TRI Resources (NGLS) 10-Q 2008 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

  For the quarterly period ended September 30, 2008

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 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	5
	Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007	5
	Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2007	6
	Consolidated Statements of Comprehensive Income (Loss) for the three and nine months ended September 30, 2008 and 2007	7
	Consolidated Statement of Changes in Stockholder’s Equity for the nine months ended September 30, 2008	8
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2008 and 2007	9
	Notes to Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4T.	Controls and Procedures	56
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	57
Item 1A.	Risk Factors	57
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	58
Item 3.	Defaults Upon Senior Securities	58
Item 4.	Submission of Matters to a Vote of Security Holders	58
Item 5.	Other Information	58
Item 6.	Exhibits	58
SIGNATURES		60

2

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

Bbl	Barrel(s)
BBtu	Billion British thermal unit(s), a measure of heating value
/d	Per day
gal	Gallon(s)
MBbl	Thousand barrels
MMBtu	Million British thermal units, a measure of heating value
MMcf	Million cubic feet
NGL(s)	Natural gas liquid(s)
Price Index Definitions
IF-HSC	Inside FERC Gas Market Report, Houston Ship Channel/Beaumont, Texas
IF-NGPL MC	Inside FERC Gas Market Report, Natural Gas Pipeline, Mid-Continent
IF-Waha	Inside FERC Gas Market Report, West Texas Waha
NY-HH	NYMEX, Henry Hub Natural Gas
NY-WTI	NYMEX, West Texas Intermediate Crude Oil
OPIS-MB	Oil Price Information Service, Mont Belvieu, Texas

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.”

3

Cautionary Statement About Forward-Looking Statements

This Quarterly Report contains “forward-looking statements” as defined in Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this Quarterly Report are forward-looking statements. Forward-looking statements include, without limitation, statements regarding our future financial position, business strategy, future capital and other expenditures, plans and objectives of management for future operations. You can typically identify forward-looking statements by the use of forward-looking words such as “may,” “potential,” “project,” “plan,” “believe,” “expect,” “anticipate,” “intend,” “estimate” or similar expressions or variations on such expressions. Each forward-looking statement reflects our current view of future events and is subject to risks, uncertainties and other factors, known and unknown, which could cause our actual results to differ materially from any results expressed or implied by our forward-looking statements. These risks and uncertainties, many of which are beyond our control, include, but are not limited to:

• 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;

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

• the timing and extent of changes in natural gas, NGL and 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;

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

• general economic, market and business conditions; and

• the risks described in this Quarterly Report and our Annual Report on Form 10-K for the year ended December 31, 2007.

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 in this Quarterly Report and under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007. 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.

Forward-looking statements contained in this Quarterly Report and all subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by this cautionary statement.

4

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TARGA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	September 30, 2008			December 31, 2007
	(Unaudited)
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	123,489		$	177,949
Trade receivables, net of allowances of $8,962 and $1,115		638,692			836,044
Inventory		118,933			143,185
Deferred income taxes		—			25,071
Assets from risk management activities		38,791			9,487
Other current assets		10,221			70,640
Total current assets		930,126			1,262,376
Property, plant and equipment, at cost		3,078,727			2,764,230
Accumulated depreciation		(451,173	)		(334,160	)
Property, plant and equipment, net		2,627,554			2,430,070
Unconsolidated investments		19,554			48,005
Long-term assets from risk management activities		22,785			4,279
Investment in debt obligations of Targa Resources Investments Inc.		14,991			—
Other assets		55,870			45,235
Total assets	$	3,670,880		$	3,789,965
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	333,162		$	470,860
Accrued liabilities		383,116			379,245
Current maturities of debt		12,500			12,500
Liabilities from risk management activities		35,281			75,568
Deferred income taxes		1,408			—
Total current liabilities		765,467			938,173
Long-term debt, less current maturities		1,402,800			1,398,475
Long-term liabilities from risk management activities		51,960			81,019
Deferred income taxes		34,560			29,501
Other long-term obligations		42,219			35,267
Minority interest		148,384			100,826
Non-controlling interest in Targa Resources Partners LP		725,185			714,300
Commitments and contingencies (see Note 11)
Stockholder’s equity:
Common stock ($0.001 par value, 1,000 shares authorized, issued, and outstanding at September 30, 2008 and December 31, 2007, collateral for Targa Resources Investments Inc. debt)		—			—
Additional paid-in capital		421,463			473,784
Retained earnings		118,470			74,736
Accumulated other comprehensive loss		(39,628	)		(56,116	)
Total stockholder’s equity		500,305			492,404
Total liabilities and stockholder’s equity	$	3,670,880		$	3,789,965

See notes to consolidated financial statements

5

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands)
Revenues	$	2,352,987		$	1,863,636		$	6,818,606		$	4,923,416
Costs and expenses:
Product purchases		2,176,830			1,664,703			6,201,360			4,373,289
Operating expenses		73,583			59,526			208,390			179,837
Depreciation and amortization expense		41,086			37,591			118,028			110,757
General and administrative expense		26,679			35,831			78,696			78,221
Casualty loss		17,899			—			17,899			—
Loss (gain) on sale of assets		(13	)		36			(4,458	)		(95	)
		2,336,064		��	1,797,687			6,619,915			4,742,009
Income from operations		16,923			65,949			198,691			181,407
Other income (expense):
Interest expense, net		(24,599	)		(34,749	)		(73,844	)		(112,752	)
Equity in earnings of unconsolidated investments		2,534			2,317			13,189			7,964
Minority interest		(12,990	)		(7,674	)		(34,747	)		(20,492	)
Non-controlling interest in Targa Resources Partners LP		(11,613	)		(2,580	)		(47,210	)		(6,628	)
Gain on insurance claims		—			—			18,566			—
Loss on mark-to-market derivative instruments		(1,311	)		—			(1,311	)		—
Income (loss) before income taxes		(31,056	)		23,263			73,334			49,499
Income tax (expense) benefit
Current		1,053			(596	)		(184	)		(1,289	)
Deferred		9,123			(9,378	)		(29,416	)		(11,881	)
		10,176			(9,974	)		(29,600	)		(13,170	)
Net income (loss)	$	(20,880	)	$	13,289		$	43,734		$	36,329

See notes to consolidated financial statements

6

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands)
Net income (loss)	$	(20,880	)	$	13,289		$	43,734		$	36,329
Other comprehensive income (loss):
Commodity hedging contracts:
Change in non-controlling partners’ share of other comprehensive income of Targa Resources Partners LP		(150,985	)		1,322			(10,867	)		6,084
Change in fair value		312,081			(1,602	)		(50,303	)		(89,677	)
Reclassification adjustment for settled periods		35,304			(2,290	)		87,705			(16,313	)
Related income taxes		(71,043	)		2,430			(8,406	)		40,907
Interest rate swaps:
Change in non-controlling partners’ share of other comprehensive income of Targa Resources Partners LP		(106	)		—			(361	)		—
Change in fair value		(984	)		139			(1,254	)		660
Reclassification adjustment for settled periods		869			(585	)		1,485			(1,633	)
Related income taxes		95			151			60			388
Available for sale securities:
Change in fair value		(165	)		—			(2,065	)		—
Related income taxes		122			—			828			—
Foreign currency items:
Foreign currency translation adjustment		(235	)		713			(477	)		1,714
Related income taxes		43			(331	)		143			(708	)
Other comprehensive income (loss)		124,996			(53	)		16,488			(58,578	)
Comprehensive income (loss)	$	104,116		$	13,236		$	60,222		$	(22,249	)

See notes to consolidated financial statements

7

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER’S EQUITY

	Common Stock			Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Loss			Total
	Shares	Amount
	(Unaudited)
	(In thousands)
Balance as of December 31, 2007	1	$	—	$	473,784		$	74,736	$	(56,116	)	$	492,404
Distribution to parent	—		—		(52,774	)		—		—			(52,774	)
Amortization of equity awards	—		—		979			—		—			979
Tax expense on vesting of common stock	—		—		(526	)		—		—			(526	)
Partnership contributions	—												—
Other comprehensive income	—		—		—			—		16,488			16,488
Net income	—		—		—			43,734		—			43,734
Balances as of September 30, 2008	1	$	—	$	421,463		$	118,470	$	(39,628	)	$	500,305

See notes to consolidated financial statements

8

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2008			2007
	(Unaudited)
	(In thousands)
Cash flows from operating activities
Net income	$	43,734		$	36,329
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization in interest expense		5,734			10,846
Amortization in general and administrative expense		1,179			1,742
Other depreciation and amortization expense		118,028			110,757
Accretion of asset retirement obligations		1,189			740
Deferred income tax expense		29,416			11,881
Equity in earnings of unconsolidated investments		(13,189	)		(7,964	)
Distributions from unconsolidated investments		2,713			3,100
Minority interest		34,747			20,492
Minority interest distributions		(29,045	)		(18,685	)
Non-controlling interest in Targa Resources Partners LP		47,210			6,628
Distributions to non-controlling interest in Targa Resources Partners LP		(45,994	)		(6,628	)
Risk management activities		(76,754	)		(13,821	)
Gain on sale of assets		(4,458	)		(95	)
Gain on property damage insurance settlement (see Note 9)		(18,566	)		—
Asset impairment charges		5,112			—
Changes in operating assets and liabilities:
Accounts receivable and other assets		268,581			(129,848	)
Inventory		22,412			(27,639	)
Accounts payable and other liabilities		(204,547	)		138,989
Net cash provided by operating activities		187,502			136,824
Cash flows from investing activities
Purchases of property, plant and equipment		(89,571	)		(97,766	)
Acquisitions, net of cash acquired		(124,938	)		—
Proceeds from property insurance		48,294			17,900
Investment in debt securities of Targa Investments Inc.		(16,400	)		—
Investment in unconsolidated affiliate		—			(4,648	)
Other		(3,696	)		2,255
Net cash used in investing activities		(186,311	)		(82,259	)
Cash flows from financing activities
Senior secured credit facility:
Repayments		(9,375	)		(709,375	)
Senior secured credit facility of Targa Resources Partners LP:
Borrowings		87,500			342,500
Repayments		(323,800	)		(48,000	)
Proceeds from issuance of senior notes of Targa Resources Partners LP		250,000			—
Distribution to non-controlling interest in Targa Resources Partners LP in excess of cumulative earnings		—			(3,161	)
Contribution from non-controlling interest in Targa Resources Partners LP		—			377,454
Distribution to parent		(52,774	)		(167	)
Costs incurred in connection with financing arrangements		(7,202	)		(4,147	)
Net cash used in financing activities		(55,651	)		(44,896	)
Net increase (decrease) in cash and cash equivalents		(54,460	)		9,669
Cash and cash equivalents, beginning of period		177,949			142,739
Cash and cash equivalents, end of period	$	123,489		$	152,408

See notes to consolidated financial statements

9

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Basis of Presentation

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

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

These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. The unaudited consolidated financial statements for the three and nine months ended September 30, 2008 and 2007 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair statement of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. Our financial results for the three and nine months ended September 30, 2008 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2008. 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, 2007.

We currently own approximately 26.5% 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 non-controlling interest in the Partnership on our consolidated balance sheets represents 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. Non-controlling interest in net income of the Partnership on our consolidated statements of operations represents those partners’ share of the net income of the Partnership.

Note 2—Accounting Policies and Related Matters

Investments in Debt Securities. Investments in debt securities that we have the positive intent and ability to hold to maturity are classified as “held-to-maturity” and reported at cost, adjusted for amortization or accretion of premiums or discounts. Securities not classified as held-to-maturity are classified as “available-for-sale” and are recorded at fair value. Unrealized gains and losses, net of the related tax effect, on available-for-sale securities are reported as accumulated other comprehensive income or loss which is a separate component of consolidated stockholder’s equity, and the annual change in such gains and losses are reported as other comprehensive income. A transfer of securities between categories is recorded at fair value on the date of transfer.

10

Realized gains and losses on the sale of available-for-sale securities are recorded on the trade date and are determined using the specific identification method. Discounts or premiums are accreted or amortized to interest income using the effective interest method over the expected terms of the related security.

Investment securities are evaluated for impairment when economic or market conditions warrant such an evaluation to determine whether a decline in their value below amortized cost is other-than-temporary. Once a decline in value is determined to be other-than-temporary, the value of the security is reduced and a corresponding charge to earnings is recognized.

The fair value of our available-for-sale securities is based on quoted market prices. In instances where quoted market prices are not available, fair values are based on indicative valuations provided by a bank.

Accounting Pronouncements Recently Adopted

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements.” SFAS 157 establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The FASB partially deferred the effective date of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We adopted SFAS 157 with respect to financial assets and liabilities that are recognized on a recurring basis on January 1, 2008. Although the adoption of SFAS 157 did not materially impact our financial condition, results of operations, or cash flows, we are now required to provide additional disclosures as part of our financial statements.

SFAS 157 establishes 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 an entity to develop its own assumptions.

Our derivative instruments consist of financially settled commodity and interest rate swap and option contracts and fixed price commodity contracts with certain customers. We determine the value of our derivative contracts utilizing a discounted cash flow model for swaps and a standard option pricing model for options, based on inputs that are either readily available in public markets or are quoted by counterparties to these contracts. In situations where we obtain inputs via quotes from our counterparties, we verify the reasonableness of these quotes via similar quotes from another source for each date for which financial statements are presented. We have consistently applied these valuation techniques in all periods presented and believe we have obtained the most accurate information available for the types of derivative contracts we hold. We have categorized the inputs for these contracts as Level 2 or Level 3. The price quotes for the Level 3 inputs are provided by a counterparty with whom we regularly transact business.

On June 10, 2008, we paid $16.4 million to acquire from a third party $20.0 million of Targa Investments’ debt (see Note 4). We have determined the fair value of our investment using an indicative valuation provided by a bank. The indicative valuation was provided for information purposes only, and did not constitute a bid or offer, or a solicitation of a bid or offer, to initiate or conclude any transaction at the stated indicative value. As a result, we have categorized the indicative valuation as a Level 3 input.

11

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Total		Level 1		Level 2		Level 3
	(In thousands)
Assets from commodity derivative contracts	$	61,349	$	—	$	21,168	$	40,181
Assets from interest rate derivatives		227		—		227		—
Available-for-sale securities (1)		14,335		—		—		14,335
Total assets	$	75,911	$	—	$	21,395	$	54,516
Liabilities from commodity derivative contracts	$	85,291	$	—	$	22,857	$	62,434
Liabilities from interest rate derivatives		1,950		—		1,950		—
Total liabilities	$	87,241	$	—	$	24,807	$	62,434

(1) Excludes $656 of interest paid in-kind.

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

	Derivative Contracts			Available For Sale Securities			Total
	(In thousands)
Balance, December 31, 2007	$	(124,282	)	$	—		$	(124,282	)
Total gains or losses (realized/unrealized)
Included in loss on mark-to-market derivatives		(1,311	)		—			(1,311	)
Included in OCI		(20,592	)		(2,065	)		(22,657	)
Included in non-controlling interest in the Partnership		(20,999	)		—			(20,999	)
Purchases		3,315			16,400			19,715
Terminations		77,792			—			77,792
Settlements		63,824			—			63,824
Balance, September 30, 2008	$	(22,253	)	$	14,335		$	(7,918	)
Unrealized gains or losses related to assets held as of September 30, 2008	$	—		$	—		$	—

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115.” SFAS 159 expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. Our adoption of SFAS 159 on January 1, 2008 did not have a material impact on our consolidated financial statements.

Accounting Pronouncements Recently Issued

In March 2008, the FASB issued SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.” SFAS 161 changes the disclosure requirements for

12

derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Early adoption is encouraged. Our adoption of SFAS 161 will not impact our consolidated financial position, results of operations or cash flows.

Note 3—Partnership Units and Related Matters

The following table lists the Partnership’s declared distribution subsequent to September 30, 2008 and distributions declared and paid in the nine months ended September 30, 2008 and 2007:

		Distributions Paid / To Be Paid										Distributions per limited partner unit
		Common Units		Subordinated Units		General Partner
Date Declared	Date Paid or To Be Paid					Incentive		2%		Total
		(In thousands, except per unit amounts)
October 23, 2008	November 14, 2008(1)	$	17,932	$	5,966	$	1,932	$	527	$	26,357	$	0.51750
July 17, 2008	August 14, 2008		17,759		5,908		1,711		518		25,896		0.51250
April 22, 2008	May 15, 2008		14,467		4,813		208		398		19,886		0.41750
January 23, 2008	February 14, 2008		13,768		4,582		66		376		18,792		0.39750
October 23, 2007	November 14, 2007		11,082		3,891		—		305		15,278		0.33750
July 23, 2007	August 14, 2007		6,526		3,890		—		212		10,628		0.33750
April 23, 2007	May 15, 2007		3,263		1,945		—		107		5,315		0.16875

(1) Payable to unitholders of record on November 4, 2008, for the period from July 1, 2008 to September 30, 2008.

Note 4—Investment in Debt Securities of Targa Investments

On June 10, 2008 we paid $16.4 million to acquire from a third party $20.0 million of Targa Investments’ outstanding variable rate indebtedness. The stated maturity date of the indebtedness is February 10, 2015, and as of September 30, 2008, the variable rate was 7.5%. We have classified this investment as an available-for-sale security. As of September 30, 2008, we have recorded an unrealized loss of $2.1 million in accumulated other comprehensive loss, based on an indicative valuation supplied by a bank.

Note 5—Unconsolidated Investments

As of September 30, 2008, our unconsolidated investments consisted of a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids. Prior to July 31, 2008 our unconsolidated investments 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 with effect from August 1, 2008, in accordance with SFAS 141, “Business Combinations”.

The following table shows our unconsolidated investments as of the dates indicated:

	September 30, 2008		December 31, 2007
	(In thousands)
Natural Gas Gathering and Processing—VESCO	$	—	$	28,767
Logistics Assets—GCF		19,554		19,238
	$	19,554	$	48,005

13

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In thousands)
Equity in earnings of:
VESCO (1)	$	1,432	$	1,567	$	10,161	$	5,067
GCF		1,102		750		3,028		2,897
	$	2,534	$	2,317	$	13,189	$	7,964
Cash contributions:
VESCO	$	—	$	—	$	—	$	4,648
Cash distributions:
GCF	$	1,938	$	775	$	2,713	$	3,100

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

Our equity in earnings of VESCO includes partially settled business interruption insurance claims of $0 and $4.1 million for the three and nine months ended September 30, 2008 and $0 and $3.1 million for the three and nine months ended September 30, 2007.

Note 6—Debt Obligations

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

	September 30, 2008			December 31, 2007
	(In thousands)
Long-term debt:
Obligations of Targa:
Senior secured term loan facility, variable rate, due October 2012	$	525,300		$	534,675
Senior unsecured notes, 8 1/2% fixed rate, due November 2013		250,000			250,000
Senior secured revolving credit facility, variable rate, due October 2011 (1)		—			—
Obligations of the Partnership (2):
Senior secured revolving credit facility, variable rate, due February 2012 (3)		390,000			626,300
Senior notes, 8 1/4% fixed rate, due July 2016		250,000			—
Total debt		1,415,300			1,410,975
Current maturities of debt		(12,500	)		(12,500	)
Total long-term debt	$	1,402,800		$	1,398,475
Irrevocable standby letters of credit:
Letters of credit outstanding under synthetic letter of credit facility (4)	$	282,344		$	272,409
Letters of credit outstanding under senior secured revolving credit facility of the Partnership		34,700			25,900
	$	317,044		$	298,309

(1) The entire availability under the senior secured revolving credit facility may also be utilized for letters of credit. In October 2008, Lehman Brothers Commercial Bank (“Lehman Bank”), a lender under our senior

14

secured credit facility, defaulted on a borrowing request. As a result of the default, we believe the availability under the facility has been effectively reduced by $10.2 million.

(2) 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.

(3) As of September 30, 2008, the Partnership had availability under this facility of $415.8 million, after giving effect to outstanding borrowings of $390.0 million, $34.7 million in outstanding letters of credit and the Lehman Bank default. As a result of the default, we believe the Partnership’s availability under its senior secured credit facility has been effectively reduced by $9.5 million.

(4) The $300 million senior secured synthetic letter of credit facility terminates in October 2012. As of September 30, 2008, we had $17.7 million available under this facility.

Information Regarding Variable Interest Rates Paid

The following table shows the range of interest rates paid and weighted average interest rates paid on our significant consolidated variable-rate debt obligations during the nine months ended September 30, 2008.

	Range of interest rates paid		Weighted average interest rate paid
Senior secured term loan facility	4.5% to 6.9	%	5.9	%
Senior secured revolving credit facility of the Partnership	3.5% to 6.4	%	4.7	%

Obligations of the Partnership

8 ¹/4% Senior Notes Due 2016

On June 18, 2008, 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 8 ¹/4% Senior Notes due 2016 (the “Partnership Notes”). Proceeds from the Partnership Notes were used to repay borrowings under the Partnership’s senior secured credit facility.

The Partnership Notes:

• are the Partnership’s senior unsecured obligations;

• rankpari passuin right of payment with the Partnership’s existing and future senior indebtedness, including indebtedness under its senior secured credit facility;

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

• are unconditionally guaranteed by the Partnership.

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

Interest on the Partnership Notes accrues at the rate of 8 ¹/4% per annum and is payable semi-annually in arrears on January 1 and July 1, commencing on January 1, 2009. Interest is computed on the basis of a 360-day year comprising twelve 30-day months.

At any time prior to July 1, 2011, the Partnership may on one or more occasions redeem up to 35% of the aggregate principal amount of the Partnership Notes with the net cash proceeds of one or more equity offerings by the Partnership, at a redemption price of 108.25% of the principal amount plus accrued and unpaid interest and liquidated damages, if any, to the redemption date, provided that:

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

15

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

At any time prior to July 1, 2012, the Partnership may redeem all or part of the Partnership Notes at a redemption price equal to 100% of the principal amount of the Partnership Notes redeemed plus the applicable premium as defined in the indenture agreement plus accrued and unpaid interest and liquidated damages (as defined in the indenture), if any, to the date of redemption.

On or after July 1, 2012, the Partnership may redeem all or part of the Partnership Notes at the redemption prices set forth below (expressed as percentages of the principal amount), plus accrued and unpaid interest and liquidated damages, if any, on the Partnership Notes redeemed, if redeemed during the twelve-month period beginning on July 1 of the year indicated:

Year	Percentage
2012	104.125	%
2013	102.063	%
2014 and thereafter	100.000	%

The Partnership Notes are subject to a registration rights agreement dated June 18, 2008. Under the registration rights agreement, the Partnership is required to file by June 19, 2009 a registration statement with respect to any Partnership Notes that are not freely transferable without volume restrictions by holders of the Partnership Notes that are not affiliates of the Partnership. If the Partnership fails to do so, additional interest will accrue on the principal amount of the Partnership Notes. Under EITF 00-19-2, “Accounting for Registration Payment Arrangements,” the Partnership has determined that the payment of additional interest is not probable, as that term is defined in SFAS 5, “Accounting for Contingencies.” As a result, the Partnership has not recorded a liability for any contingent obligation. Any subsequent accruals of a liability or payments made under the registration rights agreement will be charged to earnings as interest expense in the period they are recognized or paid.

Senior Secured Credit Facility of the Partnership

Concurrent with the closing of the private placement of the Partnership Notes, the Partnership increased the commitments under its senior secured credit facility by $100 million, bringing the total commitments under its senior secured credit facility to $850 million. The Partnership may request additional commitments under its senior secured credit facility of up to $150 million, which would increase the total commitments under its facility to $1 billion. On October 16, 2008, the Partnership requested a $100 million funding under its senior secured revolving credit facility. Lehman Bank, a lender under the Partnership’s senior secured credit facility, defaulted on its portion of the borrowing request resulting in an actual funding of $97.8 million. The proceeds from this borrowing are currently available to the Partnership as cash deposits. As a result of the default, we believe the Partnership’s availability under its senior secured credit facility has been effectively reduced by $9.5 million.

Note 7—Asset Retirement Obligations

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

	Nine Months Ended September 30, 2008
	(In thousands)
Beginning of period	$	12,608
Liabilities incurred (1)		16,932
Liabilities settled		(229	)
Change in cash flow estimate (2)		2,732
Accretion expense		1,189
End of period	$	33,232

(1) The entire amount relates to our consolidation of VESCO.

(2) The change in cash flow estimate is primarily from a reassessment of abandonment cost estimates for our offshore gathering systems.

16

Note 8—Stock and Other Compensation Plans

Stock Option Plans

Share-based compensation cost related to stock options included in general and administrative expense for the three and nine months ended September 30, 2008 was $42,000 and $150,000. Share-based compensation cost related to stock options included in general and administrative expense for the three and nine months ended September 30, 2007 was $20,000 and $50,000. As of September 30, 2008, our remaining unamortized compensation cost related to stock options was approximately $0.2 million, which is expected to be recognized over a weighted-average period of approximately one year.

During the nine months ended September 30, 2008 and 2007, there were 180,000 and 82,791 stock options granted. The fair value of each option grant was estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions for 2008 and 2007, including (i) expected term of the options of ten years, (ii) a risk-free interest rate of 3.6% and 4.9%, (iii) expected dividend yield of 0%, and (iv) expected stock price volatility on Targa Investments’ common stock of 25.5% and 29.4%. Our selection of the risk-free interest rate was based on published yields for United States government securities with comparable terms. Because Targa Investments does not have publicly traded equity shares, its expected stock price volatility was estimated based upon the historical price volatility of the Dow Jones MidCap Pipelines Index over a period equal to the expected average term of the options granted. The fair value of options granted during the nine months ended September 30, 2008 was $1.48 per share. The fair value of options granted during the nine months ended September 30, 2007 ranged from none to $0.33 per share, with a weighted-average fair value of $0.18 per share.

Non-vested (Restricted) Common Stock

Share-based compensation cost related to restricted stock included in general and administrative expense for the three and nine months ended September 30, 2008 was $0.2 million and $0.8 million. Share-based compensation cost related to restricted stock included in general and administrative expense for the three and nine months ended September 30, 2007 was $0.5 million and $1.6 million. As of September 30, 2008, our remaining unamortized compensation cost related to restricted stock was approximately $0.6 million, which is expected to be recognized over a weighted-average period of approximately one year.

Awards of non-vested common stock during the nine months ended September 30, 2008 and 2007 were 20,000 and 73,049 shares. The estimated fair values of awards of non-vested common stock during the nine months ended September 30, 2008 and 2007 were $3.45 and $1.10 per share.

Incentive Plan related to the Partnership’s Common Units

The Targa Resources Partners Long-Term Incentive Plan (the “Partnership Plan”) has been adopted by the general partner of the Partnership to promote the interests of the Partnership and its affiliates by providing to employees, consultants and directors of the Partnership and its affiliates incentive compensation awards for superior performance that are based on Partnership common units.

Non-Employee Director Grants. On March 25, 2008, the general partner of the Partnership awarded 16,000 restricted common units of the Partnership (2,000 restricted common units to each of the Partnership’s non-management directors and to each of Targa Investments’ independent directors). The awards will settle with the delivery of common units and are subject to three-year vesting, without a performance condition, and will vest ratably on each anniversary of the grant date.

Compensation expense on the restricted common units is recognized on a straight-line basis over the vesting period. The fair value of an award of restricted common units is measured on the grant date using the market price of a common unit on such date. For the three and nine months ended September 30, 2008, the Partnership

17

recognized compensation expense of approximately $80,000 and $199,000 related to equity-based awards. For the three months ended September 30, 2007 and for the period of commencement of Partnership operations (February 14, 2007) through September 30, 2007, it recognized compensation expense of approximately $52,000 and $129,000 related to equity-based awards. The Partnership estimates that the remaining fair value of $320,000 will be recognized in expense over a weighted average period of approximately two years.

Performance Units. As of September 30, 2008, the aggregate fair value of performance units expected to vest was $7.1 million. For the three and nine months ended September 30, 2008 we recognized compensation expense/(contra expense) related to the performance units of $(151,000) and $0.7 million. For the same periods in 2007, we recognized compensation expense related to the performance units of $0.6 million and $1.9 million. The total recognition period for the remaining unrecognized compensation cost is approximately two years.

Note 9—Hurricane Insurance Claims

Hurricanes Katrina and Rita

We recognize income from business interruption insurance in our consolidated statements of operations in the period that a proof of loss is executed and submitted to the insurers for payment. The following table summarizes our income recognition of business interruption insurance related to Katrina and Rita for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
	(In thousands)
Included in revenues
Natural Gas Gathering and Processing	$	—	$	1,750	$	2,540	$	2,643
Logistics Assets		—		—		441		(32	)
NGL Distribution and Marketing		—		—		8,602		3,834
Wholesale Marketing		—		—		5,920		826
		—		1,750		17,503		7,271
Included in equity in earnings of unconsolidated investments
Natural Gas Gathering and Processing		—		—		4,108		3,088
	$	—	$	1,750	$	21,611	$	10,359

Katrina and Rita affected certain of our Gulf Coast facilities in 2005. Our final purchase price allocation for the DMS acquisition in October 2005 included an $81.1 million receivable for insurance claims related to property damage caused by Katrina and Rita. During the second quarter of 2008, our cumulative receipts exceeded such amount, and we recognized a gain of $18.6 million. The insurance claim process is complete with respect to Katrina and Rita property damage.

Hurricanes Gustav and Ike

In September, certain of our facilities in Louisiana and Texas sustained damage and had disruption to their operations from Hurricanes Gustav and Ike.

Hurricane Gustav made landfall near Cocodrie, Louisiana on September 1, 2008. Hurricane Ike made landfall at Galveston, Texas on September 13, 2008. Our Venice and Yscloskey gas processing plants were impacted by the storm surge caused by both hurricanes. Damage at these two facilities was not substantial. The Venice gas plant was processing gas by early October. The Yscloskey gas plant start-up and commissioning timing has been delayed to late November as a result of hurricane damage to the Tennessee Gas Pipeline

18

Bluewater offshore system. Mechanical repairs have been completed and additional repairs are ongoing in preparation for the current schedule of available gas. Volumes available for processing at both facilities have been impacted by third-party offshore production shut-ins/evacuations ahead of the hurricanes, and by subsequent damage to those third-party facilities and pipelines from the hurricanes.

In Texas, our Galena Park marine terminal sustained a significant storm surge from Ike, resulting in damage to the docks, associated piping and related infrastructure. Temporary repairs restored limited barge and ship cargo transfers by late September, with full loading/offloading capabilities expected to be restored by the end of December. Galena Park’s shore-side facilities sustained relatively minor flood damage. Our Mont Belvieu complex sustained relatively minor wind damage and was fully operational by late September. Ike’s storm surge significantly impacted our Stingray and Barracuda gas processing facilities and our Hackberry storage facility, all of which are located in Cameron Parish, Louisiana. Operations at Hackberry resumed partial functionality in late September, with permanent repairs ongoing and full resumption of operations expected by the end of the fourth quarter. Gas processing operations at Stingray and Barracuda are anticipated to resume during the second quarter of 2009.

While it is still very early in the claims process, and we need to finalize repair assessments and cost estimates for those facilities that require repair, we currently estimate the cost associated with our interest for those repairs to be approximately $65 million. We believe that we have adequate insurance coverage (subject to customary deductibles, limits and sub-limits) to cover the respective facility repair costs and to offset the majority of the associated lost profits as a result of the hurricanes. The property damage deductibles under our insurance coverage will reduce our ultimate property damage insurance recoveries by approximately $14 million. We will have additional out of pocket costs associated with improvements (e.g., elevating critical equipment) that may not be covered by insurance. For the three months ended September 30, 2008, we recorded a loss provision of $17.9 million for our estimated out-of-pocket cleanup and repair costs related to Gustav and Ike, after estimated insurance proceeds.

We are still in the process of analyzing the factors affecting the amount of our business interruption claims. We maintain a 30 day time-element business interruption waiting period for our onshore facilities, and a 45 day time-element contingent business interruption waiting period for third-party offshore property damage related income impacts to our onshore facilities. We will recognize income from business interruption claims in the period that a Proof of Loss is executed with the insurance company.

Note 10—Derivative Instruments and Hedging Activities

As of December 31, 2007, accumulated other comprehensive income (loss) (“OCI”) included $91.7 million ($57.2 million, net of tax) of unrealized net losses on commodity hedges and $0.3 million ($0.2 million, net of tax) of unrealized net losses on interest rate hedges.

In May 2008 Targa and the Partnership entered into certain NGL derivative contracts with Lehman Brothers Commodity Services Inc. (“Lehman”). Due to Lehman’s bankruptcy filings, it is unlikely that we will receive full or partial payment of any amounts that may become owed to us under these contracts. Accordingly, Targa and the Partnership discontinued hedge accounting treatment for these contracts as of July 1, 2008. Deferred losses of $0.2 million and $0.3 million will be reclassified from OCI to revenues during 2011 and 2012 when the forecasted transactions related to these contracts are expected to occur. During the three months ended September 30, 2008, Targa and the Partnership recognized an aggregate non-cash loss on mark-to-market derivatives of $1.3 million to adjust the fair value of the Lehman derivative contracts to zero. On October 22, 2008, Targa and the Partnership terminated the Lehman derivative contracts.

During July 2008, the Partnership paid $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps. Prior to the terminations, these swaps were designated as hedges in accordance with SFAS 133. Deferred losses of approximately $20.8 million, $38.2 million, and $27.9 million will be reclassified

19

from OCI as a non-cash reduction of revenue during 2008, 2009 and 2010 when the hedged forecasted sales transactions are expected to occur. During the three months ended September 30, 2008, deferred losses of $9.3 million were reclassified from OCI as a non-cash reduction to revenue. The Partnership also entered into new natural gas and NGL commodity swaps at then current market prices that match the production volumes of the terminated swaps through 2010.

For the three and nine months ended September 30, 2008, deferred net losses on commodity hedges of $35.3 million and $87.7 million were reclassified from OCI to revenues, and deferred losses on interest rate hedges of $0.9 million and $1.5 million were reclassified from OCI to interest expense. For the three and nine months ended September 30, 2007, deferred net gains on commodity hedges of $2.3 million and $16.3 million were reclassified from OCI to revenues, and deferred gains on interest rate hedges of $0.6 million and $1.6 million were reclassified from OCI to interest expense. There were no adjustments for hedge ineffectiveness.

As of September 30, 2008, OCI consisted of $65.2 million ($39.0 million, net of tax) of unrealized net losses on commodity hedges, $0.5 million ($0.3 million, net of tax) of unrealized net losses on interest rate hedges and $2.1 million ($1.2 million, net of tax) of unrealized net losses on available-for-sale securities. Deferred net losses of $38.6 million on commodity hedges and $0.3 million on interest rate hedges recorded in OCI are expected to be reclassified to revenues from third parties and interest expense during the next twelve months.

As of September 30, 2008, we had the following hedge arrangements which will settle during the years ending December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from October 1, 2008 through December 31, 2008):

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Natural Gas Sales
Swap	IF-Waha	6.96	21,918	—	—	—	—	$	2,994
Swap	IF-Waha	6.62	—	21,918	—	—	—		(5,468	)
Swap	IF-Waha	7.40	—	—	9,300	—	—		(1,382	)
Swap	IF-Waha	7.36	—	—	—	5,500	—		(880	)
Swap	IF-Waha	7.18	—	—	—	—	5,500		(1,041	)
Total Sales			21,918	21,918	9,300	5,500	5,500	$	(5,777	)

NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	0.82	3,547	—	—	—	—	$	(4,934	)
Swap	OPIS-MB	0.79	—	3,347	—	—	—		(18,305	)
Swap	OPIS-MB	0.87	—	—	2,750	—	—		(9,092	)
Swap	OPIS-MB	0.91	—	—	—	1,550	—		(3,274	)
Swap	OPIS-MB	0.92	—	—	—	—	1,250		(2,111	)
Total Swaps			3,547	3,347	2,750	1,550	1,250
Floor	OPIS-MB	1.44		—	—	54	—		265
Floor	OPIS-MB	1.43	—	—	—	—	63		340
Total Floors			—	—	—	54	63
Total Sales			3,547	3,347	2,750	1,604	1,313	$	(37,111	)

20

As of September 30, 2008, the Partnership had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from October 1, 2008 through December 31, 2008):

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Natural Gas Purchases
Swap	NY-HH	8.69	1,300	—	—	—	—	$	(133	)
Total Purchases			1,300	—	—	—	—
Natural Gas Sales
Swap	IF-HSC	8.09	2,328	—	—	—	—		206
Swap	IF-HSC	7.39	—	1,966	—	—	—		(262	)
			2,328	1,966	—	—	—
Swap	IF-NGPL MC	8.86	6,964	—	—	—	—		2,613
Swap	IF-NGPL MC	9.18	—	6,256	—	—	—		4,515
Swap	IF-NGPL MC	8.86	—	—	5,685	—	—		2,061
Swap	IF-NGPL MC	7.34	—	—	—	2,750	—		(485	)
Swap	IF-NGPL MC	7.18	—	—	—	—	2,750		(539	)
			6,964	6,256	5,685	2,750	2,750
Swap	IF-Waha	8.91	7,389	—	—	—	—		2,330
Swap	IF-Waha	8.73	—	6,936	—	—	—		3,482
Swap	IF-Waha	7.52	—	—	5,709	—	—		(631	)
Swap	IF-Waha	7.36	—	—	—	3,250	—		(520	)
Swap	IF-Waha	7.18	—	—	—	—	3,250		(615	)
			7,389	6,936	5,709	3,250	3,250
Total Swaps			16,681	15,158	11,394	6,000	6,000
Floor	IF-NGPL MC	6.55	1,000	—	—	—	—		172
Floor	IF-NGPL MC	6.55	—	850	—	—	—		186
			1,000	850	—	—	—
Floor	IF-Waha	6.85	670	—	—	—	—		92
Floor	IF-Waha	6.55	—	565	—	—	—		111
			670	565	—	—	—
Total Floors			1,670	1,415	—	—	—
			18,351	16,573	11,394	6,000	6,000
Total Sales								$	12,583

21

NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	1.44	7,080	—	—	—	—	$	6,282
Swap	OPIS-MB	1.32	—	6,248	—	—	—		11,733
Swap	OPIS-MB	1.27	—	—	4,809	—	—		8,603
Swap	OPIS-MB	0.92	—	—	—	3,400	—		(8,470	)
Swap	OPIS-MB	0.92	—	—	—	—	2,700		(5,515	)
Total Swaps			7,080	6,248	4,809	3,400	2,700
Floor	OPIS-MB	1.44	—	—	—	199	—		978
Floor	OPIS-MB	1.43	—	—	—	—	231		1,247
Total Floors			—	—	—	199	231
Total Sales			7,080	6,248	4,809	3,599	2,931
								$	14,858

Condensate

Instrument Type	Index	Avg. Price $/Bbl	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Condensate Sales
Swap	NY-WTI	70.68	384	—	—	—	—	$	(1,054	)
Swap	NY-WTI	69.00	—	322	—	—	—		(3,823	)
Swap	NY-WTI	68.10	—	—	301	—	—		(3,643	)
Total Swaps			384	322	301	—	—
Floor	NY-WTI	60.50	55	—	—	—	—		1
Floor	NY-WTI	60.00	—	50	—	—	—		24
Total Floors			55	50	—	—	—
Total Sales			439	372	301	—	—
								$	(8,495	)

These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us with protection on the hedged volumes if prices decline below the prices at which these hedges are set. If prices rise above the prices which we have hedged, we will receive less revenue on the hedge volumes than we would in the absence of hedges.

22

Customer Hedges

As of September 30, 2008, 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							(In thousands) Fair Value
			Daily Volume		Average Price			Index
Purchases
Oct 2008 - Dec 2008	Natural gas	Swap	14,630	MMBtu	$	8.07	per MMBtu	NY-HH	$	(788	)
Jan 2009 - Dec 2009	Natural gas	Swap	1,890	MMBtu		9.94	per MMBtu	NY-HH		(1,238	)
Apr 2010 - Jun 2010	Natural gas	Swap	326	MMBtu		8.25	per MMBtu	NY-HH		(3	)
Sales
Oct 2008 - Dec 2008	Natural gas	Fixed price sale	14,630	MMBtu		8.07	per MMBtu	NY-HH		788
Jan 2009 - Dec 2009	Natural gas	Fixed price sale	1,890	MMBtu		9.94	per MMBtu	NY-HH		1,238
Apr 2010 - Jun 2010	Natural gas	Fixed price sale	326	MMBtu		8.25	per MMBtu	NY-HH		3
									$	(0	)

The fair value of derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard option valuation models with assumptions about commodity prices based on those underlying markets.

Interest Rate Swaps

As of September 30, 2008, the Partnership had $390 million outstanding under its senior secured credit facility, with interest accruing at a base rate plus an applicable margin. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates the Partnership entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

Expiration Date	Fixed Rate		Notional Amount		Fair Value
					(In thousands)
January 24, 2011	3.91	%	$	100 million	$	(1,334	)
January 24, 2012	3.75	%		200 million		(389	)
					$	(1,723	)

The Partnership has 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.

Note 11—Commitments and Contingencies

Hurricanes Gustav and Ike

Hurricanes Gustav and Ike affected certain of our Gulf Coast facilities in September 2008. For the three months ended September 30, 2008, we recognized a loss provision of $17.9 million for our estimated out-of-pocket cleanup and repair costs related to Gustav and Ike, after estimated insurance proceeds.

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 (“AICPA”) Statement of Position No. 96-1, “Environmental Remediation Liabilities.” Environmental reserves do not reflect

23

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.

In August 2005, prior to Targa’s acquisition of Versado Gas Processors, L.L.C. (“Versado”), the State of New Mexico’s Environment Department (“NMED”) inspected Versado’s Eunice Gas Processing Plant and its books and records. Targa Midstream Services Limited Partnership (“TMSLP”) is the operator of Versado. In May 2007, the NMED sent Versado a draft compliance order relating to the 2005 inspection, alleging that Versado violated certain emissions standards and permit, monitoring and recordkeeping requirements. After TMSLP provided certain responses and information concerning the alleged violations, the NMED provided a revised draft compliance order and a settlement offer containing a proposed penalty of approximately $2.1 million to resolve the remaining alleged violations. More recently, however, we have discussed with the NMED an expansion of the proposed compliance order to include the resolution of other alleged violations associated with the Eunice, Monument and Saunders plants. We may be required to incur capital expenditures at the Eunice, Monument and Saunders plants, additional facility enhancements and additional operating costs to resolve the alleged violations, the amount of which currently is not reasonably estimable. At this time, we cannot estimate the effect, if any, that this matter will have on our results of operations.

Our environmental liability as of September 30, 2008 was $4.0 million, consisting of $0.4 million for gathering system leaks, $1.5 million for ground water assessment and remediation and $2.1 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 $2.9 million.

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,

24

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 us, three other Targa entities and private equity funds affiliated with Warburg Pincus, seeking damages from the defendants. The suit alleges that we and private equity funds affiliated with Warburg Pincus, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase the SAOU System from ConocoPhillips, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from our competition to purchase the ConocoPhillips’ assets and our successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial was overruled. On January 2, 2008, WTG filed a notice of appeal, and on May 6, 2008 filed its appellant’s brief with the 14^th Court of Appeals in Houston, Texas. Targa and Warburg Pincus filed their appellee’s brief on June 26, 2008. WTG filed a reply brief on August 13, 2008. We are contesting the appeal, but can give no assurances regarding the outcome of the proceeding. We have agreed to indemnify the Partnership for any claim or liability arising out of the WTG suit.

Note 12—Related-Party Transactions

Commodity Hedges

An affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”) is an equity investor in Targa Investments. We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. The following table shows our open commodity derivatives with MLCI as of September 30, 2008:

Period	Commodity	Instrument Type	Daily Volumes		Average Price			Index
Oct 2008 - Dec 2008	Natural gas	Swap	21,918	MMBtu	$	5.47	per MMBtu	IF-Waha
Jan 2009 - Dec 2009	Natural gas	Swap	21,918	MMBtu		7.33	per MMBtu	IF-Waha
Oct 2008 - Dec 2008	NGL	Swap	3,047	Bbl		1.18	per gallon	OPIS-MB
Jan 2009 - Dec 2009	NGL	Swap	2,847	Bbl		1.15	per gallon	OPIS-MB

As of September 30, 2008, the fair value of these open positions was a liability of $24.4 million. For the three and nine months ended September 30, 2008 we paid MLCI $13.4 million and $36.6 million for amounts due under settled commodity derivative transactions. For the three and nine months ended September 30, 2007, we paid MLCI $4.3 million and $5.8 million for amounts due under settled commodity derivative transactions.

The following table shows the Partnership’s open commodity derivatives with MLCI as of September 30, 2008:

Period	Commodity	Instrument Type	Daily Volumes		Average Price			Index
Oct 2008 - Dec 2008	Natural gas	Swap	3,847	MMBtu	$	8.76	per MMBtu	IF-Waha
Jan 2009 - Dec 2009	Natural gas	Swap	3,556	MMBtu		8.07	per MMBtu	IF-Waha
Jan 2010 - Dec 2010	Natural gas	Swap	1,371	MMBtu		7.55	per MMBtu	IF-Waha
Jan 2010 - Dec 2010	Natural gas	Swap	1,209	MMBtu		7.70	per MMBtu	NY-HH
Oct 2008 - Dec 2008	NGL	Swap	3,175	Bbl		1.26	per gallon	OPIS-MB
Jan 2009 - Dec 2009	NGL	Swap	3,000	Bbl		1.18	per gallon	OPIS-MB
Oct 2008 - Dec 2008	Condensate	Swap	264	Bbl		72.66	per barrel	NY-WTI
Jan 2009 - Dec 2009	Condensate	Swap	202	Bbl		70.60	per barrel	NY-WTI
Jan 2010 - Dec 2010	Condensate	Swap	181	Bbl		69.28	per barrel	NY-WTI

As of September 30, 2008, the fair value of these Partnership open positions was a liability of $1.9 million. For the three and nine months ended September 30, 2008, the Partnership paid MLCI $6.6 million and $18.3 million to settle payments due under hedge transactions. For the three and nine months ended September 30, 2007, the Partnership paid MLCI $1.0 million and $2.8 million to settle commodity derivative transactions.

25

Other

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008		2007			2008		2007
	(In thousands)
Included in Revenues
GCF	$	56	$	6,894		$	422	$	10,138
VESCO (1)		—		(3,316	)		666		1,455
MLCI		22,519		23,071			82,868		52,171
	$	22,575	$	26,649		$	83,956	$	63,764
Included in Costs and Expenses
GCF	$	589	$	(1,605	)	$	2,734	$	170
VESCO (1)		51,508		39,171			151,589		104,828
MLCI		988		8,442			3,861		12,082
	$	53,085	$	46,008		$	158,184	$	117,080

(1) Amounts are through July 31, 2008.

Note 13—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.

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 LPG (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 amounts related to general and administrative expenses not allocated to segment operations, corporate development, interest expense, income tax expense, and the depreciation and cost of equipment used in our headquarters office. “Eliminations and Other” also includes the elimination of intersegment revenues and expenses.

26

Our reportable segment information is shown in the following tables.

	Three Months Ended September 30, 2008
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing Services			Wholesale Marketing			Eliminations and Other			Total
	(In thousands)
Revenues	$	497,785	$	25,672		$	1,514,958		$	314,572		$	—		$	2,352,987
Intersegment revenues		473,426		39,853			139,787			5,987			(659,053	)		—
Revenues		971,211		65,525			1,654,745			320,559			(659,053	)		2,352,987
Product purchases		797,661		(67	)		1,179,406			199,830			—			2,176,830
Intersegment product purchases		18,721		67			500,005			126,181			(644,974	)		—
Product purchases		816,382		—			1,679,411			326,011			(644,974	)		2,176,830
Operating expenses		37,256		36,007			304			16			—			73,583
Intersegment operating expenses		199		13,879			—			1			(14,079	)		—
Operating expenses		37,455		49,886			304			17			(14,079	)		73,583
Operating margin	$	117,374	$	15,639		$	(24,970	)	$	(5,469	)	$	—		$	102,574
Equity in earnings of unconsolidated investments	$	1,432	$	1,102		$	—		$	—		$	—		$	2,534
Unconsolidated investments	$	—	$	19,554		$	—		$	—		$	—		$	19,554
Capital expenditures	$	25,042	$	9,239		$	—		$	—		$	1,479		$	35,760
	Three Months Ended September 30, 2007
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing Services			Wholesale Marketing			Eliminations and Other			Total
	(In thousands)
Revenues	$	361,463	$	22,489		$	1,237,911		$	241,773		$	—		$	1,863,636
Intersegment revenues		364,985		29,948			85,884			4,713			(485,530	)		—
Revenues		726,448		52,437			1,323,795			246,486			(485,530	)		1,863,636
Product purchases		588,934		—			914,293			161,476			—			1,664,703
Intersegment product purchases		4		—			393,120			82,759			(475,883	)		—
Product purchases		588,938		—			1,307,413			244,235			(475,883	)		1,664,703
Operating expenses		28,515		30,856			138			17			—			59,526
Intersegment operating expenses		502		9,145			—			—			(9,647	)		—
Operating expenses		29,017		40,001			138			17			(9,647	)		59,526
Operating margin	$	108,493	$	12,436		$	16,244		$	2,234		$	—		$	139,407
Equity in earnings of unconsolidated investments	$	1,568	$	749		$	—		$	—		$	—		$	2,317
Unconsolidated investments	$	27,238	$	19,399		$	—		$	—		$	—		$	46,637
Capital expenditures	$	20,309	$	7,159		$	—		$	—		$	398		$	27,866

27

	Nine Months Ended September 30, 2008
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing Services			Wholesale Marketing		Eliminations and Other			Total
	(In thousands)
Revenues	$	1,480,253	$	74,120		$	4,118,034		$	1,146,199	$	—		$	6,818,606
Intersegment revenues		1,423,663		108,243			457,260			35,033		(2,024,199	)		—
Revenues		2,903,916		182,363			4,575,294			1,181,232		(2,024,199	)		6,818,606
Product purchases		2,426,296		(101	)		3,040,343			734,822		—			6,201,360
Intersegment product purchases		28,690		101			1,518,402			433,426		(1,980,619	)		—
Product purchases		2,454,986		—			4,558,745			1,168,248		(1,980,619	)		6,201,360
Operating expenses		101,599		105,428			1,321			42		—			208,390
Intersegment operating expenses		733		42,847			—			—		(43,580	)		—
Operating expenses		102,332		148,275			1,321			42		(43,580	)		208,390
Operating margin	$	346,598	$	34,088		$	15,228		$	12,942	$	—		$	408,856
Equity in earnings of unconsolidated investments	$	10,161	$	3,028		$	—		$	—	$	—		$	13,189
Unconsolidated investments	$	—	$	19,554		$	—		$	—	$	—		$	19,554
Capital expenditures	$	59,290	$	30,933		$	—		$	—	$	3,701		$	93,924
	Nine Months Ended September 30, 2007
	Natural Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing Services			Wholesale Marketing		Eliminations and Other			Total
	(In thousands)
Revenues	$	1,111,296	$	59,399		$	2,966,002		$	786,719	$	—		$	4,923,416
Intersegment revenues		968,325		85,750			289,690			18,622		(1,362,387	)		—
Revenues		2,079,621		145,149			3,255,692			805,341		(1,362,387	)		4,923,416
Product purchases		1,696,256		—			2,180,287			496,746		—			4,373,289
Intersegment product purchases		12		—			1,040,139			297,596		(1,337,747	)		—
Product purchases		1,696,268		—			3,220,426			794,342		(1,337,747	)		4,373,289
Operating expenses		86,028		92,414			1,374			21		—			179,837
Intersegment operating expenses		642		24,021			(23	)		—		(24,640	)		—
Operating expenses		86,670		116,435			1,351			21		(24,640	)		179,837
Operating margin	$	296,683	$	28,714		$	33,915		$	10,978	$	—		$	370,290
Equity in earnings of unconsolidated investments	$	5,068	$	2,896		$	—		$	—	$	—		$	7,964
Unconsolidated investments	$	27,238	$	19,399		$	—		$	—	$	—		$	46,637
Capital expenditures	$	64,083	$	29,983		$	—		$	—	$	1,580		$	95,646

28

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In thousands)
Operating margin	$	102,574		$	139,407		$	408,856		$	370,290
Adjustments to reconcile operating margin to net income (loss):
Depreciation and amortization		(41,086	)		(37,591	)		(118,028	)		(110,757	)
Gain (loss) on sale of assets		13			(36	)		4,458			95
General and administrative		(26,679	)		(35,831	)		(78,696	)		(78,221	)
Interest expense, net		(24,599	)		(34,749	)		(73,844	)		(112,752	)
Other		(19,210	)		—			(644	)		—
Equity in earnings of unconsolidated investments		2,534			2,317			13,189			7,964
Minority interest/Non-controlling interest		(24,603	)		(10,254	)		(81,957	)		(27,120	)
Income tax (expense) / benefit		10,176			(9,974	)		(29,600	)		(13,170	)
Net income (loss)	$	(20,880	)	$	13,289		$	43,734		$	36,329

Note 14—Allowance for Doubtful Accounts

On July 18, 2008, SemGroup LP (“SemGroup”) filed for bankruptcy protection. We had business relationships with SemGroup in our Natural Gas Gathering and Processing, NGL Distribution and Marketing Services and Logistics Assets segments. As of September 30, 2008, our recognized reserve for all product delivered and subject to the bankruptcy was $7.3 million.

Note 15—Consolidating Financial Statements

We are the issuer of the notes discussed in Note 7 to the financial statements of our Annual Report on Form 10-K for the year ended December 31, 2007. 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.

29

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

SEPTEMBER 30, 2008

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—		$	43,488		$	80,001		$	—		$	123,489
Accounts receivable and other current assets		185			674,919			131,533			—			806,637
Total current assets		185			718,407			211,534			—			930,126
Property, plant, and equipment, at cost		—			765,747			2,312,980			—			3,078,727
Accumulated depreciation		—			101,763			(552,936	)		—			(451,173	)
Property, plant, and equipment, net		—			867,510			1,760,044			—			2,627,554
Unconsolidated investments		—			19,554			—			—			19,554
Investment in subsidiaries		1,209,393			469,130			—			(1,678,523	)		—
Advance to (from) subsidiaries		(34,371	)		(224,949	)		102,897			156,423			—
Other assets		150,080			(95,881	)		39,447			—			93,646
Total assets	$	1,325,287		$	1,753,771		$	2,113,922		$	(1,522,100	)	$	3,670,880
Liabilities and stockholder’s equity
Current liabilities:
Accounts payable and other liabilities	$	20,225		$	504,483		$	228,259		$	—		$	752,967
Current maturities of debt		12,500			—			—			—			12,500
Total current liabilities		32,725			504,483			228,259			—			765,467
Long-term liabilities:
Long-term debt, net of current maturities		762,800			—			640,000			—			1,402,800
Other long-term obligations		29,457			39,895			59,387			—			128,739
Total long-term liabilities		792,257			39,895			699,387			—			1,531,539
Minority interest/Non-controlling interest		—			—			—			873,569			873,569
Stockholder’s equity:
Stockholder’s equity		539,933			1,242,600			1,246,011			(2,488,611	)		539,933
Accumulated other comprehensive income (loss).		(39,628	)		(33,207	)		(59,735	)		92,942			(39,628	)
													��
Total stockholder’s equity		500,305			1,209,393			1,186,276			(2,395,669	)		500,305
Total liabilities and stockholder’s equity	$	1,325,287		$	1,753,771		$	2,113,922		$	(1,522,100	)	$	3,670,880

30

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2007

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—		$	88,303		$	89,646		$	—		$	177,949
Accounts receivable and other current assets		25,130			954,910			104,387			—			1,084,427
Total current assets		25,130			1,043,213			194,033			—			1,262,376
Property, plant, and equipment, at cost		—			743,652			2,020,578			—			2,764,230
Accumulated depreciation		—			94,265			(428,425	)		—			(334,160	)
Property, plant, and equipment, net		—			837,917			1,592,153			—			2,430,070
Unconsolidated investments		—			48,005			—			—			48,005
Investment in subsidiaries		1,087,322			109,411			—			(1,196,733	)		—
Advances to (from) subsidiaries		66,953			(172,735	)		105,782			—			—
Other assets		134,215			(97,599	)		12,898			—			49,514
Total assets	$	1,313,620		$	1,768,212		$	1,904,866		$	(1,196,733	)	$	3,789,965
Liabilities and stockholder’s equity
Current liabilities:
Accounts payable and other liabilities	$	11,043		$	657,736		$	256,894		$	—		$	925,673
Current maturities of debt		12,500			—			—			—			12,500
Total current liabilities		23,543			657,736			256,894			—			938,173
Long-term liabilities:
Long-term debt, net of current maturities		772,175			—			626,300			—			1,398,475
Other long-term obligations		25,498			100,516			19,773			—			145,787
Total long-term liabilities		797,673			100,516			646,073			—			1,544,262
Minority interest/Non-controlling interest		—			—			—			815,126			815,126
Stockholder’s equity:
Stockholder’s equity		548,520			1,082,065			1,075,149			(2,157,214	)		548,520
Accumulated other comprehensive income (loss)		(56,116	)		(72,105	)		(73,250	)		145,355			(56,116	)
Total stockholder’s equity		492,404			1,009,960			1,001,899			(2,011,859	)		492,404
Total liabilities and stockholder’s equity	$	1,313,620		$	1,768,212		$	1,904,866		$	(1,196,733	)	$	3,789,965

31

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2008

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	—		$	2,090,748		$	802,080		$	(539,841	)	$	2,352,987
Operating costs and expenses:
Product purchases		—			2,049,237			650,691			(523,098	)		2,176,830
Operating expenses		—			37,146			53,180			(16,743	)		73,583
Depreciation and amortization		—			13,082			28,004			—			41,086
General and administrative and other		41			38,717			5,807			—			44,565
		41			2,138,182			737,682			(539,841	)		2,336,064
Income from operations		(41	)		(47,434	)		64,398			—			16,923
Other income (expense):
Interest expense, net		(13,963	)		—			(10,636	)		—			(24,599	)
Equity in earnings of unconsolidated investments		—			2,534			—			—			2,534
Equity in earnings of subsidiaries		(17,158	)		28,062			—			(10,904	)		—
Minority interest/Non-controlling interest		—			—			—			(24,603	)		(24,603	)
Other income		—			(320	)		(991	)		—			(1,311	)
Income before income tax		(31,162	)		(17,158	)		52,771			(35,507	)		(31,056	)
Income tax (expense) benefit		10,282			—			(400	)		294			10,176
Net income (loss)	$	(20,880	)	$	(17,158	)	$	52,371		$	(35,213	)	$	(20,880	)

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2007

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	—		$	1,134,462		$	555,262		$	173,912		$	1,863,636
Operating costs and expenses:
Product purchases		—			1,043,950			434,426			186,327			1,664,703
Operating expenses		—			34,335			37,606			(12,415	)		59,526
Depreciation and amortization		—			12,715			24,876			—			37,591
General and administrative and other		29			27,584			8,254			—			35,867
		29			1,118,584			505,162			173,912			1,797,687
Income (loss) from operations		(29	)		15,878			50,100			—			65,949
Other income (expense):
Interest income, net		54,159			(74,881	)		(14,027	)		—			(34,749	)
Equity in earnings of unconsolidated investments		—			2,317			—			—			2,317
Equity in earnings of subsidiaries		(30,995	)		(2,724	)		—			33,719			—
Minority interest/Non-controlling interest		—			—			—			(10,254	)		(10,254	)
Other		—			28,352			(28,352	)		—			—
Income before income taxes		23,135			(31,058	)		7,721			68,412			23,263
Income tax (expense) benefit		(9,846	)		63			(395	)		204			(9,974	)
Net income (loss)	$	13,289		$	(30,995	)	$	7,326		$	68,616		$	13,289

32

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2008

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	—		$	6,147,911		$	2,340,255		$	(1,669,560	)	$	6,818,606
Operating costs and expenses:
Product purchases		—			5,917,510			1,903,677			(1,619,827	)		6,201,360
Operating expenses		—			111,371			146,752			(49,733	)		208,390
Depreciation and amortization		—			38,444			79,584			—			118,028
General and administrative and other		128			74,683			17,326			—			92,137
		128			6,142,008			2,147,339			(1,669,560	)		6,619,915
Income (loss) from operations		(128	)		5,903			192,916			—			198,691
Other income (expense):
Interest expense, net		(46,917	)		—			(26,927	)		—			(73,844	)
Equity in earnings of unconsolidated investments		—			13,189			—			—			13,189
Equity in earnings of subsidiaries		101,522			82,750			—			(184,272	)		—
Minority interest/Non-controlling interest		—			—			—			(81,957	)		(81,957	)
Other income		18,566			(320	)		(991	)		—			17,255
Income before income tax		73,043			101,522			164,998			(266,229	)		73,334
Income tax (expense) benefit		(29,309	)		—			(1,100	)		809			(29,600	)
Net income (loss)	$	43,734		$	101,522		$	163,898		$	(265,420	)	$	43,734
TARGA RESOURCES, INC.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2007
(Unaudited)
(In thousands)
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	—		$	3,901,134		$	1,611,257		$	(588,975	)	$	4,923,416
Operating costs and expenses:
Product purchases		—			3,652,035			1,278,360			(557,106	)		4,373,289
Operating expenses		—			100,921			110,785			(31,869	)		179,837
Depreciation and amortization		—			36,740			74,017			—			110,757
General and administrative and other		61			61,999			16,066			—			78,126
		61			3,851,695			1,479,228			(588,975	)		4,742,009
Income (loss) from operations		(61	)		49,439			132,029			—			181,407
Other income (expense):
Interest income, net		(6,709	)		(74,881	)		(31,162	)		—			(112,752	)
Equity in earnings of unconsolidated investments		—			7,964			—			—			7,964
Equity in earnings of subsidiaries		55,884			44,947			—			(100,831	)		—
Minority interest/Non-controlling interest		—			—			—			(27,120	)		(27,120	)
Other		—			28,352			(28,352	)		—			—
Income before income taxes		49,114			55,821			72,515			(127,951	)		49,499
Income tax (expense) benefit		(12,785	)		63			(1,060	)		612			(13,170	)
Net income (loss)	$	36,329		$	55,884		$	71,455		$	(127,339	)	$	36,329

33

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2008

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	43,734		$	101,522		$	163,898		$	(265,420	)	$	43,734
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion		4,730			38,996			81,716			—			125,442
Deferred income taxes		29,125			—			1,100			(809	)		29,416
Earnings (loss) from unconsolidated investments		—			(13,189	)		—			—			(13,189	)
Equity in earnings of subsidiaries		(101,522	)		(82,750	)		—			184,272			—
Other		(18,078	)		2,467			(150,693	)		81,957			(84,347	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		12,745			211,802			44,034			—			268,581
Inventory		—			22,855			(443	)		—			22,412
Accounts payable and other liabilities		27,114			(219,644	)		(12,017	)		—			(204,547	)
Net cash provided by (used in) operating activities		(2,152	)		62,059			127,595			—			187,502
Cash flows from investing activities
Purchases of property and equipment		—			(40,503	)		(49,068	)		—			(89,571	)
Other		(16,474	)		(80,789	)		523			—			(96,740	)
Net cash used in investing activities		(16,474	)		(121,292	)		(48,545	)		—			(186,311	)
Cash flows from financing activities
Repayments under senior secured credit facility		—			—			(323,800	)		—			(323,800	)
Other		(9,409	)		—			330,332			—			320,923
Receipts from (payments to) subsidiaries		28,035			14,418			(95,227	)		—			(52,774	)
Net cash provided by (used in) financing activities		18,626			14,418			(88,695	)		—			(55,651	)
Net increase (decrease) in cash and cash equivalents		—			(44,815	)		(9,645	)		—			(54,460	)
Cash and cash equivalents, beginning of period		—			88,303			89,646			—			177,949
Cash and cash equivalents, end of period	$	—		$	43,488		$	80,001		$	—		$	123,489

34

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30, 2007

(Unaudited)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	36,329		$	10,937		$	71,455		$	(82,392	)	$	36,329
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion		10,338			36,245			75,760			—			122,343
Deferred income taxes		11.496			(63	)		1,060			(612	)		11,881
Earnings (loss) from unconsolidated investments		—			(7,964	)		—			—			(7,964	)
Equity in earnings (losses) of subsidiaries		(55,884	)		—			—			55,884			—
Other		(12,405	)		(25,059	)		3,077			27,120			(7,267	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		(250,692	)		113,763			7,081			—			(129,848	)
Inventory		—			(27,266	)		(373	)		—			(27,639	)
Accounts payable and other liabilities		(32,162	)		147,663			23,488			—			138,989
Net cash provided by (used in) operating activities		(292,980	)		248,256			181,548			—			136,824
Cash flows from investing activities
Purchases of property and equipment		—			(45,324	)		(53,442	)		—			(97,766	)
Other		—			15,191			316			—			15,507
Net cash used in investing activities		—			(30,133	)		(52,124	)		—			(82,259	)
Cash flows from financing activities
Repayments under senior secured credit facility		(709,375	)		—			(48,000	)		—			(757,375	)
Other		(167	)		420			712,226			—			712,479
Receipts from (payments to) subsidiaries		1,002,522			(253,102	)		(749,420	)		—			—
Net cash provided by (used in) financing activities		292,980			(252,682	)		(85,194	)		—			(44,896	)
Net increase (decrease) in cash and cash equivalents		—			(34,559	)		44,228			—			9,669
Cash and cash equivalents, beginning of period		—			117,661			25,078			—			142,739
Cash and cash equivalents, end of period	$	—		$	83,102		$	69,306		$	—		$	152,408

35

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 on Form 10-Q and in our consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2007.

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.

Critical Accounting Policies and Estimates

There have been no significant changes to our critical accounting policies and estimates since December 31, 2007. For a more complete description of our critical accounting polices and estimates, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Recent Accounting Pronouncements

On January 1, 2008, we adopted the provisions of SFAS 157. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report for information regarding fair value disclosures pertaining to our financial assets and liabilities.

The accounting standard-setting bodies have recently issued the following accounting guideline may affect our future financial statements:

• SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.”

For additional information regarding this recent accounting development and others that may affect our future financial statements, see Note 2 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

36

Results of Operations

The following table and discussion relate to the three and nine months ended September 30, 2008 and 2007 and is a summary of our results of operations for the periods then ended:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions, except operating and price data)
Revenues (1)	$	2,353.0		$	1,863.6		$	6,818.6		$	4,923.4
Product purchases		2,176.8			1,664.7			6,201.4			4,373.3
Operating expenses		73.6			59.5			208.4			179.8
Depreciation and amortization expense		41.1			37.6			118.0			110.8
General and administrative expense		26.7			35.8			78.7			78.2
Casualty loss		17.9			—			17.9			—
Gain on sales of assets		—			—			(4.5	)		(0.1	)
Income from operations		16.9			66.0			198.7			181.4
Interest expense, net		(24.6	)		(34.7	)		(73.8	)		(112.8	)
Other		(1.3	)		—			17.3			—
Equity in earnings of unconsolidated investments (2)		2.5			2.3			13.2			8.0
Minority interest / non-controlling interest		(24.6	)		(10.3	)		(82.1	)		(27.1	)
Income tax (expense) benefit		10.2			(10.0	)		(29.6	)		(13.2	)
Net income (loss)	$	(20.9	)	$	13.3		$	43.7		$	36.3
Financial data:
Operating margin (3)	$	102.6		$	139.4		$	408.8		$	370.3
Adjusted EBITDA (4)		46.4			92.1			275.7			259.3
Operating data:
Gathering throughput MMcf/d (5)		1,859.2			2,002.8			2,043.4			1,992.9
Plant natural gas inlet, MMcf/d (6) (7)		1,817.3			1,956.4			1,994.9			1,949.7
Gross NGL production, MBbl/d		100.8			107.1			103.2			105.7
Natural gas sales, BBtu/d (7)		515.3			538.0			524.9			526.6
NGL sales, MBbl/d		290.1			330.3			297.8			309.3
Condensate sales, MBbl/d		3.9			4.4			3.8			3.9
Average realized prices:
Natural Gas, $/MMBtu
Average realized sales price		9.30			5.78			9.11			6.41
Impact of hedging		(0.12	)		0.20			(0.04	)		0.16
Average realized price		9.18			5.98			9.07			6.57
NGL, $/gal
Average realized sales price		1.67			1.19			1.57			1.08
Impact of hedging		(0.03	)		(0.01	)		(0.02	)		—
Average realized price		1.64			1.18			1.55			1.08
Condensate, $/Bbl
Average realized sales price		113.05			72.96			109.35			64.10
Impact of hedging		(4.75	)		(0.25	)		(3.93	)		0.73
Average realized price		108.30			72.71			105.42			64.83

(1) Includes business interruption insurance revenue of $0 and $17.5 million for the three and nine months ended September 30, 2008 and $1.8 million and $7.3 million for the three and nine months ended September 30, 2007.

37

(2) Includes business interruption insurance revenue of $0 and $4.1 million for the three and nine months ended September 30, 2008 and $0 and $3.1 million for the three and nine months ended September 30, 2007.

(3) Operating margin is revenues less product purchases and operating expense. See “—Non-GAAP Financial Measures.”

(4) 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.”

(5) 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.

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

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

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Our net loss for the three months ended September 30, 2008 was $20.9 million, compared to net income of $13.3 million for the three months ended September 30, 2007. The decrease in net income is primarily from a $31.6 million pre-tax charge to reduce the carrying value of our NGL inventory to its net realizable value and a $17.9 million pre-tax loss reserve for damage to certain of our Gulf Coast facilities caused by Hurricanes Gustav and Ike. Other items affecting comparability of our results are more fully described below.

Revenues increased by $489.4 million, or 26%, to $2,353.0 million for the three months ended September 30, 2008 compared to $1,863.6 million for the three months ended September 30, 2007. Revenues from the sale of natural gas increased by $139.1 million, consisting of an increase of $151.6 million due to higher realized prices, partially offset by a decrease of $12.5 million due to lower sales volumes. Revenues from the sale of NGLs increased by $336.1 million, consisting of an increase of $519.6 million due to higher realized prices, partially offset by a decrease of $183.5 million due to lower sales volumes. Revenues from the sale of condensate increased by $9.5 million, consisting of an increase of $12.7 million due to higher realized prices, partially offset by a decrease of $3.2 million due to lower sales volumes. Other revenues, which includes revenues principally derived from fee-based services, increased by $4.7 million. The increase comprised $6.5 million in higher revenues from fee-based services, offset by a $1.8 million decrease in business interruption insurance revenue.

Our average realized prices for natural gas increased by $3.20 per MMBtu (net of a $0.32 decrease due to hedging), or 54%, to $9.18 per MMBtu for the three months ended September 30, 2008 compared to $5.98 per MMBtu for the three months ended September 30, 2007. Average realized prices for NGLs increased by $0.46 per gallon (net of a $0.02 decrease due to hedging), or 39%, to $1.64 per gallon for the three months ended September 30, 2008 compared to $1.18 per gallon for the three months ended September 30, 2007. Our average realized price for condensate increased by $35.59 per Bbl (net of a $4.50 decrease due to hedging), or 49%, to $108.30 per Bbl for the three months ended September 30, 2008 compared to $72.71 per Bbl for the three months ended September 30, 2007.

Our natural gas sales volumes decreased by 22.7 BBtu/d, or 4%, to 515.3 BBtu/d for the three months ended September 30, 2008 compared to 538.0 BBtu/d for the three months ended September 30, 2007. NGL sales volumes decreased by 40.2 MBbl/d, or 12%, to 290.1 MBbl/d for the three months ended September 30, 2008 compared to 330.3 MBbl/d for the three months ended September 30, 2007. Condensate sales volumes decreased by 0.5 MBbl/d, or 11%, to 3.9 MBbl/d for the three months ended September 30, 2008 compared to 4.4 MBbl/d for the three months ended September 30, 2007. For information regarding the period to period changes in our commodity sales volumes, see “—Results of Operations—By Segment.”

Our product purchases increased by $512.1 million, or 31%, to $2,176.8 million for the three months ended September 30, 2008 compared to $1,664.7 million for the three months ended September 30, 2007. See “—Results of Operations—By Segment” for an explanation of the components of the increase.

38

Our operating expenses increased by $14.1 million, or 24%, to $73.6 million for the three months ended September 30, 2008 compared to $59.5 million for the three months ended September 30, 2007. See “—Results of Operations—By Segment” for a detailed explanation of the components of the increase.

Depreciation and amortization expense increased by $3.5 million, or 9%, to $41.1 million for the three months ended September 30, 2008 compared to $37.6 million for the three months ended September 30, 2007. The increase is due to the addition of property, plant and equipment.

General and administrative expense decreased by $9.1 million, or 25%, to $26.7 million for the three months ended September 30, 2008 compared to $35.8 million for the three months ended September 30, 2007. The decrease primarily consisted of a $10.5 million decrease in compensation related expenses partially offset by increases of $0.5 million in IT software/license expenses, $0.2 million in insurance and $0.7 million in miscellaneous expenses.

Interest expense decreased by $10.1 million, or 29%, to $24.6 million for the three months ended September 30, 2008 compared to $34.7 million for the three months ended September 30, 2007. The decrease is primarily from lower outstanding debt during 2008.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Our net income was $43.7 million for the nine months ended September 30, 2008 compared to net income of $36.3 million for the nine months ended September 30, 2007. Net income for the first nine months of 2008 was negatively impacted by a $31.6 million pre-tax charge to reduce the carrying value of our NGL inventory to its net realizable value and a $17.9 million pre-tax loss reserve for damage to certain of our Gulf Coast facilities caused by Hurricanes Gustav and Ike. Other items affecting comparability of our results are more fully described below.

Revenues increased by $1,895.2 million, or 38%, to $6,818.6 million for the nine months ended September 30, 2008 compared to $4,923.4 million for the nine months ended September 30, 2007. Revenues from the sale of natural gas increased by $359.3 million, consisting of a $358.8 million increase due to higher realized prices and an increase of $0.5 million due to higher sales volumes. Revenues from the sale of NGLs increased by $1,463.7 million, consisting of an increase of $1,592.6 million due to higher realized prices, partially offset by a decrease of $128.9 million due to lower sales volumes. Revenues from the sale of condensate increased by $39.0 million, consisting of an increase of $41.8 million due to higher realized prices, partially offset by a decrease of $2.8 million due to lower sales volumes. Other revenues, which includes business interruption insurance revenue and revenues principally derived from fee-based services, increased by $33.2 million. The increase comprised $21.9 million in higher revenues from fee-based services and $11.3 million in higher business interruption insurance revenue.

Our average realized price for natural gas increased by $2.50 per MMBtu (net of a $0.20 decrease due to hedging), or 38%, to $9.07 per MMBtu for the nine months ended September 30, 2008 compared to $6.57 per MMBtu for the nine months ended September 30, 2007. Our average realized price for NGLs increased by $0.47 per gallon (net of a $0.02 decrease due to hedging), or 44%, to $1.55 per gallon for the nine months ended September 30, 2008 compared to $1.08 per gallon for the nine months ended September 30, 2007. Our average realized price for condensate increased by $40.59 per barrel (net of a $4.66 decrease due to hedging), or 63%, to $105.42 per Bbl for the nine months ended September 30, 2008 compared to $64.83 per Bbl for the nine months ended September 30, 2007.

Our natural gas sales volumes decreased by 1.7 BBtu/d, or less than one percent, to 524.9 BBtu/d for the nine months ended September 30, 2008 compared to 526.6 BBtu/d for the nine months ended September 30, 2007. Our NGL sales volumes decreased by 11.5 MBbl/d, or 4%, to 297.8 MBbl/d for the nine months ended September 30, 2008 compared to 309.3 MBbl/d for the nine months ended September 30, 2007. Our condensate

39

sales volumes decreased by 0.1 MBbl/d, or 3%, to 3.8 MBbl/d for the nine months ended September 30, 2008 compared to 3.9 MBbl/d for the nine months ended September 30, 2007. For information regarding the period to period changes in our commodity sales volumes, see “—Results of Operations—By Segment.”

Our product purchases increased by $1,828.1 million, or 42%, to $6,201.4 million for the nine months ended September 30, 2008 compared to $4,373.3 million for the nine months ended September 30, 2007. The increase is primarily due to higher product purchases and prices in the Natural Gas Gathering and Processing, NGL Distribution and Marketing, and Wholesale Marketing segments.

Our operating expenses increased by $28.6 million, or 16%, to $208.4 million for the nine months ended September 30, 2008 compared to $179.8 million for the nine months ended September 30, 2007. See “—Results of Operations—By Segment” for a more detailed explanation of the components of the increase.

Depreciation and amortization expense increased by $7.2 million, or 6%, to $118.0 million for the nine months ended September 30, 2008 compared to $110.8 million for the nine months ended September 30, 2007. The increase is due to the addition of property, plant and equipment.

General and administrative expense increased by $0.5 million, or less than 1%, to $78.7 million for the nine months ended September 30, 2008 compared to $78.2 million for the nine months ended September 30, 2007.

Interest expense decreased by $39.0 million, or 35%, to $73.8 million for the nine months ended September 30, 2008 compared to $112.8 million for the nine months ended September 30, 2007. The decrease is primarily from lower outstanding debt during 2008.

40

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 presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions, except operating and price data)
Operating statistics: (1)
Gathering throughput, MMcf/d		1,859.3			2,002.8			2,043.4			1,992.9
Plant natural gas inlet, MMcf/d		1,817.3			1,956.4			1,994.9			1,949.7
Gross NGL production, MBbl/d		100.8			107.1			103.2			105.7
Natural gas sales, BBtu/d		532.7			558.5			543.0			544.3
NGL sales, MBbl/d		84.7			91.7			88.6			90.6
Condensate sales, MBbl/d		4.8			5.5			5.0			5.2
Natural gas, $/MMBtu
Average realized sales price		9.33			5.79			9.13			6.42
Impact of hedging		(0.11	)		0.19			(0.04	)		0.15
Average realized price		9.22			5.98			9.09			6.57
NGLs, $/gal
Average realized sales price		1.51			1.08			1.44			0.97
Impact of hedging		(0.09	)		(0.02	)		(0.07	)		(0.01	)
Average realized price		1.42			1.06			1.37			0.96
Condensate, $/Bbl
Average realized sales price		107.11			69.53			99.54			60.51
Impact of hedging		(3.83	)		(0.20	)		(2.93	)		0.55
Average realized price		103.28			69.33			96.61			61.06
Revenues (2)	$	971.2		$	726.4		$	2,904.0		$	2,079.6
Product purchases		(816.4	)		(588.9	)		(2,455.0	)		(1,696.2	)
Operating expenses		(37.5	)		(29.0	)		(102.3	)		(86.7	)
Operating margin (3)	$	117.3		$	108.5		$	346.7		$	296.7
Equity in earnings of VESCO (4) (5)	$	1.4		$	1.6		$	10.2		$	5.1

(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 $0 and $2.5 million for the three and nine months ended September 30, 2008 and $1.8 million and $2.6 million for the three and nine months ended September 30, 2007.

(3) See “—Non-GAAP Financial Measures.”

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

(5) Includes business interruption insurance revenue of $0 and $4.1 million for the three and nine months ended September 30, 2008 and $0 and $3.1 million for the three and nine months ended September 30, 2007.

41

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Revenues increased by $244.8 million, or 34%, to $971.2 million for the three months ended September 30, 2008 compared to $726.4 million for the three months ended September 30, 2007. The increase was primarily due to higher natural gas and NGL prices, partially offset by lower sales volumes. The lower sales volumes were primarily the result of Gulf Coast natural gas processing plant shutdowns after Hurricanes Gustav and Ike in September 2008.

Our average realized price for natural gas increased by $3.24 per MMBtu (net of a $0.30 decrease due to hedging), or 54%, to $9.22 per MMBtu for the three months ended September 30, 2008 compared to $5.98 per MMBtu for the three months ended September 30, 2007. Our average realized price for NGLs increased by $0.36 per gallon (net of a $0.07 decrease due to hedging), or 34%, to $1.42 per gallon for the three months ended September 30, 2008 compared to $1.06 per gallon for the three months ended September 30, 2007. Our average realized price for condensate increased by $33.95 per Bbl (net of a $3.63 decrease due to hedging), or 49%, to $103.28 per Bbl for the three months ended September 30, 2008 compared to $69.33 per barrel for the three months ended September 30, 2007.

Our natural gas sales volumes decreased by 25.8 BBtu/d, or 5%, to 532.7 BBtu/d for the three months ended September 30, 2008 compared to 558.5 BBtu/d for the three months ended September 30, 2007. Our NGL sales volumes decreased by 7.0 MBbl/d, or 8%, to 84.7 MBbl/d for the three months ended September 30, 2008 compared to 91.7 MBbl/d for the three months ended September 30, 2007. Our condensate sales volumes decreased by 0.7 MBbl/d, or 13%, to 4.8 MBbl/d for the three months ended September 30, 2008 compared to 5.5 MBbl/d for the three months ended September 30, 2007.

Our product purchases increased by $227.5 million, or 39%, to $816.4 million for the three months ended September 30, 2008 compared to $588.9 million for the three months ended September 30, 2007. The increase was due primarily to the above-mentioned higher commodity prices and higher spot price purchases for industrial customers.

Our operating expenses increased $8.5 million, or 29%, to $37.5 million for the three months ended September 30, 2008 compared to $29.0 million for the three months ended September 30, 2007. The increase was primarily due to higher compensation expenses, increased general maintenance expenses, and higher costs for chemicals, lube oil and utilities.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Revenues increased by $824.4 million, or 40%, to $2,904.0 million for the nine months ended September 30, 2008 compared to $2,079.6 million for the nine months ended September 30, 2007. The increase was primarily due to higher natural gas and NGL prices, partially offset by lower sales volumes. The lower sales volumes were primarily the result of Gulf Coast natural gas processing plant shutdowns after Hurricanes Gustav and Ike in September 2008.

Our average realized price for natural gas increased by $2.52 per MMBtu (net of a $0.19 decrease due to hedging), or 38%, to $9.09 per MMBtu for the nine months ended September 30, 2008 compared to $6.57 per MMBtu for the nine months ended September 30, 2007. Our average realized price for NGLs increased by $0.41 per gallon (net of a $0.06 decrease due to hedging), or 43%, to $1.37 per gallon for the nine months ended September 30, 2008 compared to $0.96 per gallon for the nine months ended September 30, 2007. Our average realized price for condensate increased by $35.55 per Bbl (net of a $3.48 decrease due to hedging), or 58%, to $96.61 per Bbl for the nine months ended September 30, 2008 compared to $61.06 per barrel for the nine months ended September 30, 2007.

Our natural gas sales volumes decreased by 1.3 BBtu/d, or less than 1%, to 543.0 BBtu/d for the nine months ended September 30, 2008 compared to 544.3 BBtu/d for the nine months ended September 30, 2007. Our NGL sales volumes decreased by 2.0 MBbl/d, or 2%, to 88.6 MBbl/d for the nine months ended

42

September 30, 2008 compared to 90.6 MBbl/d for the nine months ended September 30, 2007. Our condensate sales volumes decreased by 0.2 MBbl/d, or 4%, to 5.0 MBbl/d for the nine months ended September 30, 2008 compared to 5.2 MBbl/d for the nine months ended September 30, 2007.

Our product purchases increased by $758.8 million, or 45%, to $2,455.0 million for the nine months ended September 30, 2008 compared to $1,696.2 million for the nine months ended September 30, 2007. The increase in product purchases for the nine months ended September 30, 2008 was due primarily to higher commodity prices mentioned above and higher spot price purchases by our industrial customers.

Our operating expenses increased by $15.6 million, or 18%, to $102.3 million for the nine months ended September 30, 2008 compared to $86.7 million for the nine months ended September 30, 2007. The increase was primarily due to higher compensation expenses and increased costs for general maintenance expenses, and higher costs for chemicals, lube oil and utilities.

Logistics Assets Segment

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions, except operating and price data)
Fractionation volumes, MBbl/d		207.1			232.0			219.3			207.3
Treating volumes, MBbl/d (1)		20.4			16.8			19.0			6.5
Revenues from services	$	65.5		$	51.8		$	181.8		$	143.6
Other revenues (2)		(0.1	)		0.6			0.5			1.5
		65.4			52.4			182.3			145.1
Operating expenses		(49.8	)		(40.0	)		(148.2	)		(116.4	)
Operating margin (3)	$	15.6		$	12.4		$	34.1		$	28.7
Equity in earnings of GCF	$	1.1		$	0.7		$	3.0		$	2.9

(1) Consists of the volumes treated in our low sulfur natural gasoline unit, which began commercial operations in June 2007.

(2) Includes business interruption insurance revenue of $0.4 million for the nine months ended September 30, 2008. No business interruption insurance revenues were recorded in the three months ended September 30, 2008 or 2007.

(3) See “—Non-GAAP Financial Measures.”

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Revenues from services (fractionation, terminalling and storage, transportation and treating) increased by $13.7 million, or 26%, to $65.5 million for the three months ended September 30, 2008 compared to $51.8 million for the three months ended September 30, 2007. The increase was primarily from:

• higher fractionation fees due to higher natural gas prices and a higher fixed portion of certain fees, partially offset by lower fractionation volumes due to Hurricanes Gustav and Ike;

• an increase in commercial transportation revenues due to increased barge activity as well as increased trucking activity as a result of pipeline allocations; and

• an increase in terminalling revenue due to increased access to raw NGL volumes as a result of a new connection into a common carrier pipeline.

43

Operating expenses increased by $9.8 million, or 25%, to $49.8 million for the three months ended September 30, 2008 compared to $40.0 million for the three months ended September 30, 2007. The increase was primarily due to:

• increased fuel and electricity expense due to higher natural gas prices;

• increased barge and truck operating expenses; and

• increased usage of third-party fractionation facilities.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Revenues from services (fractionation, terminalling and storage, transportation and treating) increased by $38.2 million, or 27%, to $181.8 million for the nine months ended September 30, 2008 compared to $143.6 million for the nine months ended September 30, 2007. The increase was primarily from:

• higher fractionation fees due to higher natural gas prices and a higher fixed portion of certain fees; and higher fractionation volumes;

• Nine months of operations at our low sulfur natural gasoline (“LSNG”) plant, which commenced commercial operations in June 2007;

• increased barge and trucking activity as a result of pipeline allocations; partially offset by

• lower barge activity at our Galena Park marine terminal.

Operating expenses increased by $31.8 million, or 27%, to $148.2 million for the nine months ended September 30, 2008 compared to $116.4 million for the nine months ended September 30, 2007. The increase was primarily due to:

• increased fuel and electricity expense due to higher natural gas prices and higher volumes;

• an increase in operating expenses at our LSNG plant which commenced commercial operations in June 2007;

• higher barge and truck activity;

• higher maintenance costs due to the Cedar Bayou Fractionator (“CBF”) turnaround, CBF boiler rentals and maintenance at the Mt. Belvieu Terminal; and

• increased usage of third-party fractionation facilities.

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 presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions, except operating and price data)
NGL sales, MBbl/d		258.1			291.1			257.6			267.1
NGL realized price, $/gal		1.66			1.18			1.54			1.06
NGL sales revenues	$	1,654.0		$	1,323.7		$	4,564.4		$	3,250.3
Other revenues (1)		0.8			0.1			10.9			5.5
		1,654.8			1,323.8			4,575.3			3,255.8
Product purchases		(1,679.4	)		(1,307.5	)		(4,558.8	)		(3,220.5	)
Operating expenses		(0.3	)		(0.1	)		(1.5	)		(1.4	)
Operating margin (2)	$	(24.9	)	$	16.2		$	15.0		$	33.9

(1) Includes business interruption insurance revenue of $8.6 million and $3.8 million for the nine months ended September 30, 2008 and 2007. No business interruption insurance revenues were recorded in the three months ended September 30, 2008 or 2007.

(2) See “—Non-GAAP Financial Measures.”

44

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

Our NGL sales revenues increased by $330.3 million, or 25%, to $1,654.0 million for the three months ended September 30, 2008 compared to $1,323.7 million for the three months ended September 30, 2007. The net increase comprised a $480.4 million increase from higher average sales prices, up 41% to $1.66 from $1.18 during the three months ended September 30, 2007; and a $150.1 million decrease from lower sales volumes, down 11% to 258.1 MBbl/d from 291.1 MBbl/d. The decrease in sales volumes was primarily attributable to Hurricanes Ike and Gustav, which disrupted offshore gas production, reduced deliveries due to power outages and other pipeline disruptions, disrupted Gulf Coast gas processing operations and impacted Gulf Coast petrochemical and refinery markets.

Other revenues, which consists primarily of non-commodity based service revenue, increased by $0.7 million.

Product purchases increased by $371.9 million, or 28%, to $1,679.4 million for the three months ended September 30, 2008 compared to $1,307.5 million for the three months ended September 30, 2007. The net increase consisted of a $520.2 million increase from higher commodity prices, inclusive of a $24.1 million charge to reduce the carrying value of our NGL inventory to its realizable value, partially offset by a $148.3 million decrease from lower purchased volumes.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Our NGL sales revenues increased by $1,314.1 million, or 40%, to $4,564.4 million for the nine months ended September 30, 2008 compared to $3,250.3 million for the nine months ended September 30, 2007. The net increase comprised a $1,418.7 million increase from higher average sales prices, up 45% to $1.54 from $1.06; and a $104.6 million decrease from lower sales volumes, down 4% to 257.6 MBbls/d from 267.1 MBbls/d. The most significant decrease in sales volumes occurred in September 2008 and is primarily attributable to the impact from Hurricanes Ike and Gustav, which disrupted offshore gas production, reduced deliveries due to power outages and other pipeline disruptions, disrupted Gulf Coast gas processing operations and impacted Gulf Coast petrochemical and refinery markets.

Other revenues, which consists primarily of business interruption insurance revenue, decreased by $5.4 million.

Product purchases increased by $1,338.3 million, or 42%, to $4,558.8 million for the nine months ended September 30, 2008 compared to $3,220.5 million for the nine months ended September 30, 2007. The net increase comprised a $1,441.9 million increase from higher commodity prices, inclusive of $25.8 million in charges to reduce the carrying value of our NGL inventory to its realizable value, partially offset by a $103.6 million decrease from lower purchased volumes.

45

Wholesale Marketing Segment

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In millions, except operating and price data)
NGL sales, MBbl/d		47.0			49.8			60.1			59.1
NGL realized price, $/gal		1.77			1.28			1.70			1.19
NGL sales revenues	$	320.6		$	246.4		$	1,175.3		$	804.1
Other revenues (1)		—			0.1			5.9			1.2
		320.6			246.5			1,181.2			805.3
Product purchases		(326.0	)		(244.2	)		(1,168.2	)		(794.3	)
Operating expenses		—			—			—			—
Operating margin (2)	$	(5.4	)	$	2.3		$	13.0		$	11.0

(1) Includes business interruption insurance revenue of $5.9 million and $0.8 million for the nine months ended September 30, 2008 and 2007. No business interruption insurance revenues were recorded in the three months ended September 30, 2008 or 2007.

(2) See “—Non-GAAP Financial Measures.”

Three Months Ended September 30, 2008 Compared to Three Months Ended September 30, 2007

NGL sales revenues increased by $74.2 million, or 30%, to $320.6 million for the three months ended September 30, 2008 compared to $246.4 million for the three months ended September 30, 2007. Higher NGL market prices increased revenue $88.0 million, partially offset by lower sales volumes which reduced revenue by $13.8 million. The increase in average realized prices is due to higher overall market prices for all components, particularly higher propane prices which were up $0.49 per gallon, and a lighter component mix due primarily to the termination of a refinery supply agreement.

Other revenues, which consisted primarily of a one-time transportation rebate, decreased by $0.1 million.

Product purchases increased by $81.8 million, or 33%, to $326.0 million for the three months ended September 30, 2008 compared to $244.2 million for the three months ended September 30, 2007. Higher NGL market prices increased costs by $87.7 million, partially offset by the effect of lower sales volumes, which reduced product purchases by $13.6 million. In addition, we had a 2008 charge of $7.5 million to reduce the carrying value of our NGL inventory to its realizable value.

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

NGL sales revenues increased by $371.2 million, or 46%, to $1,175.3 million for the nine months ended September 30, 2008 compared to $804.1 million for the nine months ended September 30, 2007. Higher NGL market prices increased revenues by $354.6 million, and higher sales volumes increased revenues by $16.6 million. The increase in average realized prices is due to higher overall market prices for all components, particularly higher propane prices, which were up $0.51 per gallon. The increased volume is primarily due to increased refinery production in the Western Region, along with new refinery supplies in the Northeast, partially offset by reduced refinery supply volume due to the expiration of a refinery supply agreement and a disruption at a customer’s facility.

Other revenues, consisting primarily of business interruption insurance revenue, increased by $4.7 million.

46

Product purchases increased by $373.9 million, or 47%, to $1,168.2 million for the nine months ended September 30, 2008 compared to $794.3 million for the nine months ended September 30, 2007. NGL market prices, which were up $0.51 per gallon, increased our product purchases by $350.0 million. Higher sales volumes increased our product purchases by $16.4 million. In addition, charges of $7.7 million and $0.2 were taken in 2008 and 2007 to reduce the carrying value of our NGL inventory to its realizable value.

Hurricane Update

Certain of our Louisiana and Texas facilities sustained damage during the 2005 hurricane season from two Gulf Coast hurricanes—Katrina and Rita. All repairs to our plant facilities relating to these two hurricanes have been completed.

During 2008, we received $48.3 million and $21.6 million related to property damage and business interruption insurance claims, most of which was in connection with the final resolution of our claims related to Katrina under the onshore property insurance program.

In September, certain of our facilities in Louisiana and Texas sustained damage and had disruption to their operations from Hurricanes Gustav and Ike.

Hurricane Gustav made landfall near Cocodrie, Louisiana on September 1, 2008. Hurricane Ike made landfall at Galveston, Texas on September 13, 2008. Our Venice and Yscloskey gas processing plants were impacted by the storm surge caused by both hurricanes. Damage at these two facilities was not substantial. The Venice gas plant was processing gas by early October. The Yscloskey gas plant start-up and commissioning timing has been delayed to late November as a result of hurricane damage to the Tennessee Gas Pipeline Bluewater offshore system. Mechanical repairs have been completed and additional repairs are ongoing in preparation for the current schedule of available gas. Volumes available for processing at both facilities have been impacted by third-party offshore production shut-ins/evacuations ahead of the hurricanes, and by subsequent damage to those third-party facilities and pipelines from the hurricanes.

In Texas, our Galena Park marine terminal sustained a significant storm surge from Ike, resulting in damage to the docks, associated piping and related infrastructure. Temporary repairs restored limited barge and ship cargo transfers by late September, with full loading/offloading capabilities expected to be restored by the end of December. Galena Park’s shore-side facilities sustained relatively minor flood damage. Our Mont Belvieu complex sustained relatively minor wind damage and was fully operational by late September. Ike’s storm surge significantly impacted our Stingray and Barracuda gas processing facilities and our Hackberry storage facility, all of which are located in Cameron Parish, Louisiana. Operations at Hackberry resumed partial functionality in late September, with permanent repairs ongoing and full resumption of operations expected by the end of the fourth quarter. Gas processing operations at Stingray and Barracuda are anticipated to resume during the second quarter of 2009.

While it is still very early in the claims process, and we need to finalize repair assessments and cost estimates for those facilities that require repair, we currently estimate the cost associated with our interest for those repairs to be approximately $65 million. We believe that we have adequate insurance coverage (subject to customary deductibles, limits and sub-limits) to cover the respective facility repair costs and to offset the majority of the associated lost profits as a result of the hurricanes. The property damage deductibles under our insurance coverage will reduce our ultimate property damage insurance recoveries by approximately $14 million. We will have additional out of pocket costs associated with improvements (e.g., elevating critical equipment) that may not be covered by insurance. For the three months ended September 30, 2008, we recorded a loss provision of $17.9 million for our estimated out-of-pocket cleanup and repair costs related to Gustav and Ike, after estimated insurance proceeds.

We are still in the process of analyzing the factors affecting the amount of our business interruption claims. We maintain a 30 day time-element business interruption waiting period for our onshore facilities, and a 45 day time-element contingent business interruption waiting period for third-party offshore property damage related

47

income impacts to our onshore facilities. Based on the information currently available to us we believe that we could receive business interruption claim proceeds in excess of $10 million. We will recognize income from business interruption claims in the period that a Proof of Loss is executed with the insurance company.

Liquidity and Capital Resources

Our ability to finance our operations, including to fund 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.

Our main sources of liquidity and capital resources are internally generated cash flow from operations, borrowing under our senior secured credit facility, the issuance of additional units by the Partnership 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. In order to increase our cash position in the face of the credit and capital market disruptions, on October 16, 2008, we requested a $100 million funding under our senior secured credit facility. Lehman Bank, a lender under our senior secured revolving credit facility, defaulted on its portion of this borrowing request, resulting in actual funding of $95.9 million. The proceeds from this borrowing are currently available to us as cash deposits. As a result, we believe the availability under our senior secured credit facility has been effectively reduced by $10.2 million. On the same date, the Partnership requested a $100 million funding under its senior secured credit facility, and Lehman Bank also defaulted on its portion of the Partnership’s borrowing request resulting in actual funding of $97.8 million. The proceeds from this borrowing request are currently available to the Partnership as cash deposits. As a result of the default, we believe the availability under the Partnership’s senior secured credit facility has been effectively reduced by $9.5 million.

Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. We have 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. 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 have declined significantly during the quarter, continuing downward since the end of the quarter. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity contracts for a portion of our estimated equity volumes through 2012 (see Note 10—Derivative Instruments and Hedging Activities). The current market conditions may also impact our ability to enter into future commodity derivative contracts. In the event of a 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 other sixteen lenders in our senior secured revolving credit facility and the other twenty three lenders in the Partnership’s senior secured credit facility. To date, other than the Lehman Bank default, neither we nor the Partnership have experienced any disruptions in the ability to access our respective bank credit facilities.

48

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 this Quarterly Report and “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.

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, hurricane-related repair expenditures, long-term indebtedness obligations and collateral requirements for at least the next year.

A significant portion of our capital resources are utilized in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade status and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. As of September 30, 2008, total outstanding letter of credit postings by us and the Partnership were $282.3 million and $34.7 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 in our Annual Report on Form 10-K for the year ended December 31, 2007.

Contractual Obligations.In June 2008, the Partnership issued $250 million aggregate principal amount of senior notes. The proceeds from the offering were used to reduce outstanding indebtedness under the Partnership’s senior secured credit facility. The interest rate on the senior unsecured notes is fixed at 8.25% with interest to be paid on January 1 and July 1 of each year and the senior unsecured notes mature on July 1, 2016.

Available Credit.As of September 30, 2008, after giving effect to the default by Lehman Bank, we had $257.5 million in total availability, including $239.8 million under our senior secured revolving credit facility and $17.7 million under our senior secured synthetic letter of credit facility. In addition, the Partnership had $415 million in availability under its senior secured credit facility, after giving effect to outstanding borrowings of $390 million, the issuance of $34.7 million of letters of credit and the default by Lehman Bank.

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 2008 related to the expansion of our natural gas gathering and processing infrastructure.

We estimate that our total capital expenditures for 2008 will be approximately $154.9 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, the issuance of additional units by the Partnership and debt offerings.

49

Cash Flow

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

	Nine Months Ended September 30,
	2008			2007
	(In millions)
Net cash provided by (used in):
Operating Activities	$	187.5		$	136.8
Investing Activities		(186.3	)		(82.3	)
Financing Activities		(55.7	)		(44.9	)

Operating Activities.Net cash provided by operating activities was $187.5 million for the nine months ended September 30, 2008 compared to $136.8 million for the nine months ended September 30, 2007. Changes in operating assets and liabilities provided $86.4 million in cash during the nine months ended September 30, 2008, compared to using $18.5 million in cash during the nine months ended September 30, 2007. The increase is primarily from the receipt of $21.6 million from business interruption issuance claims, the payment of $87.4 million to terminate certain out-of-the-money natural gas and NGL commodity swaps, and adjustments of other non-cash items as presented in the consolidated statement of cash flows.

Investing Activities.Net cash used in investing activities was $186.3 million for the nine months ended September 30, 2008 compared to $82.3 million for the nine months ended September 30, 2007. The $104.0 million increase was primarily due to our acquisition of an additional interest in VESCO, the timing of receipt of proceeds from property damage claims and the payment for the investment in debt securities of Targa Investments Inc.

Financing Activities.Net cash used in financing activities was $55.7 million for the nine months ended September 30, 2008 compared to $44.9 million for the nine months ended September 30, 2007. During the nine months ended September 20, 2008, we distributed $52.8 million in cash to Targa Investments.

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, 2007.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008		2007
	(In millions)
Natural Gas Gathering and Processing	$	117.3		$	108.5	$	346.7	$	296.7
Logistics Assets		15.6			12.4		34.1		28.7
NGL Distribution and Marketing Services		(24.9	)		16.2		15.0		33.9
Wholesale Marketing		(5.4	)		2.3		13.0		11.0
	$	102.6		$	139.4	$	408.8	$	370.3

50

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In thousands)
Reconciliation of Operating Margin to Net Income (Loss):
Operating margin	$	102.6		$	139.4		$	408.8		$	370.3
Adjustments to reconcile operating margin to net income (loss):
Depreciation and amortization		(41.1	)		(37.6	)		(118.0	)		(110.8	)
Gain (loss) on sale of assets		—			—			4.5			0.1
General and administrative		(26.7	)		(35.8	)		(78.7	)		(78.2	)
Interest expense, net		(24.6	)		(34.7	)		(73.8	)		(112.8	)
Other		(19.2	)		—			(0.6	)		—
Equity in earnings of unconsolidated investments		2.5			2.3			13.2			8.0
Minority interest/Non-controlling interest		(24.6	)		(10.3	)		(82.1	)		(27.1	)
Income tax (expense)/benefit		10.2			(10.0	)		(29.6	)		(13.2	)
Net income (loss)	$	(20.9	)	$	13.3		$	43.7		$	36.3
Reconciliation of Net Cash Provided by (Used in) Operating Activities to Adjusted EBITDA:
Net cash provided by (used in) operating activities	$	(144.4	)	$	2.5		$	187.5		$	136.8
Interest expense, net (excluding amortization)		23.0			32.9			68.1			101.9
Current income tax expense (benefit)		(1.0	)		0.6			0.2			1.3
Changes in operating working capital which used (provided) cash:
Accounts receivable and other assets		(167.8	)		114.3			(268.6	)		129.8
Inventory		13.2			62.3			(22.4	)		27.6
Accounts payable and other liabilities		233.4			(121.7	)		204.5			(139.0	)
Other, net		90.0			1.2			106.4			0.9
Adjusted EBITDA	$	46.4		$	92.1		$	275.7		$	259.3
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net income (loss)	$	(20.9	)	$	13.3		$	43.7		$	36.3
Add:
Interest expense, net		24.6			34.7			73.8			112.8
Income tax expense (benefit)		(10.2	)		10.0			29.6			13.2
Depreciation and amortization		41.1			37.6			118.0			110.8
Non-cash loss (gain) related to derivative instruments		11.8			(3.5	)		10.6			(13.8	)
Adjusted EBITDA	$	46.4		$	92.1		$	275.7		$	259.3

51

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 on Form 10-K for the year ended December 31, 2007.

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. We do not use risk sensitive instruments for trading purposes.

Commodity Price Risk

A significant portion of our revenues is derived from percent-of-proceeds contracts under which we receive 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 hedge 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 on Form 10-K for the year ended December 31, 2007.

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.

For the three and nine months ended September 30, 2008, our hedging activities decreased operating revenues by $35.3 million and $87.7 million. For the same periods in 2007, our hedging activities increased operating revenues by $2.3 million and $16.3 million.

As of September 30, 2008, we had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from October 1, 2008 through December 31, 2008):

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Natural Gas Sales
Swap	IF-Waha	6.96	21,918	—	—	—	—	$	2,994
Swap	IF-Waha	6.62	—	21,918	—	—	—		(5,468	)
Swap	IF-Waha	7.40	—	—	9,300	—	—		(1,382	)
Swap	IF-Waha	7.36	—	—	—	5,500	—		(880	)
Swap	IF-Waha	7.18	—	—	—	—	5,500		(1,041	)
Total Sales			21,918	21,918	9,300	5,500	5,500	$	(5,777	)

52

NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	0.82	3,547	—	—	—	—	$	(4,934	)
Swap	OPIS-MB	0.79	—	3,347	—	—	—		(18,305	)
Swap	OPIS-MB	0.87	—	—	2,750	—	—		(9,092	)
Swap	OPIS-MB	0.91	—	—	—	1,550	—		(3,274	)
Swap	OPIS-MB	0.92	—	—	—	—	1,250		(2,111	)
Total Swaps			3,547	3,347	2,750	1,550	1,250
Floor	OPIS-MB	1.44		—	—	54	—		265
Floor	OPIS-MB	1.43	—	—	—	—	63		340
Total Floors			—	—	—	54	63
Total Sales			3,547	3,347	2,750	1,604	1,313	$	(37,111	)

53

As of September 30, 2008, the Partnership had the following hedge arrangements which will settle during the years ended December 31, 2008 through 2012 (except as indicated otherwise, the 2008 volumes reflect daily volumes for the period from October 1, 2008 through December 31, 2008):

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Natural Gas Purchases
Swap	NY-HH	8.69	1,300	—	—	—	—	$	(133	)
Total Purchases			1,300	—	—	—	—
Natural Gas Sales
Swap	IF-HSC	8.09	2,328	—	—	—	—		206
Swap	IF-HSC	7.39	—	1,966	—	—	—		(262	)
			2,328	1,966	—	—	—
Swap	IF-NGPL MC	8.86	6,964	—	—	—	—		2,613
Swap	IF-NGPL MC	9.18	—	6,256	—	—	—		4,515
Swap	IF-NGPL MC	8.86	—	—	5,685	—	—		2,061
Swap	IF-NGPL MC	7.34	—	—	—	2,750	—		(485	)
Swap	IF-NGPL MC	7.18	—	—	—	—	2,750		(539	)
			6,964	6,256	5,685	2,750	2,750
Swap	IF-Waha	8.91	7,389	—	—	—	—		2,330
Swap	IF-Waha	8.73	—	6,936	—	—	—		3,482
Swap	IF-Waha	7.52	—	—	5,709	—	—		(631	)
Swap	IF-Waha	7.36	—	—	—	3,250	—		(520	)
Swap	IF-Waha	7.18	—	—	—	—	3,250		(615	)
			7,389	6,936	5,709	3,250	3,250
Total Swaps			16,681	15,158	11,394	6,000	6,000
Floor	IF-NGPL MC	6.55	1,000	—	—	—	—		172
Floor	IF-NGPL MC	6.55	—	850	—	—	—		186
			1,000	850	—	—	—
Floor	IF-Waha	6.85	670	—	—	—	—		92
Floor	IF-Waha	6.55	—	565	—	—	—		111
			670	565	—	—	—
Total Floors			1,670	1,415	—	—	—
			18,351	16,573	11,394	6,000	6,000
Total Sales								$	12,583

54

NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
NGL Sales
Swap	OPIS-MB	1.44	7,080	—	—	—	—	$	6,282
Swap	OPIS-MB	1.32	—	6,248	—	—	—		11,733
Swap	OPIS-MB	1.27	—	—	4,809	—	—		8,603
Swap	OPIS-MB	0.92	—	—	—	3,400	—		(8,470	)
Swap	OPIS-MB	0.92	—	—	—	—	2,700		(5,515	)
Total Swaps			7,080	6,248	4,809	3,400	2,700
Floor	OPIS-MB	1.44	—	—	—	199	—		978
Floor	OPIS-MB	1.43	—	—	—	—	231		1,247
Total Floors			—	—	—	199	231
Total Sales			7,080	6,248	4,809	3,599	2,931
								$	14,858

Condensate

Instrument Type	Index	Avg. Price $/Bbl	Barrels per day					(In thousands) Fair Value
			2008	2009	2010	2011	2012
Condensate Sales
Swap	NY-WTI	70.68	384	—	—	—	—	$	(1,054	)
Swap	NY-WTI	69.00	—	322	—	—	—		(3,823	)
Swap	NY-WTI	68.10	—	—	301	—	—		(3,643	)
Total Swaps			384	322	301	—	—
Floor	NY-WTI	60.50	55	—	—	—	—		1
Floor	NY-WTI	60.00	—	50	—	—	—		24
Total Floors			55	50	—	—	—
Total Sales			439	372	301	—	—
								$	(8,495	)

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.

55

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 September 30, 2008, we had approximately $1,415.3 million of indebtedness, of which $500.0 million was at fixed interest rates and $915.3 million was at variable interest rates. In order to mitigate the risk of changes in cash flows attributable to changes in market interest rates the Partnership entered into interest rate swaps and interest rate basis swaps that effectively fix the base rate on $300 million in borrowings as shown below:

Expiration Date	Fixed Rate		Notional Amount		Fair Value
					(In thousands)
January 24, 2011	3.91	%	$	100 million	$	(1,334	)
January 24, 2012	3.75	%		200 million		(389	)
					$	(1,723	)

The Partnership has 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. 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 $6.2 million.

Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy. On July 18, 2008, SemGroup LP filed for bankruptcy protection. As of September 30, 2008, we recognized a reserve of $7.3 million for product delivered and subject to the bankruptcy.

Item 4T. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

There has been no change in our internal control over financial reporting during the three months ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

56

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

The information required for this item is provided in Note 11—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, 2007. 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:

We may not be able to obtain funding or obtain funding on acceptable terms because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

In addition, Lehman Bank recently defaulted on a borrowing request under our and the Partnership’s senior secured credit facilities, which effectively reduced our total commitments under these facilities by $10.2 million and $9.5 million. As a result, we can provide no assurance that other lending counterparties will be willing or able to meet their existing funding obligations under our senior secured credit facility.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required, on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to grow our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on our revenues and results of operations.

Our substantial amount of indebtedness could adversely affect our financial position.

We currently have a substantial amount of indebtedness. As of September 30, 2008 we had $775.3 million of total indebtedness outstanding,$282.3 million of letters of credit outstanding and $239.8 million of additional borrowing capacity under our senior secured credit facility. As of September 30, 2008, the Partnership had approximately $640 million of total indebtedness outstanding, approximately $34.7 million of letters of credit outstanding and approximately $425.3 million of additional borrowing capacity under its senior secured credit facility. In October 2008, one of the lenders under our and the Partnership’s senior secured credit facilities, Lehman Bank, defaulted on borrowing requests. As a result, the total commitments under our and the Partnership’s credit facilities have been effectively reduced by $10.2 million and $9.5 million. We may also incur additional indebtedness in the future.

57

Our substantial indebtedness may:

• make it difficult for us to satisfy our financial obligations, including making scheduled principal and interest payments on our indebtedness;

• limit our ability to borrow additional funds for working capital, capital expenditures, acquisitions or other general business purposes;

• limit our ability to use our cash flow or obtain additional financing for future working capital, capital expenditures, acquisitions or other general business purposes;

• require us to use a substantial portion of our cash flow from operations to make debt service payments;

• limit our flexibility to plan for, or react to, changes in our business and industry;

• place us at a competitive disadvantage compared to our less leveraged competitors; and

• increase our vulnerability to the impact of adverse economic and industry conditions.

We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit agreement or otherwise in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness at or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.

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.

Item 6. Exhibits

Exhibit Number		Description
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)).

58

Exhibit Number		Description
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*	—	Supplemental Indenture dated October 31, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association.
31.1*	—	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	—	Certification of 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 Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

59

SIGNATURES

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

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

Date: November 12, 2008

60

Exhibit Index

Exhibit Number		Description
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*	—	Supplemental Indenture dated October 31, 2008, among Targa Permian Intrastate LLC, a subsidiary of Targa Resources, Inc., Targa Resources Finance Corporation, the other Subsidiary Guarantors and Wells Fargo Bank, National Association.
31.1*	—	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	—	Certification of 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 Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith

61