TRI Resources (NGLS) 10-Q 2009 Q2 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 June 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 001-33303

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 June 30, 2009 and December 31, 2008	4
	Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008	5
	Consolidated Statements of Cash Flows for the six months ended June 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	38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4T.	Controls and Procedures	59
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3.	Defaults Upon Senior Securities	61
Item 4.	Submission of Matters to a Vote of Security Holders	61
Item 5.	Other Information	61
Item 6.	Exhibits	62
SIGNATURES		63

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	Barrel(s)
BBtu	Billion British thermal unit(s)
Btu	British thermal unit, a measure of heating value
/d	Per day
Gal	Gallon(s)
MBbl	Thousand barrels
MMBtu	Million British thermal units
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
Price Index Definitions
IF-CGT	Inside FERC Gas Market Report, Columbia Gulf Transmission, Louisiana
IF-HSC	Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha	Inside FERC Gas Market Report, West Texas Waha
IF-PB	Inside FERC Gas Market Report, Permian Basin
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;

• the level of creditworthiness of counterparties to transactions;

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• 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 on Form 10-Q and our Annual Report on Form 10-K (“Annual Report”) for the year ended December 31, 2008.

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
	June 30,			December 31,
	2009			2008
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	217,825		$	362,769
Trade receivables, net of allowances of $9,089 and $9,380		308,987			303,904
Inventory		33,649			68,519
Assets from risk management activities		84,118			112,341
Other current assets		41,250			9,615
Total current assets		685,829			857,148
Property, plant and equipment, at cost		3,148,527			3,093,264
Accumulated depreciation		(559,245	)		(475,895	)
Property, plant and equipment, net		2,589,282			2,617,369
Long-term assets from risk management activities		47,811			89,774
Investment in debt obligations of Targa Resources Investments Inc.		35,198			10,953
Other assets		69,746			73,333
Total assets	$	3,427,866		$	3,648,577
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	144,649		$	153,756
Accrued liabilities		221,886			253,384
Current maturities of debt		12,500			12,500
Liabilities from risk management activities		13,921			11,664
Deferred income taxes		25,833			36,240
Total current liabilities		418,789			467,544
��
Long-term debt, less current maturities		1,410,270			1,552,440
Long-term liabilities from risk management activities		21,053			9,679
Deferred income taxes		50,731			40,027
Other long-term liabilities		61,145			49,638
Commitments and contingencies (see Note 14)
Stockholders' equity:
Common stock ($0.001 par value, 1,000 shares authorized, issued,
and outstanding at June 30, 2009 and December 31, 2008, collateral
for Targa Resources Investments Inc. debt)		-			-
Additional paid-in capital		420,348			420,067
Retained earnings		143,719			127,640
Accumulated other comprehensive income		18,103			31,934
Total Targa Resources, Inc. stockholder's equity		582,170			579,641
Noncontrolling interest in subsidiaries		883,708			949,608
Total stockholders' equity		1,465,878			1,529,249
Total liabilities and stockholders' equity	$	3,427,866		$	3,648,577
See notes to consolidated financial statements

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TARGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Unaudited)
	(In thousands)
Revenues	$	1,003,652		$	2,263,226		$	2,005,543		$	4,465,619
Costs and expenses:
Product purchases		828,786			2,023,089			1,674,784			4,024,530
Operating expenses		54,213			71,229			119,167			134,807
Depreciation and amortization expense		42,053			38,750			83,653			76,942
General and administrative expense		28,196			27,924			52,049			52,017
Other (see Note 18)		1,820			(2	)		1,807			(4,445	)
		955,068			2,160,990			1,931,460			4,283,851
Income from operations		48,584			102,236			74,083			181,768
Other income (expense):
Interest expense, net		(22,050	)		(23,660	)		(47,752	)		(49,245	)
Equity in earnings of unconsolidated investments		1,683			7,196			1,804			10,655
Gain on insurance claims (see Note 11)		-			18,566			-			18,566
Other income (see Note 19)		41			-			1,004			-
Income before income taxes		28,258			104,338			29,139			161,744
Income tax expense:
Current		(114	)		(275	)		(116	)		(1,237	)
Deferred		(6,362	)		(27,910	)		(6,289	)		(39,054	)
		(6,476	)		(28,185	)		(6,405	)		(40,291	)
Net income		21,782			76,153			22,734			121,453
Less: Net income attributable to noncontrolling interest		8,294			29,955			6,655			56,839
Net income attributable to Targa Resources, Inc.	$	13,488		$	46,198		$	16,079		$	64,614
See notes to consolidated financial statements

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TARGA RESOURCES, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
	Six Months Ended June 30,
	2009			2008
	(Unaudited)
	(In thousands)
Cash flows from operating activities
Net income	$	22,734		$	121,453
Adjustments to reconcile net income to net cash provided
by operating activities:
Amortization in interest expense		3,548			4,091
Interest income on paid-in-kind investment		(1,340	)		(30	)
Amortization in general and administrative expense		417			883
Depreciation and amortization expense		83,653			76,942
Accretion of asset retirement obligations		1,467			629
Deferred income tax expense		6,289			39,054
Equity in earnings of unconsolidated investments, net of distributions		(1,029	)		(9,880	)
Risk management activities		29,647			(1,176	)
Gain on sale of assets		(38	)		(4,445	)
Gain on property damage insurance settlement (See Note 11)		-			(18,566	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		(36,458	)		100,871
Inventory		25,093			35,630
Accounts payable and other liabilities		(21,063	)		28,919
Net cash provided by operating activities		112,920			374,375
Cash flows from investing activities
Additions to property, plant and equipment		(54,886	)		(57,978	)
Proceeds from property insurance		4,700			48,294
Investment in debt obligations of Targa Resources Investments Inc.		(12,239	)		(16,400	)
Other		155			364
Net cash used in investing activities		(62,270	)		(25,720	)
Cash flows from financing activities
Repayments of senior secured debt		(6,250	)		(6,250	)
Repayments of senior secured credit facility		(95,920	)		-
Repayments of senior secured credit facility of the Partnership		(40,000	)		(301,300	)
Proceeds from issuance of senior notes of the Partnership		-			250,000
Distributions to noncontrolling interest		(50,847	)		(42,480	)
Contribution from noncontrolling interest		1,071			-
Contribution from (distribution to) Targa Resources Investments Inc.		37			(53,752	)
Costs incurred in connection with financing arrangements		(3,685	)		(6,590	)
Net cash used in financing activities		(195,594	)		(160,372	)
Net increase (decrease) in cash and cash equivalents		(144,944	)		188,283
Cash and cash equivalents, beginning of period		362,769			177,949
Cash and cash equivalents, end of period	$	217,825		$	366,232
See notes to consolidated financial statements

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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 six months ended June 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 six months ended June 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 on Form 10-Q should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report on        Form 10-K for the year ended December 31, 2008.

We currently own approximately 26.4% 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 Gas Gathering and Processing segment in accordance with Emerging Issues Task Force (“EITF”) Issue No. 04-5, “Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights.”

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 June 30, 2009, up until the issuance of the financial statements, which occurred on August 6, 2009. See Notes 3, 7 and 21.

Note 2—Accounting Policies and Related Matters

Accounting Pronouncements Recently Adopted

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 applies to other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS 157 was initially effective as of January 1, 2008, but in February 2008, FASB delayed the effective date for applying this standard to nonfinancial assets and nonfinancial liabilities that are

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recognized or disclosed at fair value in the financial statements on a nonrecurring basis until periods beginning after November 15, 2008. We adopted SFAS 157 as of January 1, 2008 for 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 13.

On October 10, 2008, FASB issued FASB Staff Position (“FSP”) FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active.” FSP FAS 157-3 clarifies the application of SFAS 157 in a market that is not active and provides factors to take into consideration when determining the fair value of an asset in an inactive market. FSP FAS 157-3 was effective upon issuance, and applies to prior periods for which financial statements have not been issued. FSP FAS 157-3 did not have a material impact on our financial statements.

In December 2007, FASB issued SFAS 141R, “Business Combinations.” SFAS 141R 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. SFAS 141R also establishes principles and requirements for how an acquirer recognizes any noncontrolling interest in the acquiree and the goodwill acquired in a business combination. SFAS 141R was effective on a prospective basis for business combinations for which the acquisition date is on or after January 1, 2009. For any business combination that takes place subsequent to January 1, 2009, SFAS 141R may have a material impact on our financial statements. The nature and extent of any such impact will depend upon the terms and conditions of the transaction.

On April 1, 2009, FASB issued FSP FAS 141R-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination that Arise from Contingencies.” FSP FAS 141R-1 amends and clarifies SFAS 141R to address 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 FSP 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 FSP.

In December 2007, FASB issued SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of Accounting Research Bulletin No. 51.” SFAS 160 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. SFAS 160 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 SFAS 160 as of January 1, 2009. As a result, previously presented amounts have been conformed to the required presentation and additional disclosures have been provided.

On April 9, 2009, FASB issued FSP FAS 157-4, “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.” FSP FAS 157-4 relates to 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 FSP FAS 157-4 as of June 30, 2009. There have been no material financial statement implications relating to our adoption of FSP FAS 157-4.

On April 9, 2009, FASB issued FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP requires disclosures of fair value for any financial instruments not currently reflected at fair value on the balance sheet for all interim periods. We adopted this FSP as of June 30, 2009. There have been no material financial statement implications relating to the adoption of this FSP. See Note 15.

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In March 2009, FASB released Proposed Staff Position SFAS 157-e, “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 SFAS 157. SFAS 157-e 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 SFAS 157-e 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, “Recognition and Presentation of Other-Than-Temporary Impairments.”  This proposal provides guidance in determining whether impairments in debt securities are other than temporary, and modifies the presentation and disclosures surrounding such instruments.  This Proposed Staff Position 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 Proposed Staff Position as of April 1, 2009. This guidance did not have a significant impact on our financial statements.

On May 28, 2009, FASB issued SFAS 165, “Subsequent Events” . SFAS 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 sets forth (1) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. This SFAS is effective for interim and annual periods ended after June 15, 2009 and should be applied prospectively. The adoption of SFAS 165 did not have a material impact on our financial statements.

Accounting Pronouncements Recently Issued

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

Following SFAS 168, 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.

On June 30, 2009, FASB issued ASU 2009-1, “Topic 105—Generally Accepted Accounting Principles—amendments based on—Statement of Financial Accounting Standards No. 168—The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” ASU 2009-1 amends the Codification for the issuance of SFAS 168.

On June 30, 2009, FASB issued ASU 2009-2, “Omnibus Update—Amendments to Various Topics for Technical Corrections.” The technical corrections in ASU 2009-2 are not expected to impact our financial statements.

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 SFAS 141-R and SFAS 160. We do not anticipate that the adoption of this SAB will have a material impact on our consolidated financial statements.

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Note 3—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 six months ended June 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
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
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

Subsequent Event. On July 20, 2009, the Partnership announced a cash distribution of $0.5175 per unit on its outstanding common units. The distribution will be paid on August 14, 2009 to unitholders of record on August 5, 2009, for the period April 1, 2009 through June 30, 2009. The total distribution to be paid is $26.4 million, with  $18.0 million paid to the Partnership’s non-affiliated common unitholders and $6.0 million, $0.5 million and $1.9 million to be paid to us in respect of our common units, general partner interest and incentive distribution rights.

Note 4—Investment in Debt Securities of Targa Investments

During the six months ended June 30, 2009, we paid $12.2 million to acquire from a third party $27.2 million face value of Targa Investments’ outstanding variable rate indebtedness. As of June 30, 2009, we have acquired in total $47.0 million of the outstanding principal amount Targa Investments’ variable rate indebtedness for $28.6 million, including accrued interest.

The stated maturity date of the indebtedness is February 2015, and as of June 30, 2009, the variable rate was 5.3%. We have classified this investment as an available-for-sale security. During the three and six months ended June 30, 2009, we recognized unrealized gains of $8.7 million and $9.6 million in accumulated (“OCI”), based on an indicative valuation supplied by a bank. As of June 30, 2009 accumulated other comprehensive income OCI included $2.9million $1.8 million, net of tax) of net unrealized gains related to our investment in Targa Investments’ debt.

As of June 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)
$	18,080	$	5,841	$	13,430	$	(2,970	)	$	31,510	$	2,871

____________

 (1) Excludes $2.3 million of interest paid in-kind and $1.4 million in discount amortization.

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Note 5—Unconsolidated Investment

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

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

	June 30,		December 31,
	2009		2008
Logistics Assets - GCF	$	19,494	$	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.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Equity in earnings of:
VESCO (1) (2)	$	-	$	6,354	$	-	$	8,729
GCF		1,683		842		1,804		1,926
	$	1,683	$	7,196	$	1,804	$	10,655
Cash distributions:
GCF	$	775	$	-	$	775	$	775

____________

(1)   Includes our equity earnings through June 30, 2008.

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

Note 6—Income Tax Expense

Our implementation of SFAS 160 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 SFAS 160 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.

11

Note 7—Long-Term Debt

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

	June 30,			December 31,
	2009			2008
Long-term debt:
Obligations of Targa:
Senior secured term loan facility, variable rate, due October 2012	$	515,925		$	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		447,765			487,765
Senior unsecured notes, 8¼% fixed rate, due July 2016		209,080			209,080
Total debt		1,422,770			1,564,940
Current maturities of debt		(12,500	)		(12,500	)
Total long-term debt	$	1,410,270		$	1,552,440
Irrevocable standby letters of credit:
Letters of credit outstanding under synthetic letter of credit facility (2)	$	107,413		$	114,019
Letters of credit outstanding under senior secured revolving credit
facility of the Partnership		13,370			9,651
	$	120,783		$	123,670

____________

 (1) We consolidate the debt of the Partnership with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of the Partnership.

 (2) The $300 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 six months ended June 30, 2009.

	Range of interest rates paid	Weighted average interest rate paid
Senior secured term loan facility	2.3% to 6.0%		4.2	%
Senior secured revolving credit facility	2.1% to 3.5%		3.1	%
Senior secured revolving credit facility of the Partnership	1.3% to 4.5%		1.9	%

Subsequent Events.

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 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 credit facility;

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

·   are unconditionally guaranteed by the Partnership.

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The 11¼% Notes are effectively subordinated to all secured 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 agreement as of, and accrued and unpaid interest to, the date of redemption.

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

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

The 11¼% Notes are subject to a registration rights agreement dated as of July 6, 2009. Under the registration rights agreement, the Partnership is required to file by July 9, 2010 a registration statement with respect to any 11¼% Notes that are not freely transferable without volume restrictions by holders of the 11¼% Notes that are not the Partnership’s affiliates. If the Partnership fails to do so, additional interest will accrue on the principal amount of the 11¼% Notes. The Partnership has determined that the payment of additional interest is not probable. As a result, the Partnership has not recorded a liability for any contingent obligation. Any subsequent accrual of a liability under this registration rights agreement will be charged to earnings as interest expense.

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’ credit facility by $127.5 million, bringing the total commitments to $977.5 million. The Partnership may request additional commitments under its credit facility of up to $22.5 million, which would increase the total commitments under its credit facility to $1 billion.

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Note 8—Asset Retirement Obligations

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

	Six Months Ended June 30, 2009
Beginning of period	$	33,985
Change in cash flow estimate (1)		(2,854	)
Accretion expense		1,467
End of period	$	32,598

____________

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

Note 9—Statements of Changes in Stockholders’ Equity

The following table reflects 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		Non-
				Retained		Comprehensive			Paid-in		controlling
Six Months Ended June 30, 2009	Total			Earnings		Income			Capital		interest
Balance, December 31, 2008	$	1,529,249		$	127,640	$	31,934		$	420,067	$	949,608
Contributions		1,108			-		-			37		1,071
Distributions		(50,847	)		-		-			-		(50,847	)
Amortization of equity awards		417			-		-			244		173
Tax expense on vesting of common stock		-			-		-			-		-
Subtotal		1,479,927			127,640		31,934			420,348		900,005
Comprehensive income (loss):
Net income		22,734			16,079							6,655
Other comprehensive income (loss):
Change in fair value:
Commodity hedging contracts		(26,317	)				(10,947	)				(15,370	)
Interest rate swaps		3,846					557					3,289
Available for sale securities		9,571					9,571					-
Reclassification adjustment for settled periods:
Commodity hedging contracts		(36,718	)				(22,080	)				(14,638	)
Interest rate swaps		6,380					2,613					3,767
Foreign currency translation adjustment		463					463					-
Related income taxes		5,992			-		5,992			-		-
Total comprehensive income (loss)		(14,049	)		16,079		(13,831	)		-		(16,297	)
Balance, June 30, 2009	$	1,465,878		$	143,719	$	18,103		$	420,348	$	883,708

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						Accumulated
						Other			Additional			Non-
				Retained		Comprehensive			Paid-in			controlling
Six Months Ended June 30, 2008	Total			Earnings		Loss			Capital			interest
Balance, December 31, 2007	$	1,307,530		$	74,736	$	(56,116	)	$	473,784		$	815,126
Distributions		(96,232	)		-		-			(53,752	)		(42,480	)
Amortization of equity awards		883			-		-			763			120
Tax expense on vesting of common stock		(526	)		-		-			(526	)		-
Subtotal		1,211,655			74,736		(56,116	)		420,269			772,766
Comprehensive income (loss):
Net income		121,453			64,614								56,839
Other comprehensive income (loss):
Change in fair value:
Commodity hedging contracts		(362,384	)				(200,416	)					(161,968	)
Interest rate swaps		(270	)				(72	)					(198	)
Available for sale securities		(1,900	)				(1,900	)					-
Reclassification adjustment for settled periods:
Commodity hedging contracts		52,401					30,551						21,850
Interest rate swaps		616					163						453
Foreign currency translation adjustment		(242	)				(242	)					-
Related income taxes		63,408			-		63,408			-			-
Total comprehensive income (loss)		(126,918	)		64,614		(108,508	)		-			(83,024	)
Balance, June 30, 2008	$	1,084,737		$	139,350	$	(164,624	)	$	420,269		$	689,742

Note 10—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 six months ended June 30, 2009 was less than $0.1 million. Share-based compensation cost related to stock options included in general and administrative expense for the three and six months ended June 30, 2008 was $0.1million. As of June 30, 2009, our remaining unamortized compensation cost related to stock options was $0.1 million, which is expected to be recognized over a weighted-average period of approximately one year.

Non-vested (Restricted) Common Stock

Share-based compensation cost related to restricted stock included in general and administrative expense for the three and six months ended June 30, 2009 was $0.1 million and $0.2 million. Share-based compensation cost related to restricted stock included in general and administrative expense for the three and six months ended June 30, 2008 was $0.3 million and $0.7 million. As of June 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 six 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 six months ended June 30, 2009, we recognized compensation

15

expense of $0.1 million 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 two years. For the three and six months ended June 30, 2008, we recognized compensation expense of $0.1 million related to these awards.

Performance Units.  In January 2009, 122,100 performance units were awarded 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 June 30, 2009, the aggregate fair value of performance units expected to vest was $10.1 million. For the three and six months ended June 30, 2009, we recognized compensation expense related to the performance units of $1.2 million and $1.8 million. The recognition period for the remaining unrecognized compensation cost is approximately three years. For the three and six months ended June 30, 2008, we recognized compensation expense related to the performance units of $0.8 million and $0.9 million.

Note 11—Hurricane 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 six months ended June 30, 2009, the estimate was reduced by $3.7 million.

During the three and six months ended June 30, 2009, expenditures related to the hurricanes included $11.6 million and $29.1 million for previously accrued repair costs, and $3.0 million and $7.3 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 six months ended June 30, 2008, our cumulative receipts exceeded such amount. Accordingly, during the three and six months ended June 30, 2008, we recognized a gain of $18.6 million.

During the three and six months ended June 30, 2009 and 2008, we recognized revenue from business interruption insurance of:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Included in revenues
Natural Gas Gathering and Processing	$	1,374	$	2,540		2,574		2,540
Logistics Assets		1,926		441		1,926		441
NGL Distribution and Marketing		-		8,602		-		8,602
Wholesale Marketing (1)		-		5,920		500		5,920
	$	3,300	$	17,503	$	5,000	$	17,503

____________

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

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Note 12—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 June 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 our variable rate debt under our credit facility. To the extent that interest rates increase, our interest expense for our revolving debt will also increase. As of June 30, 2009, we had outstanding variable rate borrowings of approximately $963.7 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 accumulated other comprehensive income (“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 June 30, 2009, affiliates of Goldman Sachs, Bank of America (“BofA”) and Barclays Bank accounted for 65%, 20% 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 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	June 30,		December 31,		Sheet	June 30,		December 31,
	Location	2009		2008		Location	2009		2008
Derivatives designated as
hedging instruments under
SFAS 133
Commodity contracts	Current assets	$	78,784	$	108,731	Current liabilities	$	1,706	$	-
	Other assets		45,461		89,774	Other liabilities		16,863		123
Interest rate contracts	Current assets		2,352		-	Current liabilities		9,222		8,020
	Other assets		2,350		-	Other liabilities		4,190		9,556
Total			128,947		198,505			31,981		17,699
Derivatives not designated as
hedging instruments under
SFAS 133
Commodity contracts	Current assets		2,982		3,610	Current liabilities		2,993		3,644
	Other assets		-		-	Other liabilities		-		-
Total			2,982		3,610			2,993		3,644
Total derivatives		$	131,929	$	202,115		$	34,974	$	21,343

	Gain (Loss)
Derivatives in	Recognized in OCI on
SFAS 133	Derivatives (Effective Portion)
Cash Flow Hedging	Three Months Ended June 30,
Relationships	2009			2008
Interest rate contracts	$	10,434		$	9,165
Commodity contracts		(56,203	)		(268,996	)
	$	(45,769	)	$	(259,831	)

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	Gain (Loss)
Derivatives in	Recognized in OCI on
SFAS 133	Derivatives (Effective Portion)
Cash Flow Hedging	Six Months Ended June 30,
Relationships	2009			2008
Interest rate contracts	$	3,846		$	(270	)
Commodity contracts		(26,317	)		(362,384	)
	$	(22,471	)	$	(362,654	)

	Amount of Gain (Loss)						Amount of Gain (Loss)
Location of Gain (Loss)	Reclassified from OCI into						Recognized in Income on
Reclassified from	Income (Effective Portion)						Derivatives (Ineffective Portion)
Accumulated OCI	Three Months Ended June 30,						Three Months Ended June 30,
into Income	2009			2008			2009			2008
Interest expense, net	$	(3,858	)	$	(849	)	$	-		$	-
Revenues		20,926			(36,357	)		(373	)		-
	$	17,068		$	(37,206	)	$	(373	)	$	-

	Amount of Gain (Loss)						Amount of Gain (Loss)
Location of Gain (Loss)	Reclassified from OCI into						Recognized in Income on
Reclassified from	Income (Effective Portion)						Derivatives (Ineffective Portion)
Accumulated OCI	Six Months Ended June 30,						Six Months Ended June 30,
into Income	2009			2008			2009		2008
Interest expense, net	$	(6,380	)	$	(616	)	$	-	$	-
Revenues		36,718			(52,401	)		-		-
	$	30,338		$	(53,017	)	$	-	$	-

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 June 30, 2009, OCI consisted of $62.5 million ($52.7 million, net of tax) of unrealized net gains on commodity hedges, and $7.3 million ($6.8 million, net of tax) of unrealized net losses on interest rate hedges. Deferred net gains of $23.4 million on commodity hedges and deferred net losses of $0.6 million on interest rate hedges recorded in OCI are expected to be reclassified to revenues 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.

19

As of June 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 July 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-Waha		6.62		21,918		-		-		-		-		11,517
Swap	IF-Waha		6.69		-		16,300		-		-		-		6,608
Swap	IF-Waha		6.46		-		-		12,500		-		-		439
Swap	IF-Waha		7.18		-		-		-		5,500		-		921
					21,918		16,300		12,500		5,500		-
Swap	IF-PB		5.42		-		2,000		-		-		-		(32	)
Swap	IF-PB		5.42		-		-		2,000				-		(528	)
Swap	IF-PB		5.54		-		-		-		4,000		-		(1,274	)
Swap	IF-PB		5.54		-		-		-		-		4,000		(1,542	)
					-		2,000		2,000		4,000		4,000
Total Sales					21,918		18,300		14,500		9,500		4,000
Basis Swap Jul-Aug 2009 Rec NYMEX, pay IF-HSC plus $.0825, 20,000 MMBtu															12
Basis Swap Jul-Aug 2009 Rec IF-Waha, pay NYMEX less $.5175, 20,000 MMBtu															(477	)
														$	15,644

NGLs
Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	OPIS-MB		0.79		3,347		-		-		-		-	$	247
Swap	OPIS-MB		0.87		-		2,750		-		-		-		1,992
Swap	OPIS-MB		0.91		-		-		1,550		-		-		1,233
Swap	OPIS-MB		0.92		-		-		-		1,250		-		575
Total Swaps					3,347		2,750		1,550		1,250		-
Floor	OPIS-MB		0.20		-		-		54		-		-		1,068
Floor	OPIS-MB		0.24		-		-		-		63		-		1,157
Total Floors					-		-		54		63		-
Total Sales					3,347		2,750		1,604		1,313		-
														$	6,272

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Condensate
Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		67.85		-		200		-		-		-	$	(537	)
Swap	NY-WTI		71.00		-		-		200		-		-		(508	)
Swap	NY-WTI		72.60		-		-		-		200		-		(505	)
Swap	NY-WTI		73.80		-		-		-		-		200		(508	)
Total Swaps					-		200		200		200		200
Total Sales					-		200		200		200		200
														$	(2,058	)

As of June 30, 2009, the Partnership had the following hedge 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 July 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		-		-		-		-	$	1,155
					1,966		-		-		-		-
Swap	IF-NGPL MC		9.18		6,256		-		-		-		-		6,109
Swap	IF-NGPL MC		8.86		-		5,685		-		-		-		6,655
Swap	IF-NGPL MC		7.34		-		-		2,750		-		-		866
Swap	IF-NGPL MC		7.18		-		-		-		2,750		-		466
					6,256		5,685		2,750		2,750		-
Swap	IF-Waha		7.79		9,936		-		-		-		-		7,115
Swap	IF-Waha		6.53		-		11,709		-		-		-		4,020
Swap	IF-Waha		6.10		-		-		11,250		-		-		(973	)
Swap	IF-Waha		6.30		-		-		-		7,250		-		(821	)
Swap	IF-Waha		5.59		-		-		-		-		4,000		(1,536	)
					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		-		-		-		-		435
					850		-		-		-		-
Floor	IF-Waha		6.55		565		-		-		-		-		285
					565		-		-		-		-
Total Floors					1,415		-		-		-		-
Total Sales					19,573		17,394		14,000		10,000		4,000
Basis Swap Jul 09-May 2011 Rec IF-CGT, Pay NYMEX less $0.11, 20,000 MMBtu/d															(668	)
Fuel cost swap Jul 2009-May2011 Rec IF-CGT, Pay $5.96, 226 MMbtu/d															46
														$	23,154

21

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		-		-		-		-	$	24,428
Swap	OPIS-MB		1.27		-		4,809		-		-		-		30,359
Swap	OPIS-MB		0.92		-		-		3,400		-		-		1,844
Swap	OPIS-MB		0.92		-		-		-		2,700		-		545
Total Swaps					6,248		4,809		3,400		2,700		-
Floor	OPIS-MB		1.44		-		-		199		-		-		3,937
Floor	OPIS-MB		1.43		-		-		-		231		-		4,242
Total Floors					-		-		199		231		-
Total Sales					6,248		4,809		3,599		2,931		-
														$	65,355

Condensate
Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		69.00		322		-		-		-		-	$	(149	)
Swap	NY-WTI		68.04		-		401		-		-		-		(1,048	)
Swap	NY-WTI		71.00		-		-		200		-		-		(508	)
Swap	NY-WTI		72.60		-		-		-		200		-		(506	)
Swap	NY-WTI		74.00		-		-		-		-		200		(495	)
Total Swaps					322		401		200		200		200
Floor	NY-WTI		60.00		50		-		-		-		-		15
Total Floors					50		-		-		-		-
Total Sales					372		401		200		200		200
														$	(2,691	)

Customer Hedges

As of June 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

Jan 2009 - Dec 2009

Natural gas

Swap

8,380

MMBtu

5.70

per MMBtu

NY-HH

$

(2,448

)

Jan 2010 - Jun 2010

Natural gas

Swap

663

MMBtu

8.03

per MMBtu

NY-HH

(264

)

Sales

Jan 2009 - Dec 2009

Natural gas

Fixed price sale

8,380

MMBtu

5.70

per MMBtu

NY-HH

2,439

Jan 2010 - Jun 2010

Natural gas

Fixed price sale

663

MMBtu

8.03

per MMBtu

NY-HH

262

$

(11

)

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Interest Rate Hedges

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

	Fixed			Notional
Period	Rate			Amount	Fair Value
7/1/2009-3/31/2010		1.65	%	$400 million	$	(219	)
4/1/2010-3/31/2011		1.65	%	350 million		(1,488	)
4/1/2011-3/31/2012		1.65	%	300 million		2,124
					$	417

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:

	Fixed			Notional
Period	Rate			Amount	Fair Value
Remainder of 2009		3.03	%	$300 million	$	(4,668	)
2010		3.03	%	300 million		(6,703	)
2011		2.84	%	300 million		(2,048	)
2012		2.77	%	300 million		1,050
2013		2.75	%	300 million		2,318
1/1 - 4/24/2014		2.75	%	300 million		924
					$	(9,127	)

We have designated all interest rate swaps and interest rate basis swaps as cash flow 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 13 and 16 for additional disclosures related to derivative instruments and hedging activities.

Note 13—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.

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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 June 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	$	127,227	$	-	$	52,672	$	74,555
Available-for-sale securities (1)		31,510		-		-		31,510
Assets from interest rate derivatives		4,702		-		4,702		-
Total assets	$	163,439	$	-	$	57,374	$	106,065
Liabilities from commodity derivative contracts	$	21,562	$	-	$	18,634	$	2,928
Liabilities from interest rate derivatives		13,412		-		13,412		-
Total liabilities	$	34,974	$	-	$	32,046	$	2,928

___________

(1)   Excludes $2.3 million of interest paid in-kind and $1.4 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
	Commodity Derivatives								Derivatives			For Sale
	TRP LP			TRI			Reclass		Contracts			Securities		Total
Balance, December 31, 2008	$	123,304		$	24,890				$	148,194		$	9,700	$	157,894
Unrealized gains (losses) included in OCI		(26,557	)		(15,025	)				(41,582	)		9,571		(32,011	)
Purchases		-			-			-		-			12,239		12,239
Settlements		(31,392	)		(3,593	)		-		(34,985	)		-		(34,985	)
Balance, June 30, 2009	$	65,355		$	6,272		$	-	$	71,627		$	31,510	$	103,137

No unrealized gains or losses related to assets and liabilities still held as of June 30, 2009 were included in our consolidated statement of operations.

Our nonfinancial assets and liabilities measured at fair value on a nonrecurring basis during the three and six months ended June 30, 2009 were not significant.

Note 14—Commitments and Contingencies

Environmental

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

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

24

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 June 30, 2009 was $3.9 million, consisting of $0.2 million for gathering system leaks, $1.4 million for ground water assessment and remediation and $2.3 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 stands 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. On September 9, 2008, the parties presented oral arguments, and the appeal is currently pending before the Supreme Court of Texas.

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.

25

Note 15—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:

	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior secured term loan facility	$	515,925	$	495,288	$	522,175	$	331,581
Senior unsecured notes, 8½% fixed rate		250,000		187,500		250,000		134,375
Senior unsecured notes of the Partnership, 8¼% fixed rate		209,080		176,673		209,080		128,333

Note 16—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 six months ended June 30, 2009, we purchased $1.7 million and $3.1 million of product from Broad Oak. During the three and six months ended June 30, 2008, we purchased $1.2 million of product from Broad Oak.

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 June 30, 2009:

Period	Commodity	Daily Volumes			Average Price			Index
Jul 2009 - Dec 2009	Natural gas		21,918	MMBtu	$	6.62	per MMBtu	IF-Waha
Jul 2009 - Dec 2009	NGL		2,847	Bbl		31.42	per gallon	OPIS-MB

As of June 30, 2009, the fair value of these open positions was $10.3 million. For the three and six months ended June 30, 2009, we received $7.9 million and $15.0 million from BofA for amounts due under settled commodity derivative transactions. For the three and six months ended June 30, 2008, we paid BofA $15.1 million and $23.1 million for amounts due under settled commodity derivative transactions.

26

The following table shows the Partnership’s open commodity derivatives with BofA as of June 30, 2009:

Period	Commodity	Daily Volumes			Average Price			Index
Jul 2009 - Dec 2009	Natural gas		3,556	MMBtu	$	8.07	per MMBtu	IF-Waha
Jul 2009 - Dec 2009	Natural gas		652	MMBtu		8.06	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
Jul 2009 - Dec 2009	NGL		3,000	Bbl		1.18	per gallon	OPIS-MB
Jul 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 June 30, 2009, the fair value of these Partnership open positions was $12.7 million. For the three and six months ended June 30, 2009, the Partnership received $7.4 million and $15.9 million from BofA to settle payments due under hedge transactions. For the three and six months ended June 30, 2008, the Partnership paid BofA $7.4 million and $11.7 million to settle payments due under hedge transactions.

The Partnership has several interest rate derivative transactions with BofA. Open positions as of June 30, 2009 consisted of interest rate swaps and interest rate basis swaps expiring on April 24, 2012. As of June 30, 2009, the aggregate fair value of these positions was a liability of $3.6million. Payments to BofA related to settled portions were $0.6 million and $1.6 million for the three and six months ended June 30, 2009.

Commercial Relationships. During the three and six months ended June 30, 2009, we had product sales to BofA which are included in revenues of $8.0 million and $22.8 million. For the same periods, we had natural gas and NGL product purchases of zero and $0.6 million from BofA. During the three and six months ended June 30, 2008, we had product sales to BofA which are included in revenues of $28.0 million and $60.3 million. For the same periods, we had natural gas and NGL product purchases of $1.6 million and $2.9 million from BofA.

Transactions with Unconsolidated Affiliates

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
Included in revenues
GCF	$	33	$	35	$	125	$	366
VESCO (1)		-		665		-		666
	$	33	$	700	$	125	$	1,032
Included in costs and expenses
GCF	$	62	$	1,341	$	1,268	$	2,145
VESCO (1)		-		47,231		-		100,081
	$	62	$	48,572	$	1,268	$	102,226

____________

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

Note 17—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.

27

Our 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.

Our 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.

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

Our 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.

Our reportable segment information is shown in the following tables.

	Three Months Ended June 30, 2009
	Natural Gas Gathering and Processing		Logistics Assets		NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues	$	241,154	$	34,992	$	607,646	$	119,860	$	-		$	1,003,652
Intersegment revenues		222,438		20,354		55,584		10,126		(308,502	)		-
Revenues		463,592		55,346		663,230		129,986		(308,502	)		1,003,652
Product purchases		346,235		-		410,179		73,056		(684	)		828,786
Intersegment product purchases		5,862		-		243,379		53,775		(303,016	)		-
Product purchases		352,097		-		653,558		126,831		(303,700	)		828,786
Operating expenses		26,766		27,124		313		10		-			54,213
Intersegment operating expenses		140		5,346		-		-		(5,486	)		-
Operating expenses		26,906		32,470		313		10		(5,486	)		54,213
Operating margin	$	84,589	$	22,876	$	9,359	$	3,145	$	684		$	120,653
Equity in earnings of   unconsolidated investments	$	-	$	1,683	$	-	$	-	$	-		$	1,683
Unconsolidated investments		-		19,494		-		-		-			19,494
Capital expenditures		16,000		6,064		-		-		570			22,634

28

	Three Months Ended June 30, 2008
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues	$	543,267	$	27,630		$	1,383,963	$	308,366	$	-		$	2,263,226
Intersegment revenues		516,204		38,054			116,969		8,960		(680,187	)		-
Revenues		1,059,471		65,684			1,500,932		317,326		(680,187	)		2,263,226
Product purchases		904,590		(33	)		916,550		201,982		-			2,023,089
Intersegment product purchases		3,550		33			551,969		106,513		(662,065	)		-
Product purchases		908,140		-			1,468,519		308,495		(662,065	)		2,023,089
Operating expenses		34,323		36,373			517		16		-			71,229
Intersegment operating expenses		385		17,737			-		-		(18,122	)		-
Operating expenses		34,708		54,110			517		16		(18,122	)		71,229
Operating margin	$	116,623	$	11,574		$	31,896	$	8,815	$	-		$	168,908
Equity in earnings of   unconsolidated investments	$	6,354	$	842		$	-	$	-	$	-		$	7,196
Unconsolidated investments		33,389		20,389			-		-		-			53,778
Capital expenditures		22,125		15,774			-		-		1,163			39,062

	Six Months Ended June 30,  2009
	Natural Gas Gathering and Processing	Logistics Assets	NGL Distribution and Marketing	Wholesale Marketing	Eliminations and Other	Total
Revenues	$      488,193	$        56,778	$   1,075,003	$      385,569	$               -	$   2,005,543
Intersegment revenues	413,423	42,988	175,987	33,091	(665,489)	-
Revenues	901,616	99,766	1,250,990	418,660	(665,489)	2,005,543
Product purchases	681,607	-	759,960	233,901	(684)	1,674,784
Intersegment product purchases	10,360	-	466,510	177,264	(654,134)	-
Product purchases	691,967	-	1,226,470	411,165	(654,818)	1,674,784
Operating expenses	61,634	56,900	612	21	-	119,167
Intersegment operating expenses	338	11,017	-	-	(11,355)	-
Operating expenses	61,972	67,917	612	21	(11,355)	119,167
Operating margin	$      147,677	$        31,849	$        23,908	$          7,474	$             684	$      211,592
Equity in earnings of   unconsolidated investments	$               -	$          1,804	$               -	$               -	$               -	$          1,804
Unconsolidated investments	-	19,494	��             -	-	-	19,494
Capital expenditures	33,475	10,783	-	-	1,259	45,517

29

	Six Months Ended June 30, 2008
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues	$	982,468	$	48,448		$	2,603,076	$	831,627	$	-		$	4,465,619
Intersegment revenues		950,237		68,390			317,473		29,046		(1,365,146	)		-
Revenues		1,932,705		116,838			2,920,549		860,673		(1,365,146	)		4,465,619
Product purchases		1,628,635		(33	)		1,860,936		534,992		-			4,024,530
Intersegment product purchases		9,969		33			1,018,398		307,245		(1,335,645	)		-
Product purchases		1,638,604		-			2,879,334		842,237		(1,335,645	)		4,024,530
Operating expenses		64,343		69,421			1,016		27		-			134,807
Intersegment operating expenses		533		28,968			-		-		(29,501	)		-
Operating expenses		64,876		98,389			1,016		27		(29,501	)		134,807
Operating margin	$	229,225	$	18,449		$	40,199	$	18,409	$	-		$	306,282
Equity in earnings of   unconsolidated investments	$	8,729	$	1,926		$	-	$	-	$	-		$	10,655
Unconsolidated investments		33,389		20,389			-		-		-			53,778
Capital expenditures		34,248		21,694			-		-		2,222			58,164

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Reconciliation of operating margin to net income
attributable to Targa Resources, Inc.:
Operating margin	$	120,653		$	168,908		$	211,592		$	306,282
Net income attibutable to noncontrolling interest		(8,294	)		(29,955	)		(6,655	)		(56,839	)
Depreciation and amortization expense		(42,053	)		(38,750	)		(83,653	)		(76,942	)
General and administrative expense		(28,196	)		(27,924	)		(52,049	)		(52,017	)
Interest expense, net		(22,050	)		(23,660	)		(47,752	)		(49,245	)
Income tax expense		(6,476	)		(28,185	)		(6,405	)		(40,291	)
Other, net		(96	)		25,764			1,001			33,666
Net income attributable to Targa Resources, Inc.	$	13,488		$	46,198		$	16,079		$	64,614

Note 18—Other Operating Income

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Abandoned project costs	$	5,589		$	-		$	5,589		$	-
Casualty loss adjustment (see Note 11)		(3,744	)		-			(3,744	)		-
Gain on sale of assets (see Note 20)		(25	)		(2	)		(38	)		(4,445	)
	$	1,820		$	(2	)	$	1,807		$	(4,445	)

30

        During the second quarter, $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 19—Sale of Bankruptcy Claim

In 2008, we terminated certain derivative contracts with Lehman Brothers Commodity Services, Inc. and filed claims with the United States bankruptcy court. During the first quarter of 2009, we sold our claims for $1.0 million and recognized the proceeds as other income in our consolidated statement of operations. The income recognized comprises $0.3 million in claims sold by us and $0.7 million in claims sold by the Partnership.

Note 20—Supplemental Cash Flow Information

During the six months ended June 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 six months ended June 30, 2008, we had a noncash addition to property, plant and equipment of $4.1 million resulting from a like-kind exchange transaction.

Note 21—Subsequent Event

On July 27, 2009, the Partnership agreed to acquire our natural gas liquids business (the “Downstream Business”) for $530 million. As part of the transaction, we have agreed to provide distribution support to the Partnership in the form of a reduction in our reimbursement for allocated general and administrative expense if necessary for a 1.0 times distribution coverage ratio, at the current $0.5175 per limited partner unit, subject to maximum support of $8 million in any quarter. The distribution support will be in effect for the nine quarter period beginning with the fourth quarter of 2009 and continuing through the fourth quarter of 2011.

Consideration to us will include 25% of the transaction value in newly issued common and general partner units of the Partnership. The remaining 75%, or approximately $397.5 million, will be in cash, funded through borrowings under the Partnership’s senior secured credit facility.

The equity consideration from the Partnership to us will consist of 8,527,615 common units and 174,033 general partner units valued at $15.227 per unit (calculated using the volume weighted average trading price for the 10-day period through and including July 17, 2009) and equal to 25% of the transaction value, or $132.5 million.

See Notes 1, 3 and 7 for additional subsequent event disclosures.

31

Note 22—Consolidating Financial Statements

We are the issuer of the notes discussed 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.

Targa Resources, Inc.
Condensed Consolidating Balance Sheet
June 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	-		$	156,095		$	61,730		$	-		$	217,825
Trade receivables and other current assets		222			342,496			125,286			-			468,004
Total current assets		222			498,591			187,016			-			685,829
Property, plant, and equipment, at cost		-			872,397			2,276,130			-			3,148,527
Accumulated depreciation		-			31,264			(590,509	)		-			(559,245	)
Property, plant, and equipment, net		-			903,661			1,685,621			-			2,589,282
Investment in subsidiaries		(214,530	)		278,617			-			(64,087	)		-
Advance to (from) subsidiaries		(222,507	)		134,536			87,971			-			-
Other assets		45,031			57,825			49,899			-			152,755
Total assets	$	(391,784	)	$	1,873,230		$	2,010,507		$	(64,087	)	$	3,427,866
Liabilities and stockholder's equity
Current liabilities:
Accounts payable and other liabilities	$	33,011		$	224,352		$	148,926		$	-		$	406,289
Current maturities of debt		12,500			-			-			-			12,500
Total current liabilities		45,511			224,352			148,926			-			418,789
Long-term liabilities:
Long-term debt, net of current maturities		(1,071,277	)		1,824,702			656,845			-			1,410,270
Other long-term obligations		51,812			38,706			42,411			-			132,929
Total long-term liabilities		(1,019,465	)		1,863,408			699,256			-			1,543,199
Total Targa Resources, Inc.'s stockholder's equity		582,170			(214,530	)		1,162,325			(947,795	)		582,170
Noncontrolling interest in subsidiaries		-			-			-			883,708			883,708
Total stockholders' equity		582,170			(214,530	)		1,162,325			(64,087	)		1,465,878
Total liabilities and stockholders' equity	$	(391,784	)	$	1,873,230		$	2,010,507		$	(64,087	)	$	3,427,866

32

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			328,517			165,564			-			494,379
Total current assets		298			548,137			308,713			-			857,148
Property, plant, and equipment, at cost		-			837,268			2,255,996			-			3,093,264
Accumulated depreciation		-			58,095			(533,990	)		-			(475,895	)
Property, plant, and equipment, net		-			895,363			1,722,006			-			2,617,369
Unconsolidated investments		-			18,465			-			-			18,465
Investment in subsidiaries		(193,993	)		307,175			-			(113,182	)		-
Advances to (from) subsidiaries		(177,700	)		131,971			45,729			-			-
Other assets		146,950			(75,141	)		83,786			-			155,595
Total assets	$	(224,445	)	$	1,825,970		$	2,160,234		$	(113,182	)	$	3,648,577
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and other liabilities	$	50,735		$	239,929		$	164,380		$	-		$	455,044
Current maturities of debt		12,500			-			-			-			12,500
Total current liabilities		63,235			239,929			164,380			-			467,544
Long-term debt, net of current maturities		(900,976	)		1,756,571			696,845			-			1,552,440
Other long-term obligations		33,655			23,463			42,226			-			99,344
Total long-term liabilities		(867,321	)		1,780,034			739,071			-			1,651,784
Total Targa Resources, Inc.'s stockholder's equity		579,641			(193,993	)		307,175			(113,182	)		579,641
Noncontrolling interest in subsidiaries		-			-			949,608			-			949,608
Total stockholders' equity		579,641			(193,993	)		1,256,783			(113,182	)		1,529,249
Total liabilities and stockholders' equity	$	(224,445	)	$	1,825,970		$	2,160,234		$	(113,182	)	$	3,648,577

33

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	-		$	906,927		$	351,607		$	(254,882	)	$	1,003,652
Operating costs and expenses:
Product purchases		-			824,876			249,884			(245,974	)		828,786
Operating expenses		-			30,024			33,097			(8,908	)		54,213
Depreciation and amortization expense		-			13,577			28,476			-			42,053
General and administrative and other		5,670			19,077			5,269			-			30,016
		5,670			887,554			316,726			(254,882	)		955,068
Income (loss) from operations		(5,670	)		19,373			34,881			-			48,584
Other income (expense):
Interest income (expense), net		21,990			(34,275	)		(9,765	)		-			(22,050	)
Equity in earnings of unconsolidated investments		-			1,683			-			-			1,683
Equity in earnings of subsidiaries		3,574			16,820			-			(20,394	)		-
Other income (expense)		70			(27	)		(2	)		-			41
Income (loss) before income taxes		19,964			3,574			25,114			(20,394	)		28,258
Income tax expense		(6,476	)		-			-			-			(6,476	)
Net income (loss)		13,488			3,574			25,114			(20,394	)		21,782
Net income attributable to noncontrolling interest		-			-			-			8,294			8,294
Net income (loss) attributable to Targa Resources, Inc.	$	13,488		$	3,574		$	25,114		$	(28,688	)	$	13,488

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Three Months Ended June 30, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues:	$	-		$	2,038,653		$	833,414		$	(608,841	)	$	2,263,226
Operating costs and expenses:
Product purchases		-			1,931,771			681,093			(589,775	)		2,023,089
Operating expenses		-			39,263			51,032			(19,066	)		71,229
Depreciation and amortization expense		-			12,804			25,946			-			38,750
General and administrative and other		87			21,204			6,631			-			27,922
		87			2,005,042			764,702			(608,841	)		2,160,990
Income (loss) from operations		(87	)		33,611			68,712			-			102,236
Other income (expense):
Interest income (expense), net		(15,841	)		-			(7,819	)		-			(23,660	)
Other income		18,566			-			-			-			18,566
Equity in earnings of unconsolidated investments		-			7,196			-			-			7,196
Equity in earnings of subsidiaries		71,192			30,575			-			(101,767	)		-
Income before income taxes		73,830			71,382			60,893			(101,767	)		104,338
Income tax (expense) benefit		(27,632	)		(190	)		(363	)		-			(28,185	)
Net income		46,198			71,192			60,530			(101,767	)		76,153
Less: Net income attibutable to noncontrolling interest		-			-			-			29,955			29,955
Net income attributable to Targa Resources, Inc.	$	46,198		$	71,192		$	60,530		$	(131,722	)	$	46,198

34

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	-		$	1,826,449		$	707,363		$	(528,269	)	$	2,005,543
Operating costs and expenses:
Product purchases		-			1,666,606			518,106			(509,928	)		1,674,784
Operating expenses		-			59,111			78,397			(18,341	)		119,167
Depreciation and amortization expense		-			26,887			56,766			-			83,653
General and administrative and other		5,756			37,454			10,646			-			53,856
		5,756			1,790,058			663,915			(528,269	)		1,931,460
Income (loss) from operations		(5,756	)		36,391			43,448			-			74,083
Other income (expense):
Interest income (expense), net		39,539			(67,664	)		(19,627	)		-			(47,752	)
Equity in earnings of unconsolidated investments		-			1,804			-			-			1,804
Equity in earnings of subsidiaries		(11,369	)		17,891			-			(6,522	)		-
Other income (expense)		70			209			725			-			1,004
Income (loss) before income taxes		22,484			(11,369	)		24,546			(6,522	)		29,139
Income tax expense		(6,405	)		-			-			-			(6,405	)
Net income (loss)		16,079			(11,369	)		24,546			(6,522	)		22,734
Net income attributable to noncontrolling interest		-			-			-			6,655			6,655
Net income (loss) attributable to Targa Resources, Inc.	$	16,079		$	(11,369	)	$	24,546		$	(13,177	)	$	16,079

Targa Resources, Inc.
Condensed Consolidating Statement of Operations
Six Months Ended June 30, 2008
	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues:	$	-		$	4,057,163	$	1,538,175		$	(1,129,719	)	$	4,465,619
Operating costs and expenses:
Product purchases		-			3,868,273		1,252,986			(1,096,729	)		4,024,530
Operating expenses		-			74,225		93,572			(32,990	)		134,807
Depreciation and amortization expense		-			25,362		51,580			-			76,942
General and administrative and other		87			35,966		11,519			-			47,572
		87			4,003,826		1,409,657			(1,129,719	)		4,283,851
Income (loss) from operations		(87	)		53,337		128,518			-			181,768
Other income (expense):
Interest income (expense), net		(32,954	)		-		(16,291	)		-			(49,245	)
Other income		18,566			-								18,566
Equity in earnings of unconsolidated investments		-			10,655		-			-			10,655
Equity in earnings of subsidiaries		118,680			54,688		-			(173,368	)		-
Income before income taxes		104,205			118,680		112,227			(173,368	)		161,744
Income tax (expense) benefit		(39,591	)		-		(700	)		-			(40,291	)
Net income		64,614			118,680		111,527			(173,368	)		121,453
Less: Net income attibutable to noncontrolling interest		-			-		-			56,839			56,839
Net income attributable to Targa Resources, Inc.	$	64,614		$	118,680	$	111,527		$	(230,207	)	$	64,614

35

Targa Resources, Inc.
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2009
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	16,079		$	(11,369	)	$	24,546		$	(6,522	)	$	22,734
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, amortization and accretion		2,639			25,928			59,178			-			87,745
Deferred income taxes		6,289			-			-			-			6,289
Loss from unconsolidated investments, net of distributions		-			(1,029	)		-			-			(1,029	)
Equity in earnings of subsidiaries		11,369			(17,891	)		-			6,522			-
Other		-			(86	)		29,695			-			29,609
Changes in operating assets and liabilities:
Accounts receivable and other assets		(3,179	)		(50,965	)		17,686			-			(36,458	)
Inventory		-			28,474			(3,381	)		-			25,093
Accounts payable and other liabilities		(7,317	)		(6,319	)		(7,427	)		-			(21,063	)
Net cash provided by (used in) operating activities		25,880			(33,257	)		120,297			-			112,920
Cash flows from investing activities
Purchases of property and equipment		-			(23,731	)		(31,155	)		-			(54,886	)
Other		4,700			(12,190	)		106			-			(7,384	)
Net cash (used in) provided by investing activities		4,700			(35,921	)		(31,049	)		-			(62,270	)
Cash flows from financing activities
Repayments of debt		(102,170	)		-			(40,000	)		-			(142,170	)
Distributions to noncontrolling interest, net		-			-			(49,776	)		-			(49,776	)
Cost incurred in connection with financing arrangements		(3,685	)		-			-			-			(3,685	)
Contribution from Targa Resources Investments Inc.		37			-			-			-			37
Receipts from (payments to) subsidiaries		75,238			5,653			(80,891	)		-			-
Net cash used in financing activities		(30,580	)		5,653			(170,667	)		-			(195,594	)
Net decrease in cash and cash equivalents		-			(63,525	)		(81,419	)		-			(144,944	)
Cash and cash equivalents, beginning of period		-			219,620			143,149			-			362,769
Cash and cash equivalents, end of period	$	-		$	156,095		$	61,730		$	-		$	217,825

36

Targa Resources, Inc.
Condensed Consolidating Statement of Cash Flows
Six Months Ended June 30, 2008
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	64,614		$	118,680		$	111,527		$	(173,368	)	$	121,453
Adjustments to reconcile net income (loss) to net cash
provided by (used in)operating activities:
Depreciation, amortization and accretion		4,027			25,772			52,716			-			82,515
Deferred income taxes		38,354			-			700			-			39,054
Loss from unconsolidated investments, net of distributions		-			(9,880	)		-			-			(9,880	)
Equity in earnings (losses) of subsidiaries		(118,680	)		(54,688	)		-			173,368			-
Other		(18,626	)		(3,674	)		(1,887	)		-			(24,187	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		14,979			112,107			(26,215	)		-			100,871
Inventory		-			35,566			64			-			35,630
Accounts payable and other liabilities		(16,211	)		(46,291	)		91,421			-			28,919
Net cash provided by (used in) operating activities		(31,543	)		177,592			228,326			-			374,375
Cash flows from investing activities
Purchases of property and equipment		-			(25,574	)		(28,237	)		-			(53,811	)
Other		(16,400	)		48,306			(3,815	)		-			28,091
Net cash used in investing activities		(16,400	)		22,732			(32,052	)		-			(25,720	)
Cash flows from financing activities
Debt Repayments		(6,250	)		-			(301,300	)		-			(307,550	)
Proceeds from issuance of senior notes of the Partnership		-			-			250,000			-			250,000
Cost incurred in connection with financing arrangements		-			-			(6,590	)		-			(6,590	)
Distributions to noncontrolling interests		-			-			(42,480	)		-			(42,480	)
Distributions to Targa Resources Investments Inc.		(53,752	)											(53,752	)
Receipts from (payments to) subsidiaries		107,945			(21,086	)		(86,859	)		-			-
Net cash provided by (used in) financing activities		47,943			(21,086	)		(187,229	)		-			(160,372	)
Net increase in cash and cash equivalents		-			179,238			9,045			-			188,283
Cash and cash equivalents, beginning of period		-			88,303			89,646			-			177,949
Cash and cash equivalents, end of period	$	-		$	267,541		$	98,691		$	-		$	366,232

37

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 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 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 2 to the accompanying consolidated financial statements, as a result of our adoption of SFAS 160 certain 2008 financial information has been reclassified so that the basis of presentation is consistent with that of the 2009 financial information.

Recently Issued Pronouncements

See Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

38

Results of Operations

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(In millions, except operating and price data)
Revenues (1)	$	1,003.7		$	2,263.2		$	2,005.5		$	4,465.6
Product purchases		828.8			2,023.1			1,674.8			4,024.5
Operating expenses		54.2			71.2			119.2			134.8
Depreciation and amortization expense		42.1			38.8			83.7			76.9
General and administrative expense		28.1			27.9			51.9			52.0
Other		1.8			-			1.8			(4.4	)
Income from operations		48.7			102.2			74.1			181.8
Interest expense, net		(22.1	)		(23.7	)		(47.8	)		(49.2	)
Gain on insurance claims		-			18.6			-			18.6
Equity in earnings of unconsolidated investments		1.7			7.2			1.8			10.6
Other		-			0.1			1.0			(0.1	)
Income tax expense		(6.5	)		(28.2	)		(6.4	)		(40.3	)
Net income		21.8			76.2			22.7			121.4
Less: Net income attibutable to noncontrolling interest		8.3			30.0			6.6			56.8
Net income attributable to Targa Resources, Inc.	$	13.5		$	46.2		$	16.1		$	64.6
Financial data:
Operating margin (2)	$	120.7		$	168.9		$	211.5		$	306.3
Adjusted EBITDA (3)		95.9			137.6			183.0			229.3
Operating statistics:
Gathering throughput  MMcf/d (4)		2,139.4			2,070.1			2,050.5			2,125.7
Plant natural gas inlet, MMcf/d (5) (6)		2,098.0			2,026.3			2,008.0			2,084.7
Gross NGL production, MBbl/d		118.2			104.0			113.8			104.3
Natural gas sales, BBtu/d (6)		588.5			526.6			553.5			529.8
NGL sales, MBbl/d		287.7			285.9			293.2			301.7
Condensate sales, MBbl/d		5.2			3.7			4.8			3.7
Average realized prices:
Natural gas, $/MMBtu		3.54			10.11			3.98			9.00
NGL, $/gal		0.68			1.54			0.67			1.50
Condensate, $/Bbl		54.39			114.15			47.65			103.88

____________

(1) Includes business interruption insurance revenue of $3.3 million and $5.0 million for the three and six months ended June 30, 2009 and $17.5 million for the three and six months ended June 30, 2008.

(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.

39

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

Revenues decreased by $1,259.5 million, or 56%, to $1,003.7 million for 2009 compared to $2,263.2 million for 2008. Revenues from the sale of natural gas decreased by $294.8 million, consisting of a decrease of $351.7 million due to lower realized prices, partially offset by an increase of $56.9 million due to higher sales volumes. Revenues from the sale of NGLs decreased by $943.5 million, consisting of a decrease of $954.4 million due tolower realized prices, partially offset by an increase of $10.9 million due to higher sales volumes. Revenues from the sale of condensate decreased by $12.9 million, consisting of a decrease of $28.5 million due to lower realized prices, partially offset by an increase of $15.5 million due to higher sales volumes. Other revenues, which includes revenues principally derived from fee-based services, decreased by $8.3 million.

Our average realized price for natural gas decreased by $6.57 per MMBtu, or 65%, to $3.54 per MMBtu for 2009 compared to $10.11 per MMBtu for 2008. Average realized prices for NGLs decreased by $0.86 per gallon, or 56%, to $0.68 per gallon for 2009 compared to $1.54 per gallon for 2008. Our average realized price for condensate decreased by $59.76 per Bbl, or 52%, to $54.39 per Bbl for 2009 compared to $114.15 per Bbl for 2008.

Our natural gas sales volumes increased by 61.9 BBtu/d, or 12%, to 588.5 BBtu/d for 2009 compared to 526.6 BBtu/d for 2008. NGL sales volumes increased by 1.8 MBbl/d, or 1%, to 287.7 MBbl/d for 2009 compared to 285.9 MBbl/d for 2008. Condensate sales volumes increased by 1.5 MBbl/d, or 41%, to 5.2 MBbl/d for 2009 compared to 3.7 MBbl/d for 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.”

Our product purchases decreased by $1,194.3 million, or 59%, to $828.8 million for 2009 compared to $2,023.1 million for 2008. See “—Results of Operations—By Segment” for an explanation of the components of the decrease.

Our operating expenses decreased by $17.0million, or 24%, to $54.2 million for 2009 compared to $71.2 million for 2008. See “—Results of Operations—By Segment” for a detailed explanation of the components of the decrease.

Depreciation and amortization expense increased by $3.3 million, or 9%, to $42.1 million for 2009 compared to $38.8 million for 2008. The increase is due to 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 $0.2 million, or 1%, to $28.1 million for 2009 compared to $27.9 million for 2008. We experienced increases in property insurance and outside professional services which were offset by decreases in compensation costs.

Other operating expenses were $1.8 million for 2009.  The operating expenses resulted from a $5.6 million charge for project abandonment costs, offset by a $3.7 million favorable adjustment from a revision of estimated casualty losses.

Equity earnings decreased $5.5 million to $1.7 million for 2009 compared to $7.2 million for 2008. The decrease is due primarily to our consolidation of VESCO, following our acquisition of majority ownership starting August 1, 2008.

Other items included in income decreased $18.7 million in 2009 compared to 2008. This decrease is primarily the recognition of an $18.6 million gain on insurance claims relating to the 2005 hurricanes in 2008.

Interest expense decreased by $1.6million, or 7%, to $22.1 million for 2009 compared to $23.7 million for 2008. This was primarily due to lower interest rates on our variable debt.

Income tax expense decreased by $21.7 million, or 77%, primarily driven by a 73% decrease in income before income taxes.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Revenues decreased by $2,460.1 million, or 55%, to $2,005.5 million for 2009 compared to $4,465.6 million for 2008. Revenues from the sale of natural gas decreased by $468.9 million, consisting of a decrease of $502.7 million due to lower realized prices and an increase of $33.8 million due to higher sales volumes. Revenues from the sale of

40

NGLs decreased by $1,958.7 million, consisting of a decrease of $1,843.4 million due to lower realized prices and a decrease of $115.3 million due to lower sales volumes. Revenues from the sale of condensate decreased by $28.5 million, consisting of a decrease of $48.8 million due to lower realized prices, partially offset by an increase of $20.3 million due to higher sales volumes. Other revenues, which includes revenues principally derived from fee-based services, decreased by $4.0 million.

Our average realized price for natural gas decreased by $5.02 per MMBtu, or 56%, to $3.98 per MMBtu for 2009 compared to $9.00 per MMBtu for 2008. Average realized prices for NGLs decreased by $0.83 per gallon, or 55%, to $0.67 per gallon for 2009 compared to $1.50 per gallon for 2008. Our average realized price for condensate decreased by $56.23 per Bbl, or 54%, to $47.65 per Bbl for 2009 compared to $103.88 per Bbl for 2008.

Our natural gas sales volumes increased by 23.7 BBtu/d, or 4%, to 553.5 BBtu/d for 2009 compared to 529.8 BBtu/d for 2008. NGL sales volumes decreased by 8.5 MBbl/d, or 3%, to 293.2 MBbl/d for 2009 compared to 301.7 MBbl/d for 2008. Condensate sales volumes increased by 1.1 MBbl/d, or 30%, to 4.8 MBbl/d for 2009 compared to 3.7 MBbl/d for 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.”

Our product purchases decreased by $2,349.7 million, or 58%, to $1,674.8 million for 2009 compared to $4,024.5 million for 2008. See “—Results of Operations—By Segment” for an explanation of the components of the decrease.

Our operating expenses decreased by $15.6million, or 12%, to $119.2 million for 2009 compared to $134.8 million for 2008. See “—Results of Operations—By Segment” for a detailed explanation of the components of the decrease.

Depreciation and amortization expense increased by $6.8 million, or 9%, to $83.7 million for 2009 compared to $76.9 million for 2008. The increase is due to 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 decreased by $0.1 million, or less than 1%, to $51.9 million for 2009 compared to $52.0 million for 2008. We experienced increases in property insurance and outside professional services which were offset by decreases in compensation costs.

Other operating expenses increased $6.2 million to a $1.8 million charge in 2009 compared to $4.4 million in income for 2008.  For 2009, we had a $5.6 million charge for project abandonment costs, offset by a $3.7 million favorable adjustment from a revision of estimated casualty losses, compared to a $4.4 million gain on sale of assets in 2008.

Equity earnings decreased $8.8 million to $1.8 million for 2009 compared to $10.6 million in 2008. This decrease is due primarily to our consolidation of VESCO, following our acquisition of majority ownership starting August 1, 2008.

Other items included in income decreased by $17.4 million in 2009 compared to 2008. The decrease is primarily due to the recognition of a $18.6 million gain on insurance claims in 2008 relating to the 2005 hurricanes in 2008, offset by a $1.0 million gain on the recognition of sale of bankruptcy claims.

Interest expense decreased by $1.4million, or 3%, to $47.8 million for 2009 compared to $49.2 million for 2008. This is primarily due to lower interest rates on our variable debt.

Income tax expense decreased by $33.9 million, or 84%, primarily driven by an 82% decrease in income before income taxes.

41

Results of Operations—By Segment

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 Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	($ in millions)
Revenues (1) (2)	$	463.6		$	1,059.5		$	901.6		$	1,932.7
Product purchases		(352.1	)		(908.2	)		(691.9	)		(1,638.6	)
Operating expenses		(26.9	)		(34.7	)		(62.0	)		(64.9	)
Operating margin (3)	$	84.6		$	116.6		$	147.7		$	229.2
Equity in earnings of VESCO (4)	$	-		$	6.4		$	-		$	8.8
Operating statistics: (5)
Gathering throughput, MMcf/d		2,139.4			2,070.1			2,050.5			2,125.7
Plant natural gas inlet, MMcf/d		2,098.0			2,026.3			2,008.0			2,084.7
Gross NGL production, MBbl/d		118.2			104.0			113.8			104.3
Natural gas sales, BBtu/d		608.0			546.2			571.2			548.2
NGL sales, MBbl/d		92.6			91.5			92.6			90.5
Condensate sales, MBbl/d		5.2			5.0			5.1			5.0
Average realized prices:
Natural gas, $/MMBtu		3.54			10.14			3.98			9.02
NGL, $/gal		0.66			1.42			0.61			1.34
Condensate, $/Bbl		54.39			106.24			46.50			96.14

____________

(1) Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period.

(2) Includes business interruption insurance revenue of $1.4 million and $2.6 million for the three and six months ended June 30, 2009, and $2.5 million for the three and six months ended June 30, 2008.

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

(4) Amounts are through June 30, 2008. VESCO was included in our consolidated results effective August 1, 2008.

(5) Segment operating statistics include the effect of intersegment sales, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter.

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

Revenues decreased by $595.9 million, or 56%, to $463.6 million for 2009 compared to $1,059.5 million for 2008. The decrease was primarily due to lower natural gas, NGL and condensate prices, and lower NGL sales volumes, partially offset by higher natural gas sales volumes.

Our average realized price for natural gas decreased by $6.60 per MMBtu, or 65%, to $3.54 per MMBtu for 2009 compared to $10.14 per MMBtu for 2008. Our average realized price for NGLs decreased by $0.76 per gallon, or 54%, to $0.66 per gallon for 2009 compared to $1.42per gallon for 2008. Our average realized price for condensatedecreased by $51.85per Bbl, or 49%, to $54.39 per Bbl for 2009 compared to $106.24 per barrel for 2008.

Our natural gas sales volumes increased by 61.8 BBtu/d, or 11%, to 608.0 BBtu/d for 2009 compared to 546.2BBtu/d for 2008. Our NGL sales volumes decreased by 1.1 MBbl/d, or 1%, to 92.6 MBbl/d for 2009 compared to

42

91.5 MBbl/d for 2008. Our condensate sales volumes increased by 0.2 MBbl/d, or 4%, to 5.2 MBbl/d for 2009 compared to 5.0 MBbl/d for 2008. The increase in natural gas sales volumes was primarily due to increased sales under third party contracts.

Our product purchases decreased by $556.1 million, or 61%, to $352.1 million for the 2009 compared to $908.2 million for 2008. The decrease in product cost corresponds to the decrease in commodity revenue.

Our operating expenses decreased $7.8 million, or 22%, to $26.9 million for 2009 compared to $34.7 million for 2008. The decrease is 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.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Revenues decreased by $1,031.1 million, or 53%, to $901.6 million for 2009 compared to $1,932.7 million for 2008. The decrease was primarily due to lower natural gas, NGL and condensate prices.

Our average realized price for natural gas decreased by $5.04 per MMBtu, or 56%, to $3.98 per MMBtu for 2009 compared to $9.02 per MMBtu for 2008. Our average realized price for NGLs decreased by $0.73 per gallon, or 54%, to $0.61 per gallon for 2009 compared to $1.34per gallon for 2008. Our average realized price for condensate decreased by $49.64per Bbl, or 52%, to $46.50 per Bbl for 2009 compared to $96.14 per barrel for 2008.

Our natural gas sales volumes increased by 23.0 BBtu/d, or 4%, to 571.2 BBtu/d for 2009 compared to 548.2BBtu/d for 2008.  Our NGL sales volumes increased by 2.1 MBbl/d, or 2%, to 92.6 MBbl/d for 2009 compared to 90.5 MBbl/d for 2008. Our condensate sales volumes increased by 0.1 MBbl/d, or 2%, to 5.1 MBbl/d for 2009 compared to 5.0 MBbl/d for 2008.

Our product purchases decreased by $946.7 million, or 58%, to $691.9 million for the 2009 compared to $1,638.6 million for 2008. The decrease in product cost reflects lower commodity pricing and purchases of wellhead volumes.

Our operating expenses decreased $2.9 million, or 4%, to $62.0 million for 2009 compared to $64.9 million for 2008. The decrease is 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.

43

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 June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	($ in millions)
Revenues from services	$	53.2		$	64.6		$	97.8		$	115.4
Other revenues (1)		2.0			1.1			1.9			1.5
		55.2			65.7			99.7			116.9
Operating expenses		(32.4	)		(54.1	)		(67.9	)		(98.4	)
Operating margin (2)	$	22.8		$	11.6		$	31.8		$	18.5
Equity in earnings of GCF	$	1.7		$	0.8		$	1.8		$	1.9
Operating statistics:
Fractionation volumes, MBbl/d		230.0			235.2			210.0			225.6
Treating volumes, MBbl/d (3)		19.5			21.4			14.0			18.2

____________

(1) Includes business interruption insurance revenue of $1.9 million for the three and six months ended June 30, 2009, and $0.4 million for the three and six months ended June 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 (“LSNG”) unit.

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

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $11.4 million, or 18%, to $53.2 million for 2009 compared to $64.6 million for 2008. The decrease is primarily due to a lower fuel component of the fractionation fees, which has an impact on operating expenses. In addition, volumes decreased as a result of damage to certain of our and third party Gulf Coast processing, pipeline and production facilities from Hurricane Ike. Truck and barge volumes were also lower for 2009 due to decreased mixed butanes and wholesale activity.

Operating expenses decreased by $21.7 million, or 40%, to $32.4 million for 2009 compared to $54.1 million for 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.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Revenues from services (fractionation, terminalling and storage, transportation and treating) decreased by $17.6 million, or 15%, to $97.8 million for 2009 compared to $115.4 million for 2008. The decrease is 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 $30.5 million, or 31%, to $67.9 million for 2009 compared to $98.4 million for 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.

44

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 June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	662.2		$	1,491.6		$	1,248.8		$	2,910.4
Other revenues (1)		1.0			9.3			2.2			10.1
		663.2			1,500.9			1,251.0			2,920.5
Product purchases		(653.5	)		(1,468.5	)		(1,226.5	)		(2,879.3	)
Operating expenses		(0.2	)		(0.5	)		(0.6	)		(1.0	)
Operating margin (2)	$	9.5		$	31.9		$	23.9		$	40.2
Operating data:
NGL sales, MBbl/d		256.4			252.3			254.6			257.3
NGL realized price, $/gal		0.68			1.55			0.65			1.48

____________

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

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

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

Our NGL sales revenues decreased by $829.4 million, or 56%, to $662.2 million for 2009 compared to $1,491.6 million for 2008. The net decrease comprised an $853.7 million decrease from lower average sales prices, which were down 56% to $0.68 per gallon during 2009 from $1.55 per gallon during 2008; partially offset by a $24.3 million increase from higher sales volumes, up2% to 256.4 MBbl/d during 2009 from 252.3 MBbl/d during 2008. The increase in sales volumes is primarily attributable to higher spot sales offset by decreased sales to petrochemical customers associated with their lower plant operational rates.

Product purchases decreased by $815.0 million, or 55%, to $653.5 million for 2009 compared to $1,468.5 million for 2008. The net decrease comprised an $839.9 million decrease from lower average market prices partially offset by a $23.9 million increase from purchased volumes and a $1.0 million lower of cost or market adjustment in 2009.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

Our NGL sales revenues decreased by $1,661.6 million, or 57%, to $1,248.8 million for 2009 compared to $2,910.4 million for 2008. The net decrease comprised a $1,616.2 million decrease from lower average sales prices during 2009 down 56% to $0.65 per gallon from $1.48 per gallon in 2008 and a $45.4 million decrease from lower sales volumes down 1% to 254.6 MBbl/d in 2009 from 257.3 MBbl/d in 2008. The decrease in sales volumes is primarily due to reduced sales to petrochemical customers associated with their lower plant operational rates offset by higher spot sales.

Product purchases decreased by $1,652.8 million, or 57%, to $1,226.5 million for 2009 compared to $2,879.3 million for 2008. The net decrease comprised a $1,608.8 million decrease in average commodity prices and a $45.0 million decrease from lower purchase volumes offset by a $1.0 million lower of cost or market adjustment in 2009.

45

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 Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	($ in millions)
NGL sales revenues	$	129.8		$	311.4		$	417.7		$	854.7
Other revenues (1)		0.2			5.9			0.9			5.9
		130.0			317.3			418.6			860.6
Product purchases		(126.9	)		(308.5	)		(411.2	)		(842.2	)
Operating margin (2)	$	3.1		$	8.8		$	7.4		$	18.4
Operating data:
NGL sales, MBbl/d		43.3			46.5			61.9			66.7
NGL realized price, $/gal		0.78			1.75			0.89			1.68

____________

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

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

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

NGL sales revenues decreased by $181.6 million, or 58%, to $129.8 million for 2009 compared to $311.4 million for 2008. Lower NGL market prices decreased revenue by $160.3 million and lower sales volumes decreased revenue by an additional $21.3 million. The 3.2 MBbl/d decrease in volumes is primarily due to decreased sales of propane due to the expiration of refinery purchase agreements and lower butane sales due to the expiration of a refinery supply agreement.

Product purchases decreased by $181.6 million, or 59%, to $126.9 million for 2009 compared to $308.5 million for 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $160.9 million and $21.1 million partially offset by an increase of $0.4 million of lower of cost or market adjustments in 2009.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008

NGL sales revenues decreased by $437.0 million, or 51%, to $417.7 million for 2009 compared to $854.7 million for 2008. Lower NGL market prices decreased revenue by $288.9 million and lower sales volumes decreased revenue by an additional $148.1 million. The 4.8 MBbl/d decrease in volumes is primarily due to reduced sales of propane due to the expiration of sales supply agreements as well as lower butane sales due to the expiration of a refinery supply agreement.

Product purchases decreased by $431.0 million, or 51%, to $411.2 million for 2009 compared to $842.2 million for 2008. Lower NGL market prices and lower sales volumes resulted in decreases in product purchases of $365.9 million and $65.5 million, partially offset by an increase of $0.4 million of lower of cost or market adjustments in 2009.

46

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 six months ended June 30, 2009, the estimate was reduced by $3.7 million.

During the six months ended June 30, 2009, expenditures related to the hurricanes included $29.1 million for previously accrued repair costs, and $7.3 million capitalized as improvements.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements depends on our ability to generate cash in the future. Our 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 our 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 markets. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit crisis includes our revolving credit facility, cash investments and counterparty performance risks. Continued volatility in the debt markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets.

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 12 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report). The 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 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, our cash generated from 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 and borrowings available under our senior secured credit facilities should provide sufficient resources to finance our operations, non-acquisition related capital expenditures,

47

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 June 30, 2009, our total outstanding letter of credit postings were $120.8 million.

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.

Contractual Obligations.  As of June 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 June 30, 2009, we had approximately $433 million in total availability under our credit facility, including $240 million under our senior secured revolving credit facility (after giving effect to the Lehman Bank default) and $193 million under our senior secured synthetic letter of credit facility. In addition, the Partnership had approximately $378 million in availability under its senior secured credit facility (also after giving effect to the Lehman Bank default).

On July 27, 2009, we agreed to sell our natural gas liquids business (the “Downstream Business”) to the Partnership for $530 million. Consideration to us will include 25% of the transaction value in newly issued common and general partner units of the Partnership; the maximum equity component permitted under our financing agreements. The remaining 75%, or approximately $397.5 million, will be in cash, funded through borrowings under the Partnership’s senior secured revolving credit facility. We plan to use the cash received from the sale of the Downstream Business to reduce debt.

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”) . The 11¼% Notes were issued at 94.973% of the face amount, resulting in gross proceeds of $237.4 million. The Partnership used the proceeds from this offering to reduce 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 the Partnership’s credit facility by $127.5 million, bringing the total commitments to $977.5 million. The Partnership may request additional commitments under its credit facility of up to $22.5 million.

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

	Six Months Ended June 30,
	2009			2008
	(In millions)
Net cash provided by (used in):
Operating activities	$	112.9		$	374.4
Investing activities		(62.3	)		(25.7	)
Financing activities		(195.6	)		(160.4	)

Net cash provided by operating activities was $112.9 million for the six months ended June 30, 2009 compared to $374.4 million for the six months ended June 30, 2008. The $261.5 million decrease was primarily due to changes in operating assets and liabilities which used an additional $197.8 million as well as a $98.7 million decrease in net income, partially offset by $30.8 million in commodity hedge adjustments.

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        Net cash used in investing activities was $62.3 million for the six months ended June 30, 2009 compared to $25.7 million for the six months ended June 30, 2008. The $36.6 million increase is primarily due to $48.3 million of nonrecurring proceeds from property insurance received in 2008 partially offset by a $4.2 million decrease in investment in debt obligations of Targa Investments and a $3.1 million decrease in additions to property plant and equipment for the comparable periods.

Net cash used in financing activities was $195.6 million for the six months ended June 30, 2009 compared to $160.4 million for the six months ended June 30, 2008. The $35.2 million increase in cash used was primarily due to $95.9 million used to repay borrowings under our senior secured revolving credit facility partially offset by a $53.8 million reduction in distributions to Targa Investments and $11.3 million less net reduction in the Partnership’s total debt.

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 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 $130 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 on Form 10-K for the year ended December 31, 2008.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Natural Gas Gathering and Processing	$	84.6	$	116.6	$	147.7	$	229.2
Logistics Assets		22.8		11.6		31.8		18.5
NGL Distribution and Marketing Services		9.5		31.9		23.9		40.2
Wholesale Marketing		3.1		8.8		7.4		18.4
Other		0.7		-		0.7		-
	$	120.7	$	168.9	$	211.5	$	306.3

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

49

	Three Months Ended June 30,					Six Months Ended June 30,
	2009		2008			2009			2008
	(In millions)
Reconciliation of net income attributable to Targa operating margin:
Resources, Inc. to operating margin:
Net income attributable to Targa Resources, Inc.	$	13.5	$	46.2		$	16.1		$	64.6
Add:
Net income attibutable to noncontrolling interest		8.3		30.0			6.6			56.8
Depreciation and amortization expense		42.1		38.8			83.7			76.9
General and administrative expense		28.1		27.9			51.9			52.0
Interest expense, net		22.1		23.7			47.8			49.2
Income tax expense		6.5		28.2			6.4			40.3
Other, net		0.1		(25.9	)		(1.0	)		(33.5	)
Operating margin	$	120.7	$	168.9		$	211.5		$	306.3

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Reconciliation of net cash provided by	(In millions)
operating activities to Adjusted EBITDA:
Net cash provided by operating activities	$	38.9		$	134.6		$	112.9		$	374.4
Net income attibutable to noncontrolling interest		(8.3	)		(30.0	)		(6.6	)		(56.8	)
Interest expense, net (1)		20.5			21.6			44.3			45.1
Current income tax expense		0.1			0.2			0.1			1.2
Other		0.1			24.9			(0.2	)		30.8
Changes in operating assets and liabilities which used (provided) cash:
Accounts receivable and other assets		88.1			136.4			11.4			(136.5	)
Accounts payable and other liabilities		(43.5	)		(150.1	)		21.1			(28.9	)
Adjusted EBITDA	$	95.9		$	137.6		$	183.0		$	229.3

____________

(1)     Net of debt issue costs of $1.6 million and $3.5 million for the three and six months ended June 30, 2009, and $2.1 million and $4.1 million for the three and six months ended June 30, 2008.

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	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(In millions)
Reconciliation of net income attributable to Targa
Resources, Inc. to Adjusted EBITDA:
Net income attributable to Targa Resources, Inc.	$	13.5	$	46.2	$	16.1	$	64.6
Add:
Interest expense, net		22.1		23.7		47.8		49.2
Income tax expense (1)		5.9		27.9		5.8		39.8
Depreciation and amortization expense		42.1		38.8		83.7		76.9
Non-cash (gain) loss related to derivatives		12.3		1.0		29.6		(1.2	)
Adjusted EBITDA	$	95.9	$	137.6	$	183.0	$	229.3

____________

(1)   Net of income tax expense attributable to noncontrolling interest of $0.2 million and $0.5 million for the three and six months ended June 30, 2009, and $0.2 million and $0.5 million for the three and six months ended June 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. Our 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 June 30, 2009, the net book value of our property, plant and equipment was $2.6 billion and we recorded $42.1 million and $83.7 million of depreciation and amortization expense for three and six months ended June 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 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 $18.6 million, which would result in a corresponding reduction in our operating income.  In

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addition, if an assessment of impairment resulted in a reduction of 1% of our long-lived assets, our operating income would decrease by $25.9 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. At June 30, 2009, our balance sheet reflects total accounts receivable of approximately $309.0 million. Our allowance for doubtful accounts as of June 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 $3.1 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 $97.0 million as of June 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 $3.6 million at June 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 $9.7 million.

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.

52

Commodity Price Risk. A significant portion of our revenues is derived from percent-of-proceeds contracts under which we receive either an agreed upon percentage of the actual proceeds that we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on index-related prices for the natural gas and NGLs. 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 hedging transactions designed to mitigate the impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a 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 June 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 July 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-Waha		6.62		21,918		-		-		-		-		11,517
Swap	IF-Waha		6.69		-		16,300		-		-		-		6,608
Swap	IF-Waha		6.46		-		-		12,500		-		-		439
Swap	IF-Waha		7.18		-		-		-		5,500		-		921
					21,918		16,300		12,500		5,500		-
Swap	IF-PB		5.42		-		2,000		-		-		-		(32	)
Swap	IF-PB		5.42		-		-		2,000				-		(528	)
Swap	IF-PB		5.54		-		-		-		4,000		-		(1,274	)
Swap	IF-PB		5.54		-		-		-		-		4,000		(1,542	)
					-		2,000		2,000		4,000		4,000
Total Sales					21,918		18,300		14,500		9,500		4,000
Basis Swap Jul-Aug 2009 Rec NYMEX, pay IF-HSC plus $.0825, 20,000 MMBtu															12
Basis Swap Jul-Aug 2009 Rec IF-Waha, pay NYMEX less $.5175, 20,000 MMBtu															(477	)
														$	15,644

NGLs
Instrument		Avg. Price		Barrels per day
Type	Index	$/gal		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	OPIS-MB		0.79		3,347		-		-		-		-	$	247
Swap	OPIS-MB		0.87		-		2,750		-		-		-		1,992
Swap	OPIS-MB		0.91		-		-		1,550		-		-		1,233
Swap	OPIS-MB		0.92		-		-		-		1,250		-		575
Total Swaps					3,347		2,750		1,550		1,250		-
Floor	OPIS-MB		0.20		-		-		54		-		-		1,068
Floor	OPIS-MB		0.24		-		-		-		63		-		1,157
Total Floors					-		-		54		63		-
Total Sales					3,347		2,750		1,604		1,313		-
														$	6,272

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Condensate
Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		67.85		-		200		-		-		-	$	(537	)
Swap	NY-WTI		71.00		-		-		200		-		-		(508	)
Swap	NY-WTI		72.60		-		-		-		200		-		(505	)
Swap	NY-WTI		73.80		-		-		-		-		200		(508	)
Total Swaps					-		200		200		200		200
Total Sales					-		200		200		200		200
														$	(2,058	)

As of June 30, 2009, the Partnership had the following hedge 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 July 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		-		-		-		-	$	1,155
					1,966		-		-		-		-
Swap	IF-NGPL MC		9.18		6,256		-		-		-		-		6,109
Swap	IF-NGPL MC		8.86		-		5,685		-		-		-		6,655
Swap	IF-NGPL MC		7.34		-		-		2,750		-		-		866
Swap	IF-NGPL MC		7.18		-		-		-		2,750		-		466
					6,256		5,685		2,750		2,750		-
Swap	IF-Waha		7.79		9,936		-		-		-		-		7,115
Swap	IF-Waha		6.53		-		11,709		-		-		-		4,020
Swap	IF-Waha		6.10		-		-		11,250		-		-		(973	)
Swap	IF-Waha		6.30		-		-		-		7,250		-		(821	)
Swap	IF-Waha		5.59		-		-		-		-		4,000		(1,536	)
					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		-		-		-		-		435
					850		-		-		-		-
Floor	IF-Waha		6.55		565		-		-		-		-		285
					565		-		-		-		-
Total Floors					1,415		-		-		-		-
Total Sales					19,573		17,394		14,000		10,000		4,000
Basis Swap Jul 09-May 2011 Rec IF-CGT, Pay NYMEX less $0.11, 20,000 MMBtu/d															(668	)
Fuel cost swap Jul 2009-May2011 Rec IF-CGT, Pay $5.96, 226 MMbtu/d															46
														$	23,154

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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		-		-		-		-	$	24,428
Swap	OPIS-MB		1.27		-		4,809		-		-		-		30,359
Swap	OPIS-MB		0.92		-		-		3,400		-		-		1,844
Swap	OPIS-MB		0.92		-		-		-		2,700		-		545
Total Swaps					6,248		4,809		3,400		2,700		-
Floor	OPIS-MB		1.44		-		-		199		-		-		3,937
Floor	OPIS-MB		1.43		-		-		-		231		-		4,242
Total Floors					-		-		199		231		-
Total Sales					6,248		4,809		3,599		2,931		-
														$	65,355

Condensate
Instrument		Avg. Price		Barrels per day
Type	Index	$/Bbl		2009		2010		2011		2012		2013		Fair Value
Sales
Swap	NY-WTI		69.00		322		-		-		-		-	$	(149	)
Swap	NY-WTI		68.04		-		401		-		-		-		(1,048	)
Swap	NY-WTI		71.00		-		-		200		-		-		(508	)
Swap	NY-WTI		72.60		-		-		-		200		-		(506	)
Swap	NY-WTI		74.00		-		-		-		-		200		(495	)
Total Swaps					322		401		200		200		200
Floor	NY-WTI		60.00		50		-		-		-		-		15
Total Floors					50		-		-		-		-
Total Sales					372		401		200		200		200
														$	(2,691	)

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. As of June 30, 2009, we had approximately $1.4 billion of consolidated indebtedness, of which $1.0 billion was at variable interest rates.

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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:

	Fixed			Notional
Period	Rate			Amount	Fair Value
					(In thousands)
7/1/2009-3/31/2010		1.65	%	$400 million	$	(219	)
4/1/2010-3/31/2011		1.65	%	350 million		(1,488	)
4/1/2011-3/31/2012		1.65	%	300 million		2,124
					$	417

In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates, the Partnership entered into interest rate hedges that effectively fix the base rate on the borrowings as shown below:

	Fixed			Notional
Period	Rate			Amount	Fair Value
					(In thousands)
Remainder of 2009		3.03	%	$300 million	$	(4,668	)
2010		3.03	%	300 million		(6,703	)
2011		2.84	%	300 million		(2,048	)
2012		2.77	%	300 million		1,050
2013		2.75	%	300 million		2,318
1/1 - 4/24/2014		2.75	%	300 million		924
					$	(9,127	)

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 $2.8 million.

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 June 30, 2009, affiliates of Goldman Sachs, BofA and Barclays Bank accounted for 65%, 20% 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 June 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 14—Commitments and Contingencies 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 on Form 10-K for the year ended December 31, 2008. 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 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.  The finding and determination allows the EPA to begin regulating GHG emissions under existing provisions of the Clean Air Act. Any limitation imposed by the EPA on GHG emissions from our natural gas–fired compressor stations and processing facilities 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.  In addition, the U.S. Congress and various states are currently considering legislation that may impose national or regional caps on GHG emissions and may require major sources of GHG emissions to purchase “allowances” that would permit such sources to continue to emit GHGs.  Such legislation could require us to obtain allowances to offset emissions of GHGs that result from the combustion of natural gas or natural gas liquids we produce.  As an alternative to a “cap and trade” program, it is possible that Congress or individual states could implement carbon tax programs.  Any such regulatory initiatives adopted by EPA or legislation adopted by Congress or the states could increase our costs of doing business and/or increase the cost and reduce demand for our services.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for oil and natural gas products.

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.  The purpose of ACESA is to control and reduce emissions of “greenhouse gases,” or “GHGs,” in the United States.  GHGs are certain gases, including carbon dioxide and methane, that may be contributing to warming of the Earth’s atmosphere and other climatic changes.  ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050.  Under ACESA, most 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, and natural gas.

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

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issued each year but that allows parties to buy, sell and trade allowances as needed to fulfill their GHG emission 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, compressing, treating, processing and fractionating services.

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 trading and commodity positions 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 and 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
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.
10.1	Second Amendment to Credit Agreement dated May 1, 2009 between Targa Resources Inc., the Lenders named therein and Credit Suisse, as Administrative Agent, Swing Line Lender, Revolving L/C Issuer and Synthetic L/C Issuer (incorporated by reference to Exhibit 10.2 to Targa Resources Inc.’s Form 10-Q filed May 8, 2009 (File No. 333-147066)).
10.2**	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.
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: August 6, 2009

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Exhibit Index

0
Exhibit Number	Description
2.1*	Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP and 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
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.
10.1	Second Amendment to Credit Agreement dated May 1, 2009 between Targa Resources Inc., the Lenders named therein and Credit Suisse, as Administrative Agent, Swing Line Lender, Revolving L/C Issuer and Synthetic L/C Issuer (incorporated by reference to Exhibit 10.2 to Targa Resources Inc.’s Form 10-Q filed May 8, 2009 (File No. 333-147066)).
10.2**	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.
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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