.5 million for the nine months ended September 30, 2009 in non-hurricane business interruption insurance revenue in our wholesale marketing segment.

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Note 13—Derivative Instruments and Hedging Activities

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

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

The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2009, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2009 through 2013 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are hedged decrease over time. With swaps, we typically receive an agreed upon fixed price for a specified notional quantity of natural gas or NGL and we pay the hedge counterparty a

floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge additional expected equity commodity volumes without creating volumetric risk. Our commodity hedges may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if market prices decline below the prices at which these hedges are set. If market prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

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

Interest Rate Risk. We are exposed to changes in interest rates, primarily as a result of variable rate borrowings under our and the Partnership’s credit facilities. To the extent that interest rates increase, interest expense for our revolving debt will also increase. As of September 30, 2009, we had outstanding variable rate borrowings of $65.3 million and the Partnership had outstanding variable rate borrowings of $510.5 million. In an effort to reduce the variability of our cash flows, we have entered into several interest rate swap and interest rate basis swap agreements. Under these agreements, which are accounted for as cash flow hedges, the base interest rate on the specified notional amount of our variable rate debt is effectively fixed for the term of each agreement and ineffectiveness is required to be measured each reporting period.  The fair values of the interest rate swap agreements, which are adjusted regularly, have been aggregated by counterparty for classification in our consolidated balance sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings.

Credit Risk. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value to us at the reporting date.  At such times, these outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the

17

creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

As of September 30, 2009, affiliates of Goldman Sachs, Barclays Bank and Bank of America (“BofA”) accounted for 70%, 15% and 13% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, Barclays Bank and BofA 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 financial statements:

	Asset Derivatives					Liability Derivatives
	Balance	Fair Value as of				Balance	Fair Value as of
	Sheet	September 30,		December 31,		Sheet	September 30,		December 31,
	Location	2009		2008		Location	2009		2008
Derivatives designated as hedging instruments under ASC 815
Commodity contracts	Current assets	$	55,332	$	108,731	Current liabilities	$	3,237	$	-
	Long-term assets		25,639		89,774	Long-term liabilities		18,210		123
Interest rate contracts	Current assets		-		-	Current liabilities		8,601		8,020
	Long-term assets		493		-	Long-term liabilities		6,230		9,556
Total derivatives designated
as hedging instruments			81,464		198,505			36,278		17,699
Derivatives not designated as hedging instruments under ASC 815
Commodity contracts	Current assets		3,199		3,610	Current liabilities		2,911		3,644
	Long-term assets		285		-	Long-term liabilities		-		-
Interest rate contracts	Current assets		-		-	Current liabilities		3,582		-
	Long-term assets		1,670		-	Long-term liabilities		-		-
Total derivatives not designated
as hedging instruments			5,154		3,610			6,493		3,644
Total derivatives		$	86,618	$	202,115		$	42,771	$	21,343

The following table reflects the gain (loss) recognized in OCI on the consolidated balance sheet and shown in Note 10:

	Gain (Loss)						Gain (Loss)
Derivatives in	Recognized in OCI on						Recognized in OCI on
ASC 815	Derivatives (Effective Portion)						Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended September 30,						Nine Months Ended September 30,
Relationships	2009			2008			2009			2008
Interest rate contracts	$	(11,671	)	$	(1,706	)	$	(7,825	)	$	(1,976	)
Commodity contracts		(17,366	)		311,854			(43,683	)		(50,530	)
	$	(29,037	)	$	310,148		$	(51,508	)	$	(52,506	)

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 The following tables reflect amounts reclassified from OCI to revenue and expense:

	Amount of Gain (Loss) Recognized in Income on Derivatives
Location of Gain (Loss)	(Ineffective Portion)
Reclassified from	Three Months Ended September 30,					Nine Months Ended September 30,
OCI into Income	2009			2008		2009			2008
Interest expense, net	$	(1,882	)	$	-	$	(1,882	)	$	-
Revenues		(618	)		-		(618	)		-
	$	(2,500	)	$	-	$	(2,500	)	$	-

	Amount of Gain (Loss) Reclassified from OCI into Income
Location of Gain (Loss)	(Effective Portion)
Reclassified from	Three Months Ended September 30,					Nine Months Ended September 30,
OCI into Income	2009			2008		2009			2008
Interest expense, net	$	(4,075	)	$	2,101	$	(10,455	)	$	1,485
Revenues		23,012			140,105		59,730			87,704
	$	18,937		$	142,206	$	49,275		$	89,189

As of December 31, 2008, OCI consisted of $125.6 million ($105.2 million, net of tax) of unrealized net gains on commodity hedges, and $17.6 million ($16.0 million, net of tax) of unrealized net losses on interest rate hedges.

As of September 30, 2009, OCI consisted of $22.8 million ($19.9 million, net of tax) of unrealized net gains on commodity hedges, and $13.1 million ($11.4 million, net of tax) of unrealized net losses on interest rate hedges. Deferred net gains of $79.9 million on commodity hedges and deferred net losses of $13.7 million on interest rate hedges recorded in OCI are expected to be reclassified to revenues from third parties and interest expense during the next twelve months.

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, we 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	NY-HH		2.97		968		-		-		-		-	$	(23	)
Swap	IF-Waha		6.62		21,918		-		-		-		-		4,259
Swap	IF-Waha		6.69		-		16,300		-		-		-		4,665
Swap	IF-Waha		6.46		-		-		12,500		-		-		(162	)
Swap	IF-Waha		7.18		-		-		-		5,500		-		1,154
					21,918		16,300		12,500		5,500		-
Swap	IF-PB		5.42		-		2,000		-		-		-		(305	)
Swap	IF-PB		5.42		-		-		2,000		-		-		(686	)
Swap	IF-PB		5.54		-		-		-		4,000		-		(1,257	)
Swap	IF-PB		5.54		-		-		-		-		4,000		(1,314	)
					-		2,000		2,000		4,000		4,000
Total Sales					22,886		18,300		14,500		9,500		4,000
Basis Swap Oct 2009, 20,000 MMBtu/d															(32	)
Basis Swap Oct 2009, Rec IF-HH, Pay HH-GD, 10,000 MMBtu/d															(430	)
														$	5,869

NGLs
Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	OPIS-MB		0.80		3,347		-		-		-		-	$	(567	)
Swap	OPIS-MB		0.84		-		3,100		-		-		-		24
Swap	OPIS-MB		0.86		-		-		1,900		-		-		51
Swap	OPIS-MB		0.92		-		-		-		1,250		-		795
Total Swaps					3,347		3,100		1,900		1,250		-
Floor	OPIS-MB		1.44		-		-		54		-		-		395
Floor	OPIS-MB		1.43		-		-		-		63		-		479
Total Floors					-		-		54		63		-
Total Sales					3,347		3,100		1,954		1,313		-
														$	1,177

20

Condensate
Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		67.85		-		200		-		-		-	$	(472	)
Swap	NY-WTI		71.00		-		-		200		-		-		(446	)
Swap	NY-WTI		72.60		-		-		-		200		-		(449	)
Swap	NY-WTI		73.80		-		-		-		-		200		(472	)
Total Swaps					-		200		200		200		200
Total Sales					-		200		200		200		200
														$	(1,839	)

21

As of September 30, 2009, the Partnership had the following commodity derivative arrangements which will settle during the years ended December 31, 2009 through 2013 (except as otherwise indicated, 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 2009-May 2011, Rec IF-CGT, Pay NYMEX less $0.11, 20,000 MMBtu/d															586
Fuel cost swap Oct 2009-May 2011, Rec IF-CGT, Pay $5.96, 226 MMbtu/d															18
														$	13,883

22

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	)

23

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

Oct2009 - 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

Our consolidated variable rate indebtedness accrues interest at a fixed base rate plus an applicable margin. On September 24, 2009, we paid down our variable rate debt to $65.3 million. Accordingly all but $65.3 million of our interest rate hedges became ineffective and were dedesignated as they no longer qualified for hedge accounting. On these dedesignated hedges, we recorded a mark-to-market gain of $0.2 million for the period from September 24, 2009 to September 30, 2009. The fair value of the dedesignated interest rate swaps at September 30, 2009 was a liability of $1.9 million. The remaining $65.3 million notional amount effectively fixes the base rate on $65.3 million of borrowings for the indicated periods:

Period	Fixed Rate		Notional Amount			Fair Value
Remainder of 2009		1.65%	$	65	million	$	(231	)
2010		1.65%		65	million		(542	)
2011		1.65%		65	million		346
01/01-03/31/2012		1.65%		65	million		195
						$	(232	)

Subsequent Event. In October 2009, we made payments of $3.2 million to terminate all of our interest rate hedges.

In addition, the Partnership’s interest rate swaps and interest rate basis swaps effectively fix the base rate on the indicated notional amount of borrowings as shown below:

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
01/01-04/24/2014		3.39%		300	million		617
						$	(14,106	)

We have designated all interest rate swaps and interest rate basis swaps as cash flow hedges, except for the designated portion of our interest rate hedges. Accordingly, unrealized gains and losses relating to the swaps are recorded in OCI until interest expense on the related debt is recognized in earnings.

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

24

Note 14—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.

	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts	$	84,455	$	-	$	84,455	$	-
Available-for-sale securities (1)		56,571		-		-		56,571
Assets from interest rate derivatives		2,163		-		2,163		-
Total assets	$	143,189	$	-	$	86,618	$	56,571
Liabilities from commodity derivative contracts	$	24,358	$	-	$	24,358	$	-
Liabilities from interest rate derivatives		18,413		-		18,413		-
Total liabilities	$	42,771	$	-	$	42,771	$	-

___________

(1) Excludes $3.2 million of interest paid in-kind and $2.5 million in discount amortization.

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:

				Available
	Derivatives			For Sale
	Contracts			Securities		Total
Balance, December 31, 2008	$	148,194		$	9,700	$	157,894
Unrealized gains (losses) included in OCI		(41,582	)		7,575		(34,007	)
Purchases		-			39,296		39,296
Settlements		(34,985	)		-		(34,985	)
Transfers out of Level 3		(71,627	)		-		(71,627	)
Balance, September 30, 2009	$	-		$	56,571	$	56,571

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 during the three and nine months ended September 30, 2009 were not significant.

25

Note 15—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 have been in discussions with the New Mexico Environment Department (“NMED”) to resolve alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants. In May 2007, the NMED initially provided us with a draft compliance order proposing to resolve certain of these alleged violations, which were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005. In December 2007, the NMED offered a settlement containing a proposed penalty of approximately $2 million to resolve the alleged violations arising out of the August 2005 inspection of the Eunice plant.  We have since discussed with the NMED an expansion of the proposed compliance order to include the resolution of other alleged violations associated with the operation of flares at the Eunice, Monument and Saunders plants and to install air pollution control technology. We may incur additional operating costs to implement various leak detection and monitoring programs in order to resolve these alleged violations, the amount of which currently is not reasonably ascertainable.  It is also possible that the NMED may assess a penalty for the alleged violations associated with the operation of the flares at the Eunice, Monument and Saunders plants as part of an overall settlement.

Our environmental liability as of September 30, 2009 was $3.8 million, consisting of $0.2 million for gathering system leaks, $1.4 million for ground water assessment and remediation and $2.2 million for gas processing plant environmental violations.

Legal Proceedings

We are a party to various legal proceedings and/or regulatory proceedings and certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against us. We believe all such matters are without merit or involve amounts which, if resolved unfavorably, would not have a material effect on our financial position, results of operations, or cash flows, except for the items more fully described below.

In May 2002, Apache Corporation (“Apache”) filed suit in Texas state court against Versado Gas Processors, LLC (“Versado”), as purchaser and processor of Apache’s gas, and Dynegy Midstream Services, Limited Partnership (now known as Targa Midstream Services Limited Partnership, a wholly owned subsidiary of ours), as operator of the Versado assets in New Mexico (“Versado Defendants”) alleging (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that the Versado Defendants engaged in certain transactions with affiliates, resulting in the Versado Defendants not receiving fair market value when it sold gas and liquids, and (iii) that the formula for calculating the amount the Versado Defendants received from its buyers of gas and liquids is flawed since it is based on gas price indices that were allegedly manipulated. At trial, the jury found in favor of Apache on the lost gas claim, awarding approximately $1.6 million in damages. Apache’s claims with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the trial court and abated for a future trial. The parties settled the severed lawsuit in May 2007.

In May 2004, the trial court granted the Versado Defendants’ motion to set aside the jury verdict on the lost gas claim and vacated the jury award to Apache. Apache filed its notice of appeal with the 14th Court of Appeals of Houston in October 2004. In 2006, the Court of Appeals reinstated the jury verdict in Apache’s favor on the issue of lost gas and also awarded Apache legal fees and interest, bringing the total award against the Versado Defendants to approximately $2.7 million. After rehearing, the Court of Appeals affirmed its decision reinstating the original jury verdict in Apache’s favor. With interest and attorneys’ fees that verdict stood at approximately $3.1million.

In January 2007, the Versado Defendants filed their petition for review with the Supreme Court of Texas and in March 2007, Apache filed its conditional petition for review with the Supreme Court of Texas. On April 4, 2008, the Supreme Court of Texas granted review of the petitions, and on September 9, 2008, the parties presented oral

26

arguments. On August 28, 2009, the Supreme Court of Texas delivered its opinion in favor of the Versado Defendants on every issue and remanded the case to the trial court for entry of judgment consistent with the opinion.

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. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit.

Note 16—Fair Value of Financial Instruments

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

The carrying value of our and the Partnership’s credit facilities approximates their fair values, as the interest rates are based on prevailing market rates. The fair value of the senior secured term loan facility and the senior unsecured notes are 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 financial statements are stated at fair value.

The carrying amounts and fair values of our other financial instruments are as follows as of the dates indicated:

	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior secured term loan facility	$	65,300	$	64,647	$	522,175	$	331,581
Senior unsecured notes, 8½% fixed rate		250,000		235,000		250,000		134,375
Senior unsecured notes of the Partnership, 8¼% fixed rate		209,080		193,922		209,080		128,333
Senior unsecured notes of the Partnership, 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 17—Related Party Transactions

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. During the three and nine months ended September 30, 2009, we purchased $2.5 million and $5.7 million of product from Broad Oak. During the three and nine months ended September 30, 2008, we purchased $2.2 million and $3.4 million of product from Broad Oak.

27

Relationship with Bank of America

An affiliate of BofA is an equity investor in Targa Resources Investments Inc.

Financial Services. BofA is a lender under our senior secured credit facilities. Additionally, BofA is a lender and an administrative agent under the Partnership’s 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		21,918	MMBtu	$	6.62	per MMBtu	IF-Waha
Oct 2009 - Dec 2009	NGL		2,847	Bbl		31.83	per gallon	OPIS-MB

As of September 30, 2009, the fair value of these open positions was $3.3 million. For the three and nine months ended September 30, 2009, we received $6.9 million and $21.9 million from BofA for amounts due under settled commodity derivative transactions. For the three and nine months ended September 30, 2008, we paid BofA $13.4 million and $36.6 million for amounts due under settled commodity derivative transactions.

The following table shows the Partnership’s 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
Oct2009 - 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 fair value of these Partnership open positions was $6.0 million. For the three and nine months ended September 30, 2009, the Partnership received $6.2 million and $22.2 million from BofA to settle payments due under hedge transactions. For the three and nine months ended September 30, 2008, the Partnership paid BofA $6.3 million and $17.9 million for amounts due under settled commodity derivative transactions.

The Partnership has 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, 2012. As of September 30, 2009, the aggregate fair value of these positions was a liability of $2.7 million. Payments to BofA related to settled portions were $0.7 million and $1.7 million for the three and nine months ended September 30, 2009.

Commercial Relationships. During the three and nine months ended September 30, 2009, we had product sales to BofA which are included in revenues of $6.3 million and $29.1 million. For the same periods, we had natural gas and NGL product purchases of $0 and $0.6 million from BofA. During the three and nine months ended September 30, 2008, we had product sales to BofA which are included in revenues of $22.5 million and $82.9 million. For the same periods, we had natural gas and NGL product purchases of $1.0 million and $3.9 million from BofA.

28

Transactions with Unconsolidated Affiliates

For the periods indicated, related party transactions included in our statements of operations were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Included in revenues
GCF	$	34	$	56	$	159	$	422
VESCO (1)		-		-		-		666
	$	34	$	56	$	159	$	1,088
Included in costs and expenses
GCF	$	158	$	589	$	1,426	$	2,734
VESCO (1)		-		51,508		-		151,589
	$	158	$	52,097	$	1,426	$	154,323

____________

(1) Subsequent to July 31, 2008, VESCO is consolidated in our results of operations and all intercompany transactions have been eliminated.

Note 18—Segment Information

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

The Natural Gas Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. These assets are located in North Texas, Louisiana and the Permian Basin of West Texas and Southeast New Mexico. We are 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, the cost of equipment used in our headquarters office and the elimination of intersegment revenues and expenses.

29

Our reportable segment information is shown in the following tables:

	Three Months Ended September 30, 2009
	Natural Gas Gathering and Processing		Logistics Assets		NGL Distribution and Marketing			Wholesale Marketing		Eliminations and Other			Total
Revenues	$	276,387	$	30,349	$	692,167		$	122,574	$	-		$	1,121,477
Intersegment revenues		276,740		24,727		71,614			19,418		(392,499	)		-
Revenues		553,127		55,076		763,781			141,992		(392,499	)		1,121,477
Product purchases		416,134		-		438,150			77,153		684			932,121
Intersegment product purchases		10,048		-		317,579			61,488		(389,115	)		-
Product purchases		426,182		-		755,729			138,641		(388,431	)		932,121
Operating expenses		36,453		27,032		(20	)		41		-			63,506
Intersegment operating expenses		136		3,248		-			-		(3,384	)		-
Operating expenses		36,589		30,280		(20	)		41		(3,384	)		63,506
Operating margin	$	90,356	$	24,796	$	8,072		$	3,310	$	(684	)	$	125,850
Other financial information:
Equity in earnings of   unconsolidated investments	$	-	$	1,417	$	-		$	-	$	-		$	1,417
Unconsolidated investments		-		17,811		-			-		-			17,811
Capital expenditures		13,754		5,070		-			-		186			19,010
Revenues by type:
Commodity sales	$	539,671	$	-	$	762,373		$	141,752	$	(367,373	)	$	1,076,423
Services		7,639		55,076		1,408			240		(25,126	)		39,237
Business interruption		2,900		-		-			-		-			2,900
Other		2,917		-		-			-		-			2,917
	$	553,127	$	55,076	$	763,781		$	141,992	$	(392,499	)	$	1,121,477

30

	Three Months Ended September 30, 2008
	Natural Gas Gathering  and Processing		Logistics Assets			NGL Distribution and Marketing			Wholesale Marketing			Eliminations and Other			Total
Revenues	$	497,785	$	25,672		$	1,514,958		$	314,572		$	-		$	2,352,987
Intersegment revenues		473,426		39,853			139,787			5,987			(659,053	)		-
Revenues		971,211		65,525			1,654,745			320,559			(659,053	)		2,352,987
Product purchases		797,661		(67	)		1,179,406			199,830			-			2,176,830
Intersegment product purchases		18,721		67			500,005			126,181			(644,974	)		-
Product purchases		816,382		-			1,679,411			326,011			(644,974	)		2,176,830
Operating expenses		37,256		36,007			304			16			-			73,583
Intersegment operating expenses		199		13,879			-			1			(14,079	)		-
Operating expenses		37,455		49,886			304			17			(14,079	)		73,583
Operating margin	$	117,374	$	15,639		$	(24,970	)	$	(5,469	)	$	-		$	102,574
Other financial information:
Equity in earnings of   unconsolidated investments	$	1,432	$	1,102		$	-		$	-		$	-		$	2,534
Unconsolidated investments		-		19,554			-			-			-			19,554
Capital expenditures		25,042		9,239			-			-			1,479			35,760
Revenues by type:
Commodity sales	$	963,841	$	-		$	1,653,998		$	320,564		$	(619,164	)	$	2,319,239
Services		6,594		65,527			747			(5	)		(39,889	)		32,974
Business interruption		749		-			-			-			-			749
Other		27		(2	)		-			-			-			25
	$	971,211	$	65,525		$	1,654,745		$	320,559		$	(659,053	)	$	2,352,987

31

	Nine Months Ended September 30, 2009
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing			Wholesale Marketing		Eliminations and Other			Total
Revenues	$	764,580	$	87,127		$	1,767,170		$	508,143	$	-		$	3,127,020
Intersegment revenues		690,163		67,715			247,601			52,509		(1,057,988	)		-
Revenues		1,454,743		154,842			2,014,771			560,652		(1,057,988	)		3,127,020
Product purchases		1,097,741		-			1,198,110			311,054		-			2,606,905
Intersegment product purchases		20,408		-			784,089			238,752		(1,043,249	)		-
Product purchases		1,118,149		-			1,982,199			549,806		(1,043,249	)		2,606,905
Operating expenses		98,087		83,932			592			62		-			182,673
Intersegment operating expenses		474		14,265			-			-		(14,739	)		-
Operating expenses		98,561		98,197			592			62		(14,739	)		182,673
Operating margin	$	238,033	$	56,645		$	31,980		$	10,784	$	-		$	337,442
Other financial information:
Equity in earnings of   unconsolidated investments	$	-	$	3,221		$	-		$	-	$	-		$	3,221
Unconsolidated investments		-		17,811			-			-		-			17,811
Capital expenditures		47,229		15,853			-			-		1,445			64,527
Revenues by type:
Commodity sales	$	1,422,225	$	29		$	2,011,166		$	559,426	$	(988,876	)	$	3,003,970
Services		22,077		152,888			3,607			726		(69,113	)		110,185
Business interruption		5,474		1,926			-			500		-			7,900
Other		4,967		(1	)		(2	)		-		1			4,965
	$	1,454,743	$	154,842		$	2,014,771		$	560,652	$	(1,057,988	)	$	3,127,020

32

	Nine Months Ended September 30, 2008
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing		Wholesale Marketing			Eliminations and Other			Total
Revenues	$	1,480,253	$	74,120		$	4,118,034	$	1,146,199		$	-		$	6,818,606
Intersegment revenues		1,423,663		108,243			457,260		35,033			(2,024,199	)		-
Revenues		2,903,916		182,363			4,575,294		1,181,232			(2,024,199	)		6,818,606
Product purchases		2,426,296		(101	)		3,040,343		734,822			-			6,201,360
Intersegment product purchases		28,690		101			1,518,402		433,426			(1,980,619	)		-
Product purchases		2,454,986		-			4,558,745		1,168,248			(1,980,619	)		6,201,360
Operating expenses		101,599		105,428			1,321		42			-			208,390
Intersegment operating expenses		733		42,847			-		-			(43,580	)		-
Operating expenses		102,332		148,275			1,321		42			(43,580	)		208,390
Operating margin	$	346,598	$	34,088		$	15,228	$	12,942		$	-		$	408,856
Other financial information:
Equity in earnings of   unconsolidated investments	$	10,161	$	3,028		$	-	$	-		$	-		$	13,189
Unconsolidated investments		-		19,554			-		-			-			19,554
Capital expenditures		59,290		30,933			-		-			3,701			93,924
Revenues by type:
Commodity sales	$	2,878,360	$	53		$	4,564,413	$	1,175,165		$	(1,914,301	)	$	6,703,690
Services		22,060		181,870			2,268		150			(109,897	)		96,451
Business interruption		3,289		441			8,602		5,920			-			18,252
Other		207		(1	)		11		(3	)		(1	)		213
	$	2,903,916	$	182,363		$	4,575,294	$	1,181,232		$	(2,024,199	)	$	6,818,606

The following table is a reconciliation of operating margin to net income (loss) for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reconciliation of operating margin to net income (loss)
attributable to Targa Resources, Inc.:
Operating margin	$	125,850		$	102,574		$	337,442		$	408,856
Net income attributable to noncontrolling interest		(11,068	)		(24,309	)		(17,723	)		(81,148	)
Depreciation and amortization expense		(44,255	)		(41,086	)		(127,908	)		(118,028	)
General and administrative expense		(31,429	)		(26,679	)		(83,478	)		(78,696	)
Interest expense, net		(29,386	)		(24,599	)		(77,138	)		(73,844	)
Loss on early debt extinguishment		(14,808	)		-			(14,808	)		-
Income tax benefit (expense)		1,197			9,882			(5,208	)		(30,409	)
Other, net		1,306			(16,663	)		2,307			17,003
Net income (loss) attributable to Targa Resources, Inc.	$	(2,593	)	$	(20,880	)	$	13,486		$	43,734

33

Note 19—Other Operating Income

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Abandoned project costs	$	-		$	-		$	5,589		$	-
Casualty loss adjustment (see Note 12)		-			17,899			(3,744	)		17,899
Gain on sale of assets (see Note 20)		(3	)		(13	)		(41	)		(4,458	)
	$	(3	)	$	17,886		$	1,804		$	13,441

For the nine months ended September 30, 2009, $5.6 million of previously capitalized project development cost related to a liquefied natural gas storage project were charged to expense when we determined that we would be unable to obtain sufficient customer commitments.

Note 20—Supplemental Cash Flow Information

During the nine months ended September 30, 2009, we had a noncash addition to property, plant and equipment of $9.8 million resulting from the reclassification from inventory of working NGL volumes in third-party and Targa owned facilities. During the nine months ended September 30, 2008, we had a noncash addition to property, plant and equipment of $4.3 million resulting from a like-kind exchange transaction.

Note 21—Consolidating Financial Statements

We are the issuer of the 8½% senior unsecured notes listed in Note 10 to the financial statements of our Annual Report on Form 10-K for the year ended December 31, 2008. The notes are jointly and severally, irrevocably and unconditionally guaranteed by our wholly owned subsidiaries (referred to as “Guarantor Subsidiaries”).

The following financial information presents condensed consolidating financial statements, which include:

• The Parent company only (“Parent”);

• The Guarantor Subsidiaries on a consolidated basis;

• Non-wholly owned and foreign subsidiaries (referred to as “Non-Guarantor Subsidiaries”);

• Elimination entries necessary to consolidate the Parent, the Guarantor Subsidiaries, and the Non-Guarantor Subsidiaries; and

• The Company on a consolidated basis.

34

Targa Resources, Inc.
Condensed Consolidating Balance Sheet
September 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	-		$	110,085		$	77,842		$	-		$	187,927
Trade receivables and other current assets		269			72,768			357,514			-			430,551
Total current assets		269			182,853			435,356			-			618,478
Property, plant, and equipment, at cost		-			493,556			2,673,668			-			3,167,224
Accumulated depreciation		-			26,694			(630,049	)		-			(603,355	)
Property, plant, and equipment, net		-			520,250			2,043,619			-			2,563,869
Investment in subsidiaries		(429,426	)		372,418			-	��		57,008			-
Other assets		28,630			14,023			106,518			-			149,171
Total assets	$	(400,527	)	$	1,089,544		$	2,585,493		$	57,008		$	3,331,518
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and other liabilities	$	26,596		$	126,138		$	272,145		$	-		$	424,879
Current maturities of debt		12,500			-			-			-			12,500
Total current liabilities		39,096			126,138			272,145			-			437,379
Long-term debt, net of current maturities		302,800			-			939,424			-			1,242,224
Affiliated indebtedness		(1,359,212	)		1,359,212			-			-			-
Other long-term obligations		52,322			33,620			50,357			-			136,299
Total Targa Resources, Inc.'s stockholder's equity		564,467			(429,426	)		1,324,819			(895,393	)		564,467
Noncontrolling interest in subsidiaries		-			-			(1,252	)		952,401			951,149
Total stockholders' equity		564,467			(429,426	)		1,323,567			57,008			1,515,616
Total liabilities and stockholders' equity	$	(400,527	)	$	1,089,544		$	2,585,493		$	57,008		$	3,331,518

35

Targa Resources, Inc.
Condensed Consolidating Balance Sheet
December 31, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	-		$	219,620		$	143,149		$	-		$	362,769
Trade receivables and other current assets		298			80,099			413,982			-			494,379
Total current assets		298			299,719			557,131			-			857,148
Property, plant, and equipment, at cost		-			471,852			2,621,412			-			3,093,264
Accumulated depreciation		-			56,192			(532,087	)		-			(475,895	)
Property, plant, and equipment, net		-			528,044			2,089,325			-			2,617,369
Investment in subsidiaries		(291,600	)		(22,913	)		-			314,513			-
Other assets		45,185			26,610			102,265			-			174,060
Total assets	$	(246,117	)	$	831,460		$	2,748,721		$	314,513		$	3,648,577
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and other liabilities	$	50,733		$	97,707		$	306,604		$	-		$	455,044
Current maturities of debt		12,500			-			-			-			12,500
Total current liabilities		63,233			97,707			306,604			-			467,544
Long-term debt, net of current maturities		855,595			-			696,845			-			1,552,440
Affiliated indebtedness		(1,785,694	)		1,011,811			773,883			-			-
Other long-term obligations		41,108			13,542			44,694			-			99,344
Total Targa Resources, Inc.'s stockholder's equity		579,641			(291,600	)		926,408			(634,808	)		579,641
Noncontrolling interest in subsidiaries		-			-			287			949,321			949,608
Total stockholders' equity		579,641			(291,600	)		926,695			314,513			1,529,249
Total liabilities and stockholders' equity	$	(246,117	)	$	831,460		$	2,748,721		$	314,513		$	3,648,577

36

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	-		$	297,908		$	1,080,706		$	(257,137	)	$	1,121,477
Operating costs and expenses:
Product purchases		-			266,898			914,705			(249,482	)		932,121
Operating expenses		-			9,155			62,006			(7,655	)		63,506
Depreciation and amortization expense		-			11,143			33,112			-			44,255
General and administrative and other		43			14,155			17,228			-			31,426
		43			301,351			1,027,051			(257,137	)		1,071,308
Income (loss) from operations		(43	)		(3,443	)		53,655			-			50,169
Other income (expense):
Interest expense, net		(11,403	)		(3,369	)		(14,614	)		-			(29,386	)
Affiliated interest (expense) income, net		34,108			(20,407	)		(13,701	)		-			-
Other income (expense)		(14,781	)		201			(342	)		-			(14,922	)
Equity in earnings of unconsolidated investments		-			-			1,417			-			1,417
Equity in earnings of subsidiaries		(11,671	)		15,347			-			(3,676	)		-
Income (loss) before income taxes		(3,790	)		(11,671	)		26,415			(3,676	)		7,278
Income tax benefit		1,197			-			-			-			1,197
Net income (loss)		(2,593	)		(11,671	)		26,415			(3,676	)		8,475
Less: Net income attributable to noncontrolling interest		-			-			888			10,180			11,068
Net income (loss) attributable to Targa Resources, Inc.	$	(2,593	)	$	(11,671	)	$	25,527		$	(13,856	)	$	(2,593	)

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	-		$	468,953		$	2,387,035		$	(503,001	)	$	2,352,987
Operating costs and expenses:
Product purchases		-			438,740			2,223,553			(485,463	)		2,176,830
Operating expenses		-			7,906			83,215			(17,538	)		73,583
Depreciation and amortization expense		-			9,065			32,021			-			41,086
General and administrative and other		44			20,366			24,155			-			44,565
		44			476,077			2,362,944			(503,001	)		2,336,064
Income (loss) from operations		(44	)		(7,124	)		24,091			-			16,923
Other income (expense):
Interest income (expense), net		(14,622	)		540			(10,517	)		-			(24,599	)
Affiliate interest income (expense), net		34,681			(19,849	)		(14,832	)		-			-
Other income (expense)		-			(320	)		(991	)		-			(1,311	)
Equity in earnings of unconsolidated investments		-			1,432			1,102			-			2,534
Equity in earnings of subsidiaries		(51,177	)		(25,856	)		-			77,033			-
Income  (Loss) before income taxes		(31,162	)		(51,177	)		(1,147	)		77,033			(6,453	)
Income tax (expense) benefit		10,282			-			(400	)		-			9,882
Net income (loss)		(20,880	)		(51,177	)		(1,547	)		77,033			3,429
Less: Net income attributable to noncontrolling interest		-			-			161			24,148			24,309
Net income (loss) attributable to Targa Resources, Inc.	$	(20,880	)	$	(51,177	)	$	(1,708	)	$	52,885		$	(20,880	)

37

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	-		$	743,670		$	3,024,587		$	(641,237	)	$	3,127,020
Operating costs and expenses:
Product purchases		-			655,474			2,570,076			(618,645	)		2,606,905
Operating expenses		-			23,545			181,720			(22,592	)		182,673
Depreciation and amortization expense		-			29,693			98,215			-			127,908
General and administrative and other		5,798			27,472			52,012			-			85,282
		5,798			736,184			2,902,023			(641,237	)		3,002,768
Income (loss) from operations		(5,798	)		7,486			122,564			-			124,252
Other income (expense):
Interest expense, net		(39,996	)		(4,705	)		(32,437	)		-			(77,138	)
Affiliated interest (expense) income, net		103,519			(60,105	)		(43,414	)		-			-
Other income		(14,711	)		436			357			-			(13,918	)
Equity in earnings of unconsolidated investments		-			-			3,221			-			3,221
Equity in earnings of subsidiaries		(24,320	)		32,568			-			(8,248	)		-
Income (loss) before income taxes		18,694			(24,320	)		50,291			(8,248	)		36,417
Income tax expense		(5,208	)		-			-			-			(5,208	)
Net income (loss)		13,486			(24,320	)		50,291			(8,248	)		31,209
Less: Net income attributable to noncontrolling interest		-			-			1,179			16,544			17,723
Net income (loss) attributable to Targa Resources, Inc.	$	13,486		$	(24,320	)	$	49,112		$	(24,792	)	$	13,486

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Nine Months Ended September 30, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	-		$	1,454,337		$	6,911,442		$	(1,547,173	)	$	6,818,606
Operating costs and expenses:
Product purchases		-			1,365,041			6,331,977			(1,495,658	)		6,201,360
Operating expenses		-			26,336			233,569			(51,515	)		208,390
Depreciation and amortization expense		-			26,445			91,583			-			118,028
General and administrative and other		17,618			20,661			53,858		��	-			92,137
		17,618			1,438,483			6,710,987			(1,547,173	)		6,619,915
Income (loss) from operations		(17,618	)		15,854			200,455			-			198,691
Other income (expense):
Interest income (expense), net		(49,827	)		2,714			(26,731	)		-			(73,844	)
Affiliate interest income (expense), net		103,946			(59,546	)		(44,400	)		-			-
Other income		36,054			(13,264	)		(5,535	)		-			17,255
Equity in earnings of unconsolidated investments		-			10,161			3,028			-			13,189
Equity in earnings of subsidiaries		488			44,569			-			(45,057	)		-
Income before income taxes		73,043			488			126,817			(45,057	)		155,291
Income tax expense		(29,309	)		-			(1,100	)		-			(30,409	)
Net income		43,734			488			125,717			(45,057	)		124,882
Less: Net income attributable to noncontrolling interest		-			-			91			81,057			81,148
Net income attributable to Targa Resources, Inc.	$	43,734		$	488		$	125,626		$	(126,114	)	$	43,734

38

Targa Resources, Inc.
Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	13,486		$	(24,320	)	$	50,291		$	(8,248	)	$	31,209
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, amortization and accretion		4,318			28,584			100,732			-			133,634
Interest on affiliate indebtedness		(103,519	)		60,105			43,414			-			-
Deferred income taxes		4,880			-			-			-			4,880
Loss from unconsolidated investments, net of distributions		654			-			-			-			654
Equity in earnings (losses) of subsidiaries		24,320			(32,568	)		-			8,248			-
Other		14,189			2,828			34,389			-			51,406
Changes in operating assets and liabilities:
Accounts receivable and other assets		834			32,917			(67,539	)		-			(33,788	)
Inventory		-			(670	)		18,582			-			17,912
Accounts payable and other liabilities		(2,928	)		19,627			(13,528	)		-			3,171
Net cash provided by (used in) operating activities		(43,766	)		86,503			166,341			-			209,078
Cash flows from investing activities
Purchases of property and equipment		-			(19,413	)		(55,461	)		-			(74,874	)
Other		-			(15,483	)		353			-			(15,130	)
Net cash provided by (used in) investing activities		-			(34,896	)		(55,108	)		-			(90,004	)
Cash flows from financing activities
Borrowings		-			-			635,051			-			635,051
Repayments of debt		(155,295	)		-			(772,400	)		-			(927,695	)
Retirement of debt		-			-			(18,882	)		-			(18,882	)
Distributions to noncontrolling interest, net		-			-			30,496			-			30,496
Cost incurred in connection with financing arrangements		(2,950	)		-			(9,722	)		-			(12,672	)
Contribution from Targa Resources Investments Inc., net		(214	)		287,296			(287,296	)		-			(214	)
Receipts from (payments to) subsidiaries		202,225			(448,438	)		246,213			-			-
Net cash provided by (used in) financing activities		43,766			(161,142	)		(176,540	)		-			(293,916	)
Net decrease in cash and cash equivalents		-			(109,535	)		(65,307	)		-			(174,842	)
Cash and cash equivalents, beginning of period		-			219,620			143,149			-			362,769
Cash and cash equivalents, end of period	$	-		$	110,085		$	77,842		$	-		$	187,927

39

Targa Resources, Inc.
Condensed Consolidating Statement of Cash Flows
Nine Months Ended September 30, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	43,734		$	488		$	125,717		$	(45,057	)	$	124,882
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, amortization and accretion		5,218			26,956			93,956			-			126,130
Interest on affiliate indebtedness		(103,946	)		59,546			44,400			-			-
Deferred income taxes		29,125			-			1,100			-			30,225
Loss from unconsolidated investments, net of distributions		-			(10,161	)		(315	)		-			(10,476	)
Equity in earnings (losses) of subsidiaries		(488	)		(44,569	)		-			45,057			-
Other		(18,566	)		4,106			(80,206	)		-			(94,666	)
Changes in operating assets and liabilities		39,787			(60,566	)		107,225			-			86,446
Net cash provided by (used in) operating activities		(5,136	)		(24,200	)		291,877			-			262,541
Cash flows from investing activities
Purchases of property and equipment		-			(16,670	)		(77,178	)		-			(93,848	)
Other		(16,400	)		(81,008	)		4,945			-			(92,463	)
Net cash provided by (used in) investing activities		(16,400	)		(97,678	)		(72,233	)		-			(186,311	)
Cash flows from financing activities
Borrowings		-			-			337,500			-			337,500
Repayments of debt		(9,375	)		-			(323,800	)		-			(333,175	)
Distributions to noncontrolling interest, net		-			-			(75,039	)		-			(75,039	)
Cost incurred in connection with financing arrangements		(34	)		-			(7,168	)		-			(7,202	)
Distribution to Targa Resources Investments Inc.		(52,774	)		-			-			-			(52,774	)
Receipts from (payments to) subsidiaries		83,719			77,124			(160,843	)		-			-
Net cash provided by (used in) financing activities		21,536			77,124			(229,350	)		-			(130,690	)
Net decrease in cash and cash equivalents		-			(44,754	)		(9,706	)		-			(54,460	)
Cash and cash equivalents, beginning of period		-			88,302			89,647			-			177,949
Cash and cash equivalents, end of period	$	-		$	43,548		$	79,941		$	-		$	123,489

40

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

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and notes included elsewhere in this Quarterly Report and in our consolidated financial statements and notes thereto included in our Annual Report.

Overview

We are a Delaware corporation formed in 2004 by our management team and Warburg Pincus LLC to acquire, own and operate assets in the midstream natural gas business.

Our gathering and processing assets are located primarily in the Permian Basin in West Texas and Southeast New Mexico, the Louisiana Gulf Coast primarily accessing the offshore region of Louisiana, and, through the Partnership, the Fort Worth Basin in North Texas, the Permian Basin in West Texas and the onshore region of the Louisiana Gulf Coast. Our NGL logistics and marketing assets, which are held by the Partnership, are located primarily at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana, with terminals and transportation assets across the United States.

We conduct our business operations through two divisions and report our results of operations under four segments: our Natural Gas Gathering and Processing division, which includes the Partnership, is a single segment consisting of our natural gas gathering and processing facilities, as well as certain fractionation capability integrated within those facilities; and the Partnership’s NGL Logistics and Marketing division, which consists of three segments: Logistics Assets, NGL Distribution and Marketing and Wholesale Marketing.

Change in Basis of Presentation

As discussed in Note 3 to the accompanying consolidated financial statements, certain 2008 financial information has been retrospectively adjusted to reflect the requirements of ASC 810 so that the basis of presentation is consistent with that of the 2009 financial information.

Recent Developments

On May 19, 2009, all 11,528,231 of our subordinated units in the Partnership converted to common units on a one-for-one basis. The conversion had no impact upon our calculation of earnings per unit since the subordinated units were included in the basic and diluted earnings per unit calculation.

On July 6, 2009, the Partnership completed a 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 were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. Proceeds were used by the Partnership to repay borrowings under its credit facility.

On July 29, 2009, the Partnership executed a Commitment Increase Supplement to its existing senior secured credit facility. The Commitment Increase Supplement increased the commitments under its 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.

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 of the offering were $105.3 million, after deducting underwriting discounts, commissions and estimated offering expenses, and including the general partner’s proportionate capital contribution of $2.2 million. The Partnership used a portion of the proceeds to repay $103.5 million of outstanding borrowings under its senior secured revolving credit facility.

On September 24, 2009, the Partnership purchased our interests in Targa Downstream GP LLC, Targa LSNG GP LLC, Targa Downstream LP and Targa LSNG LP (collectively the “Downstream Business”) for $530 million.

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Consideration to us comprised $397.5 million in cash and the issuance to us of 174,033 general partner units in the Partnership and 8,527,615 common units in the Partnership.

On October 19, 2009, the general partner of the Partnership announced a cash distribution of $0.5175 per unit on the outstanding common units of the Partnership. The distribution will be paid on November 13, 2009 to unitholders of record on November 4, 2009, for the three months ended September 30, 2009. The total distribution to be paid is $35.2 million, with $21.5 million to be paid to the non-affiliated common unitholders and $10.4 million, $0.7 million and $2.6 million to be paid to us for our common unit ownership, general partner interest and incentive distribution rights.

Recently Issued Pronouncements

See Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

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Results of Operations

The following table and discussion relate to the three and nine months ended September 30, 2009 and 2008 and is a summary of our results of operations for the periods then ended:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions, except operating and price data)
Revenues (1)	$	1,121.5		$	2,353.0		$	3,127.0		$	6,818.6
Product purchases		932.1			2,176.8			2,606.9			6,201.4
Operating expenses		63.5			73.6			182.7			208.4
Depreciation and amortization expense		44.3			41.1			127.9			118.0
General and administrative expense		31.4			26.7			83.5			78.7
Other		-			17.9			1.8			13.4
Income from operations		50.2			16.9			124.2			198.7
Interest expense, net		(29.4	)		(24.6	)		(77.1	)		(73.8	)
Gain on insurance claims		-			-			-			18.6
Equity in earnings of unconsolidated investments		1.4			2.5			3.2			13.2
Loss on debt repurchases		(1.5	)		-			(1.5	)		-
Loss on early debt extinguishment		(14.8	)		-			(14.8	)		-
Gain (loss) on mark-to-market derivative instruments		0.8			(1.3	)		0.8			(1.3	)
Other		0.6			-			1.6			(0.1	)
Income tax (expense) benefit		1.2			9.9			(5.2	)		(30.4	)
Net income		8.5			3.4			31.2			124.9
Less: Net income attributable to noncontrolling interest		11.1			24.3			17.7			81.2
Net income attributable to Targa Resources, Inc.	$	(2.6	)	$	(20.9	)	$	13.5		$	43.7
Financial data:
Operating margin (2)	$	125.9		$	102.6		$	337.4		$	408.8
Adjusted EBITDA (3)		90.3			46.1			273.3			275.4
Operating statistics:
Gathering throughput  MMcf/d (4)		2,323.5			1,854.1			2,142.5			2,034.5
Plant natural gas inlet, MMcf/d (5) (6)		2,274.2			1,817.2			2,097.7			1,994.9
Gross NGL production, MBbl/d		123.5			100.8			117.1			103.2
Natural gas sales, BBtu/d (6)		662.8			515.3			590.4			524.9
NGL sales, MBbl/d		269.2			290.1			285.1			297.8
Condensate sales, MBbl/d		4.8			3.9			4.8			3.8
Average realized prices:
Natural gas, $/MMBtu		3.46			9.18			3.78			9.06
NGL, $/gal		0.81			1.65			0.71			1.54
Condensate, $/Bbl		67.54			108.30			54.35			105.42

____________

(1) Includes business interruption insurance revenue of $2.9 million and $7.9 million for the three and nine months ended September 30, 2009 and $0.7 million and $18.3 million for the three and nine months ended September 30, 2008.

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(2) Operating margin is revenues less product purchases and operating expense. See “Non-GAAP Financial Measures” included in this Item 2.

(3) Adjusted EBITDA is net income before interest, income taxes, depreciation and amortization and non-cash income or loss related to derivative instruments. See “—Non-GAAP Financial Measures.”

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

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

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

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues decreased by $1,231.5 million, or 52%, for 2009 compared to 2008. Revenues from the sale of natural gas decreased by $224.5 million, consisting of a decrease of $349.2 million due to lower realized prices, partially offset by an increase of $124.7 million due to higher sales volumes. Revenues from the sale of NGLs decreased by $1,007.4 million, consisting of a decrease of $874.3 million due tolower realized prices, and a decrease of $133.1 million due to lower sales volumes. Revenues from the sale of condensate decreased by $8.9 million, consisting of a decrease of $17.9 million due to lower realized prices, partially offset by an increase of $9.0 million due to higher sales volumes. Other revenues, which includes revenues principally derived from fee-based services, increased by $9.3 million.

Average realized price for natural gas decreased by $5.72 per MMBtu, or 62%, for 2009 compared to 2008. Average realized prices for NGLs decreased by $0.84 per gallon, or 51%, for 2009 compared 2008. Our average realized price for condensate decreased by $40.76 per Bbl, or 38%, for 2009 compared to 2008.

Natural gas sales volumes increased by 147.5 BBtu/d, or 29%, for 2009 compared to 2008. NGL sales volumes decreased by 20.9 MBbl/d, or 7%, for 2009 compared to 2008. Condensate sales volumes increased by 0.9 MBbl/d, or 23%, for 2009 compared to 2008 due to a reduction in affiliate sales. For information regarding the period to period changes in our commodity sales volumes, see “—Results of Operations—By Segment.”

Product purchases decreased by $1,244.7 million, or 57%, for 2009 compared to 2008. See “—Results of Operations—By Segment” for an explanation of the components of the decrease.

Operating expenses decreased by $10.1 million, or 14%, for 2009 compared to 2008. See “—Results of Operations—By Segment” for a detailed explanation of the components of the decrease.

Depreciation and amortization expense increased by $3.2 million, or 8%, for 2009 compared to 2008. The increase was due to a $1.5 million asset impairment included in depreciation expense, the addition of property, plant and equipment and the consolidation of our investment in VESCO, starting August 1, 2008, following our acquisition of majority ownership.

General and administrative expense increased by $4.7 million, or 18%, for 2009 compared to 2008. We experienced increases in property insurance and compensation costs, partially offset by decreases in outside professional service costs.

Other operating income for 2008 included a $17.9 million loss provision for our estimated out-of-pocket cleanup and repair costs related to Hurricanes Gustav and Ike. Hurricanes did not disrupt our operations or damage our facilities during the 2009 hurricane season.

Equity earnings decreased $1.1 million for 2009 compared to 2008. The decrease was due primarily to our consolidation of VESCO, following our acquisition of a controlling ownership interest effective August 1, 2008.

Loss on debt repurchases of $1.5 million resulted from the Partnership’s retirement of a portion of its outstanding 11¼% Notes during 2009.

The $14.8 million loss on early debt extinguishment consisted of the write-off of debt issue costs related to prepayments on our senior secured term loan facility. In addition, the loss includes a $6.3 million out of period adjustment related to prepayments made during 2007. See Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

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Interest expense increased by $4.8 million, or 20%, for 2009 compared to 2008. This was primarily attributable to the issuance of the Partnership’s 11¼ % Senior Unsecured Notes in July, 2009.

During interim periods income tax expense is based on an estimated annual effective income tax rate plus any significant unusual or infrequently occurring items recorded in the period that the specific item occurs. As our annual estimate of pre-tax income changes, our effective tax rate may increase or decrease. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the inclusion in our pre-tax income of income from pass-through entities, the tax effects of estimated annual permanent differences and state income taxes.

For the three months ended September 30, 2009 and 2008, our effective income tax rates have been distorted by changes in our estimated annual effective rate. As of September 30, 2009 and 2008, our estimated annual effective income tax rates were approximately 14% and 20%, as compared to approximately 22% and 25% as of June 30, 2009 and 2008.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues decreased by $3,691.6 million, or 54%, for 2009 compared to 2008. Revenues from the sale of natural gas decreased by $693.4 million, consisting of a decrease of $850.5 million due to lower realized prices and an increase of $157.1 million due to higher sales volumes. Revenues from the sale of NGLs decreased by $2,966.1 million, consisting of a decrease of $2,722.1 million due to lower realized prices and a decrease of $244.0 million due to lower sales volumes. Revenues from the sale of condensate decreased by $37.4 million, consisting of a decrease of $66.7 million due to lower realized prices, partially offset by an increase of $29.3 million due to higher sales volumes. Other revenues, which includes revenues principally derived from fee-based services, increased by $5.3 million.

Average realized price for natural gas decreased by $5.28 per MMBtu, or 58%, for 2009 compared to 2008. Average realized prices for NGLs decreased by $0.83 per gallon, or 54%, for 2009 compared to 2008. Our average realized price for condensate decreased by $51.07 per Bbl, or 48%, for 2009 compared to 2008.

Natural gas sales volumes increased by 65.5 BBtu/d, or 12%, for 2009 compared to 2008. NGL sales volumes decreased by 12.7 MBbl/d, or 4%, for 2009 compared to 2008. Condensate sales volumes increased by 1.0 MBbl/d, or 26%, for 2009 compared to 2008 due to a reduction in affiliate sales. For information regarding the period to period changes in our commodity sales volumes, see “—Results of Operations—By Segment.”

Product purchases decreased by $3,594.5 million, or 58%, for 2009 compared to 2008. See “—Results of Operations—By Segment” for an explanation of the components of the decrease.

Operating expenses decreased by $25.7 million, or 12%, for 2009 compared to 2008. See “—Results of Operations—By Segment” for a detailed explanation of the components of the decrease.

Depreciation and amortization expense increased by $9.9 million, or 8%, for 2009 compared to 2008. The increase was due to a $1.5 million asset impairment included in depreciation expense, the addition of property, plant and equipment and the consolidation of our investment in VESCO, starting August 1, 2008, following our acquisition of majority ownership.

General and administrative expense increased by $4.8 million, or 6%, for 2009 compared to 2008. We experienced increases in property insurance and compensation costs, partially offset by decreases in outside professional service costs.

Other operating expenses decreased by $11.6 million in 2009 compared to $ 2008.  The decrease included a $17.9 million 2008 casualty loss related to Hurricanes Gustav and Ike, and a $3.7 million 2009 favorable casualty loss adjustment related to the 2008 hurricanes, partially offset by $5.6 million in 2009 project abandonment costs and a $4.5 million reduction in gains from asset sales.

Equity earnings decreased $10.0 million for 2009 compared to 2008. This decrease was due primarily to our consolidation of VESCO, following our acquisition of majority ownership starting August 1, 2008.

45

Loss on debt repurchases of $1.5 million resulted from the Partnership’s retirement of a portion of its outstanding 11¼% Notes during 2009.

The $14.8 million loss on early debt extinguishment consisted of the write-off of debt issue costs related to prepayments on our senior secured term loan facility. In addition, the loss includes a $7.2 million out of period adjustment related to prepayments made during 2007. See Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Interest expense increased by $3.3 million, or 4%, for 2009 compared to 2008. This was primarily attributable to the issuance of the Partnership’s $250 million par value 11¼ % Senior Unsecured Notes in July, 2009.

During interim periods income tax expense is based on an estimated annual effective income tax rate plus any significant unusual or infrequently occurring items recorded in the period that the specific item occurs. As our annual estimate of pre-tax income changes, our effective tax rate may increase or decrease. The variance in our estimated annual effective tax rate from the 35% federal statutory rate primarily results from the inclusion in our pre-tax income of income from pass-through entities, the tax effects of estimated annual permanent differences and state income taxes.

For the nine months ended September 30, 2009 and 2008, our income tax expense was approximately 14% and 20% of pre-tax income. The effective tax rate for the periods result primarily from changes in the relationship of estimated pre-tax income relative to estimated permanent differences.

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Results of Operations—By Segment

Segment operating financial results and operating statistics include the effects of intersegment transactions. These intersegment transactions have been eliminated from the consolidated presentation. For all operating statistics presented, the numerator is the total volumes or sales for the period and the denominator is the number of calendar days for the period.

Natural Gas Gathering and Processing Segment

The following table provides summary financial data regarding results of operations in our Natural Gas Gathering and Processing segment for the periods indicated:

	Three Months						Nine Months
	Ended September 30						Ended September 30,
	2009			2008			2009			2008
	($ in millions)
Revenues (1)	$	553.2		$	971.2		$	1,454.8		$	2,904.0
Product purchases		(426.0	)		(816.4	)		(1,118.0	)		(2,455.0	)
Operating expenses		(36.7	)		(37.5	)		(98.7	)		(102.3	)
Operating margin (2)	$	90.5		$	117.3		$	238.1		$	346.7
Equity in earnings of VESCO (3)	$	-		$	1.4		$	-		$	10.2
Operating statistics:
Gathering throughput, MMcf/d		2,323.5			1,859.2			2,142.5			2,034.5
Plant natural gas inlet, MMcf/d		2,274.2			1,817.3			2,097.7			1,994.9
Gross NGL production, MBbl/d		123.5			100.8			117.1			103.2
Natural gas sales, BBtu/d		683.9			532.7			609.2			543.0
NGL sales, MBbl/d		99.5			84.7			95.0			88.6
Condensate sales, MBbl/d		4.8			4.8			5.0			4.9
Average realized prices:
Natural gas, $/MMBtu		3.46			9.22			3.79			9.08
NGL, $/gal		0.75			1.48			0.66			1.42
Condensate, $/Bbl		67.54			102.36			53.29			97.54

____________

(1) Includes business interruption insurance revenue of $2.9 million and $5.5 million for the three and nine months ended September 30, 2009, and $0.7 million and $3.3 million for the three and nine months ended September 30, 2008.

(2) See “Non-GAAP Financial Measures” included in this Item 2.

(3) Amounts are through July 31, 2008. VESCO was included in our consolidated results effective August 1, 2008.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues decreased by $418.0 million, or 43%, for 2009 compared to 2008. The decrease was primarily due to lower natural gas, NGL and condensate prices, partially offset by higher natural gas, NGL and condensate sales volumes.

Average realized price for natural gas decreased by $5.76 per MMBtu, or 62%, for 2009 compared to 2008. Our average realized price for NGLs decreased by $0.73 per gallon, or 49%, for 2009 compared to 2008. Our average realized price for condensatedecreased by $34.82 per Bbl, or 34%, for 2009 compared to 2008.

Natural gas sales volumes increased by 151.2 BBtu/d, or 28%, for 2009 compared to 2008. Our NGL sales volumes increased by 14.8 MBbl/d, or 17%, for 2009 compared to 2008. Our condensate sales volumes remained unchanged at 4.8 MBbl/d for 2009 compared to 2008. The increase in natural gas sales volumes was primarily due to increased demand from our industrial customers and increased sales under third party contracts. The increase in NGL sales volumes was primarily due to the consolidation of VESCO, starting August 1, 2008 and the impact of plant shutdowns after hurricanes Ike and Gustav in September 2008.

47

Product purchases decreased by $390.4 million, or 48%, for 2009 compared to 2008. The decrease in product purchases corresponds to the decrease in commodity revenue.

Operating expenses decreased $0.8 million, or 2%, for 2009 compared to 2008. The decrease was primarily due to decreases in maintenance, repairs and supplies, and chemical and lubricants expenses, partially offset by increased costs associated with the consolidation of our investment in VESCO, starting August 1, 2008, following our acquisition of majority ownership.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues decreased by $1,449.2 million, or 50%, for 2009 compared to 2008. The decrease was primarily due to lower natural gas, NGL and condensate prices, partially offset by higher natural gas and NGL sales volumes.

Average realized price for natural gas decreased by $5.29 per MMBtu, or 58%, for 2009 compared to 2008. Our average realized price for NGLs decreased by $0.76 per gallon, or 54%, for 2009 compared to 2008. Our average realized price for condensate decreased by $44.25 per Bbl, or 45%, for 2009 compared to 2008.

Natural gas sales volumes increased by 66.2 BBtu/d, or 12%, for 2009 compared to 2008.  The increase in natural gas sales volumes was primarily due to increased demand from our industrial customers and increased sales under third party contracts. Our NGL sales volumes increased by 6.4 MBbl/d, or 7%, for 2009 compared to 2008. The increase in NGL sales volumes was primarily due to the consolidation of VESCO, starting August 1, 2008 and the impact of plant shutdowns after hurricanes Ike and Gustav in September 2008. Our condensate sales volumes increased by 0.1 MBbl/d, or 2%, for 2009 compared to 2008.

Product purchases decreased by $1,337.0 million, or 54%, for 2009 compared to 2008. The decrease in product purchases reflects lower commodity pricing and purchases of wellhead volumes.

Operating expenses decreased $3.6 million, or 4%, for 2009 compared to 2008. The decrease was primarily due to decreases in maintenance, repairs and supplies and chemicals and lubricants, partially offset by increased costs associated with the consolidation of our investment in VESCO, starting August 1, 2008, following our acquisition of majority ownership.

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Logistics Assets Segment

The following table provides summary financial data regarding results of operations of our Logistics Assets segment for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	($ in millions)
Revenues from services	$	55.1		$	65.5		$	152.9		$	181.8
Other revenues (1)		(0.1	)		(0.1	)		1.9			0.5
		55.0			65.4			154.8			182.3
Operating expenses		(30.2	)		(49.8	)		(98.2	)		(148.2	)
Operating margin (2)	$	24.8		$	15.6		$	56.6		$	34.1
Equity in earnings of GCF	$	1.4		$	1.1		$	3.2		$	3.0
Operating statistics:
Fractionation volumes, MBbl/d		225.9			207.1			215.4			219.3
Treating volumes, MBbl/d (3)		27.5			20.4			18.5			19.0

____________

(1) Includes business interruption insurance revenue of $0 and $1.9 million for the three and nine months ended September 30, 2009, and $0 and $0.4 million for the three and nine months ended September 30, 2008.

(2) See “Non-GAAP Financial Measures” included in this Item 2.

(3) Consists of the volumes treated in our low sulfur natural gasoline unit.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $10.4 million, or 16%, for 2009 compared to 2008. Although fractionation and treating volumes increased, revenue decreased as the fuel component of the related fees was lower due to lower natural gas prices which also lowered operating expense.

Operating expenses decreased by $19.6 million, or 39%, for 2009 compared to 2008. The decrease was due to lower fuel, utility, equipment rental/maintenance, and barge fees related to lower volumes and decreased fuel and utility rates.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $28.9 million, or 16%, for 2009 compared to 2008. The decrease was primarily due to decreased fractionation and terminalling and storage volumes as a result of damage to certain of our and third party Gulf Coast processing, pipeline and production facilities from Hurricane Ike as well as a lower fuel component of the fractionation fees. In addition, truck and barge volumes were lower for 2009 due to decreased mixed butanes and wholesale activity.

Operating expenses decreased by $50.0 million, or 34%, for 2009 compared to 2008. The decrease was due to lower fuel, utility, equipment rental/maintenance, and barge fees related to lower volumes and decreased fuel and utility rates.

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NGL Distribution and Marketing Services Segment

The following table provides summary financial data regarding results of operations of our NGL Distribution and Marketing Services segment for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	762.4		$	1,654.0		$	2,011.2		$	4,564.4
Other revenues (1)		1.4			0.8			3.6			10.9
		763.8			1,654.8			2,014.8			4,575.3
Product purchases		(755.7	)		(1,679.4	)		(1,982.2	)		(4,558.8	)
Operating expenses		-			(0.3	)		(0.6	)		(1.5	)
Operating margin (2)	$	8.1		$	(24.9	)	$	32.0		$	15.0
Operating data:
NGL sales, MBbl/d		244.5			258.1			251.2			257.5
NGL realized price, $/gal		0.81			1.66			0.70			1.54

____________

(1) Includes business interruption insurance revenue of $0 and $8.6 million for the three and nine months ended September 30, 2008.

(2) See “Non-GAAP Financial Measures” included in this Item 2.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

NGL sales revenues decreased by $891.6 million, or 54%, for 2009 compared to 2008. The net decrease comprised an $804.4 million decrease from lower average sales prices, which were down 51% during 2009 compared to 2008 and an $87.2 million decrease from lower sales volumes, down5% during 2009 compared to 2008. The decrease in sales volumes was primarily attributable to a change in contract terms with a large petrochemical customer partially offset by higher plant operational rates and spot sales.

Other revenues, which consist primarily of non-commodity based service revenue, increased by $0.6 million.

Product purchases decreased by $923.7 million, or 55%, for 2009 compared to 2008. The net decrease comprised a $744.1 million decrease from lower average market prices, a $155.5 million decrease from lower purchased volumes and no lower of cost or market adjustment in 2009. Product purchases in 2008 included a $24.1 million lower of cost or market adjustment.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

NGL sales revenues decreased by $2,553.2 million, or 56%, for 2009 compared to 2008. The net decrease comprised a $2,424.9 million decrease from lower average sales prices during 2009 down 55% to $0.70 per gallon from $1.54 per gallon in 2008 and a $128.3 million decrease from lower sales volumes down 2% in 2009 compared to 2008. The decrease in sales volumes was primarily due to reduced sales to petrochemical customers associated with their lower plant operational rates offset by higher spot sales.

Other revenues, decreased by $7.3 million primarily due to $8.6 million in proceeds from business interruption claims received in 2008 partially offset by lower 2008 non-commodity based service revenue of $1.3 million.

Product purchases decreased by $2,576.6 million, or 57%, for 2009 compared to 2008. The net decrease comprised a $2,273.2 million decrease in average commodity prices, a $279.3 million decrease from lower purchased volumes and no lower of cost or market adjustment in 2009. Product purchases in 2008 included a $24.1 million lower of cost or market adjustment.

50

Wholesale Marketing Segment

The following table provides summary financial data regarding results of operations of our Wholesale Marketing segment for the periods indicated:

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	141.7		$	320.6		$	559.4		$	1,175.3
Other revenues (1)		0.3			-			1.2			5.9
		142.0			320.6			560.6			1,181.2
Product purchases		(138.7	)		(326.0	)		(549.9	)		(1,168.2	)
Operating margin (2)	$	3.3		$	(5.4	)	$	10.7		$	13.0
Operating data:
NGL sales, MBbl/d		41.2			47.0			54.9			60.1
NGL realized price, $/gal		0.89			1.77			0.89			1.70

____________

(1) Includes business interruption insurance revenue of $0 and $0.5 million for the three and nine months ended September 30, 2009, and $0 and $5.9 million for the three and nine months ended September 30, 2008.

(2) See “Non-GAAP Financial Measures” included in this Item 2.

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

NGL sales revenues decreased by $178.9 million, or 56%, for 2009 compared to 2008. Lower NGL market prices decreased revenue by $139.2 million and lower sales volumes decreased revenue by an additional $39.6 million. The 5.8 MBbl/d decrease in volumes was primarily due to decreased sales of propane due to the expiration of refinery purchase agreements.

Product purchases decreased by $187.3 million, or 57%, for 2009 compared to 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $142.6 million and $39.6 million as well as a decrease of $5.1 million related to lower of cost or market adjustments in 2009.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

NGL sales revenues decreased by $615.9 million, or 52%, for 2009 compared to 2008. Lower NGL market prices decreased revenue by $510.4 million and lower sales volumes decreased revenue by an additional $105.5 million. The 5.2 MBbl/d decrease in volumes was primarily due to reduced sales of propane as a result of the expiration of sales supply agreements as well as lower butane sales associated with the expiration of a refinery supply agreement.

Product purchases decreased by $618.3 million, or 53%, for 2009 compared to 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $523.3 million and $90.3 million as well as a decrease of $4.7 million related to lower of cost or market adjustments in 2009.

Hurricane Update

Certain of our Louisiana and Texas facilities sustained damage and had disruption to their operations during the 2008 hurricane season from two Gulf Coast hurricanes—Gustav and Ike. As of December 31, 2008, we recorded a $19.3 million loss provision (net of estimated insurance reimbursements) related to the hurricanes. During the nine months ended September 30, 2009, the estimate was reduced by $3.7 million.

During the nine months ended September 30, 2009, expenditures related to the hurricanes included $32.8 million for previously accrued repair costs, and $7.5 million capitalized as improvements.

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Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet indebtedness obligations, to refinance indebtedness or to meet collateral requirements depends on the ability to generate cash in the future. The ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for natural gas and NGLs, and ongoing efforts to manage operating costs and maintenance capital expenditures as well as general economic, financial, competitive, legislative, regulatory and other factors. See “Item 1A. Risk Factors” in this Quarterly Report and our Annual Report.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowings under our senior secured credit facility and access to debt capital markets. While the credit markets have improved somewhat, we remain exposed to availability under our revolving credit facility and counterparty risks. In addition, the recent volatility in the debt markets have increased costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks.

Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. We have substantially all of our commodity derivatives with major financial institutions. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges under lower commodity prices, which could have a materially adverse effect on our results of operations. We sell a significant portion of our natural gas, NGLs and condensate to a variety of purchasers. Non-performance by a trade creditor could result in losses.

Crude oil and natural gas prices are also volatile and in the case of natural gas have declined significantly during the year.  In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity derivative contracts for a portion of our estimated equity volumes through 2013 (see Note 13 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report). Current market conditions may also impact our ability to enter into future commodity derivative contracts. In the event of a continuing global recession, commodity prices may stay depressed or reduce further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

At this point, we do not believe our liquidity has been materially affected by the current credit crisis and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the credit markets. Additionally, we will continue to monitor events and circumstances surrounding each of the lenders under our senior secured revolving credit facility and the lenders under the Partnership’s senior secured credit facility. To date, other than a default by an affiliate of Lehman Brothers Commercial Bank (“Lehman Bank”) on a borrowing request in October 2008, neither we nor the Partnership have experienced any material disruptions in our ability to access our respective bank credit facilities. However, we cannot predict with any certainty the impact to us of any further disruption in the credit environment. See “Item 1A. Risk Factors” in our Annual Report.

Historically, cash generated by our operations has been sufficient to finance our operating expenditures and non-acquisition related capital expenditures. Based on our anticipated levels of operations and absent any disruptive events, we believe that internally generated cash flow, borrowings available under our senior secured revolving credit facilities and access to capital markets should provide sufficient resources to finance our operations, non-acquisition related capital expenditures, hurricane-related repair expenditures, long-term indebtedness obligations and collateral requirements for at least the next year.

A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of September 30, 2009, our total outstanding letter of credit postings were $38.1 million.

The Partnership may issue equity or debt securities to assist the Partnership in meeting its liquidity and capital spending requirements. The Partnership has a universal shelf registration statement on file with the SEC that allows it to periodically issue up to $500 million in equity or debt securities. Proceeds from offerings under this universal shelf registration statement are currently expected to be used by the Partnership for general partnership purposes or

52

other purposes to be specified in connection with an offering. After taking into account the issuances of common units under this shelf registration in August 2009, the Partnership can issue approximately $391.7 million of additional equity or debt securities under this registration statement.

Our derivative contracts do not have margin requirements or collateral provisions that could require posting of margin prior to the scheduled cash settlement date. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report and our Annual Report and see Part II, Item 1A, Risk Factors in this Quarterly Report.

Contractual Obligations.  As of September 30, 2009, Except for changes in the ordinary course of our business, our contractual obligations have not changed materially from those reported in our Annual Report.

Available Credit. As of September 30, 2009, we had approximately $252.0 million in total availability under our credit facility, including $240.0 million under our senior secured revolving credit facility (after giving effect to the Lehman Bank default) and $12.0 million under our senior secured synthetic letter of credit facility. In addition, the Partnership had approximately $390.0 million in availability under its senior secured credit facility (also after giving effect to the Lehman Bank default). We consolidate the debt of the Partnership in our financial statements; however, we do not have any obligations with respect to the debt of the Partnership.

Cash Flow. Net cash provided by or used in operating activities, investing activities and financing activities for the periods presented were as follows:

	Nine Months Ended September 30,
	2009			2008
	(In millions)
Net cash provided by (used in):
Operating activities	$	209.1		$	262.5
Investing activities		(90.0	)		(186.3	)
Financing activities		(293.9	)		(130.7	)

Net cash provided by operating activities decreased $53.4 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The decrease was primarily due to decreases of $99.2 million in working capital, $93.7 million in net income and $25.3 million in deferred tax adjustments, partially offset by increases of $111.9 million in risk management activities, $18.6 million in prior year noncash gain on insurance settlement, $16.3 million in noncash loss on debt extinguishments, $11.1 million in equity earnings from unconsolidated affiliates and $9.9 million in depreciation and amortization adjustments.

Net cash used in investing activities decreased $96.3 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The decrease was primarily due to a $124.9 million nonrecurring payment in 2008 to acquire an additional interest in VESCO and a $19.0 million decrease in additions to property, plant and equipment, partially offset by a $24.5 million decrease in insurance proceeds and a $22.9 million increase in purchases of debt obligations of Targa Resources Investments Inc.

Net cash used in financing activities increased $163.2 million for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The increase in cash used in 2009 compared to 2008 was primarily due to $594.5 million in additional payments of long term debt, and $18.9 million in repurchases of the Partnership’s senior notes partially offset by $310.1 million in additional borrowings from long term debt, $105.5 million in additional net contributions from noncontrolling interest, and a $52.6 million decrease in distributions to our parent.

Capital Requirements. The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A significant portion of the cost of constructing new gathering lines to connect to our gathering system is generally paid for by the natural gas producer. However, we expect to continue to

53

incur significant expenditures throughout 2009 related to the expansion of our natural gas gathering and processing infrastructure.

We estimate that our total capital expenditures for 2009 will be approximately $90.0 million. Given our objective of growth through acquisitions, expansions of existing assets and other internal growth projects, we anticipate that we will invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our senior secured credit facility and debt offerings.

Non-GAAP Financial Measures

For a complete discussion of the measures that management uses to evaluate our operations, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate our Operations” in our Annual Report.

Our operating margin by segment and in total was as follows for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009		2008
	(In millions)
Natural Gas Gathering and Processing	$	90.5		$	117.3		$	238.1	$	346.7
Logistics Assets		24.8			15.6			56.6		34.1
NGL Distribution and Marketing Services		8.1			(24.9	)		32.0		15.0
Wholesale Marketing		3.3			(5.4	)		10.7		13.0
Other		(0.8	)		-			-		-
	$	125.9		$	102.6		$	337.4	$	408.8

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The following tables reconcile the non-GAAP financial measures used by management to their most directly comparable GAAP measures for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(In millions)
Reconciliation of net income (loss) attributable to
Targa Resources, Inc. to operating margin:
Net income (loss) attributable to Targa Resources, Inc.	$	(2.6	)	$	(20.9	)	$	13.5		$	43.7
Add:
Net income attributable to noncontrolling interest		11.1			24.3			17.7			81.2
Depreciation and amortization expense		44.3			41.1			127.9			118.0
General and administrative expense		31.4			26.7			83.5			78.7
Loss on debt repurchases		1.5			-			1.5			-
Loss on early debt extinguishment		14.8			-			14.8			-
Interest expense, net		29.4			24.6			77.1			73.8
Income tax benefit (expense)		(1.2	)		(9.9	)		5.2			30.4
Other, net		(2.8	)		16.7			(3.8	)		(17.0	)
Operating margin	$	125.9		$	102.6		$	337.4		$	408.8

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Reconciliation of net cash provided by (used in)	(In millions)
operating activities to Adjusted EBITDA:
Net cash provided by (used in) operating activities	$	96.2		$	(111.8	)	$	209.1		$	262.6
Net income attributable to noncontrolling interest		(11.1	)		(24.4	)		(17.7	)		(81.2	)
Interest expense, net (1)		27.7			22.8			72.0			67.9
Loss on debt repurchases		(1.5	)		-			(1.5	)		-
Current income tax expense (benefit)		0.2			(1.0	)		0.3			0.2
Other		(1.5	)		81.6			(1.7	)		112.4
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		4.5			(154.5	)		15.9			(291.0	)
Accounts payable and other liabilities		(24.2	)		233.4			(3.1	)		204.5
Adjusted EBITDA	$	90.3		$	46.1		$	273.3		$	275.4

____________

(1)   Net of debt issue costs of $1.5 million and $5.1 million for the three and nine months ended September 30, 2009, and $1.6 million and $5.7 million for the three and nine months ended September 30, 2008.

55

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009		2008
	(In millions)
Reconciliation of net income (loss) attributable to
Targa Resources, Inc. to Adjusted EBITDA:
Net income (loss) attributable to Targa Resources, Inc.	$	(2.6	)	$	(20.9	)	$	13.5	$	43.7
Add:
Interest expense, net (1)		44.1			24.6			91.9		73.8
Income tax expense (benefit) (2)		(0.9	)		(10.6	)		4.9		29.2
Depreciation and amortization expense		44.2			41.1			127.9		118.0
Non-cash loss related to derivatives		5.5			11.9			35.1		10.7
Adjusted EBITDA	$	90.3		$	46.1		$	273.3	$	275.4

_________

(1)   Includes loss on early debt extinguishment.

(2)   Net of income tax expense attributable to noncontrolling interest of $0.4 million and $1.2 million for the three and nine months ended September 30, 2008.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates. The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. Please see the description of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.

Property, Plant and Equipment. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits. Property, plant and equipment is depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in-service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include:

· changes in energy prices;

· changes in competition;

· changes in laws and regulations that limit the estimated economic life of an asset;

· changes in technology that render an asset obsolete;

· changes in expected salvage values; or

· changes in the forecast life of applicable resource basins, if any.

At September 30, 2009, the net book value of our property, plant and equipment was $2.6 billion and we recorded $44.3 million and $127.9 million of depreciation and amortization expense for three and nine months ended September 30, 2009. The weighted average life of our long-lived assets is approximately 20 years.  If the useful lives of these assets were found to be shorter than originally estimated, depreciation and amortization expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result. For example, if the depreciable lives of our assets were reduced by 10%, we estimate that depreciation expense would increase by $14.2 million, which would result in a corresponding

56

reduction in our operating income.  In addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, our operating income would decrease by $25.6 million. There have been no material changes impacting estimated useful lives of the assets.

Revenue Recognition. Revenues for a period reflect collections to the report date plus any uncollected revenues reported for the period which are reflected as accounts receivable in the balance sheet. As of September 30, 2009, our balance sheet reflects total accounts receivable of approximately $303.3 million. Our allowance for doubtful accounts as of September 30, 2009 was $9.1 million.

Our exposure to uncollectible accounts receivable relates to the financial health of our counterparties.  We have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties.  If an assessment of uncollectibility resulted in a 1% reduction of our accounts receivable, our operating income would decrease by $3.0 million. There have been no material changes impacting accounts receivable.

Price Risk Management (Hedging). Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. To reduce the volatility of our cash flows, we have entered into (i) derivative financial instruments related to a portion of our equity volumes to manage the purchase and sales prices of commodities and (ii) interest rate financial instruments to fix the interest rate on our variable debt. We are exposed to the credit risk of our counterparties in these derivative financial instruments.

Our cash flow is affected by the derivative financial instruments we enter into to the extent these instruments are settled by (i) making or receiving a payment to/from the counterparty or (ii) making or receiving a payment for entering into a contract that exactly offsets the original derivative financial instrument. Typically a derivative financial instrument is settled when the physical transaction that underlies the derivative financial instrument occurs.

One of the primary factors that can affect our financial position each period is the price assumptions we use to value our derivative financial instruments, which are reflected at their fair values in the balance sheet. The relationship between the derivative financial instruments 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 derivative financial instrument and on an ongoing basis. Hedge accounting is discontinued prospectively when a derivative financial instrument becomes ineffective. Gains and losses deferred in other comprehensive income related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the derivative financial instrument are reclassified to earnings immediately.

The estimated fair value of our derivative financial instruments was $43.8 million as of September 30, 2009, net of an adjustment for credit risk. The credit risk adjustment is based on the default probabilities by year for each counterparty’s traded credit default swap transactions. These default probabilities have been applied to the unadjusted fair values of the derivative financial instruments to arrive at the credit risk adjustment, which aggregates to $0.5 million at September 30, 2009. We have an active credit management process which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties.  If a financial instrument counterparty were to declare bankruptcy, we would be exposed to the loss of fair value of the financial instrument transaction with that counterparty.  Ignoring our adjustment for credit risk, if a bankruptcy by a financial instrument counterparty impacted 10% of the fair value of commodity-based financial instruments, we estimate that our operating income would decrease by $4.4 million.

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Item 3.             Quantitative and Qualitative Disclosures about Market Risk

For an in-depth discussion of market risks, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our Annual Report.

Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas and NGLs (including the impact of reduced commodity prices on oil and gas drilling levels), changes in interest rates, as well as nonperformance by our customers, joint venture partners and derivative counterparties. We do not use risk sensitive instruments for trading purposes.

Commodity Price Risk. A significant portion of our revenues is derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs, or equity volumes, as payment for services. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into commodity derivative transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as hedges are classified in the same category as the cash flows from the item being hedged. For an in-depth discussion of our hedging strategies, see Item “7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk” in our Annual Report.

Our payment obligations in connection with substantially all of these hedging transactions, and any additional credit exposure due to a rise in natural gas and NGL prices relative to the fixed prices set forth in the hedges, are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (or floor) transaction does not create credit exposure to us for our counterparties.

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We have entered into hedging arrangements for a portion of our forecasted equity volumes. Floor volumes and floor pricing are based solely on purchased puts (or floors). As of September 30, 2009, we had the following hedge 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
														(In thousands)
Sales
Swap	NY-HH		2.97		968		-		-		-		-	$	(23	)
Swap	IF-Waha		6.62		21,918		-		-		-		-		4,259
Swap	IF-Waha		6.69		-		16,300		-		-		-		4,665
Swap	IF-Waha		6.46		-		-		12,500		-		-		(162	)
Swap	IF-Waha		7.18		-		-		-		5,500		-		1,154
					21,918		16,300		12,500		5,500		-
Swap	IF-PB		5.42		-		2,000		-		-		-		(305	)
Swap	IF-PB		5.42		-		-		2,000		-		-		(686	)
Swap	IF-PB		5.54		-		-		-		4,000		-		(1,257	)
Swap	IF-PB		5.54		-		-		-		-		4,000		(1,314	)
					-		2,000		2,000		4,000		4,000
Total Sales					22,886		18,300		14,500		9,500		4,000
														$	6,331

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NGLs
Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
														(In thousands)
Sales
Swap	OPIS-MB		0.80		3,347		-		-		-		-	$	(567	)
Swap	OPIS-MB		0.84		-		3,100		-		-		-		24
Swap	OPIS-MB		0.86		-		-		1,900		-		-		51
Swap	OPIS-MB		0.92		-		-		-		1,250		-		795
Total Swaps					3,347		3,100		1,900		1,250		-
Floor	OPIS-MB		1.44		-		-		54		-		-		395
Floor	OPIS-MB		1.43		-		-		-		63		-		479
Total Floors					-		-		54		63		-
Total Sales					3,347		3,100		1,954		1,313		-
														$	1,177

Condensate
Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
														(In thousands)
Sales
Swap	NY-WTI		67.85		-		200		-		-		-	$	(472	)
Swap	NY-WTI		71.00		-		-		200		-		-		(446	)
Swap	NY-WTI		72.60		-		-		-		200		-		(449	)
Swap	NY-WTI		73.80		-		-		-		-		200		(472	)
Total Swaps					-		200		200		200		200
Total Sales					-		200		200		200		200
														$	(1,839	)

60

As of September 30, 2009, the Partnership had the following hedge 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
														(In thousands)
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
														$	13,279

61

NGLs
Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
														(In thousands)
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
														(In thousands)
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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These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

Interest Rate Risk. We are exposed to changes in interest rates primarily as a result of variable rate debt under our senior secured credit facilities. To the extent that interest rates increase, interest expense on our revolving debt will also increase.

On September 24, 2009, we paid down our variable rate debt to $65.3 million. Accordingly all but $65.3 million of our interest rate hedges became ineffective and were dedesignated as they no longer quality for hedge accounting. On these dedesignated hedges, we recorded a mark-to-market gain of $0.2 million for the period from September 24, 2009 to September 30, 2009. The fair value of the dedesignated interest rate swaps at September 30, 2009 was a liability of $1.9 million. The remaining $65.3 million notional amount effectively fixes the base rate on $65.3 million of borrowings for the indicated periods. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates we entered into interest rate hedges that effectively fix the base rate on the indicated notional amount of borrowings as shown below:

Period	Fixed Rate		Notional Amount			Fair Value
						(In thousands)
Remainder of 2009		1.65%	$	65	million	$	(231	)
2010		1.65%		65	million		(542	)
2011		1.65%		65	million		346
01/01-03/31/2012		1.65%		66	million		195
						$	(232	)

In October 2009, we made payments of $3.2 million to terminate all of our interest rate hedges.

As of September 30, 2009, the Partnership had variable rate borrowings of $510.5 million outstanding under its senior secured revolving credit facility. In an effort to reduce the variability of its flows, the Partnership has entered into various 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 sheets. Accordingly, unrealized gains and losses relating to the interest rate swaps are recorded in OCI until the interest expense on the related debt is recognized in earnings. The effect of the Partnership’s interest rate hedges effectively fixes the base rate on $300 million in variable rate borrowings as shown below:

Period	Fixed Rate		Notional Amount			Fair Value
						(In thousands)
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
01/01-04/24/2014		3.39%		300	million		617
						$	(14,106	)

We have designated all interest rate derivative instruments as cash flow hedges. Accordingly, related unrealized gains and losses are recorded in OCI until interest expense on the related debt is recognized in earnings. A hypothetical increase of 100 basis points in the underlying interest rate, after taking into account these interest rate swaps and interest rate basis swaps, would increase our annual interest expense by $2.1 million.

63

Credit Risk. We are subject to risk of losses resulting from nonpayment or nonperformance by our customers, joint venture partners and derivative counterparties.

We monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy. A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could impact our overall exposure to credit risk since these customers may be impacted by similar economic or other conditions. To help reduce our credit risk, we evaluate our counterparties’ financial condition and, where appropriate, negotiate netting agreements. We generally do not require collateral for our accounts receivable; however, in certain circumstances we will call for prepayment, require automatic debit agreements or obtain collateral to minimize our potential exposure to defaults.

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

As of September 30, 2009, affiliates of Goldman Sachs, Barclays Bank and BofA accounted for 70%, 15% and 13% of our counterparty credit exposure related to commodity derivative instruments. Goldman Sachs, BofA and Barclays Bank are major financial institutions, each possessing investment grade credit ratings based upon credit ratings assigned by Standard & Poor’s Ratings Services.

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Item 4T.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of the end of the period covered by this report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of such period, our disclosure controls and procedures were effective at a reasonable assurance level to provide reasonable assurance that all material information relating to us required to be included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.

There has been no change in our internal control over financial reporting during the three months ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

The information required for this item is provided in Note 15—Commitments and Contingencies, under the heading “Legal Proceeding” included in the Notes to Consolidated Financial Statements included under Part I, Item 1, which is incorporated by reference into this item.

Item 1A. Risk Factors

For an in-depth discussion of our risk factors, see “Item 1A. Risk Factors” in our Annual Report. These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition and/or results of operations, as could the following:

A recent determination that emissions of carbon dioxide and other “greenhouse gases” present an endangerment to public health could result in regulatory initiatives that increase our costs of doing business and the costs of our services.

On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other “greenhouse gases” (“GHGs”) presented an endangerment to human health and the environment because emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes.  Once finalized, EPA’s finding and determination would allow the agency to begin regulating GHG emissions under existing provisions of the Clean Air Act.  In late September 2009, EPA announced two sets of proposed regulations in anticipation of finalizing its findings and determination, one rule to reduce emissions of greenhouse gases from motor vehicles and the other to control emissions of greenhouse gases from stationary sources.  Although the motor vehicle rules are expected to be adopted in March 2010, it may take EPA several years to adopt and impose regulations limiting emissions of greenhouse gases from stationary sources.  In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S., including natural gas liquids fractionators, beginning in 2011 for emissions occurring in 2010.  Any limitation imposed by the EPA on GHG emissions from our natural gas–fired compressor stations, processing facilities and fractionators or from the combustion of natural gas or natural gas liquids that we produce could increase our costs of doing business and/or increase the cost and reduce demand for our services.

The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the products and services we provide.

On June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA”, which would establish an economy-wide cap-and-trade program in the United States to reduce emissions of “greenhouse gases,” or “GHGs,” including carbon dioxide and methane that may be contributing to warming of the Earth’s atmosphere and other climatic changes. ACESA would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Under ACESA, covered sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, natural gas and NGLs.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States.  If the Senate adopts GHG legislation that is different from ACESA, the Senate legislation would need to be reconciled with ACESA and both chambers would be required to approve identical legislation before it could become law.  President Obama has indicated that he is in support of the adoption of legislation to control and reduce emissions of GHGs through an emission allowance permitting system that results in fewer allowances being issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission

66

obligations.  Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and could have an adverse effect on demand for our gathering, treating, processing and fractionating services.

Even if such legislation is not adopted at the national level, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, with most of the state-level initiatives focused on large sources of GHG emissions, such as coal-fired electric plants. It is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. ACESA contains provisions that would prohibit private energy commodity derivative and hedging transactions.  ACESA would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, and to mandate clearance of such derivative contracts through registered derivative clearing organizations.  Under ACESA, the CFTC’s expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The Chairman of the CFTC has announced that the CFTC intends to conduct hearings to determine whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products.  The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants.  In addition, the Treasury Department recently has indicated that it intends to propose legislation to subject all OTC derivative dealers and all other major OTC derivative market participants to substantial supervision and regulation, including by imposing conservative capital and margin requirements and strong business conduct standards.  Derivative contracts that are not cleared through central clearinghouses and exchanges may be subject to substantially higher capital and margin requirements.  Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or how any climate change bill approved by the Senate would be reconciled with ACESA, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our use of derivatives could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

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

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

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

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

0
Exhibit Number	Description
2.1*	Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP,  Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources, Inc.’s Current Report on Form 8-K filed July 29, 2009 (File No. 333-147066)).
3.1	Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.2	Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.3	Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.4	Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.5	Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
4.1	Indenture dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 7, 2009 (File No. 333-147066)).
4.2	Registration Rights Agreement dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources, Inc.’s Form 10-Q filed August 7, 2009 (File No. 333-147066)).
4.3**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.4**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.5**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.6**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.

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4.7**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.8**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.9**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.10**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.11**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.12**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.13**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.14**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.15**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.16**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.17**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.18**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.19**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.20**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.21**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.22**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.23**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.24**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.25**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.26**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
10.1	Commitment Increase Supplement, dated July 29, 2009, by and among Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto Issuer (incorporated by reference to Exhibit 10.2 to Targa Resources, Inc.’s Form 10-Q filed August 7, 2009 (File No. 333-147066)).
10.2	Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.3	Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.4	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Permian LP (incorporated by reference to Exhibit 10.3 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).

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10.5	Specification Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (SE La) (incorporated by reference to Exhibit 10.4 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.6	Raw Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (Versado) (incorporated by reference to Exhibit 10.5 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.7	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (West La) (incorporated by reference to Exhibit 10.6 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
31.1**	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2**	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementary a copy of any omitted exhibit or schedule to the SEC upon request.

** Filed herewith

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SIGNATURES

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

Targa Resources, Inc. (Registrant)
By:		/s/    JOHN ROBERT SPARGER
	John Robert Sparger Senior Vice President and Chief Accounting Officer (Authorized signatory and Principal Accounting Officer)

Date: November 9, 2009

71

Exhibit Index

0
Exhibit Number	Description
2.1*	Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP,  Targa GP Inc. and Targa LP Inc. (incorporated by reference to Exhibit 2.1 to Targa Resources, Inc.’s Current Report on Form 8-K filed July 29, 2009 (File No. 333-147066)).
3.1	Amended and Restated Certificate of Incorporation of Targa Resources, Inc. (incorporated by reference to Exhibit 3.1 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.2	Amended and Restated Bylaws of Targa Resources, Inc. (incorporated by reference to Exhibit 3.2 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.3	Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.3 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.4	Certificate of Amendment of the Certificate of Incorporation of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.4 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
3.5	Bylaws of Targa Resources Finance Corporation (incorporated by reference to Exhibit 3.5 to Targa Resources, Inc.’s Registration Statement on Form S-4 filed October 31, 2007 (File No. 333-147066)).
4.1	Indenture dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the Guarantors named therein and U.S. Bank National Association (incorporated by reference to Exhibit 4.1 to Targa Resources, Inc.’s Form 10-Q filed August 7, 2009 (File No. 333-147066)).
4.2	Registration Rights Agreement dated as of July 6, 2009, among Targa Resources Partners LP, Targa Resources Finance Corporation, the Guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Targa Resources, Inc.’s Form 10-Q filed August 7, 2009 (File No. 333-147066)).
4.3**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.4**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.5**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.6**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Downstream LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.7**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.8**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.9**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.10**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa LSNG LP, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.11**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.12**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Sparta LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.13**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.14**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Midstream Barge Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.15**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.16**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Retail Electric LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.17**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.18**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa NGL Pipeline Company LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.19**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.20**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Transport LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.21**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.22**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Co-Generation LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.23**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.24**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids GP LLC, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.25**	Supplemental Indenture dated September 24, 2009 to Indenture dated June 18, 2008, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
4.26**	Supplemental Indenture dated September 24, 2009 to Indenture dated July 6, 2009, among Targa Liquids Marketing and Trade, a subsidiary of Targa Resources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association.
10.1	Commitment Increase Supplement, dated July 29, 2009, by and among Targa Resources Partners LP, Bank of America, N.A. and the other parties signatory thereto Issuer (incorporated by reference to Exhibit 10.2 to Targa Resources, Inc.’s Form 10-Q filed August 7, 2009 (File No. 333-147066)).
10.2	Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.3	Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.4	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Permian LP (incorporated by reference to Exhibit 10.3 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).

10.5	Specification Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (SE La) (incorporated by reference to Exhibit 10.4 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.6	Raw Product Purchase Agreement dated September 24 , 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (Versado) (incorporated by reference to Exhibit 10.5 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
10.7	Raw Product Purchase Agreement dated September 24, 2009, to be effective September 1, 2009, between Targa Liquids Marketing and Trade and Targa Midstream Services Limited Partnership (West La) (incorporated by reference to Exhibit 10.6 to Targa Resources, Inc.’s Current Report on Form 8-K filed September 28, 2009 (file No. 333-147066)).
31.1**	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2**	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementary a copy of any omitted exhibit or schedule to the SEC upon request.

** Filed herewith