Targa Liquids Marketing & Trade 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)
Registration No. 333-147066

Prospectus

Targa Resources, Inc.

Targa Resources Finance Corporation

Offer to Exchange up to

$250,000,000 of 8 ¹/2% Senior Notes due 2013 for

$250,000,000 of 8 ¹/2% Senior Notes due 2013

that have been Registered under the Securities Act of 1933

Terms of the Exchange Offer

New Notes. We are offering to exchange up to $250,000,000 of our outstanding 8 ¹/2% Senior Notes due 2013 for new notes. The terms of the new notes are substantially identical to the outstanding notes, except that we have registered the new notes under the Securities Act of 1933.

Notes Exchanged. We will exchange for an equal principal amount of new notes all outstanding notes that you validly tender and do not validly withdraw before the exchange offer expires. Tenders of outstanding notes may be withdrawn at any time prior to the expiration of the exchange offer.

Expiration Date. The exchange offer expires at 5:00 p.m., New York City time, on January 24, 2008, unless extended.

Taxation. The exchange of outstanding notes for new notes will not be a taxable event for U.S. federal income tax purposes.

Broker-Dealers. Each broker-dealer that receives the new notes for its own account pursuant to this exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal accompanying this prospectus states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act of 1933. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer for a period of 180 days after the expiration of the exchange offer in connection with resales of the new notes received in exchange for outstanding notes where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

Terms of the 8 ¹/2% Senior Notes Offered in the Exchange Offer

Maturity.The new notes will mature on November 1, 2013.

Interest. Interest on the new notes accrues at the rate of 8 ¹/2% per year and is payable semi-annually in arrears on May 1^st and November 1^st of each year.

Redemption. Prior to November 1, 2008, we may redeem up to 35% of the aggregate principal amount of the notes at a price equal to 108.500% of the principal amount of the notes to be redeemed with the net proceeds of certain public equity offerings. Prior to November 1, 2009, we may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes to be redeemed plus a make-whole amount described in this prospectus. On or after November 1, 2009, we may redeem the notes, in whole or in part, at the redemption prices described in this prospectus.

Guarantees and Ranking. The new notes will be jointly and severally guaranteed on a senior unsecured basis by each of our current and future restricted subsidiaries. The notes and the guarantees are senior unsecured obligations ranking equally in right of payment with all of our and the subsidiary guarantors’ other senior unsecured debt and senior in right of payment to all of our and the subsidiary guarantors’ future subordinated debt. The notes and the guarantees are effectively subordinated to our and the subsidiary guarantors’ existing and future secured debt to the extent of the value of the assets securing such debt.

Please read “Risk Factors” on page 7 for a discussion of factors you should consider before participating in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The date of this prospectus is December 20, 2007.

This prospectus incorporates important business and financial information about us that is not included in or delivered with this document. This information is available to you without charge upon written or oral request to: Targa Resources, Inc., 1000 Louisiana, Suite 4300, Houston, Texas 77002, Attention: Corporate Secretary, (713) 584-1000. The exchange offer is expected to expire on January 24, 2008 and you must make your exchange decision by the expiration date. To obtain timely delivery, you must request the information no later than January 16, 2008, or the date which is five business days before the expiration date of this exchange offer.

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained or incorporated by reference in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you receive any unauthorized information, you must not rely on it. This exchange offer is not being made to, nor will we accept tenders of outstanding notes from, holders of existing notes in any jurisdiction in which the exchange offer or the issuance of new notes would not be permitted. You should not assume that the information contained in this prospectus, or the documents incorporated by reference into this prospectus, is accurate as of any date other than the date on the front cover of this prospectus or the date of such document, as the case may be.

TABLE OF CONTENTS

Prospectus Summary	1
Ratio of Earnings to Fixed Charges	6
Risk Factors	7
Exchange Offer	24
Use of Proceeds	32
Selected Historical Financial and Operating Data	33
Management’s Discussion and Analysis of Financial Condition and Results of Operation	38
Business	73
Management	101
Certain Relationships and Related Party Transactions	121
Security Ownership of Certain Beneficial Owners and Management	126
Description of New Notes	127
Federal Income Tax Considerations	191
Plan of Distribution	191
Legal Matters	192
Experts	192
Where You Can Find More Information	192
Forward-Looking Statements	193
Index to Financial Statements	F-1
Letter of Transmittal	A-1

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PROSPECTUS SUMMARY

This summary provides a brief overview of certain information from this prospectus, but may not contain all the information that may be important to you. You should read this entire prospectus before making an investment decision. You should carefully consider the information set forth under “Risk Factors.” In addition, certain statements include forward-looking information which involve risks and uncertainties. Please read “Forward-Looking Statements.”

In this prospectus, we use the term “outstanding notes” to refer to the 8 ¹/2% Senior Notes due 2013 that were issued on October 31, 2005, and the term “new notes” to refer to the 8 ¹/2% Senior Notes due 2013 that have been registered under the Securities Act of 1933 and are being offered in exchange for the outstanding notes as described in this prospectus. References to the “notes” in this prospectus include both the outstanding notes and the new notes. As used in this prospectus, unless the context otherwise requires, “Targa,” “our,” “we,” “us” and similar terms refer to Targa Resources, Inc., together with its subsidiaries, including its publicly traded master limited partnership, Targa Resources Partners LP, which we refer to in this prospectus as the “Partnership.”

Targa Resources, Inc.

Targa Resources, Inc. was formed in 2004 by its management team, which consists of former members of senior management of several midstream and other diversified energy companies, and Warburg Pincus LLC. We are a leading provider of midstream natural gas and natural gas liquid, or NGL, services in the United States. We provide these services through our integrated platform of midstream assets. 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. Additionally, our natural gas liquids 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 believe our asset locations, including those of the Partnership, provide us access to natural gas supplies and proximity to end-use markets and leading market hubs while positioning us to capitalize on potential growth opportunities from selected areas of the Permian Basin, the continued development of deepwater and deep shelf Gulf of Mexico natural gas reserves, the increasing importation of liquefied natural gas, or LNG, to the Gulf Coast and the growth of the Barnett Shale production in north Texas. We believe our asset locations, scale, broad range of services, operational focus and competitive cost structure position us well to serve customers and to benefit from the importance of infrastructure in the growing U.S. energy market.

We own interests in or operate approximately 10,000 miles of natural gas pipelines and approximately 550 miles of NGL pipelines, with natural gas gathering systems covering approximately 14,500 square miles and 21 natural gas processing plants with access to natural gas supplies in the Permian Basin, north Texas, onshore southern Louisiana, and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with 16 storage, marine and transport terminals with above ground NGL storage capacity of approximately 900 MBbls, net NGL fractionation capacity of approximately 300 MBbls/d and 43 owned and operated storage wells with a net storage capacity of approximately 65 MMBbls. For the twelve months ended December 31, 2006 and the nine months ended September 30, 2007, we generated, on a consolidated basis, income from operations of $235.8 million and $181.4 million, respectively.

On October 24, 2007 the Partnership completed a public offering of 13,500,000 common units. The Partnership used the proceeds from the offering, borrowings under its senior secured revolving credit facility and the issuance of approximately 275 thousand general partner units to us to finance the acquisition from us of certain natural gas gathering and processing businesses located in west Texas and Louisiana for approximately $705 million, subject to certain adjustments. The Partnership sold an additional 1,800,000 common units to the underwriters on November 20, 2007 pursuant to a partial exercise of their option to purchase additional common units and used the net proceeds of approximately $47 million to repay a portion of outstanding indebtedness.

Our executive offices are located at 1000 Louisiana, Suite 4300, Houston, Texas 77002 and our telephone number is (713) 584-1000.

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The Exchange Offer

On October 31, 2005, we completed a private offering of the outstanding notes. We entered into a registration rights agreement with the initial purchasers in the private offering in which we agreed to deliver to you this prospectus and to use commercially reasonable efforts to consummate the exchange offer.

Exchange Offer We are offering to exchange up to $250,000,000 of new notes for an identical principal amount of outstanding notes.

Expiration Date The exchange offer will expire at 5:00 p.m. New York City time, on January 24, 2008, unless we decide to extend it. While we do not currently intend to extend the exchange offer, it is possible that we will extend the exchange offer until all outstanding notes are tendered.

Condition to the Exchange Offer The registration rights agreement does not require us to accept outstanding notes for exchange if the exchange offer or the making of any exchange by a holder of the outstanding notes would violate any applicable law or interpretation of the staff of the SEC, or if a threatened or pending judicial or administrative proceeding impairs our ability to proceed with the exchange offer. A minimum aggregate principal amount of outstanding notes being tendered is not a condition to the exchange offer.

Procedures for Tendering Outstanding Notes The outstanding notes were issued as global securities and were deposited with Wells Fargo Bank, National Association, who holds the outstanding notes as the custodian for the Depository Trust Company, or DTC. Beneficial interests in the outstanding notes are held by participants in DTC on behalf of the beneficial owners of the outstanding notes. We refer to beneficial interests in notes held by DTC as notes held in book-entry form. Beneficial interests in notes held in book-entry form are shown on, and transfers of notes can be made only through, records maintained by DTC and its participants.

To tender your outstanding notes in the exchange offer, you must transmit to Wells Fargo Bank, National Association, as exchange agent, on or prior to the expiration date of the exchange offer, the following:

• a computer-generated message transmitted by means of DTC’s Automated Tender Offer Program (ATOP) system that, when received by the exchange agent will form a part of a confirmation of book-entry transfer in which you acknowledge and agree to be bound by the terms of the letter of transmittal; and

• a timely confirmation of book-entry transfer of your existing notes into the exchange agent’s account at DTC, according to the procedure for book-entry transfers described in this prospectus under the heading “Exchange Offer—Terms of the Exchange Offer” and “—Procedures for Tendering.”

Guaranteed Delivery Procedures None

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Withdrawal of Tenders You may withdraw your tender of outstanding notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m. New York City time on the expiration date of the exchange offer. Please read “Exchange Offer—Withdrawal of Tenders.”

Acceptance of Outstanding Notes and Delivery of New Notes If the conditions described under “Exchange Offer—Conditions to the Exchange Offer” are satisfied, we will accept any and all outstanding notes that you properly tender in the exchange offer before 5:00 p.m. New York City time on the expiration date. We will return to you, without expense, as promptly as practicable after the expiration date, any outstanding note that we do not accept for exchange. We will deliver the new notes as promptly as practicable after the expiration date and acceptance of the outstanding notes for exchange. Please refer to the section in this prospectus entitled “Exchange Offer— Terms of the Exchange Offer.”

Fees and Expenses We will bear all expenses related to the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Fees and Expenses.”

Use of Proceeds The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under our registration rights agreement.

Consequences of Failure to Exchange Outstanding Notes If you do not exchange your outstanding notes in this exchange offer, you will no longer be able to require us to register the outstanding notes under the Securities Act except in the limited circumstances provided under our registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the outstanding notes unless we have registered the outstanding notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

U.S. Federal Income Tax Considerations The exchange of new notes for outstanding notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Federal Income Tax Considerations.”

Exchange Agent We have appointed Wells Fargo Bank, National Association as exchange agent for the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer—Exchange Agent” for the address, telephone number and fax number of the exchange agent.

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Terms of the Notes

The new notes will be identical to the outstanding notes except that the new notes will be registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest and will contain different administrative terms. The new notes will evidence the same debt as the outstanding notes, and the same indenture will govern the new notes and the outstanding notes.

The following summary contains basic information about the notes and is not intended to be complete. It does not contain all the information that may be important to you. For a more complete understanding of the notes, please refer to the section of this prospectus entitled “Description of New Notes.”

Issuers Targa Resources, Inc. and Targa Resources Finance Corporation.

Targa Resources Finance Corporation, a Delaware corporation, is a wholly owned subsidiary of Targa Resources, Inc. organized for the purpose of co-issuing our existing notes and the notes offered hereby. Targa Resources Finance Corporation does not have any operations of any kind and will not have any revenue other than as may be incidental to its activities as a co-issuer of the notes.

Notes Offered $250 million in aggregate principal amount of 8 ¹/2% senior notes due 2013

Maturity Date November 1, 2013

Interest Interest on the notes accrues at the rate of 8 ¹/2% per year and is payable semi-annually in arrears on May 1^st and November 1^st of each year.

Optional Redemption Prior to November 1, 2008, we may redeem up to 35% of the aggregate principal amount of the notes at a price equal to 108.500% of the principal amount of the notes to be redeemed with the net proceeds of certain public equity offerings. Prior to November 1, 2009, we may redeem the notes, in whole or in part, at a price equal to 100% of the principal amount of the notes to be redeemed plus a make-whole amount described in this prospectus. On or after November 1, 2009, we may redeem the notes, in whole or in part, at the redemption prices described in this prospectus under “Description of New Notes—Optional Redemption.”

Guarantees Initially, all payments with respect to the notes (including principal and interest) are fully and unconditionally guaranteed, jointly and severally, by substantially all of our existing subsidiaries, other than the Partnership and its subsidiaries. In the future, our subsidiaries that guarantee other indebtedness of ours or another subsidiary guarantor must also guarantee the notes. The guarantees are also subject to release in certain circumstances.

Ranking The notes and the guarantees thereof are senior unsecured obligations ranking equally in right of payment with all of our and the subsidiary guarantors’ other senior unsecured debt and senior in right of payment to all of our and the subsidiary guarantors’ future

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subordinated debt. The notes and the guarantees thereof are effectively subordinated to our and the subsidiary guarantors’ existing and future secured debt to the extent of the value of the assets securing such debt.

Certain Covenants The indenture governing the notes contains covenants that, among other things, limit our ability and certain of our subsidiaries’ ability to:

• incur or guarantee additional indebtedness or issue preferred stock;

• pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

• make investments;

• create restrictions on the payment of dividends or other amounts to us from our non-guarantor restricted subsidiaries;

• engage in transactions with our affiliates;

• sell assets, including capital stock of our subsidiaries;

• transfer assets;

• enter into sale and leaseback transactions;

• consolidate or merge; and

• incur liens.

These covenants are subject to important exceptions and qualifications which are described in this prospectus under “Description of New Notes.”

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RATIO OF EARNINGS TO FIXED CHARGES

	Targa Resources, Inc.					Predecessor
	Nine Months Ended  September 30,		Year Ended December 31,			106-Day Period Ended April 15, 2004	Year Ended December 31,
	2007	2006	2006	2005	2004		2003	2002
RATIO OF EARNINGS TO FIXED CHARGES(1)	1.4x	1.3x	1.2x	0.6x	3.2x	N/A	N/A	N/A

(1) Not applicable to the predecessor because the predecessor has not historically incurred debt obligations.

(2) See Exhibit 12.1 to this registration statement for a ratio of earnings to fixed charges computation.

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RISK FACTORS

You should carefully consider the following risks and other information contained in this prospectus before deciding to participate in the exchange offer. The risks and uncertainties described below are not the only risks facing us or applicable to your investment in our new notes. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. If any of the following risks or uncertainties actually occur, our business, financial condition and results of operations could be materially adversely affected.

Risks Related to the Exchange Offer and the Notes and our Capital Structure

We have a substantial amount of indebtedness which may adversely affect our cash flow and our ability to operate our business, to comply with debt covenants and to make payments on our indebtedness, including the notes.

We are highly leveraged. As of September 30, 2007, our total indebtedness, including the notes and the indebtedness of the Partnership, was $1,769.5 million, which represents approximately 65% of our capitalization. For the twelve-month period ended December 31, 2006, our interest expense was $180 million. In addition, as of December 31, 2006, we had issued approximately $227.5 million in irrevocable standby letters of credit under our $300 million senior secured synthetic letter of credit facility, which is not reflected on our balance sheet. We may also utilize our $250 million senior secured revolving credit facility in the future.

Our substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of our indebtedness, including the notes. Our substantial indebtedness, combined with our lease and other financial obligations and contractual commitments, could have other important consequences to you as a holder of notes, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• satisfying our obligations with respect to our indebtedness, including the notes, may be more difficult and any failure to comply with the obligations of any of our debt instruments could result in an event of default under the indenture governing the notes and the agreements governing such other indebtedness;

• we will need a portion of our cash flow to make interest payments on our debt, reducing the funds that would otherwise be available for operations and future business opportunities;

• our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

• our debt level may limit our flexibility in planning for, or responding to, changing business and economic conditions.

Our ability to service our debt, including the notes, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Capital Requirements.”

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Increases in interest rates could adversely affect our business.

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of September 30, 2007, our total indebtedness was $1,769.5 million, of which $250 million was at fixed interest rates and $1,519.5 million was at variable interest rates. A one percentage point increase in the interest rate on our variable interest rate debt would have increased annual interest expense by approximately $11.7 million. As a result of our significant amount of variable interest rate debt, our financial condition could be adversely affected by significant increases in interest rates.

Despite current indebtedness levels, we and our subsidiaries may still be able to incur substantially more debt. This could increase the risks associated with our substantial leverage.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. Although the indenture governing the notes and our senior secured credit facilities contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could be substantial. For example, in addition to the $1,225 million of indebtedness outstanding under our senior secured term loan facility at September 30, 2007 and up to $250 million available under our senior secured revolving credit facility, the indenture governing the notes will allow us to incur additional indebtedness of up to $200 million of senior secured debt. As an additional example, the indenture governing the notes will allow us to incur a significant amount of indebtedness in connection with acquisitions (including an unlimited amount of certain types of debt that will require cash payments of interest during the period the notes are outstanding). The indenture also permits the incurrence of indebtedness by the Partnership. If we incur additional debt, the risks associated with our substantial leverage would increase.

Repayment of our debt, including the notes, is dependent on cash flow generated by our subsidiaries.

Targa Resources, Inc. is a holding company and Targa Resources Finance Corporation was created solely to serve as a corporate co-obligor on the obligations of Targa Resources, Inc. under the Indenture and will continue to have nominal assets and no operations or revenues. Our subsidiaries own substantially all of our operating assets and conduct substantially all of our operations. Accordingly, repayment of our indebtedness, including the notes, is dependent, to a material extent, on the generation of cash flow by our subsidiaries and their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors of the notes, our subsidiaries do not have any obligation to pay amounts due on the notes or to make funds available for that purpose. Our subsidiaries may not be able to, or be permitted to, make distributions to enable us to make payments in respect of our indebtedness, including the notes. Each subsidiary is a distinct legal entity and, under certain circumstances, legal and contractual restrictions may limit our ability to obtain cash from our subsidiaries. While the indenture governing the notes and our senior secured credit facilities limit the ability of our subsidiaries that are not subsidiary guarantors to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to certain significant qualifications and exceptions, including an exception with respect to any restrictions included in the documentation governing indebtedness that is permitted to be incurred under the terms of the indenture governing the notes. In the event that we do not receive distributions from our subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the notes.

The notes will be structurally subordinated to claims of creditors of our current and future non-guarantor subsidiaries.

The notes will be structurally subordinated to indebtedness and other liabilities of our subsidiaries that are not guarantors of the notes, including the Partnership. The indenture governing the notes will allow our non-guarantor subsidiaries to incur a significant amount of permitted indebtedness in the future, including refinancing indebtedness under all of the baskets for our senior secured credit facilities and our incremental

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$200 million senior secured debt basket. In the event of a bankruptcy, liquidation or reorganization of any of our non-guarantor subsidiaries, these non-guarantor subsidiaries will pay the holders of their debts, holders of preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us.

Investors may not be able to rely on the earnings and assets of our joint ventures to support payments due under the notes.

We hold majority interests in our Versado and Cedar Bayou Fractionators joint ventures. While the minority shareholders’ income related to these joint ventures is deducted as minority expense in calculating our net income, our consolidated financial statements reflect the financial results of these companies, including all of their revenue and operating income, even though we own less than 100% of their equity and do not solely control the distribution of their income. We also hold minority interests in VESCO and Gulf Coast Fractionators, and do not control the distribution of their income.

The ability of our joint ventures to distribute their earnings to us, in the form of dividends or otherwise, is subject to, among other things, the consent of our joint venture partners. Each of our existing majority-owned joint ventures are, and any future majority-owned joint venture will likely be, an unrestricted subsidiary and, therefore, will not be subject to the covenants contained in the indenture governing the notes or our senior secured credit facilities and will not guarantee the notes or our senior secured credit facilities. The indenture governing the notes will permit us to distribute to our stockholders all of our equity interests in future unrestricted subsidiaries (but not the equity of our existing majority-owned joint ventures) without any restriction. Accordingly, investors in the notes may not be able to rely upon income from or the assets of our joint ventures to support the payment of interest, principal or other amounts owing in respect of the notes.

We may transfer a significant amount of our assets to master limited partnerships, which will not be restricted subsidiaries and will not guarantee the notes.

Our senior secured credit facilities and the indenture governing the notes permit us, subject to certain conditions, to transfer assets, including equity interests we hold in other entities, to the Partnership or other master limited partnerships, or MLPs, and their subsidiaries, which will not be restricted subsidiaries or guarantors of the notes. These conditions include, among other things, that (i) after and as a result of any such transfer we receive an amount of cash attributable to such transfer equal to at least 75% of the fair market value of the assets or equity interests transferred, with the remaining consideration in the form of equity interests in the Partnership or other MLP to which the assets or equity interests are contributed and (ii) we apply the net cash proceeds received from the transfer to repay senior indebtedness, repurchase notes or, subject to certain limitations, reinvest in our business. Provided that we comply with these and other conditions, we may transfer a significant portion of our assets to the Partnership or other MLPs and their subsidiaries, and they will not be subject to any restrictions under our senior secured credit facilities or the indenture governing the notes or be required to distribute any funds to us or provide any guarantee in respect of the notes.

Investors may not be able to rely on the earnings or assets of the Partnership or the general partner of the Partnership to support payments due under the notes.

The ability of the Partnership, any other MLP or a general partner of an MLP following such general partner’s initial public offering, to distribute earnings to us is subject to the decisions of the board of directors (or similar governing body) of the Partnership’s or other MLP’s general partner. The members of these boards owe fiduciary duties to public equity holders of the Partnership or other MLP, and will not owe any duties, fiduciary or otherwise, to holders of the notes. The Partnership is not, and any other MLPs will not be, subject to the covenants contained in the indenture governing the notes or our senior secured credit facilities and will not guarantee the notes or our senior secured credit facilities. Likewise, following its initial public offering, the general partner of the Partnership or other MLP will no longer be subject to the covenants contained in the indenture governing the notes or our senior secured credit facilities and will be released from its guarantee of the notes and the senior secured credit facilities.

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Our senior secured credit facilities and the indenture governing the notes permit us, subject to certain conditions, to sell equity interests in the Partnership or any other MLP. In addition, we are allowed to distribute to our stockholders equity interests we may hold in the Partnership or any other MLPs and general partners of MLPs if our pro forma consolidated leverage ratio after giving effect to any such distributions is less than 2.75 to 1.00. Accordingly, investors in the notes may not be able to rely upon income from or the assets of the Partnership or any other MLPs, or any general partners of MLPs to support the payment of interest, principal or other amounts owing in respect of the notes.

The terms of our senior secured credit facilities and the indenture governing the notes may restrict our current and future operations, particularly our ability to respond to changes in our business or to take certain actions.

The credit agreement governing our senior secured credit facilities and the indenture governing the notes contain, and any future indebtedness we incur would likely contain, a number of restrictive covenants that impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests. The senior secured credit agreement and indenture governing the notes include covenants that, among other things, restrict our ability to:

• incur or guarantee additional indebtedness or issue preferred stock;

• pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

• make investments;

• create restrictions on the payment of dividends or other distributions to us from our non-guarantor restricted subsidiaries;

• engage in transactions with our affiliates;

• sell assets, including capital stock of the subsidiaries;

• make certain acquisitions;

• transfer assets;

• enter into sale and lease back transactions;

• consolidate or merge; and

• incur liens.

The senior secured credit agreement also includes covenants that, among other things, restrict our ability to:

• prepay, redeem and repurchase certain debt, other than loans under the senior secured credit facilities;

• make capital expenditures;

• amend debt and other material agreements; and

• change business activities conducted by us.

In addition, our senior secured credit facilities require us to satisfy and maintain specified financial ratios and other financial condition tests, some of which will become more restrictive over time. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.

A breach of any of these covenants could result in an event of default under our senior secured credit facilities. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under the senior secured credit facilities to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our senior secured credit facilities could proceed against the collateral granted to them to secure that indebtedness. We have

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pledged substantially all of our assets as collateral under our senior secured credit facilities. If the lenders under our senior secured credit facilities accelerate the repayment of borrowings, we cannot assure you that we will have sufficient assets to repay our senior secured credit facilities, as well as our unsecured indebtedness, including the notes.

The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

The notes and the guarantees are not secured by our assets nor those of the subsidiary guarantors, and the lenders under our senior secured credit facilities and certain present and future counterparties under our secured hedging arrangements will be entitled to remedies available to secured creditors, which gives them priority over the note holders to collect amounts due to them.

The notes and the guarantees are not secured by any of our assets. Our obligations under our senior secured credit facilities and certain of our hedging arrangements are secured by, among other things, a first priority pledge of substantially all our and our subsidiary guarantors’ assets, subject to certain exceptions. The notes are effectively subordinated to this senior secured indebtedness and such secured hedging arrangements to the extent of the value of the collateral securing such indebtedness. As of September 30, 2007, on a combined basis, the notes and the guarantees were effectively subordinated to approximately $1,519.5 million of indebtedness outstanding under our senior secured credit facilities. Under the terms of the indenture governing the notes, we may incur additional senior secured indebtedness under, or in addition to, our senior secured credit facilities, and such additional indebtedness could be significant. We have entered into long-term, fixed price hedges covering a portion of our expected natural gas and NGL equity volumes. If the difference between the amount we owe our hedge counterparties is more than the amount our counterparties owe to us, then the amount of such difference will be secured by our assets.

The right of repayment under the notes may be compromised if we enter into bankruptcy, liquidation, reorganization or other winding-up proceedings or if there is a default in, or acceleration of, payment under our senior secured credit facilities, our senior secured hedging arrangements or other senior secured indebtedness. If any of these events occurs, the senior secured creditors could sell those of our assets in which they have been granted a security interest, to the exclusion of the note holders, even if an event of default exists under the indenture at such time. As a result, upon the occurrence of any of these events, there may not be sufficient funds to pay amounts due on the notes.

Federal and state statutes may allow courts, under specific circumstances, to void guarantees and subordinate claims in respect of the guarantees.

The issuance of the guarantees by the subsidiary guarantors may be subject to review under state and federal laws if a bankruptcy, liquidation or reorganization case or a lawsuit, including in circumstances in which bankruptcy is not involved, were commenced at some future date by the subsidiary guarantors or on behalf of our unpaid creditors or the unpaid creditors of a guarantor.

Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer and fraudulent conveyance laws, a court may void or otherwise decline to enforce a subsidiary guarantor’s guarantee, or a court may subordinate such guarantee to the applicable subsidiary guarantor’s existing and future indebtedness.

While the relevant laws may vary from state to state, a court might void or otherwise decline to enforce the guarantee if it found that when the applicable subsidiary guarantor entered into its guarantee, or, in some states, when payments became due under the guarantee, the applicable subsidiary guarantor received less than reasonably equivalent value or fair consideration and either:

• the applicable subsidiary guarantor was insolvent, or rendered insolvent by reason of issuing the guarantee;

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• the applicable subsidiary guarantor was engaged in a business or transaction for which the applicable subsidiary guarantor’s remaining assets constituted unreasonably small capital;

• the applicable subsidiary guarantor intended to incur, or believed that the applicable subsidiary guarantor would incur, debts beyond such subsidiary guarantor’s ability to pay such debts as they mature; or

• the applicable subsidiary guarantor was a defendant in an action for monetary damages, or had a judgment for monetary damages rendered against such guarantor, and the damages remained unsatisfied after final judgment.

A court might also void a guarantee, without regard to the above factors, if it found that the applicable subsidiary guarantor entered into its guarantee with actual intent to hinder, delay or defraud its creditors.

A court would likely find that a subsidiary guarantor did not receive reasonably equivalent value or fair consideration for the guarantee if such subsidiary guarantor did not substantially benefit directly or indirectly from the issuance of the applicable guarantee. As a general matter, value is given for a guarantee if, in exchange for the guarantee, property is transferred or an antecedent debt is satisfied. In the case of the subsidiary guarantees, a court could find that the benefit from the guarantees went to Targa and that the guarantors did not, directly or indirectly, receive any benefit from the guarantees.

The measures of insolvency applied by courts will vary depending upon the particular fraudulent transfer law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, an entity would be considered insolvent if:

• the sum of its debts, including subordinate and contingent liabilities, was greater than the fair saleable value of its assets;

• if the present fair saleable value of its assets were less than the amount that would be required to pay the probable liability on its existing debts, including subordinate and contingent liabilities, as they become absolute and mature; or

• it cannot pay its debts as they become due.

In the event of a finding that a fraudulent conveyance or transfer has occurred, a court may void, or hold unenforceable, any of the guarantees, which could mean that you may not receive any payments on the guarantees and the court may direct you to repay any amounts that you have already received from any subsidiary guarantor to such subsidiary guarantor or a fund for the benefit of such subsidiary guarantor’s creditors. Furthermore, the holders of voided notes would cease to have any direct claim against the applicable subsidiary guarantor. Consequently, the applicable subsidiary guarantor’s assets would be applied first to satisfy our or the applicable subsidiary guarantor’s liabilities, if any, before any portion of the applicable subsidiary guarantor’s assets could be applied to the payment of the notes. Sufficient funds to repay the notes may not be available from other sources, including the remaining subsidiary guarantors, if any. Moreover, the voidance of a guarantee could result in an event of default with respect to our and our subsidiary guarantors’ other debt that could result in acceleration of such debt (if not otherwise accelerated due to such subsidiary guarantor’s insolvency or other proceeding).

Although each guarantee will contain a provision intended to limit that subsidiary guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer, this provision may not be effective to protect those guarantees from being voided under fraudulent transfer law, or may reduce that subsidiary guarantor’s obligation to an amount that effectively makes its guarantee worthless.

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Because each subsidiary guarantor’s liability under its guarantee may be reduced to zero, avoided or released under certain circumstances, you may not receive any payments from some or all of the subsidiary guarantors.

You have the benefit of the guarantees of the subsidiary guarantors. However, the guarantees by the subsidiary guarantors are limited to the maximum amount that the subsidiary guarantors are permitted to guarantee under applicable law. As a result, a subsidiary guarantor’s liability under its guarantee could be reduced to zero, depending upon the amount of other obligations of such subsidiary guarantor. Further, under the circumstances discussed more fully above, a court under federal or state fraudulent conveyance and transfer statutes could void the obligations under a guarantee or further subordinate it to all other obligations of the subsidiary guarantor. In addition, you will lose the benefit of a particular guarantee if it is released under certain circumstances described in the indenture.

We may not be able to repurchase the notes upon a change of control.

Upon the occurrence of certain change of control events, we will be required to offer to repurchase all notes that are outstanding at 101% of the principal amount thereof, plus any accrued and unpaid interest, and additional interest, if any, to the date of repurchase. Our senior secured credit facilities provide that certain change of control events (including a change of control as defined in the indenture governing the notes) constitute a default. Any future credit agreement or other agreements relating to our indebtedness would likely contain similar provisions. If we experience a change of control event that triggers a default under our senior secured credit facilities or any future credit facility, we could seek a waiver of such default or seek to refinance the relevant indebtedness. In the event we do not obtain such a waiver or refinance our senior secured credit facilities, such default could result in amounts outstanding under our senior secured credit facilities being declared due and payable. In the event we experience a change of control event that results in our having to offer to repurchase your notes, we may not have sufficient financial resources to satisfy all of our obligations under our senior or any replacement secured credit facilities, any other outstanding debt and the notes. A failure to make the applicable change of control offer or to pay the applicable change of control purchase price when due would result in a default under the indenture.

In addition, the change of control covenant in the indenture governing the notes does not cover all corporate reorganizations, mergers or similar transactions and may not provide you with protection in a highly leveraged transaction.

If you do not properly tender your outstanding notes, you will continue to hold unregistered outstanding notes and your ability to transfer outstanding notes will be adversely affected.

We will only issue new notes in exchange for outstanding notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the outstanding notes and you should carefully follow the instructions on how to tender your outstanding notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of outstanding notes.

If you do not exchange your outstanding notes for new notes pursuant to the exchange offer, the outstanding notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the outstanding notes except under exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register outstanding notes under the Securities Act unless our registration rights agreement with the initial purchaser of the outstanding notes requires us to do so. Further, if you continue to hold any outstanding notes after the exchange offer is consummated, you may have trouble selling them because there will be fewer notes outstanding.

We cannot assure you that an active trading market for the notes will develop.

The new notes are a new issue of securities for which there is no established trading market. We do not intend to have the notes listed on a national securities exchange or included in any automated quotation system. The liquidity of any market for the notes will depend upon the number of holders of the notes, our performance,

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the market for similar securities, the interest of securities dealers in making a market in the notes and other factors. A liquid trading market may not develop for the notes. If an active market does not develop or is not maintained, the price and liquidity of the notes may be adversely affected.

Risks Related to Our Business

Our cash flow is affected by supply and demand for natural gas and NGL products, natural gas and NGL prices, and decreases in these prices due to weather and other natural and economic forces could materially and adversely affect our results of operations and financial condition.

Our operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of natural gas and NGLs have been volatile and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the prompt month contract in the year ended December 31, 2005 ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu and for the year ended December 31, 2006 ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu. From the beginning of 2007 through September 30, 2007 the NYMEX daily settlement price for natural gas has ranged from a high of $8.19 per MMBtu to a low of $5.38 per MMBtu. NGL prices exhibit similar volatility. Based on monthly index prices, the average price for our NGL composition in the year ended December 31, 2005 ranged from a high of $1.12 per gallon to a low of $0.73 per gallon and for the year ended December 31, 2006 ranged from a high of $1.18 per gallon to a low of $0.92 per gallon. From the beginning of 2007 through September 30, 2007 the average price for our NGL composition ranged from a high of $1.27 per gallon to a low of $0.93 per gallon.

Our future cash flow will be materially adversely affected if we experience significant, prolonged pricing deterioration below general price levels experienced over the past few years in our industry.

The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for these commodities, which fluctuate with changes in market and economic conditions and other factors, including:

• the impact of seasonality and weather;

• general economic conditions;

• the level of domestic crude oil and natural gas production and consumption;

• the availability of imported natural gas, NGLs and crude oil;

• actions taken by foreign oil and gas producing nations;

• the availability of local, intrastate and interstate transportation systems;

• the availability and marketing of competitive fuels;

• the impact of energy conservation efforts; and

• the extent of governmental regulation and taxation.

Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gas and NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceeds arrangements, we remit to the producer a percentage of an index price for residue gas and NGL products, less agreed adjustments, rather than remitting a portion of the actual sales proceeds. Under these types of arrangements, our revenues and our cash flows increase or decrease, whichever is applicable, as the price of natural gas, NGLs and/or crude oil fluctuates.

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Because of the natural decline in production from existing wells in our operating regions, our success depends on our ability to obtain new sources of supplies of natural gas and NGLs which depends on certain factors beyond our control. Any decrease in supplies of natural gas or NGLs could adversely affect our business and operating results.

Our gathering systems are connected to natural gas wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will likely also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Additionally, our profitability is materially affected by the volume of raw NGL mix fractionated at our fractionation facilities. A material decrease in natural gas production from producing areas that we rely on for raw NGL mix, as a result of depressed commodity prices or otherwise, could result in a decline in the volume of NGL products delivered to our fractionation facilities. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.

We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, availability of drilling rigs and other production and development costs and the availability and cost of capital. Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. Natural gas prices reached historic highs in 2005 and early 2006, but declined substantially in the second half of 2006 and have continued to decline in 2007. Reductions in exploration or production activity or shut-ins by producers in the areas in which we operate as a result of a sustained decline in natural gas prices would lead to reduced utilization of our gathering and processing assets.

Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If, due to reductions in drilling activity or competition, we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our treating, processing and fractionation facilities would decline, which could reduce our revenue.

Some of our business is seasonal, requires that we build inventory to meet seasonal demand, and is potentially impacted by weather.

While the volumes of raw NGL mix that we fractionate are generally stable on an average annual basis, they often vary on a seasonal basis. For example, we typically fractionate lower volumes during the winter months, when more raw NGL mix is fractionated by facilities closer to the field to capture propane for heating purposes and when natural gas wells and certain oil wells tend to be less productive. Conversely, we typically fractionate greater volumes during the summer months, when less raw NGL mix is locally fractionated for heating purposes, when natural gas wells tend to be more productive and when refineries have excess supply of raw NGL mix due to various regulatory restrictions. This seasonality in demand may cause our results of operations to lack predictability on a quarter to quarter basis.

Similarly, weather conditions have a significant impact on the demand for propane because end-users depend on propane principally for heating purposes. Warmer-than-normal temperatures in one or more regions in which we operate can significantly decrease the total volume of propane we sell. Lack of consumer demand for propane may also adversely affect the retailers we transact with in our wholesale propane marketing operations, exposing us to their inability to satisfy their contractual obligations to us.

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If we fail to balance our purchases of natural gas and our sales of residue gas and NGLs, our exposure to commodity price risk will increase.

We may not be successful in balancing our purchases of natural gas and our sales of residue gas and NGLs. In addition, a producer could fail to deliver promised volumes to us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance between our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income.

Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes that are hedged decreases substantially over time.

We have entered into derivative transactions related to only a portion of our equity volumes. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a reduction of our liquidity. The percentages of our expected equity volumes that are covered by our hedges decrease over time. The derivative instruments we utilize for these hedges are based on posted market prices, which may be lower than the actual natural gas, NGL and condensate prices that we realize in our operations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certain circumstances may actually increase the variability of our cash flows. To the extent we hedge our commodity price risk, we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. For additional information regarding our hedging activities, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Quantitative and Qualitative Disclosures about Market Risk.”

If third-party pipelines and other facilities interconnected to our natural gas pipelines and facilities become partially or fully unavailable to transport natural gas and NGLs, our revenues could be adversely affected.

We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and processing and fractionation facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport natural gas and NGLs, or if the gas quality specifications for their pipelines or facilities change so as to restrict our ability to transport gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies or integrated midstream energy companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers in the gathering and processing business, as well as the natural gas logistics and marketing business, at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

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We typically do not obtain independent evaluations of natural gas reserves dedicated to our gathering pipeline systems; therefore, volumes of natural gas on our systems in the future could be less than we anticipate.

We typically do not obtain independent evaluations of natural gas reserves connected to our gathering systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas transported on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas on our systems could have a material adverse effect on our business, results of operations, and financial condition.

A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect our business, results of operations and financial condition.

The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction in demand for NGL products, whether because of general economic conditions, new government regulations, reduced demand by consumers for products made with NGL products, increased competition from petroleum-based products due to pricing differences, mild winter weather or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we charge for our services. Our NGL products and their demand are affected as follows:

Ethane. Ethane is typically supplied as purity ethane and as part of ethane-propane mix. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be more profitable for natural gas producers to leave the ethane in the natural gas stream thereby reducing the volume of NGLs delivered for fractionation and marketing. We have experienced periods where natural gas producers have retained ethane in the natural gas stream and may experience such periods in the future.

Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and in agricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heating season of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.

Normal Butane. Normal butane is used in the production of isobutane, as a refined product blending component, as a fuel gas, either alone or in a mixture with propane, and in the production of ethylene and propylene. Changes in the mandated composition of refined products, demand for heating fuel and for ethylene and propylene, could adversely affect demand for normal butane.

Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand for motor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.

Natural Gasoline. Natural gasoline is used as a blending component for certain refined products and as a feedstock used in the production of ethylene and propylene. Changes in the mandated composition of motor gasoline and in demand for ethylene and propylene could adversely affect demand for natural gasoline.

Any reduced demand for ethane, propane, normal butane, isobutane or natural gasoline for any of the reasons stated above could adversely affect demand for the services we provide as well as NGL prices, which would negatively impact our results of operations and financial condition.

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We have significant relationships with Chevron as a producer utilizing our gas processing operations, a purchaser of our NGLs and a customer for our marketing and refinery services. In some cases, these agreements are subject to renegotiation and termination rights.

We have several gas processing agreements with Chevron pursuant to which Chevron has dedicated, for the life of the fields, substantially all of the natural gas it produces from committed areas in New Mexico, Texas and the Gulf of Mexico. In 2006 and in the first nine months of 2007, approximately 19% and 21%, respectively, of our natural gas gathered for processing was from Chevron under these gas processing agreements. These contracts provide that either party has the right to periodically renegotiate the processing terms. If the parties are unable to agree on revised terms, then the agreements provide for the issue to be settled by binding arbitration. It is possible that the terms will be renegotiated or arbitrated on terms that are less favorable to us than the current terms of these agreements. In addition, to the extent that the volume of natural gas processed under these contracts declines as a result of depletion or otherwise, we would be adversely affected.

In 2006 and in the first nine months of 2007, approximately 28% and 24%, respectively, of our consolidated revenues and approximately 20% and 13%, respectively, of our consolidated cost of sales, were derived from transactions with Chevron and ChevronPhillipsCompany, or CPC. We are in the process of renegotiating our contracts with CPC. See “Business—Significant Customers.” Under many of our Chevron contracts where we purchase or market NGLs on Chevron’s behalf, Chevron may elect to terminate the contracts or renegotiate the price terms. To the extent Chevron reduces the volumes of NGLs that it purchases from us or reduces the volumes of NGLs that we market on its behalf, or to the extent the economic terms of such contracts are changed, our revenues and cash available for debt service could decline.

We do not own most of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own most of the land on which our pipelines and facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse or terminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts, leases or otherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere, and reduce our revenue.

We may be unable to cause our majority-owned joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.

We participate in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not take certain actions, even though taking or preventing those actions may be in the best interest of us or the particular joint venture.

In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.

If we lose our senior management or key business line personnel, our business may be adversely affected.

Our success is dependent upon the efforts of our senior management, as well as on our ability to attract and retain senior management. There is substantial competition for qualified personnel in the midstream natural gas

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industry. We may not be able to retain our existing senior management, fill new positions or vacancies created by expansion or turnover, or attract additional qualified senior management personnel. We have not entered into employment agreements with any of our key executive officers. In addition, we do not maintain “key man” life insurance on the lives of any members of our senior management. A loss of one or more of these key people could harm our business and prevent us from implementing our business strategy.

Weather may limit our ability to operate our business and could adversely affect our operating results.

The weather in the areas in which we operate can cause delays in our operations and, in some cases, work stoppages. For example, natural gas sales volumes for the nine months ended September 30, 2007 were negatively impacted by unseasonably wet weather, which limited our ability to complete connections to new wells. Any similar delays or work stoppages caused by the weather could adversely affect our operating results for the affected periods.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.

Our operations are subject to many hazards inherent in the gathering, compressing, treating, processing and transport ting of natural gas and the fractionation, storage and transportation of NGLs, including:

• damage to pipelines, plants, logistical assets and related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;

• inadvertent damage from third parties, including from construction, farm and utility equipment;

• leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities; and

• other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. For example, Hurricanes Katrina and Rita damaged gathering systems, processing facilities, NGL fractionators and pipelines along the Gulf Coast, including certain of our facilities. These hurricanes disrupted the operations of our customers in August and September 2005, which curtailed or suspended the operations of various energy companies with assets in the region. The size and complexity of insurance claims associated with these storms resulted in longer than anticipated delays in some recoveries of insurance proceeds and these delays and any ultimate failure to recover insurance proceeds could adversely affect our financial results. We are not fully insured against all risks inherent to our business. We are not insured against all environmental accidents that might occur which may include toxic tort claims, other than those considered to be sudden and accidental. If a significant accident or event occurs that is not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements increased substantially, and terms generally are less favorable than terms that could be obtained prior to such hurricanes. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

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Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time.

Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

With the exception of our interest in Venice Gathering System, L.L.C., or VGS, we are generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still affects our businesses and the markets for products derived from those businesses. FERC has recently proposed to require intrastate pipelines, possibly including natural gas gathering pipelines, to comply with certain Internet posting requirements, with the goal of promoting transparency in the interstate natural gas market. FERC has not yet issued a final rule on that proposed rulemaking. We may experience an increase in costs if the rule is adopted as proposed.

Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportation capacity.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. In addition, the courts have determined that certain pipelines that would otherwise be subject to the Interstate Commerce Act of 1887, or ICA, are exempt from regulation by the FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classification and regulation of some of our gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, or EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation.

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State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and as a number of such companies have transferred gathering facilities to unregulated affiliates. The states we operate in have adopted regulations that generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering and intrastate transportation pipeline access and rate discrimination. Our gathering and intrastate transportation operations could be adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. These operations may also be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowables from natural gas wells. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business. For more information regarding regulation of Targa’s operations, please read “Business—Regulation.”

We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances or hydrocarbons into the environment.

Our natural gas gathering, treating, fractionating and processing operations are subject to stringent and complex federal, state and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws include, for example, (1) the federal Clean Air Act and comparable state laws that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling, storage, treatment or disposal of solid and hazardous waste from our facilities, (3) the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which our wastes have been transported for disposal, and (4) the Federal Water Pollution Control Act, also know as the Clean Water Act, and comparable state laws that regulate discharges of wastewater from our facilities to state and federal waters. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations or imposing additional compliance requirements on such operations. Certain environmental laws, including CERCLA and analogous state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

There is inherent risk of incurring environmental costs and liabilities in connection with our operations due to our handling of natural gas and other petroleum products, air emissions and water discharges related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our

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operational or compliance costs and the cost of any remediation that may become necessary. In particular, we may incur expenditures in order to maintain compliance with legal requirements governing emissions of air pollutants from our facilities. We may not be able to recover all or any of these costs from insurance. Please see “Business—Environmental and Other Matters” for more information.

We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas,” including high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release and commercially navigable waterways, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators of covered pipelines to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventive and mitigating actions.

We currently estimate that we will incur an aggregate cost of approximately $10.2 million for years 2007 through 2009 to implement necessary pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines required by existing DOT and state regulations. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliance with this regulation, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. Following this initial round of testing and repairs, we will continue our pipeline integrity testing programs to assess and maintain the integrity or our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our pipelines.

We are controlled by a major stockholder, whose interests may conflict with the interests of the holders of the notes.

Warburg Pincus beneficially owns approximately 74% of the outstanding voting stock of our parent. Warburg Pincus is able to elect members of our board of directors, appoint new management and approve any action requiring the approval of our stockholders, including amendment of our certificate of incorporation and mergers or sales of substantially all of our assets. The directors elected by Warburg Pincus will be able to make decisions affecting our capital structure, including decisions to issue additional capital stock, implement stock repurchase programs and declare dividends. Our interests and the interests of our affiliates could conflict with your interests. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of our equity holders might conflict with your interests as a note holder. In addition, our equity holders may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in their judgment, could enhance their equity investments, even though such transactions might involve risks to you as a holder of the notes. Furthermore, Warburg Pincus may in the future own businesses that directly compete with our business. In addition, the indenture governing the notes contains significant exceptions to the covenant governing transactions with affiliates, including an exception for permitted investments, which would allow such investments in entities controlled by Warburg Pincus without any restriction. None of our stockholders has any obligation to provide us with any additional debt or equity financing.

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If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition, potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.

Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely and reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financial reporting capabilities. These enhancements will require a significant commitment of additional resources, hiring additional personnel and developing formalized internal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could prevent us from timely and reliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material effect on our business, results of operations, financial condition and ability to pay our note holders.

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

In connection with the issuance of the outstanding notes, we entered into a registration rights agreement. Under the registration rights agreement, we agreed to file, within two years after the original issuance of the outstanding notes on October 31, 2005, a registration statement, of which this prospectus is a part, with the SEC with respect to a registered offer to exchange each outstanding note for a new note having terms substantially identical in all material respects to such outstanding note except that the new note will not contain terms with respect to transfer restrictions, registration rights or additional interest. We also agreed to use commercially reasonable efforts to:

• cause the registration statement to be declared effective under the Securities Act within 870 days after the original issuance of the outstanding notes;

• as soon as practicable after the effectiveness of the registration statement, offer the new notes in exchange for surrender of the outstanding notes;

• keep the exchange offer open for not less than 20 business days (or longer if required by applicable law) after the date notice of the exchange offer is mailed to the holders of the outstanding notes;

• if the exchange offer is effected, consummate the exchange offer not later than 910 days (or if the 910th day is not a business day, the first business day thereafter) after the original issuance of the outstanding notes; and

• keep the registration statement effective, and amend and supplement this prospectus in order to permit such prospectus to be lawfully delivered by all persons subject to the prospectus delivery requirements of the Securities Act for such period of time as such persons must comply with such requirements in order to resell the new notes, subject to certain extensions and limitations set forth in the registration rights agreement.

We have fulfilled our agreement to file the exchange offer registration statement and are now offering eligible holders of the outstanding notes the opportunity to exchange their outstanding notes for new notes registered under the Securities Act. Holders are eligible if they are not prohibited by any law or policy of the SEC from participating in this exchange offer.

Under limited circumstances, we agreed to use commercially reasonable efforts to cause the SEC to declare effective a shelf registration statement for the resale of the outstanding notes. We also agreed to use commercially reasonable efforts to keep the shelf registration statement effective for up to two years after the date of the original issuance of the outstanding notes, subject to certain extensions and limitations set forth in the registration rights agreement. The circumstances include if:

• a change in law or in applicable interpretations of the staff of the SEC do not permit us to effect the exchange offer;

• for any other reason the exchange offer is not consummated within 910 days from October 31, 2005, the date of the original issuance of the outstanding notes;

• an initial purchaser notifies us following consummation of the exchange offer that outstanding notes held by it are not eligible to be exchanged for new notes in the exchange offer;

• any holder, other than an exchanging dealer, notifies us within 30 days after the consummation of the exchange offer that it is prohibited by law or SEC policy from participating in such exchange offer; or

• any holder, other than an exchanging dealer, that participates in the exchange offer may not resell the new notes acquired by it in the exchange offer to the public without delivering a prospectus and so notifies us within 30 days after such holder first becomes aware of such restrictions.

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Subject to certain exceptions, we will pay additional cash interest on the applicable outstanding notes if:

• the exchange offer registration statement is not declared effective by the SEC on or prior to the 870th day after the original issuance of the outstanding notes;

• the exchange offer is not consummated on or prior to the 40th day after the exchange offer registration statement is declared effective;

• we are obligated to file a shelf registration statement as a result of a change in law or in applicable interpretations of the staff of the SEC do not permit us to effect the exchange offer and the shelf registration statement is not declared effective on or prior to the 910th day after the original issuance of the outstanding notes;

• we are obligated to file a shelf registration statement for any other reason, we fail to file the shelf registration statement with the SEC on or prior to the 60^th day after the date on which the obligation to file a shelf registration statement arises or the shelf registration statement is not declared effective on or prior to the 90^th day after the date the shelf registration statement is filed;

• after this registration statement or the shelf registration statement, as the case may be, is declared effective, such registration statement thereafter ceases to be effective; or

• after this registration statement or the shelf registration statement, as the case may be, is declared effective, such registration statement or the related prospectus ceases to be usable in connection with certain resales during certain periods because either (i) an event occurs as a result of which the prospectus would include an untrue statement of a material fact or omit to state a material fact necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading or (ii) it is necessary to amend such registration statement or supplement the prospectus to comply with the Securities Act or the Exchange Act or the respective rules thereunder.

Each event referred to in the first, second and fourth bullet points above is a “registration default.” Such additional interest will be payable from and including the date on which any such registration default occurs to the date on which all registration defaults have been cured.

The rate of the additional interest will be 0.25% per year for the first 90-day period immediately following the occurrence of a registration default, and such rate will increase by an additional 0.25% per year with respect to each subsequent 90-day period until all registration defaults have been cured, up to a maximum additional interest rate of 1.0% per year. We will pay such additional interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the outstanding notes and the new notes.

To exchange your outstanding notes for transferable new notes in the exchange offer, you will be required to make the following representations:

• any new notes will be acquired in the ordinary course of your business;

• you have no arrangement or understanding with any person to participate in the distribution of the new notes;

• you are not our “affiliate,” as defined in Rule 405 of the Securities Act, or, if you are our “affiliate,” as defined in Rule 405 of the Securities Act, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;

• if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the new notes; and

• if you are a broker-dealer, you will receive new notes for your own account in exchange for outstanding notes that you acquired as a result of market-making activities or other trading activities and you will comply with the applicable provisions of the Securities Act including, but not limited to, delivery of a prospectus in connection with any resale of such new notes; see “Plan of Distribution.”

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In addition, we may require you to provide information to be used in connection with the shelf registration statement to have your outstanding notes included in the shelf registration statement. A holder who sells outstanding notes under the shelf registration statement generally will be required to be named as a selling securityholder in the related prospectus and to deliver a prospectus to purchasers. Such a holder will also be subject to the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such a holder, including indemnification obligations.

The description of the registration rights agreement contained in this section is a summary only. For more information, you should review the provisions of the registration rights agreement that we filed with the SEC as an exhibit to the registration statement of which this prospectus is a part.

Resale of New Notes

Based on no-action letters of the SEC staff issued to third parties, we believe that new notes may be offered for resale, resold and otherwise transferred by holders, other than broker-dealers, without further compliance with the registration and prospectus delivery provisions of the Securities Act if:

• you are not our “affiliate” within the meaning of Rule 405 under the Securities Act;

• such new notes are acquired in the ordinary course of your business; and

• you do not intend to participate in a distribution of the new notes.

The SEC, however, has not considered the exchange offer for the new notes in the context of a no-action letter, and the SEC may not make a similar determination as in the no-action letters issued to these third parties.

If you tender in the exchange offer with the intention of participating in any manner in a distribution of the new notes, you

• cannot rely on such interpretations by the SEC staff; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction.

Unless an exemption from registration is otherwise available, any security holder intending to distribute new notes should be covered by an effective registration statement under the Securities Act. The registration statement should contain the selling security holder’s information required by Item 507 of Regulation S-K under the Securities Act.

This prospectus may be used for an offer to resell or other retransfer of new notes only as specifically described in this prospectus. Failure to comply with the registration and prospectus delivery requirements by a holder subject to these requirements could result in that holder incurring liability for which it is not indemnified by us. If you are a broker-dealer, you may participate in the exchange offer only if you acquired the outstanding notes as a result of market-making activities or other trading activities. Each broker-dealer that receives new notes for its own account in exchange for outstanding notes, where such outstanding notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge in the letter of transmittal that it will deliver a prospectus in connection with any resale of the new notes. Please read the section captioned “Plan of Distribution” for more details regarding the transfer of new notes.

Terms of the Exchange Offer

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any outstanding notes properly tendered and not withdrawn prior to 5:00 p.m. New York City time on the expiration date. We will issue new notes in principal amount equal to the principal amount of outstanding notes surrendered under the exchange offer. Outstanding notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000.

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The exchange offer is not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered for exchange.

As of the date of this prospectus, $250 million in aggregate principal amount of the outstanding notes are outstanding. This prospectus is being sent to DTC, the sole registered holder of the outstanding notes, and to all persons that we can identify as beneficial owners of the outstanding notes. There will be no fixed record date for determining registered holders of outstanding notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement and the applicable requirements of the Securities Act, the Securities Exchange Act of 1934 and the rules and regulations of the SEC. Outstanding notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These outstanding notes will be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered outstanding notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender outstanding notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of outstanding notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read the section labeled “—Fees and Expenses” for more details regarding fees and expenses incurred in the exchange offer.

We will return any outstanding notes that we do not accept for exchange for any reason without expense to their tendering holder as promptly as practicable after the expiration or termination of the exchange offer.

Expiration Date

The exchange offer will expire at 5:00 p.m. New York City time on January 24, 2008, unless, in our sole discretion, we extend it.

Extensions, Delays in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. During any such extensions, all outstanding notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of outstanding notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

If any of the conditions described below under “—Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion

• to delay accepting for exchange any outstanding notes,

• to extend the exchange offer, or

• to terminate the exchange offer,

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

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Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of outstanding notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the outstanding notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we will extend the exchange offer if the exchange offer would otherwise expire during such period.

Conditions to the Exchange Offer

We will not be required to accept for exchange, or exchange any new notes for, any outstanding notes if the exchange offer, or the making of any exchange by a holder of outstanding notes, would violate applicable law or any applicable interpretation of the staff of the SEC, or if a threatened or pending judicial or administrative proceeding impairs our ability to proceed with the exchange offer. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting outstanding notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the outstanding notes of any holder that has not made to us the representations described under “—Purpose and Effect of the Exchange Offer,” “—Procedures for Tendering” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

Furthermore, we will not accept for exchange any outstanding notes tendered, and will not issue new notes in exchange for any such outstanding notes, if at such time any stop order has been threatened or is in effect with respect to (1) the registration statement of which this prospectus constitutes a part or (2) the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the outstanding notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

Procedures for Tendering

In order to participate in the exchange offer, you must properly tender your outstanding notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your notes, please call the exchange agent, whose address and phone number are set forth in “Prospectus Summary—The Exchange Offer—Exchange Agent.”

All of the outstanding notes were issued in book-entry form, and all of the outstanding notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the outstanding notes may be tendered using DTC’s Automated Tender Offer Program (ATOP). The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the

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exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their outstanding notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender outstanding notes and that the participant has received and agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange outstanding notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

There is no procedure for guaranteed delivery of the outstanding notes.

Determinations Under the Exchange Offer

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered outstanding notes and withdrawal of tendered outstanding notes. Our determination will be final and binding. We reserve the absolute right to reject any outstanding notes not properly tendered or any outstanding notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular outstanding notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of outstanding notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of outstanding notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of outstanding notes will not be deemed made until such defects or irregularities have been cured or waived. Any outstanding notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date.

When We Will Issue New Notes

In all cases, we will issue new notes for outstanding notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

• a book-entry confirmation of such outstanding notes into the exchange agent’s account at DTC; and

• a properly transmitted agent’s message.

Return of Outstanding Notes Not Accepted or Exchanged

If we do not accept any tendered outstanding notes for exchange or if outstanding notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged outstanding notes will be returned without expense to their tendering holder. Such non-exchanged outstanding notes will be credited to an account maintained with DTC. These actions will occur as promptly as practicable after the expiration or termination of the exchange offer.

Your Representations to Us

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

• any new notes will be acquired in the ordinary course of your business;

• you have no arrangement or understanding with any person to participate in the distribution of the new notes;

• you are not our “affiliate,” as defined in Rule 405 of the Securities Act, or, if you are our “affiliate,” as defined in Rule 405 of the Securities Act, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;

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• if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the new notes; and

• if you are a broker-dealer, you will receive new notes for your own account in exchange for outstanding notes that you acquired as a result of market-making activities or other trading activities and you will comply with the applicable provisions of the Securities Act including, but not limited to, delivery of a prospectus in connection with any resale of such new notes; see “Plan of Distribution.”

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m. New York City time on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC’s ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn outstanding notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any outstanding notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any outstanding notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the outstanding notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn outstanding notes by following the procedures described under “—Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the expiration date.

Exchange Agent

Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance and requests for additional copies of this prospectus or of the letter of transmittal should be directed to the exchange agent addressed as follows:

WELLS FARGO BANK, NATIONAL ASSOCIATION

By Registered and Certified Mail	By Overnight Courier or Regular Mail:	By Hand Delivery
Wells Fargo Bank, N.A.	Wells Fargo Bank, N.A.	Wells Fargo Bank, N.A.
Corporate Trust Operations	Corporate Trust Operations	Corporate Trust Services
MAC N9303-121	MAC N9303-121	608 2nd Avenue South
P.O. Box 1517	6th & Marquette Avenue	Northstar East Building - 12th Floor
Minneapolis, MN 55480	Minneapolis, MN 55479	Minneapolis, MN 55402

Or

By Facsimile Transmission:

(612) 667-6282

Telephone:

(800) 344-5128

Delivery of the letter of transmittal to an address other than as set forth above or transmission of such letter of transmittal via facsimile other than as set forth above does not constitute a valid delivery of the letter of transmittal.

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Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by telephone or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out of pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

• SEC registration fees;

• fees and expenses of the exchange agent and trustee;

• accounting and legal fees and printing costs; and

• related fees and expenses.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of outstanding notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of outstanding notes under the exchange offer.

Consequences of Failure to Exchange

If you do not exchange new notes for your outstanding notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the outstanding notes. In general, you may not offer or sell the outstanding notes unless the offer or sale is either registered under the Securities Act or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the outstanding notes under the Securities Act.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the outstanding notes. This carrying value is the aggregate principal amount of the outstanding notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Other

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered outstanding notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any outstanding notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered outstanding notes.

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any cash proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive outstanding notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the outstanding notes, except the new notes do not include certain transfer restrictions. Outstanding notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in our outstanding indebtedness.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The following table summarizes selected historical financial and operating data of Targa and the predecessor for the periods and as of the dates indicated. The selected historical financial information included in this prospectus reflects the unaudited results of operations of Targa as of and for the nine months ended September 30, 2007 and 2006, and the audited results of operations of Targa as of and for the years ended December 31, 2006, 2005 and 2004, and is derived from the audited consolidated financial statements of Targa. Targa’s consolidated financial results for the year ended December 31, 2004 includes the results of operations for the eight and a half month period commencing with its April 16, 2004 acquisition of the predecessor business from ConocoPhillips, combined with the acquisition-related activities of Targa for the period from January 1 to April 15, 2004.

The selected combined historical financial information of the predecessor as of and for the years ended December 31, 2002 and 2003 and as of and for the three and a half months ended April 15, 2004 is derived from the audited financial statements of the predecessor. The historical financial statements of the predecessor were prepared on a going-concern basis, as if certain midstream assets of ConocoPhillips, which Targa acquired on April 16, 2004, had existed as an entity separate from ConocoPhillips during the periods presented. The assets acquired from ConocoPhillips were not a separate legal entity during the periods presented. During the periods presented, ConocoPhillips charged the predecessor operations a portion of its corporate support costs, including engineering, legal, treasury, planning, environmental, tax, auditing, information technology and other corporate services, based on usage, actual costs or other allocation methods considered reasonable by ConocoPhillips management. Accordingly, expenses included in the predecessor’s financial statements may not be indicative of the level of expenses that might have been incurred had the predecessor been operating as a separate stand-alone company.

This information should be read together with and is qualified in its entirety by reference to, the historical combined financial statements and the accompanying notes included elsewhere in this prospectus. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operation” for a discussion of factors that affect the comparability of the information reflected in the selected financial and operating data.

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(in thousands)	Targa Resources, Inc.															Predecessor
	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005(1)			Year Ended December 31, 2004(2)			Three and a Half Months Ended April 15, 2004			Year Ended December 31, 2003			Year Ended December 31, 2002
Statement of Operations Data:
Revenues(3)	$	4,923,416		$	4,699,283		$	6,132,881		$	1,829,027		$	602,376		$	232,769		$	724,667		$	541,195
Costs and expenses
Product purchases		4,373,289			4,174,895			5,440,832			1,631,963			544,918			212,306			665,357			479,682
Operating expenses(4)		179,837			160,554			224,169			52,090			15,253			9,257			27,552			29,146
Depreciation and amortization		110,757			110,938			149,687			27,141			10,631			3,833			12,866			9,791
General and administrative		78,126			64,860			82,351			28,275			11,149			757			3,289			3,281
Total costs and expenses		4,742,009			4,511,247			5,897,039			1,739,469			581,951			226,153			709,064			521,900
Operating income		181,407			188,036			235,842			89,558			20,425			6,616			15,603			19,295
Other income (expense):
Interest expense, net		(112,752	)		(133,245	)		(180,189	)		(39,856	)		(6,406	)		—			—			—
Equity in earnings of unconsolidated investments		7,964			5,403			9,968			(3,776	)		2,370			—			—			—
Gain on sale of investment in Bridgeline(5)		—			—			—			18,008			—			—			—			—
Loss on mark-to-market derivative contracts		—			—			—			(73,950	)		—			—			—			—
Loss on early debt extinguishment		—			—			—			(3,375	)		—			—			—			—
Minority interest		(20,492	)		(22,403	)		(25,998	)		(7,361	)		—			—			—			—
Non-controlling interest in Targa Resources Partners LP		(6,628	)		—			—			—			—			—			—			—
Income (loss) before income taxes		49,499			37,791			39,623			(20,752	)		16,389			6,616			15,603			19,295
Income tax (expense) benefit		(13,170	)		(16,365	)		(16,209	)		6,537			(5,227	)		(2,567	)		(6,062	)		(7,475	)
Net income (loss)		36,329			21,426			23,414			(14,215	)		11,162			4,049			9,541			11,820
Dividends on redeemable preferred stock		—			—			—			(7,167	)		(5,829	)		—			—			—
Net income (loss) to common stock	$	36,329		$	21,426		$	23,414		$	(21,382	)	$	5,333		$	4,049		$	9,541		$	11,820
Balance Sheet Data (end of period):
Current assets	$	997,168		$	822,497		$	859,657		$	827,575		$	92,496		$	22,810		$	47,974		$	16,706
Total assets		3,554,511			3,437,825			3,458,025			3,396,586			443,213			288,821			316,790			313,289
Current liabilities		747,926			571,020			1,303,730			575,985			131,143			29,179			50,579			48,928
Long-term debt, less current maturities		1,757,000			2,175,000			1,471,875			2,184,375			157,473			—			—			—
Other long-term liabilities		83,907			66,160			66,622			89,135			12,508			88,781			88,947			94,807
Total liabilities		2,588,833			2,812,180			2,842,227			2,849,495			301,124			117,960			139,526			143,735
Minority interest		471,673			105,703			101,528			112,714			—			—			—			—
Redeemable preferred stock		—			—			—			—			135,050			—			—			—
Total stockholder’s equity(6)		494,005			519,942			514,270			434,377			7,039			170,861			177,264			169,554
Total liabilities and stockholder’s equity		3,554,511			3,437,825			3,458,025			3,396,586			443,213			288,821			316,790			313,289
Other Financial Data:
Net cash provided by (used in):
Operating activities	$	136,824		$	181,597		$	233,286		$	108,855		$	33,135		$	11,480		$	(6,349	)	$	43,454
Investing activities		(82,259	)		(96,055	)		(117,812	)		(2,328,916	)		(353,234	)		(1,176	)		(2,413	)		(11,407	)
Financing activities		(44,896	)		(10,023	)		(14,162	)		2,250,621			330,676			(10,304	)		8,762			(32,047	)
Capital expenditures, excluding acquisitions		95,646			109,730			142,902			21,976			5,499			1,176			2,413			11,407
EBITDA(7)		273,008			281,974			369,499			46,245			33,426			10,449			28,469			29,086
Operating margin(7)		370,290			363,834			467,880			144,974			42,205			11,206			31,758			32,367

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(in thousands)	Targa Resources, Inc.															Predecessor
	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005(1)			Year Ended December 31, 2004(2)			Three and a Half Months Ended April 15, 2004			Year Ended December 31, 2003			Year Ended December 31, 2002
Operating Statistics(8)
Consolidated
Natural gas sales volume, BBtu/d		526.6			504.3			501.2			313.5			252.7			297.4			279.7			324.9
Average realized natural gas price, $/MMBtu		6.58			6.95			6.61			8.45			6.45			5.42			5.30			3.19
Natural gas liquids sales volume, MBbl/d		309.3			299.6			300.2			59.8			22.8			24.8			24.6			29.7
Average realized natural gas liquids price, $/gal		1.08			1.05			1.02			0.85			0.70			0.55			0.50			0.36
Natural Gas Gathering and Processing
Gathering throughput volume, MMcf/d		1,992.9			2,046.2			1,871.7			477.9			285.6			316.5			294.8			379.9
Plant inlet volume, MMcf/d		1,949.7			1,875.0			1,841.5			400.8			262.6			313.5			296.9			346.0
Natural gas sales volume, BBtu/d		544.3			521.6			517.8			313.5			252.7			297.4			279.7			324.9
Average realized natural gas price, $/MMBtu		6.58			6.93			6.61			8.45			6.45			5.42			5.30			3.19
Natural gas liquids sales volume, MBbl/d		90.6			88.7			89.8			29.0			22.8			24.8			24.6			29.7
Average realized natural gas liquids price, $/gal		0.96			0.89			0.88	��		0.85			0.70			0.55			0.50			0.36
Logistics Assets
Fractionation volume, MBbl/d		207.3			186.6			181.9			23.7			N/A			N/A			N/A			N/A
Terminalling and storage volume, MBbl/d		338.9			378.8			373.1			56.3			N/A			N/A			N/A			N/A
Transport volume, MBbl/d		35.1			35.2			34.8			5.6			N/A			N/A			N/A			N/A
NGL Distribution and Marketing Services
Natural gas liquids sales volume, MBbl/d		267.1			244.5			246.30			30.80			N/A			N/A			N/A			N/A
Average realized natural gas liquids price, $/gal		1.06			1.02			0.99			1.00			N/A			N/A			N/A			N/A
Wholesale Marketing
Natural gas liquids sales volume, MBbl/d		59.1			73.9			74.4			16.5			N/A			N/A			N/A			N/A
Average realized natural gas liquids price, $/gal		1.19			1.18			1.16			1.18			N/A			N/A			N/A			N/A
Reconciliation of EBITDA to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	$	136,824		$	181,597		$	233,286		$	108,855		$	33,135		$	11,480		$	(6,349	)	$	43,454
Interest expense, net		112,752			133,245			180,189			39,856			6,406			—			—			—
Amortization of debt issue costs		(10,846	)		(9,737	)		(13,001	)		(6,742	)		(956	)		—			—			—
Amortization of issue discount		—			—			—			(531	)		(113	)		—			—			—
Current income tax expense (benefit)		1,289			—			34			205			—			3,215			5,182			6,109
Changes in operating working capital which (provided) used cash:
Accounts receivable and other assets		129,848			(17,075	)		2,052			97,135			77,843			(25,164	)		31,275			(5,155	)
Inventory		27,639			(26,064	)		(23,407	)		16,756			381			—			(7	)		(128	)
Accounts payable and other liabilities		(138,989	)		(6,714	)		(37,043	)		(138,941	)		(85,210	)		21,400			(1,651	)		(14,830	)
Other		14,491			26,722			27,389			(70,348	)		1,940			(482	)		19			(364	)
EBITDA	$	273,008		$	281,974		$	369,499		$	46,245		$	33,426		$	10,449		$	28,469		$	29,086
Reconciliation of EBITDA to net income (loss):
Net income (loss)	$	36,329		$	21,426		$	23,414		$	(14,215	)	$	11,162		$	4,049		$	9,541		$	11,820
Add:
Interest expense, net		112,752			133,245			180,189			39,856			6,406			—			—			—
Income tax expense (benefit)		13,170			16,365			16,209			(6,537	)		5,227			2,567			6,062			7,475
Depreciation and amortization expense		110,757			110,938			149,687			27,141			10,631			3,833			12,866			9,791
EBITDA	$	273,008		$	281,974		$	369,499		$	46,245		$	33,426		$	10,449		$	28,469		$	29,086

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(in thousands)	Targa Resources, Inc.												Predecessor
	Nine Months Ended September 30, 2007		Nine Months Ended September 30, 2006		Year Ended December 31, 2006		Year Ended December 31, 2005 (1)			Year Ended December 31, 2004 (2)			Three and a Half Months Ended April 15, 2004		Year Ended December 31, 2003		Year Ended December 31, 2002
Reconciliation of operating margin to net income (loss):
Net income (loss)	$	36,329	$	21,426	$	23,414	$	(14,215	)	$	11,162		$	4,049	$	9,541	$	11,820
Add:
Depreciation and amortization expense		110,757		110,938		149,687		27,141			10,631			3,833		12,866		9,791
Income tax expense (benefit)		13,170		16,365		16,209		(6,537	)		5,227			2,567		6,062		7,475
Other, net		19,156		17,000		16,030		70,454			(2,370	)		—		—		—
Interest expense, net		112,752		133,245		180,189		39,856			6,406			—		—		—
General and administrative expense		78,126		64,860		82,351		28,275			11,149			757		3,289		3,281
Operating margin	$	370,290	$	363,834	$	467,880	$	144,974		$	42,205		$	11,206	$	31,758	$	32,367

(1) Reflects acquisition of DMS effective October 31, 2005.

(2) Targa commenced operations on April 16, 2004 with the closing of the acquisition of certain assets in Texas and Louisiana from ConocoPhillips. Prior to April 16, 2004, certain investors in Targa had previous investments in Pipeco, f.k.a. Targa Resources, Inc., f.k.a. Warburg Pincus VIII Development Company, Inc. Pipeco was the entity that performed due diligence and other acquisition-specific activities associated with the asset acquisitions from ConocoPhillips.

Pipeco and Targa are considered “entities under common control” as defined under GAAP and, as such, Targa’s audited financial results also include the results of Pipeco for the year ended December 31, 2004.

(3) For Targa, the amount includes $83 million, $9 million, and $1 million of transactions with affiliates for the years ended December 31, 2006, 2005, and 2004, respectively. For the predecessor, the amount includes $113 million, $558 million, and $322 million of transactions with affiliates for the three and a half months ended April 15, 2004, and for the years ended December 31, 2003 and 2002, respectively.

(4) Includes taxes other than income taxes for the predecessor’s financial information.

(5) In August 2005 we sold our 40% interest in Bridgeline for $117.0 million in cash.

(6) The comparable line-item in the predecessor’s historical financial statements is “Parent company investment.”

(7) We define EBITDA as net income before interest, income taxes, depreciation, and amortization. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks, and others, to assess:

• the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

• our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

The economic substance behind management’s use of EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions to our investors.

EBITDA is not a presentation made in accordance with generally accepted accounting principles (“GAAP’) and has important limitations as an analytical tool. The GAAP measures most directly comparable to EBITDA are net cash provided by operating activities and net income. Our non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. You should not consider EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA excludes some, but not all items that affect GAAP net income and GAAP net cash provided by operating activities and is defined differently by different companies in our industry, our definition of EBITDA may not be comparable to similarly titled measures of other companies.

Management compensates for the limitations of EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures, and considering such differences in management’s decision-making processes.

We define operating margin as total operating revenues, which consist of natural gas and natural gas liquids (“NGL”) sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas and NGL purchases, less operating expense. Management reviews operating margin monthly for consistency and trend analysis. Based on this monthly analysis, management takes appropriate action to maintain positive trends or to reverse negative trends. Management uses operating margin as an important measure of the core profitability of our operations.

The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all items that affect net income and is defined differently by different companies in our industry, our definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

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Management compensates for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures, and considering such differences in management’s decision-making processes.

We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Operating margin provides useful information to investors because it is used as a supplemental financial measure by our management and by external users of our financial statements, including such investors, commercial banks, and others, to assess:

• the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;

• our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

(8) 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. Volumes from assets acquired in the DMS acquisition are included from the acquisition date, October 31, 2005. NGL-related statistics include condensate.

Gathering throughput consists of natural gas volumes gathered from wellheads and central delivery points directly connected to gathering systems. We sometimes supplement gathering throughput with natural gas purchased from third parties and natural gas gathered by third parties and these combined volumes flow to the processing facilities. This combined volume, less fuel consumption and loss and less direct resales of unprocessed or bypassed gas, comprises plant inlet volumes. Plant inlet volumes, less additional fuel consumption and loss, less natural gas volume processed into NGLs and less volumes contractually redelivered to third party gatherers and producers, comprise natural gas sales. NGL sales are equivalent to the amount of NGL recovered from natural gas, less NGL contractually redelivered to third parties and producers.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATION

General Overview

We are a Delaware corporation formed in 2004 by our management team and Warburg Pincus to acquire, own and operate assets in the midstream natural gas business. Since our formation, we have made the following significant acquisitions and dispositions, the impact of which is central to an understanding of our historical and anticipated results of operations:

• in April 2004, we purchased certain midstream natural gas assets located in west Texas and South Louisiana from ConocoPhillips for $247 million;

• in December 2004, we purchased a 40% interest in Bridgeline from Enron for $101 million including acquisition-related costs;

• in August 2005, we sold our 40% interest in Bridgeline to Chevron for $117 million;

• in October 2005, we acquired Dynegy Midstream Services, Limited Partnership (“DMS”) for approximately $2,452 million, including acquisition-related costs of $11 million. The north Texas natural gas gathering and processing assets (“North Texas”) we acquired were initially classified as “held for sale”;

• in September 2006, we reclassified North Texas from “held for sale” to “held for use;”

• in February 2007, we contributed North Texas to the Partnership and completed an initial public offering of Partnership common units. We retained a controlling 38.6% interest in the Partnership; and

• in October 2007, we sold Permian Basin and South Louisiana natural gas gathering assets to the Partnership in connection with its sale of additional common units.

• in November 2007, the Partnership sold an additional 1,800,000 common units pursuant to the partial exercise by the underwriters of their over-allotment option and used the net proceeds to repay a portion of its outstanding indebtedness.

We are an integrated midstream energy company and offer a range of midstream services to producers and consumers of natural gas and natural gas liquids. 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. Additionally, our natural gas liquids 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 own or operate approximately 10,000 miles of natural gas pipelines and approximately 550 miles of NGL pipelines, with natural gas gathering systems covering approximately 14,500 square miles and 21 natural gas processing plants with access to natural gas supplies in the Permian Basin, north Texas, onshore southern Louisiana and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with 16 storage marine and transport terminals with above ground NGL storage capacity of approximately 900 MBbls, net NGL fractionation capacity of approximately 300 MBbls/d and 43 owned and operated storage wells with a net storage capacity of approximately 65 MMBbls.

How We Measure and Evaluate Our Operations

We conduct our business through two divisions and report our results of operations under four segments as follows:

• the Natural Gas Gathering and Processing division, which 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;

38

• NGL Distribution and Marketing, and

• Wholesale Marketing.

Our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the natural gas and NGLs we sell, and the costs associated with conducting our operations, including the costs of natural gas and NGLs we purchase as well as operating and general and administrative costs. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for natural gas and NGLs, our hedging program and the natural gas and NGL throughput on our system are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, demand for our products, changes in our customer portfolio and the effect of changing commodity prices on the value of our inventory. For a discussion of our contract portfolio and the effects of commodity prices on our results of operations, please read “—Contractual Arrangements” and “Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk.”

To evaluate and manage our business, our management uses a variety of financial and operational measurements. These measurements, some of which are described below, enable our management to monitor our results of operations and profitability.

Throughput and Marketed Volumes, Facility Efficiencies and Fuel Consumption.For our Natural Gas Gathering and Processing division, our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our systems. This is achieved by connecting new wells as well as by capturing supplies currently gathered by third-parties. These supplies are contracted based on the competitive dynamics of the area and producer preference. In addition, we generally seek to increase operating margins and meet producing customer needs by limiting volume losses and reducing fuel consumption by increasing compression efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes of natural gas received at the wellhead or central delivery points along our gathering systems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. This information is tracked through our processing plants to determine customer settlements and helps us increase efficiency and reduce fuel consumption.

As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGL and residue gas produced at the outlet of such plants to monitor the fuel consumption and recoveries of the facilities. These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis.

For our NGL Logistics and Marketing division, we monitor volumes, NGL composition and similar factors that impact our segment margins. Similar to our processing plants, we monitor NGL throughput volumes, fuel consumption and recovery efficiencies at our fractionation facilities. For our sales and services businesses, we monitor (i) total NGL volumes and margins generated by such sales, measured as the difference between the price at which we purchase NGLs and the price at which we sell NGLs, (ii) inventory volumes across our businesses and (iii) general and administrative costs in these business lines, and the margin after allocation of such general and administrative costs, to ensure they are efficient and competitive.

Operating Margin. We review performance based on the non-generally accepted accounting principle (“non-GAAP”) financial measure of operating margin. We view our operating margin as an important performance measure of the core profitability of our operations. We review our operating margin monthly for consistency and trend analysis.

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With respect to our Natural Gas Gathering and Processing division, we define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases less operating expense. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges. Our Natural Gas Gathering and Processing segment operating margin is impacted by volumes and commodity prices as well as by our contract mix and hedging program, which are described in more detail below.

With respect to our NGL Logistics and Marketing division, we define operating margin as total revenue, which consists primarily of service fee revenues and NGL sales, less cost of sales, which consists primarily of NGL purchases and changes in inventory valuation. Within this division, our management analyzes segment operating margin for each of the three segments per unit of NGL handled or sold as an indicator of operational and commercial performance.

The GAAP measure most directly comparable to operating margin is net income. Our non-GAAP financial measure of operating margin should not be considered as an alternative to GAAP net income. Operating margin is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because operating margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of operating margin may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

We compensate for the limitations of operating margin as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into our decision-making processes.

We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results. Operating margin provides useful information to investors because it is used as a supplemental financial measure by us and by external users of our financial statements, including such investors, commercial banks and others, to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

Operating Expenses.Operating expenses are costs associated with the operation of a specific asset. Direct labor, ad valorem taxes, repair and maintenance, utilities and contract services compose the most significant portion of our operating expenses. These expenses generally remain relatively stable independent of the volumes through our systems but fluctuate depending on the scope of the activities performed during a specific period.

General and Administrative Expenses. General and administrative expenses (“G&A”) include the cost of employee compensation and related benefits, office lease and expenses, insurance, professional fees and information technology expenses, as well as other expenses not directly associated with our field operations. We also look at margin less business-specific G&A for the segments in the NGL Logistics and Marketing division where G&A reflects necessary personnel expense for the segments.

EBITDA.EBITDA is another non-GAAP financial measure that is used by us. We define EBITDA as net income before interest, income taxes, depreciation and amortization. EBITDA is used as a supplemental financial

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measure by us and by external users of our financial statements such as investors, commercial banks and others, to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and

• the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

The economic substance behind our use of EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.

The GAAP measures most directly comparable to EBITDA are net cash provided by operating activities and net income. Our non-GAAP financial measure of EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities and GAAP net income. EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. You should not consider EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of EBITDA may not be comparable to similarly titled measures of other companies.

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We compensate for the limitations of EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these learnings into our decision-making processes.

	Targa															Combined(1)			Predecessor
	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004			Year Ended December 31, 2004			Three and a Half Months Ended April 15, 2004
Reconciliation of EBITDA to net cash provided by (used in) operating activities:
Net cash provided by (used in) operating activities	$	136,824		$	181,597		$	233,286		$	108,855		$	33,135		$	44,615		$	11,480
Interest expense, net		112,752			133,245			180,189			39,856			6,406			6,406			—
Amortization of debt issue costs		(10,846	)		(9,737	)		(13,001	)		(6,742	)		(956	)		(956	)		—
Amortization of issue discount		—			—			—			(531	)		(113	)		(113	)		—
Current income tax expense (benefit)		1,289			—			34			205			—			3,215			3,215
Changes in operating working capital which (provided) used cash:
Accounts receivable and other assets		129,848			(17,075	)		2,052			97,135			77,843			52,679			(25,164	)
Inventory		27,639			(26,064	)		(23,407	)		16,756			381			381			—
Accounts payable and other liabilities		(138,989	)		(6,714	)		(37,043	)		(138,941	)		(85,210	)		(63,810	)		21,400
Other		14,491			26,722			27,389			(70,348	)		1,940			1,458			(482	)
EBITDA	$	273,008		$	281,974		$	369,499		$	46,245		$	33,426		$	43,875		$	10,449
Reconciliation of EBITDA to net income (loss):
Net income (loss)	$	36,329		$	21,426		$	23,414		$	(14,215	)	$	11,162		$	15,211		$	4,049
Add:
Interest expense, net		112,752			133,245			180,189			39,856			6,406			6,406			—
Income tax expense (benefit)		13,170			16,365			16,209			(6,537	)		5,227			7,794			2,567
Depreciation and amortization expense		110,757			110,938			149,687			27,141			10,631			14,464			3,833
EBITDA	$	273,008		$	281,974		$	369,499		$	46,245		$	33,426		$	43,875		$	10,449
Reconciliation of operating margin to net income (loss):
Net income (loss)	$	36,329		$	21,426		$	23,414		$	(14,215	)	$	11,162		$	15,211		$	4,049
Add:
Depreciation and amortization expense		110,757			110,938			149,687			27,141			10,631			14,464			3,833
Income tax expense (benefit)		13,170			16,365			16,209			(6,537	)		5,227			7,794			2,567
Other, net		19,156			17,000			16,030			70,454			(2,370	)		(2,370	)		—
Interest expense, net		112,752			133,245			180,189			39,856			6,406			6,406			—
General and administrative expense		78,126			64,860			82,351			28,275			11,149			11,906			757
Operating margin	$	370,290		$	363,834		$	467,880		$	144,974		$	42,205		$	53,411		$	11,206

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(1) See discussion of the presentation of the combined results of operations for the year ended December 31, 2004 at “—Results of Operations.”

Acquisition of DMS

On October 31, 2005, we acquired DMS for approximately $2,452 million, including certain acquisition-related costs. Under the terms of the agreement, we acquired Dynegy Inc.’s (“Dynegy”) ownership interests in DMS, which held Dynegy’s natural gas gathering and processing assets and its NGL fractionation, terminalling, storage, transportation, distribution and marketing assets.

We acquired DMS to expand our natural gas gathering and processing asset base in Texas, Louisiana and New Mexico and to gain greater access to marketing and distribution channels for our produced NGL.

We have accounted for the acquisition under the purchase method of accounting in accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 141, “Business Combinations.” The purchase price and the final allocation to assets and liabilities based on their estimated fair values as of October 31, 2005 are shown below (in thousands):

Purchase Price:
Cash purchase price	$	2,350,000
Cash collateral		90,703
Acquisition-related costs incurred		11,739
Total purchase price	$	2,452,442
Fair value of assets acquired and liabilities assumed:
Current assets, including cash of $34 million	$	601,915
Property, plant and equipment		2,231,503
Unconsolidated investments		21,195
Other assets		3,059
Current liabilities		(279,636	)
Other long-term liabilities		(20,241	)
Minority interest		(105,353	)
	$	2,452,442

Proposed Disposition of Assets and Initial and Subsequent Public Offerings

At the time we acquired DMS, we planned to market North Texas in an auction style sales process in early 2006, with the expectation that the sales transaction would close by mid 2006. In September 2006, our Board of Directors (the “Board”) determined that the available sales options did not meet the Board’s criteria. As a result, North Texas was reclassified from “held for sale” to “held for use” and we began activities necessary for an initial public offering (“IPO”) of common units representing limited partnership interests in Targa Resources Partners LP (“the Partnership”).

On February 14, 2007, we completed the IPO and the Partnership borrowed $294.5 million under its newly established credit facility. In return for our contribution of North Texas to the Partnership we received a 2% general partner interest and a 36.6% limited partner interest in the Partnership and cash proceeds of $665.7 million. We consolidate the Partnership’s net assets and results due to our continuing control of the Partnership through our general partner interest.

We used the proceeds received from contributing North Texas to the Partnership and cash on hand to retire in full the outstanding balance (including accrued interest) of our $700 million senior secured asset sale bridge loan facility.

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On October 24, 2007 the Partnership completed a public offering of 13,500,000 common units. The Partnership used the proceeds from the offering, borrowings under its senior secured revolving credit facility and the issuance of approximately 275 thousand general partner units to us to finance the acquisition from us of certain natural gas gathering and processing businesses located in west Texas and Louisiana for approximately $705 million, subject to certain adjustments. The Partnership sold an additional 1,800,000 common units to the underwriters on November 20, 2007 pursuant to a partial exercise of their option to purchase additional common units and used the net proceeds of approximately $47 million to repay a portion of outstanding indebtedness.

Contractual Arrangements

Because of the significant volatility of natural gas and NGL prices in our natural gas gathering and processing division, contract mix can have a significant impact on our profitability. Negotiated contract terms are based upon a variety of factors, including natural gas quality, geographic location, the competitive environment at the time the contract is executed and customer preferences. Contract mix and, accordingly, exposure to natural gas and NGL prices may change over time as a result of changes in these underlying factors.

Contract Mix

Set forth below is a table summarizing the contract mix of our natural gas gathering and processing division for the month of December 2006, and the potential impacts of commodity prices on operating margins:

Contract Type	Percent of Throughput		Impact of Commodity Prices
Percent-of-Proceeds / Percent-of-Liquids	47	%	Decreases in natural gas and or NGL prices generate decreases in operating margins
Fee-Based	23	%	No direct impact from commodity price movements
Wellhead Purchases / Keep-Whole	2	%	Increases in natural gas prices relative to NGL prices generate decreases in operating margins Decreases in NGL prices relative to natural gas prices generate decreases in operating margins
Hybrid	28	%	In periods of favorable processing economics, similar to percent-of-liquids (or wellhead purchases/keep-whole in some circumstances, if economically advantageous to the processor) In periods of unfavorable processing economics, similar to fee-based

Processing customer preferences, competitive forces and other factors sometimes cause us to enter into more commodity price sensitive contracts such as wellhead purchases and keep-whole arrangements. We prefer to enter into contracts with less commodity price sensitivity including fee-based and percent-of-proceeds arrangements (which we can hedge).

In general, with respect to our Permian Basin assets, onshore Louisiana Gillis and Acadia plants and North Texas, the majority of our throughput is subject to percent-of-proceeds or similar arrangements. Our Coastal Louisiana straddle plants are generally governed by percent-of-proceeds or hybrid contracts. Our NGL fractionation, storage, terminalling, transportation and distribution services are generally provided under fee-based arrangements. Finally, within our NGL Distribution and Marketing and our Wholesale Marketing segments we operate under a variety of fee- and margin-based marketing arrangements.

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Results of Operations

Comparison of Results of Operations. The most significant event affecting the comparability of our results of operations was the DMS acquisition. Because the closing date of the DMS acquisition was on October 31, 2005, our Consolidated Statements of Operations do not include any revenues or expenses from DMS prior to November 1, 2005.

The following discussion is based on our results of operations for the nine months ended September 30, 2007 and 2006, for the years ended December 31, 2006 and 2005, and the unaudited sum of: (i) the audited results of operations of the predecessor for the three and a half months ended April 15, 2004 and (ii) the audited results of operations of Targa for the year ended December 31, 2004 which reflects operating results only for the eight and a half months ended December 31, 2004. Because Targa and its predecessor followed different bases of accounting, the combined results of operations for the year ended December 31, 2004 are not prepared on the same basis and, thus, this combined presentation is not in accordance with GAAP. The discussion based on the combined information is presented for the convenience of investors to facilitate the presentation of a more meaningful discussion of the historical periods. The combined results of operations of the predecessor and Targa for the year ended December 31, 2004 does not necessarily represent the results that would have been achieved during this period had the business been operated by Targa for the entire year.

The following table summarizes the key components of our consolidated results of operations for the periods indicated:

	Targa Resources, Inc.															Combined			Predecessor
(in thousands)	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004			Year Ended December 31, 2004			Three and a Half Months Ended April 15, 2004
Revenues	$	4,923,416		$	4,699,283		$	6,132,881		$	1,829,027		$	602,376		$	835,145		$	232,769
Product purchases		(4,373,289	)		(4,174,895	)		(5,440,832	)		(1,631,963	)		(544,918	)		(757,224	)		(212,306	)
Operating expenses		(179,837	)		(160,554	)		(224,169	)		(52,090	)		(15,253	)		(24,510	)		(9,257	)
Operating margin		370,290			363,834			467,880			144,974			42,205			53,411			11,206
Depreciation and amortization		(110,757	)		(110,938	)		(149,687	)		(27,141	)		(10,631	)		(14,464	)		(3,833	)
General and administrative		(78,126	)		(64,860	)		(82,351	)		(28,275	)		(11,149	)		(11,906	)		(757	)
Operating income		181,407			188,036			235,842			89,558			20,425			27,041			6,616
Interest expense		(112,752	)		(133,245	)		(180,189	)		(39,856	)		(6,406	)		(6,406	)		—
Equity in earnings of unconsolidated investments		7,964			5,403			9,968			(3,776	)		2,370			2,370			—
Other income (expense)		(27,120	)		(22,403	)		(25,998	)		(66,678	)		—			—			—
Income tax (expense) benefit		(13,170	)		(16,365	)		(16,209	)		6,537			(5,227	)		(7,794	)		(2,567	)
Net income (loss)	$	36,329		$	21,426		$	23,414		$	(14,215	)	$	11,162		$	15,211		$	4,049

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

	Targa Resources, Inc.										Combined		Predecessor
(in thousands)	Nine Months Ended September 30, 2007		Nine Months Ended September 30, 2006		Year Ended December 31, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004		Year Ended December 31, 2004		Three and a Half Months Ended April 15, 2004
Natural Gas Gathering and Processing	$	296,683	$	317,019	$	404,904	$	128,371	$	42,205	$	53,411	$	11,206
Logistics Assets		28,714		34,655		42,415		6,075		—		—		—
NGL Distribution and Marketing Services		33,915		7,012		10,604		6,028		—		—		—
Wholesale Marketing		10,978		5,148		9,957		4,500		—		—		—
	$	370,290	$	363,834	$	467,880	$	144,974	$	42,205	$	53,411	$	11,206

Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006

Revenues increased by $224.1 million, or 5%, to $4,923.4 million for the nine months ended September 30, 2007 compared to $4,699.3 million for the nine months ended September 30, 2006.

Revenues from the sale of natural gas decreased by $10.7 million, consisting of a decrease of $52.8 million due to lower realized prices, offset by an increase of $42.1 million due to higher sales volumes. Revenues from the sale of NGL increased by $222.0 million, consisting of increases of $117.4 million due to higher sales volumes and $104.6 million due to higher realized prices. Revenues from the sale of condensate increased by $1.8 million, consisting of an increase of $2.0 million due to higher sales volumes, offset by a decrease of $0.2 million due to lower realized prices. Non-commodity sales revenues, which are principally derived from fee-based services, increased by $11.0 million.

Average realized prices for natural gas decreased by $0.37 per MMBtu (including a $0.04 decrease due to hedging), or 5%, to $6.58 per MMBtu for the nine months ended September 30, 2007 compared to $6.95 per MMBtu for the nine months ended September 30, 2006. The average realized prices for NGL increased by $0.03 per gallon, or 3%, to $1.08 per gallon for the nine months ended September 30, 2007 compared to $1.05 per gallon for the nine months ended September 30, 2006. The average realized price for condensate decreased by $0.20 per barrel (net of a $0.73 increase due to hedging), or less than 1%, to $64.83 per barrel for the nine months ended September 30, 2007 compared to $65.03 per barrel for the nine months ended September 30, 2006.

Natural gas sales volumes increased by 22.3 BBtu per day, or 4%, to 526.6 BBtu per day for the nine months ended September 30, 2007 compared to 504.3 BBtu per day for the nine months ended September 30, 2006. NGL sales volumes increased by 9.7 MBbl per day, or 3%, to 309.3 MBbl per day for the nine months ended September 30, 2007 compared to 299.6 MBbl per day for the nine months ended September 30, 2006. Condensate sales volumes increased by 0.1 MBbl per day, or 3%, to 3.9 MBbl per day for the nine months ended September 30, 2007 compared to 3.8 MBbl per day for the nine months ended September 30, 2006. For information regarding the period to period changes in our commodity sales volumes, please see “Results of Operations—By Segment”.

Product purchases increased by $198.4 million, or 5%, to $4,373.3 million for the nine months ended September 30, 2007 compared to $4,174.9 million for the nine months ended September 30, 2006.

Operating expenses increased by $19.2 million, or 12%, to $179.8 million for the nine months ended September 30, 2007 compared to $160.6 million for the nine months ended September 30, 2006. Please see “Results of Operations—By Segment” for a more detailed explanation of the components of the increase.

Depreciation and amortization expense decreased by $0.1 million, or less than 1% to $110.8 million for the nine months ended September 30, 2007 compared to $110.9 million for the nine months ended September 30, 2006.

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General and administrative expense increased by $13.1 million, or 20%, to $78.2 million for the nine months ended September 30, 2007 compared to $65.1 million for the nine months ended September 30, 2006. The increase primarily consisted of increases of $15.4 million in compensation related expenses and $1.1 million in insurance expenses, partially offset by decreases of $2.0 million in professional services fees and $1.4 million in miscellaneous expenses.

Interest expense decreased $20.4 million, or 15%, to $112.8 million for the nine months ended September 30, 2007 compared to $133.2 million for the nine months ended September 30, 2006. The decrease is primarily the result of lower average debt outstanding during 2007, partially offset by higher interest rates during 2007 and the early amortization of $0.6 million of debt issue costs related to retired debt. Please see Liquidity and Capital Resources for information regarding our outstanding debt obligations.

During the nine months ended September 30, 2007, income tax expense was $13.2 million on pre-tax net income of $49.5 million, compared to income tax expense of $16.4 million on pre-tax net income of $37.8 million for the nine months ended September 30, 2006. Income tax expense for the nine months ended September 30, 2007 decreased by $8.3 million as a result of Texas House Bill 3928 (“HB 3928”), effective June 15, 2007, which required us to recognize changes in deferred tax assets related to a computational change of the temporary credit related to the Texas Margin Tax. Excluding the effect of HB 3928, our effective income tax rate would have been flat at 43% for the nine months ended September 30, 2007 and the comparable period in 2006.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

Revenues were $6,132.9 million for 2006 compared to $1,829.0 million for 2005. The $4,303.9 million, or 235%, increase was primarily due to the following factors:

• higher commodity sales volumes primarily as a result of the DMS acquisition increased revenues $3,712.5 million, consisting of increases in natural gas and NGL revenue of $579.0 million and $3,133.5 million, respectively;

• a net increase attributable to commodity prices of $461.6 million, consisting of a decrease in natural gas revenue of $336.5 million, offset by an increase in NGL revenue of $798.1 million; and

• an increase in fee-based and other revenue of $129.8 million, primarily as a result of twelve months of operations of the DMS acquisition assets for 2006 compared to two months for 2005.

Our average realized price for natural gas decreased $1.84 per MMBtu, or 22%, to $6.61 per MMBtu for 2006 compared to $8.45 per MMBtu for 2005. Our average realized price for NGL increased $0.17 per gallon, or 20%, to $1.02 per gallon for 2006 compared to $0.85 per gallon for 2005.

Natural gas sales volumes increased 187.7 BBtu/d, or 60%, to 501.2 BBtu/d for 2006 compared to 313.5 BBtu/d for 2005. NGL sales volumes increased 240.4 MBbl/d, or 402%, to 300.2 MBbl/d for 2006 compared to 59.8 MBbl/d for 2005. The increase in natural gas and NGL volumes is primarily the result of twelve months of operations of the DMS acquisition assets for 2006 compared to two months for 2005.

Product purchases were $5,440.8 million for 2006 compared to $1,632.0 million for 2005. The $3,808.8 million, or 233%, increase was primarily the result of twelve months of NGL purchases by our NGL Logistics and Marketing division for 2006 compared to two months for 2005.

Operating expenses increased $172.1 million, or 330%, to $224.2 million for 2006 compared to $52.1 million for 2005. The increase was primarily attributable to the additional costs required to operate the company after the DMS acquisition, the most significant of which was for salary-related employee expenses.

Depreciation and amortization expense increased $122.6 million, or 452%, to $149.7 million for 2006 compared to $27.1 million for 2005. The increase is due to the DMS acquisition. Approximately $9.1 million of

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the increase was previously deferred depreciation expense for the North Texas assets, which were reclassified from “held for sale” to “held for use” during 2006.

General and administrative expense increased $54.1 million, or 191%, to $82.4 million for 2006 compared to $28.3 million for 2005. The increase is primarily due to increased corporate headcount as a result of the DMS acquisition. Corporate headcount, classified as general and administrative expense, increased from 39 at October 31, 2005 to 205 at December 31, 2006. Higher costs for insurance and information technology infrastructure also impacted general and administrative expense for 2006.

Net interest expense increased by $140.3 million, or 352%, to $180.2 million for 2006 compared to $39.9 million for 2005. The increase was primarily the result of higher debt levels related to the DMS acquisition financing.

Equity in earnings of unconsolidated investments increased $13.8 million, or 363%, to income of $10.0 million for 2006 compared to a loss of $3.8 million for 2005. The increase was the result of our sale of Bridgeline, where our equity loss for 2005 was $4.7 million, coupled with equity earnings from Venice Energy Services Company LLC (“VESCO”) and Gulf Coast Fractionators LP (“GCF”) for twelve months for 2006 compared to two months for 2005.

Our loss on mark-to-market derivative contracts for 2005 occurred because certain commodity swap derivatives we entered into concurrent with the execution of the DMS acquisition agreement did not qualify for hedge accounting treatment until the closing of the acquisition. For the year ended December 31, 2005, such loss consisted of (i) a $60.4 million non-cash mark-to-market loss and (ii) $13.6 million in premium amortization expense. There were no mark-to-market gains or losses during 2006.

Income tax expense was $16.2 million on pretax income of $39.6 million for 2006 compared to an income tax benefit of $6.5 million on a pretax loss of $20.8 million for 2005. Our effective tax rates for 2006 and 2005 were 40.9% and 37.5%, respectively. Our 2006 effective rate was increased by the May 2006 enactment of the Texas margins tax, which caused 2006 Texas losses to become unusable, increased deferred Texas income taxes and provided a partial offset through a temporary credit period. Variances in our annual effective tax rate from the 35% federal statutory rate are primarily caused by state income taxes.

Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004 (Combined)

The following discussion is based on our results of operations for the year ended December 31, 2005 as compared to the unaudited sum of: (i) the audited results of operations of the predecessor for the three and a half months ended April 15, 2004 and (ii) the audited results of operations of Targa for the eight and a half months ended December 31, 2004. Because Targa and its predecessor followed different bases of accounting during the respective periods, the combined results of operations for the year ended December 31, 2004 are not prepared on the same basis and, thus, this combined presentation is not in accordance with GAAP. The following discussion based on the combined information is presented for the convenience of investors to facilitate the presentation of a more meaningful discussion of the historical periods. The combined results of operations of the predecessor and Targa for the year ended December 31, 2004 do not necessarily represent the results that would have been achieved during this period had the business been operated by Targa for the entire year.

Revenues increased $993.9 million, or 119%, to $1,829.0 million for 2005 compared to $835.1 million for 2004. The increase is primarily due to:

• higher commodity sales volumes as a result of the DMS acquisition increased revenues $472.6 million, consisting of increases in natural gas and NGL revenue of $105.2 million and $367.4 million, respectively;

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• higher commodity prices increased revenues $440.7 million, consisting of increases in natural gas and NGL revenue $266.6 million and $174.1 million, respectively; and

• an increase in fee-based and other revenue of $80.6 million.

Our average realized price for natural gas, increased $2.33 per MMBtu, or 38%, to $8.45 per MMBtu for 2005 compared to $6.12 per MMBtu for 2004. Our average realized price for NGL increased $0.19 per gallon, or 29%, to $0.85 per gallon for 2005 compared to $0.66 per gallon for 2004.

Natural gas sales volumes increased 47.8 BBtu/d, or 18%, to 313.5 BBtu/d for 2005 compared to 265.7 BBtu/d for 2004. NGL sales volumes increased 36.4 MBbl/d, or 156%, to 59.8 MBbl/d for 2005 compared to 23.4 MBbl/d for 2004. The increase in natural gas and NGL volumes is primarily the result of the DMS acquisition.

Product purchases increased $874.8 million, or 116%, to $1,632.0 million for 2005 compared to $757.2 million for 2004. Of the increase, $624.5 million is directly attributable to the DMS acquisition, with the remainder primarily due to higher commodity prices in 2005.

Operating expenses increased $27.6 million, or 113%, to $52.1 million for 2005 compared to $24.5 million for 2004. Excluding a $31.2 million increase due to the DMS acquisition, operating expenses decreased $3.6 million from 2004 to 2005. The decrease was attributable primarily to cost reductions subsequent to our acquisition of the predecessor business from ConocoPhillips in April 2004, the most significant of which was a decrease in non-salary related employee expenses.

Depreciation and amortization expense increased $12.6 million, or 87%, to $27.1 million for 2005 compared to $14.5 million for 2004. The increase is primarily due to the DMS acquisition.

General and administrative expense increased $16.4 million, or 138%, to $28.3 million for 2005 compared to $11.9 million for 2004. Approximately $11.7 million of the increase was for salaries and wages of former DMS employees we hired as a result of the DMS acquisition, and the remainder was due to business development and higher corporate overhead expenses during 2005.

Interest income (expense), net increased $33.5 million, or 523%, to $39.9 million for 2005 compared to $6.4 million for 2004. The increase was primarily the result of higher debt levels related to the DMS acquisition financing, and to a lesser extent, higher interest rates during 2005.

Equity in earnings of unconsolidated investments for 2005 was a loss of $3.8 million, consisting of a loss of $4.7 million related to Bridgeline, offset by income of $0.6 million and $0.3 million related to VESCO and GCF, respectively. For 2004, our equity in earnings of unconsolidated investments was income of $2.4 million related to Bridgeline.

On August 5, 2005, we sold our equity investment in Bridgeline for $117.0 million in cash, and realized a pre-tax gain of $18.0 million.

Our loss on mark-to-market derivative contracts for 2005 occurred because certain commodity swap derivatives we entered into concurrent with the execution of the DMS acquisition agreement did not qualify for hedge accounting treatment until the closing of the acquisition. For the year ended December 31, 2005, such loss consisted of a $60.4 million non-cash mark-to-market loss and $13.6 million in premium amortization expense. There were no mark-to-market gains or losses during 2004.

We recognized a net income tax benefit of $6.5 million on a pretax loss of $20.8 million for 2005 compared to income tax expense of $7.8 million on pretax income of $23.0 million for 2004. Our effective tax rates for 2005 and 2004 were 37.5% and 35.0%, respectively. Variances in our annual effective tax rate from the 35% federal statutory rate are primarily caused by state income taxes.

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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.

	Targa Resources, Inc.															Combined			Predecessor
(in thousands)	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005(1)			Year Ended December 31, 2004(3)			Year Ended December 31, 2004			Three and a Half Months Ended April 15, 2004
Operating statistics:(2)
Gathering throughput, MMcf/d		1,992.9			2,046.2			1,871.7			477.9			285.6			294.6			316.5
Plant natural gas inlet, MMcf/d		1,949.7			1,875.0			1,841.5			400.8			262.6			277.3			313.5
Natural gas sales, BBtu/d		544.3			521.6			517.8			313.5			252.7			265.7			297.4
Gross NGL production, MBbl/d		105.7			106.7			106.8			31.8			22.8			23.4			24.8
Net NGL sales, MBbl/d		90.6			88.7			89.8			29.0			22.8			23.4			24.8
Average realized prices:
Natural gas, $/MMBtu		6.58			6.93			6.61			8.45			6.45			6.12			5.42
NGLs, $/gal		0.96			0.89			0.88			0.85			0.70			0.66			0.55
Revenues	$	2,079,621		$	1,983,247		$	2,591,019		$	1,309,058		$	602,376		$	835,145		$	232,769
Product purchases		(1,696,268	)		(1,581,821	)		(2,067,375	)		(1,145,577	)		(544,918	)		(757,224	)		(212,306	)
Operating expenses		(86,670	)		(84,407	)		(118,740	)		(35,110	)		(15,253	)		(24,510	)		(9,257	)
Operating margin	$	296,683		$	317,019		$	404,904		$	128,371		$	42,205		$	53,411		$	11,206
General and administrative	$	39,725		$	27,655		$	40,471		$	16,377		$	7,698		$	8,455		$	757
Equity in earnings of unconsolidated investments	$	5,068		$	3,302		$	7,214		$	(4,159	)	$	2,370		$	2,370		$	—

(1) Includes the results of assets acquired in the DMS acquisition for the two months ended December 31, 2005.

(2) 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. Volumes from assets acquired in the DMS acquisition are included from and after the acquisition date, October 31, 2005.

(3) Prior to April 16, 2004, certain investors in Targa had previous investments in Pipeco, f.k.a. Targa Resources, Inc., f.k.a. Warburg Pincus VIII Development Company, Inc. Pipeco was the entity that performed due diligence and other acquisition specific activities associated with the asset acquisitions from ConocoPhillips.

Pipeco and Targa are considered “entities under common control” as defined under GAAP and, as such, Targa’s audited financial results also include the results of Pipeco for the year ended December 31, 2004.

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Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006

Revenues increased $96.4 million, or 5% to $2,079.6 million for the nine months ended September 30, 2007 compared to $1,983.2 million for the nine months ended September 30, 2006. The net increase is primarily due to:

• an increase in commodity sales volumes that increased revenues by $68.8 million, consisting of increases in natural gas, NGL and condensate revenues of $43.0 million, $20.0 million, and $5.8 million, respectively;

• an increase in commodity prices that increased revenues by $19.2 million, consisting of an increase in NGL revenue of $72.6 million, partially offset by decreases in natural gas and condensate revenues of $52.6 million and $0.8 million, respectively; and

• an increase in compression and gathering, processing, and other services, which increased revenues by $8.4 million.

Our average realized price for natural gas decreased $0.35 per MMBtu (including a $0.04 decrease due to hedging), or 5%, to $6.58 per MMBtu for the nine months ended September 30, 2007 compared to $6.93 per MMBtu for the nine months ended September 30, 2006. Our average realized price for NGL increased $0.07 per gallon, or 8%, to $0.96 per gallon for the nine months ended September 30, 2007 compared to $0.89 per gallon for the nine months ended September 30, 2006. Our average realized price for condensate decreased $0.56 per barrel (net of a $0.55 increase due to hedging), or 1%, to $61.06 per barrel for the nine months ended September 30, 2007 compared to $61.62 per barrel for the nine months ended September 30, 2006.

Our natural gas sales volumes increased 22.7 BBtu/d, or 4%, to 544.3 BBtu/d for the nine months ended September 30, 2007 compared to 521.6 BBtu/d for the nine months ended September 30, 2006. The net increase in gas sales volumes is due to:

• an increase in natural gas sales volumes in north Texas due to increased wellhead production in the region, partially offset by the impact of unseasonably wet weather, which limited our ability to complete connections to new wells; and

• an increase due to increased wellhead production in certain of our west Texas operations, partially offset by plant maintenance curtailments at certain of our Permian Basin facilities.

Our NGL sales volumes increased 1.9 MBbl/d, or 2%, to 90.6 MBbl/d for the nine months ended September 30, 2007 compared to 88.7 MBbl/d for the nine months ended September 30, 2006. The increase in NGL sales volumes is primarily from increased production from our Louisiana straddle plants compared to 2006. During 2006, several of these plants were either shut-down or severely curtailed as a result of damage suffered from hurricanes Katrina and Rita during 2005.

Our condensate sales volumes increased 0.3 MBbl/d, or 6%, to 5.2 MBbl/d for the nine months ended September 30, 2007 compared to 4.9 MBbl/d for the nine months ended September 30, 2006.

Product purchases increased $114.5 million, or 7%, to $1,696.3 million for the nine months ended September 30, 2007 compared to $1,581.8 million for the nine months ended September 30, 2006. For the nine months ended September 30, 2007 and 2006, product purchases were 82% and 80% of total revenue, respectively. The increase in product purchases for the nine months ended September 30, 2007 corresponds with the increase in revenue for the same period.

Operating expenses increased $2.3 million, or 3%, to $86.7 million for the nine months ended September 30, 2007 compared to $84.4 million for the nine months ended September 30, 2006. The increase is primarily attributable to the additional cost of operating straddle plants in Louisiana that were off line for a portion of the

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nine months ended September 30, 2006 as a result of damage suffered from hurricanes Katrina and Rita during 2005. Operating expenses were also higher for the nine months ended September 30, 2007 due to settlements paid related to a fire near our Saunders facility.

General and administrative expense increased by $12.0 million, or 43%, to $39.7 million for the nine months ended September 30, 2007 compared to $27.7 million for the nine months ended September 30, 2006. This segment’s general and administrative expense is an allocation of corporate-level expenses, which were higher in 2007.

Our equity in earnings of unconsolidated investments was $5.1 million for the nine months ended September 30, 2007 compared to $3.3 million for the nine months ended September 30, 2006. The increase resulted from VESCO operating close to available capacity during 2007 compared to being off line for most of the first quarter of 2006 as a result of damage suffered from hurricane Katrina during 2005.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

Revenues increased $1,281.9 million, or 98%, to $2,591.0 million for 2006 compared to $1,309.1 million for 2005. This increase is primarily due to:

• an increase attributable to commodity sales volumes of $1,472.0 million, consisting of increases in natural gas and NGL revenue of $680.0 million and $792.0 million, respectively;

• a decrease attributable to commodity prices of $355.1 million, consisting of a decrease in natural gas revenue of $397.9 million, offset by an increase in NGL revenue of $42.8 million; and

• an increase in fee-based and other revenue of $165.0 million, primarily from miscellaneous processing activities.

Our average realized price for natural gas decreased $1.84 per MMBtu, or 22%, to $6.61 per MMBtu for 2006 compared to $8.45 per MMBtu for 2005. Our average realized price for NGL increased $0.03 per gallon, or 4%, to $0.88 per gallon for 2006 compared to $0.85 per gallon for 2005.

Our natural gas sales volume increased 204.3 BBtu/d, or 65%, to 517.8 BBtu/d for 2006 compared to 313.5 BBtu/d for 2005. Our NGL sales volume increased 60.8 MBbl/d, or 210%, to 89.8 MBbl/d for 2006 compared to 29.0 MBbl/d for 2005. The increases in volumes are primarily from a full year of operations for the DMS acquisition assets in 2006 compared to two months for 2005.

Product purchases increased $921.8 million, or 80%, to $2,067.4 million for 2006 compared to $1,145.6 million for 2005. The increase is attributable primarily to the DMS acquisition.

Operating expenses increased $83.6 million, or 238%, to $118.7 million for the 2006 compared to $35.1 million for 2005. The increase is primarily attributable to the DMS acquisition.

General and administrative expense increased $24.1 million, or 147%, to $40.5 million for the year ended December 31, 2006 compared to $16.4 million for the year ended December 31, 2005. General and administrative expense for this segment is an allocation of corporate-level expenses, which were generally higher during 2006 as a result of the DMS acquisition.

For 2006, earnings from unconsolidated investments consisted of our $7.2 million equity in the earnings of VESCO. For the year ended December 31, 2005, earnings from unconsolidated investments consisted of our $0.5 million equity in the earnings of VESCO and our $4.7 million equity in the losses of Bridgeline. We sold our interest in Bridgeline in August 2005.

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Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004 (Combined)

The following discussion is based on our results of operations for the year ended December 31, 2005 as compared to the unaudited sum of: (i) the audited results of operations of the predecessor for the three and a half months ended April 15, 2004 and (ii) the audited results of operations of Targa for the eight and a half months ended December 31, 2004. Because Targa and its predecessor followed different bases of accounting, the combined results of operations for the year ended December 31, 2004 are not prepared on the same basis and, thus, this combined presentation is not in accordance with GAAP. The following discussion based on the combined information is presented for the convenience of investors to facilitate the presentation of a more meaningful discussion of the historical periods. The combined results of operations of the predecessor and Targa for the year ended December 31, 2004 do not necessarily represent the results that would have been achieved during this period had the business been operated by Targa for the entire year.

Revenues increased $474.0 million, or 57%, to $1,309.1 million for 2005 compared to $835.1 million for 2004. The increase is primarily due to:

• higher commodity sales volumes primarily as a result of the DMS acquisition increased revenues $161.2 million, consisting of increases in natural gas and NGL revenue of $105.2 million and $56.0 million, respectively;

• higher commodity prices increased revenue $351.1 million, consisting of an increase in natural gas and NGL revenue of $266.6 million and $84.5 million.

Our average realized price for natural gas increased $2.33 per MMBtu, or 38%, to $8.45 per MMBtu for 2005 compared to $6.12 per MMBtu for 2004. Our average realized price for NGL increased $0.19 per gallon, or 29%, to $0.85 per gallon for 2005 compared to $0.66 per gallon for 2004.

Our natural gas sales volume increased 47.8 BBtu/d, or 18%, to 313.5 BBtu/d for 2005 compared to 265.7 BBtu/d for 2004. The increase is primarily attributable to the DMS acquisition.

Our NGL sales volume increased 5.6 MBbl/d, or 24%, to 29.0 MBbl/d for 2005 compared to 23.4 MBbl/d for 2004. An increase of 8.8 MBbl/d attributable to the DMS acquisition was partially offset by a 3.2 MBbl/d decrease due to the impact of hurricane related production volume losses, bypass of gas due to hurricane damage to processing plants and bypass of gas due to unfavorable processing economics.

Product purchases increased $388.4 million, or 51%, to $1,145.6 million for 2005 compared to $757.2 million for the year ended December 31, 2004. The increase consisted of a $138.1 million in product purchases for two months of operations attributable to the DMS acquisition, and a $250.3 million increase in product purchases that resulted primarily from higher commodity prices in 2005 compared to 2004.

Operating expenses increased $10.6 million, or 43%, to $35.1 million for the year ended December 31, 2005 compared to $24.5 million for the year ended December 31, 2004. The increase consisted of $14.2 million in operating expenses for two months of operations attributable to the DMS acquisition, and a $3.6 million decrease in operating expenses achieved because many of our Louisiana assets that would have undergone routine maintenance instead required major overhauls or replacement in 2005 compared to 2004 due to hurricane related damage. These overhauls were generally capitalized instead of expensed.

General and administrative expense increased $7.9 million, or 93%, to $16.4 million for the year ended December 31, 2005 compared to $8.5 million for the year ended December 31, 2004. General and administrative expense for this segment is an allocation of corporate-level expenses, which were generally higher during 2005 as a result of the DMS acquisition.

For the year ended December 31, 2004, equity in earnings of unconsolidated investments consisted of our $2.4 million equity in the earnings of Bridgeline. For the year ended December 31, 2005, equity in earnings of unconsolidated investments consisted of our $4.7 million equity in the loss of Bridgeline and our $0.5 million equity in the earnings of VESCO.

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Logistics Assets Segment

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

($ in thousands)	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005(1)
Fractionation volumes, MBbl/d(2)		207.3			186.6			181.9			23.7
Terminalling & storage, MBbl/d(2)		338.9			378.8			373.1			56.3
Transport, MBbl/d(2)		35.1			35.2			34.8			5.6
Revenues from services(3)	$	143,631		$	132,509		$	175,227		$	24,812
Other revenues		1,518			2,327			3,286			186
		145,149			134,836			178,513			24,998
Operating expenses		(116,435	)		(100,181	)		(136,098	)		(18,923	)
Operating margin	$	28,714		$	34,655		$	42,415		$	6,075
General and administrative	$	14,902		$	10,450		$	14,074		$	2,472
Equity income (loss) of unconsolidated investments(4)	$	2,896		$	2,101		$	2,754		$	383

(1) Reflects results beginning with the DMS acquisition on October 31, 2005.

(2) Operating statistics for 2005 are based on a 365-day year. For the sixty-one day period ended December 31, 2005, throughput volumes for fractionation, terminalling and storage, and transport were 141.9 MBbl/d, 337.1 MBbl/d and 33.4 MBbl/d, respectively.

(3) Excludes intrasegment revenue earned from barge day-rates and pipeline transport fees.

(4) Consists of earnings from our investment in Gulf Coast Fractionators LP (“GCF”).

Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006

Revenues from fractionation, terminalling and storage, and transport increased $11.1 million, or 8%, to $143.6 million for the nine months ended September 30, 2007 compared to $132.5 million for the nine months ended September 30, 2006. Higher service rates for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 increased revenues by $15.4 million, partially offset by a $4.3 million decrease as the result of lower terminalling and storage volumes. Revenues from other sources decreased $0.8 million to $1.5 million for the nine months ended September 30, 2007 compared to $2.3 million for the nine months ended September 30, 2006.

Higher service rates for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 were derived primarily from commercial transportation activities. New barge transportation contracts for Pascagoula mixed butanes and propane/propylene mix coupled with new railcar lease revenue earned from our NGL Distribution and Marketing and Wholesale Marketing segments added revenue of $10.2 million.

Terminalling and storage volumes were lower for the nine months ended September 30, 2007 than for the nine months ended September 30, 2006 primarily due to lower import volumes into our Galena Park facility, partially offset by higher volumes at our Cedar Bayou fractionator. Our fractionation facilities operated at 74% and 68% of design capacity for the nine months ended September 30, 2007 and 2006, respectively.

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Operating expenses increased $16.2 million, or 16%, to $116.4 million for the nine months ended September 30, 2007 compared to $100.2 million for the nine months ended September 30, 2006. This increase is primarily due to:

• the termination of the Chevron shared railcar fleet agreement in September 2006, which increased operating expenses by $6.4 million;

• higher barge transportation costs, which increased operating expenses by $2.9 million;

• the June 2007 commencement of commercial operations at our new low-sulfur natural gasoline unit, which added operating expenses of $2.5 million;

• increased storage well workovers at our Mont Belvieu terminal, which increased operating expenses by $1.9 million;

• increased operating expenses of $1.7 million at our truck terminals as a result of new leases, higher fuel prices and increased truck maintenance costs; and

• expenditures of $0.6 million for upgrades to our Houston NGL gathering system south route, which were charged to expense.

General and administrative expense increased by $4.4 million, or 42%, to $14.9 million for the nine months ended September 30, 2007 compared to $10.5 million for the nine months ended September 30, 2006. General and administrative expense for this segment is an allocation of corporate-level expenses, which were higher in 2007.

Our equity in earnings of unconsolidated investments was $2.9 million for the nine months ended September 30, 2007 compared to $2.1 million for the nine months ended September 30, 2006.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

Revenues from fractionation, terminalling and storage, and transport increased $150.4 million, or 606%, to $175.2 million for 2006 compared to $24.8 million for 2005. Approximately $148.4 million of the increase is the result of twelve months of operations for 2006 compared to two months for 2005. Higher service rates for 2006 compared to 2005 increased revenues by $2.0 million.

Fractionation, terminalling and storage, and transport volumes were higher for 2006 than for the two month period ended December 31, 2005 largely as a result of reduced raw NGL mix supplies from plants affected by Hurricane Rita and normal seasonal variations in volumes delivered to Mont Belvieu for fractionation during the winter months. Our fractionation facilities operated at 66% and 54% of design capacity for 2006 and 2005, respectively.

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NGL Distribution and Marketing Services Segment

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

($ in thousands)	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005(1)
NGLs sold, MBbl/d(2)		267.1			244.5			246.3			30.8
NGL realized price, $/gal		1.06			1.02			0.99			1.00
NGL sales revenues	$	3,250,184		$	2,854,995		$	3,728,373		$	474,163
Other revenues(3)		5,508			7,354			10,396			500
		3,255,692			2,862,349			3,738,769		$	474,663
Product purchases		(3,220,426	)		(2,854,101	)		(3,726,121	)		(468,542	)
Operating expenses		(1,351	)		(1,236	)		(2,044	)		(93	)
Operating margin	$	33,915		$	7,012		$	10,604		$	6,028
General and administrative expenses	$	8,163		$	10,235		$	9,504		$	1,523

(1) Reflects results beginning with the DMS acquisition on October 31, 2005.

(2) Operating statistics for 2005 are based on a 365-day year. For the two months ended December 31, 2005, NGLs sold averaged 184.3 MBbl/d.

(3) Reflects revenue generated from miscellaneous products and services.

Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006

Revenues increased $393.4 million, or 14%, to $3,255.7 million for the nine months ended September 30, 2007 compared to $2,862.3 million for the nine months ended September 30, 2006. The net increase comprised a $264.0 million increase as a result of higher sales volumes, a $131.2 million increase due to higher commodity prices and a $1.8 million decrease in non-commodity revenues, which are principally derived from fee-based services.

NGLs sold increased 22.6MBbl/d, or 9%, to 267.1 MBbl/d for the nine months ended September 30, 2007 compared to 244.5 MBbl/d for the nine months ended September 30, 2006. The increase in sales volumes were primarily due to:

• the effect of new raw product supply contracts entered into during June;

• sales of production which, prior to April 2006, were marketed by our Natural Gas Gathering and Processing segment; and

• increased sales of production from our Yscloskey facility and from VESCO, which were not in operation during a portion of 2006 as a result of damage suffered from hurricane Katrina during 2005.

Our average realized price for NGL increased $0.04 per gallon, or 4%, to $1.06 per gallon for the nine months ended September 30, 2007 compared to $1.02 per gallon for the nine months ended September 30, 2006.

Our operating margin increased by $26.9 million, or 384%, to $33.9 million for the nine months ended September 30, 2007 compared to $7.0 million for the nine months ended September 30, 2006. Our operating margin for the nine months ended September 30, 2006 was impacted by the effect hurricanes Katrina and Rita had on our seasonal-build inventory at December 31, 2005, with the consequence being both higher unit costs and increased volumes. As we liquidated the seasonal-build inventory, a mild winter contributed to increasing supplies and declining prices, resulting in a negative operating margin for the first quarter. The operating margin for the nine months ended September 30, 2007 improved in comparison to 2006 due to a general increase in commodity prices in 2007.

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General and administrative expense decreased by $2.0 million, or 20%, to $8.2 million for the nine months ended September 30, 2007 compared to $10.2 million for the nine months ended September 30, 2006. This segment’s general and administrative expense is an allocation of corporate-level expenses, which overall were higher in 2007.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

Revenues from the sale of NGLs were $3,728.4 million for 2006 compared to $474.2 million for 2005. The $3,254.2 million, or 686%, increase consisted of a $3,316.1 million increase from higher sales volumes offset by a $61.9 million decrease as a result of lower commodity prices. The increase in sales volumes was primarily from twelve months of operations for 2006 compared to two months for 2005.

NGLs sold for the year ended December 31, 2006 were 246.3 MBbl/d compared to 184.3 MBbl/d for the two months ended December 31, 2005. Our sources of NGL supply and demand were sharply curtailed in late 2005 as a result of Hurricanes Katrina and Rita. These sources were restored during 2006 as facilities damaged or closed as a result of the hurricanes resumed operations.

Wholesale Marketing Segment

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

($ in thousands)	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005(1)
NGLs sold, MBbl/d(2)		59.1			73.9			74.4			16.5
NGL realized price, $/gal		1.19			1.18			1.16			1.18
NGL sales revenues	$	804,098		$	1,002,312		$	1,322,689		$	298,320
Other revenues(3)		1,243			6,047			7,869			1,000
		805,341			1,008,359			1,330,558			299,320
Product purchases		(794,342	)		(1,003,202	)		(1,320,591	)		(294,757	)
Operating expenses		(21	)		(9	)		(10	)		(63	)
Operating margin	$	10,978		$	5,148		$	9,957		$	4,500
General and administrative expenses	$	15,194		$	13,032		$	17,820		$	2,335

(1) Reflects results beginning with the DMS acquisition on October 31, 2005.

(2) Operating statistics for 2005 are based on a 365-day year. For the two months ended December 31, 2005, NGLs sold averaged 98.5 MBbl/d.

(3) Reflects revenue generated from miscellaneous products and services.

Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006

Revenues decreased $203.1 million, or 20%, to $805.3 million for the nine months ended September 30, 2007 compared to $1,008.4 million for the nine months ended September 30, 2006. The decrease is primarily due to lower NGL sales volumes, slightly offset by higher average realized prices. Lower NGL sales volumes decreased revenues by $200.4 million and higher commodity prices increased revenues by $2.1 million. In addition, non-commodity, fee based service revenue decreased by $4.8 million.

NGLs sold decreased 14.8 MBbl/d, or 20%, to 59.1 MBbl/d for the nine months ended September 30, 2007 compared to 73.9 MBbl/d for the nine months ended September 30, 2006. The decrease is primarily due to direct and indirect impact of terminated feedstock contracts with Chevron that ended in September 2006.

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The slight increase in average realized prices is primarily attributable to higher market prices for the nine months ended September 2007 compared to 2006, partially offset by the impact of terminated Chevron feedstock contracts, which were terminated in September 2006. The terminated contracts were primarily for the higher priced NGL products.

Our operating margin increased by $5.9 million, or 116%, to $11.0 million for the nine months ended September 30, 2007 compared to $5.1 million for the nine months ended September 30, 2006. The significant increase is primarily attributable to a loss of $3.9 million related to the lower of cost or market inventory adjustments for the nine months ended September 30, 2006.

General and administrative expense increased by $2.2 million, or 17%, to $15.2 million for the nine months ended September 30, 2007 compared to $13.0 million for the nine months ended September 30, 2006. This segment’s general and administrative expense is primarily an allocation of corporate-level expenses, which were higher for the nine months ended September 30, 2007.

Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005

Revenues from the sale of NGLs were $1,322.7 million for 2006 compared to $298.3 million for 2005. The $1,024.4 million, or 343%, increase consisted of a $1,049.9 million increase from higher sales volumes offset by a $25.5 million decrease as a result of lower commodity prices. The increase in sales volumes was primarily from twelve months of operations for 2006 compared to two months for 2005.

NGLs sold for the year ended December 31, 2006 were 74.4 MBbl/d compared to 98.5 MBbl/d for the two months ended December 31, 2005. The Wholesale Marketing segment builds and holds propane inventory during the summer and generates the bulk of its revenue in the winter from propane sales.

Wholesale Marketing’s results for 2006 have been impacted by negative margins in our Florida operations due primarily to the loss of product previously supplied from VESCO and increased barge costs in the Gulf Coast.

Hurricanes Katrina and Rita

Certain of our Louisiana and Texas facilities sustained damage during the 2005 hurricane season from two gulf coast hurricanes—Katrina and Rita.

The Pelican offshore pipeline resumed full operations in January 2006. The Barracuda, Stingray and Yscloskey straddle plants resumed full operations in February, April and June 2006, respectively.

The Venice facility resumed partial operations during February 2006. When Venice becomes fully operational in mid-2008, its gross natural gas processing capacity will be approximately 750 MMcf/d. Also, the Venice partners have elected to not restore the facility’s NGL fractionation capability. We have a 22.9% equity ownership interest in the Venice facility.

While we believe that we have adequate insurance coverage for the facility repair costs, we are unable to predict the timing of insurance payments at this stage of the claims process. We will experience a reduction in physical damage recoveries from OIL Insurance Ltd. (as a Loss Payee) related to the salvage of the Pelican Platform destroyed by Hurricane Rita, as OIL is currently paying losses at 70% due to their $1 billion aggregate coverage limit for all insured members, which has been substantially exceeded. Our initial purchase price allocation for the DMS acquisition in October 2005 included an $81.1 million receivable for insurance claims related to expenditures to repair pre-acquisition property damage caused by Katrina and Rita. That estimate of recoveries remains unchanged.

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Our repair expenditures and property damages insurance recoveries are summarized in the following table.

	Year Ended December 31,				Nine Months Ended September 30, 2007
(in thousands)	2005		2006				Total
Property Damage
Repair/rebuild expenditures	$	6,931	$	48,408	$	9,597	$	64,936
Contributions to VESCO		5,990		9,102		4,648		19,740
	$	12,921	$	57,510	$	14,245	$	84,676
Insurance proceeds(1)	$	—	$	27,221	$	17,900	$	45,121

(1) Represents partial payments from insurance carriers related to property damage claims, which is reflective of the timing lag involved in the claims review process.

We have submitted and continue to submit business interruption insurance claims for our estimated losses caused by the hurricanes. We recognize income from business interruption insurance claims in our consolidated statements of operations and comprehensive income in the period that a proof of loss is executed and submitted to the insurers for payment. This income recognition criterion has resulted in and will likely continue to result in business interruption insurance recoveries being recorded in periods subsequent to the periods that we experience lost income from the affected property, resulting in fluctuations in our net income that may reduce the comparability of reported quarterly and annual results for some periods into the future.

At December 31, 2005, we estimated that our total business interruption claims proceeds could exceed $50 million. That estimate remains unchanged. Our income recognition from business interruption claims is summarized in the following table.

	Year Ended December 31,				Nine Months Ended September 30, 2007
(in thousands)	2005		2006				Total
Business Interruption Insurance
Included in revenues	$	1,185	$	10,720	$	7,272	$	19,177
Included in equity earnings		1,449		2,856		3,088		7,393
	$	2,634	$	13,576	$	10,360	$	26,570

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 will depend 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. Please read “Risk Factors.”

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 twelve months.

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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. At December 31, 2006 and September 30, 2007, our total outstanding letter of credit postings were $227.6 million and $274.9 million, respectively.

In connection with the IPO completed on February 14, 2007, the General Partner of TRP LP is obligated to make minimum quarterly cash distributions to unit holders from available cash, as defined in the partnership agreement. As of September 30, 2007, such minimum amounts payable to non-Targa unit holders total approximately $26 million annually.

Cash Flow

The following table summarizes cash flow provided by or used in operating activities, investing activities and financing activities for the periods presented.

	Targa Resources, Inc.														Combined			Predecessor
(in thousands)	Nine Months Ended September 30, 2007			Nine Months Ended September 30, 2006			Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004		Year Ended December 31, 2004			Three and a Half Months Ended April 15, 2004
Net cash provided by (used in)
Operating activities	$	136,824		$	181,597		$	233,286		$	108,855		33,135		$	44,615		$	11,480
Investing activities		(82,259	)		(96,055	)		(117,812	)		(2,328,916	)	(353,234	)		(354,410	)		(1,176	)
Financing activities		(44,896	)		(10,023	)		(14,162	)		2,250,621		330,676			320,372			(10,304	)

The discussion of cash flows for the year ended December 31, 2004 is based on the unaudited sum of (i) the audited cash flows of the predecessor for the three and a half months ended April 15, 2004, and (ii) the audited cash flows of Targa for the year ended December 31, 2004. Prior to April 16, 2004, certain investors in Targa had previous investments in Pipeco, f.k.a. Targa Resources, Inc., f.k.a. Warburg Pincus VIII Development Company, Inc. Pipeco was the entity that performed due diligence and other acquisition specific activities associated with the asset acquisitions from ConocoPhillips. Pipeco and Targa are considered “entities under common control” as defined under GAAP and, as such, Targa’s audited financial results include the year ended December 31, 2004. Because Targa and its predecessor followed different bases of accounting, the combined cash flow information for the year ended December 31, 2004 is not prepared on the same basis and, thus, is not in accordance with GAAP. The following discussion based on the combined cash flows is presented for the convenience of investors to facilitate the presentation of a more meaningful discussion of the historical period. The combined cash flows of the predecessor and Targa for the year ended December 31, 2004 do not necessarily represent the cash flows that would have occurred during this period had the business been operated by Targa for the entire year.

Operating Activities

Net cash provided by operating activities was $136.8 million for the nine months ended September 30, 2007 compared to $181.6 million for the nine months ended September 30, 2006. Changes in working capital negatively impacted cash flow from operating activities by $18.5 million in 2007 compared to an increase of $49.9 million in 2006. The difference resulted primarily from the delay until early 2006 of sales of our 2005 seasonal-build propane inventory. The delay was due to disruptions in demand as a result of hurricanes Katrina and Rita. Our normal cycle of accumulation and distribution resumed during the summer of 2006. The negative

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impact of working capital changes was partially offset by higher operating margins in 2007 due to higher revenues as a result of higher sales volumes and lower distributions to minority interest holders during 2007.

Net cash provided by operating activities was $233.3 million for 2006 compared to $108.9 million for 2005 and $44.6 for 2004. Improved operating cash flow was primarily the result of operating income contributions from assets acquired in the DMS acquisition, as well as improved margins from existing assets, partially offset by higher interest costs related to funding of the DMS acquisition.

Investing Activities

Net cash used in investing activities was $82.3 million for the nine months ended September 30, 2007 compared to $96.1 million for the nine months ended September 30, 2006. The $13.8 million decrease is primarily due to a decrease of cash paid for purchases of property, plant and equipment of $10.2 million and lesser contributions to unconsolidated investments during 2007 as a result of decreased hurricane repair expenditures.

Net cash used in investing activities was $117.8 million for 2006, compared with $2,328.9 million for 2005 and $354.4 million for 2004. Factors affecting the comparability of net cash used in investing activities are:

• During 2006, we had net cash outflows of $30.3 million attributable to facilities damaged by Hurricanes Katrina and Rita, consisting of $48.4 million in repair expenditures and a $9.1 million contribution to VESCO, offset by $27.2 million in cash receipts from property damage insurance claims;

• During 2005, we made cash payments of $2,417.1 million related to the DMS acquisition, expended $8.9 million for hurricane related repairs, made a contribution of $6.1 million to VESCO to fund repair costs, and received $117.0 million from the sale of Bridgeline;

• During 2004, we paid $247.0 million to acquire assets in West Texas and Louisiana from ConocoPhillips, and $101.3 million for a 40% interest in Bridgeline.

The remaining $87.5 million, $13.8 million, and $6.1 million for 2006, 2005, and 2004, respectively, primarily reflect maintenance and expansion capital expenditures during the periods.

Financing Activities

Net cash used in financing activities was $44.9 million for the nine months ended September 30, 2007 compared to $10.0 million for the nine months ended September 30, 2006. For the nine months ended September 30, 2007, repayments of $757.4 million to retire indebtedness and $4.1 million incurred in connection with financing arrangements were partially offset by $342.5 million borrowed under TRP LP’s new credit facility and $377.5 million in net proceeds from TRP LP’s IPO.

Net cash used in financing activities was $14.2 million for 2006, compared with net cash provided by financing activities of $2,250.6 million for 2005 and $330.7 million for 2004. The decrease as compared to 2005 in cash provided by financing activities of $2,236.4 million is primarily attributable to cash required to fund the DMS acquisition in 2005. During 2005, borrowings of $2,200 million and equity contributions of $316 million were used for funding of the DMS acquisition, the refinancing of $84 million of existing debt, and payment of $59 million in costs incurred in connection with the new credit facility and the issuance of our notes.

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. We expect to make significant expenditures during the next year for the construction of additional natural gas gathering and processing infrastructure and to enhance the value of our natural gas logistics and marketing assets.

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We categorize our capital expenditures as either: (i) maintenance expenditures or (ii) expansion expenditures. Maintenance expenditures are those expenditures that are necessary to maintain the service capability of our existing assets including the replacement of system components and equipment which is worn, obsolete or completing its useful life, the addition of new sources of natural gas supply to our systems to replace natural gas production declines and expenditures to remain in compliance with environmental laws and regulations. Expansion expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues.

Our planned capital expenditures for 2007, excluding expenditures for the repair of previously discussed hurricane damage, are:

($ in millions)	Maintenance		Expansion		Total
Gas gathering and processing	$	67.3	$	18.9	$	86.2
Logistics assets		11.2		15.9		27.1
Wholesale marketing		1.2		0.3		1.5
	$	79.7	$	35.1	$	114.8

We are currently funding the cost of hurricane damage related repairs for the facilities we operate and have been and expect to continue to be reimbursed by our partners for their share of costs under the normal joint interest billing process. We expect to be reimbursed under our property insurance coverage for our portion of repair costs. For the non-operated facilities, we are funding our share through joint interest billings from the facility operator and expect to be reimbursed by our insurance coverage. For VESCO, we are funding our share through capital contributions. The funding-recovery time lag may require us to increase borrowings under our revolving credit facility; however, we believe we have adequate capacity to fund this activity and meet our normal working capital requirements.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

Contractual Obligations

The following is a summary of our contractual cash obligations over the next several fiscal years, as of December 31, 2006:

(in millions)	Payments due by period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Debt obligations(1)	$	2,184.4	$	712.5	$	25.0	$	25.0	$	1,421.9
Interest on debt obligations(2)		758.7		167.3		243.1		238.0		110.2
Operating lease obligations(3)		87.7		17.6		23.2		16.4		30.5
Capacity payments(4)		8.2		2.6		4.8		0.8		—
Asset retirement obligation		11.6		—		—		—		11.6
	$	3,050.6	$	900.0	$	296.1	$	280.2	$	1,574.2

(1) Includes (i) a $1,234.4 million remaining outstanding balance on our senior secured term loan facility due October 2012, (ii) a $700.0 million senior secured asset sale bridge loan facility, which was repaid in February 2007, and (iii) $250.0 million of senior notes due November 2013.

(2) Represents interest expense on our debt obligations based on interest rates as of December 31, 2006 and the timing of required future principal repayments of the respective facilities. We used an average rate of 6.7% to estimate our interest on variable rate debt obligations.

(3) Operating lease obligations include minimum lease payment obligations associated with gas processing plant site leases, railcar leases, office space leases and pipeline rights-of-way.

(4) Consist of capacity payments, primarily for NGL storage facilities.

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Credit Ratings

At September 30, 2007 we had the following credit ratings, all of which are speculative ratings:

	Moody’s Investor Services	Standard & Poor’s
Corporate rating	B1	B
Senior secured credit facilities	Ba3	B+
Senior unsecured notes	B3	CCC+

A speculative rating signifies a higher risk that we will default on our obligations than does an investment grade rating.

Debt Obligations

Our debt obligations consisted of the following at the dates indicated:

(in thousands)	September 30, 2007			December 31, 2006
Long-term debt:
Senior secured term loan facility, variable rate, due October 2012	$	1,225,000		$	1,234,375
Senior secured asset sale bridge loan facility, variable rate (1)		—			700,000
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 (2)		—			—
Senior secured revolving credit facility of the Partnership, variable rate, due February 2012		294,500			—
Subtotal debt		1,769,500			2,184,375
Current maturities of debt		(12,500	)		(712,500	)
Long-term debt	$	1,757,000		$	1,471,875
Irrevocable standby letters of credit:
Letters of credit outstanding under synthetic letter of credit facility (3)	$	274,630		$	227,571
Letters of credit outstanding under senior secured revolving credit facility of the Partnership		300			—
	$	274,930		$	227,571

(1) The entire amount was repaid in February 2007 concurrent with the closing of the Partnership's IPO.

(2) The entire $250 million available under the senior secured revolving credit facility may also be utilized for letters of credit.

(3) The $300 million senior secured synthetic letter of credit facility terminates in October 2012. At September 30, 2007 we had $25.4 million available under this facility.

Available Credit

At September 30, 2007 we had $250 million in borrowing capacity under our senior secured revolving credit facility. This borrowing capacity was available in any combination of cash borrowings and letters of credit. We also had $25.4 million of availability for letters of credit under our $300 million senior secured synthetic letter of credit facility.

Description of Debt Obligations

For a complete description of our debt obligations please see Note 7 to our Consolidated Financial Statements beginning on page F-1 of this Registration Statement.

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Critical Accounting Policies

The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements, because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See Note 3 of the accompanying Notes to the Consolidated Financial Statements included in this Registration Statement for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.

The preparation of financial statements in accordance with GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from these estimates.

Revenue Recognition

Our primary types of sales and service activities reported as operating revenue include:

• Sales of natural gas, NGLs, and condensate;

• Natural gas processing, from which we generate revenue through the compression, gathering, treating, and processing of natural gas; and

• Other services including fractionation, storage, terminalling and transportation of NGLs.

We recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured.

For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under percent-of-proceeds contracts, we are paid for our services by keeping a percentage of the NGLs extracted and the residue gas resulting from processing natural gas. In percent-of-proceeds arrangements, we remit either a percentage of the proceeds received from the sales of residue gas and NGLs or a percentage of the residue gas or NGLs at the tailgate of the plant to the producer. Under the terms of percent-of-proceeds and similar contracts, we may purchase the producer’s share of the processed commodities for resale or deliver the commodities to the producer at the tailgate of the plant. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. Natural gas or NGLs that we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. Under fee-based contracts, we receive a fee based on throughput volumes.

We generally report revenues gross in the combined statements of operations, in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee-based contracts, we act as the principal in these transactions where we receive natural gas or NGLs, take title to the commodities, and incur the risks and rewards of ownership.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect our reported financial positions and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation

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of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues and operating and general and administrative costs, (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of our assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.

Property, Plant, and Equipment

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

Asset Group	Range of Years
Natural gas gathering systems and processing facilities	15 to 25
Fractionation, terminalling and natural gas liquids storage facilities	25
Transportation equipment and barges	5 to 10
Office and miscellaneous equipment	3 to 7

Expenditures for maintenance and repairs are generally expensed as incurred. However, expenditures for refurbishments that extend the useful lives of assets or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset.

Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs. From time to time, we utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

We may capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is charged to operations.

In accordance with SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses and the market and business environments to identify indicators that may suggest an asset may not be recoverable.

We evaluate an asset for recoverability by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our Consolidated Statements of Operations.

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Price Risk Management (Hedging)

We account for derivative instruments in accordance with SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS 133, all of our derivative financial instruments not qualifying for the normal purchases and normal sales exception are recorded on the balance sheet at fair market value as current and long-term assets or liabilities on a net basis by counterparty and are adjusted each period for changes in the fair market value. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay or receive to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We use external market quotes and indices to value substantially all of the financial instruments we utilize.

If a derivative does not qualify as a hedge, or is not designated as a hedge, the unrealized gain or loss on the derivative is recognized currently in earnings each period. If a derivative qualifies for cash flow hedge accounting, the effective portion of the unrealized gain or loss on the derivative is deferred in Accumulated Other Comprehensive Income (“OCI”), a component of stockholders’ equity, and reclassified to the Statement of Operations in the period the hedged forecasted transaction is recognized or is no longer expected to occur. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain unchanged until the related product has been delivered. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in other revenues immediately.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on a quarterly basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of the unrealized gain or loss is recognized in earnings in the current period.

Asset Retirement Obligations

Under the provisions of SFAS 143, “Accounting for Asset Retirement Obligations,” we record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, recorded at a discount, when such liabilities are incurred. We have recorded approximately $11.6 million in asset retirement obligations as of December 31, 2006.

In March 2005, the FASB issued FASB Interpretation (“FIN”) 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in SFAS 143. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about potential future cash outflows for these obligations and more consistent recognition of these liabilities. Our adoption of FIN 47 on December 31, 2005 had no effect on our financial position, results of operations, or cash flows.

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Accounting for Income Taxes

We follow the guidance in SFAS No. 109, “Accounting for Income Taxes”, which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.

We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no reserve has been established. While we have considered these factors in assessing the need for a valuation allowance, there is no assurance that a valuation allowance would not need to be established in the future if information about future years change. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.

Estimated Useful Lives

The estimated useful lives of our long-lived assets are used to compute depreciation expense, future asset retirement obligations and in impairment testing. Estimated useful lives are based, among other things, on the assumption that we provide an appropriate level of maintenance capital expenditures while the assets are still in operation. Without these continued capital expenditures, the useful lives of these assets could decrease significantly. Estimated lives could be impacted by such factors as future energy prices, environmental regulations, various legal factors and competition. If the useful lives of these assets were found to be shorter than originally estimated, depreciation expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result.

Recent Accounting Pronouncements

We adopted SFAS 154, “Accounting Changes and Error Corrections,” on January 1, 2006. SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections.

We adopted SFAS 123R, “Share-Based Payment,” on January 1, 2006. SFAS 123R requires us to recognize compensation expense related to equity awards based on the fair value of the award at the grant date. The fair value of an equity award is estimated using the Black-Scholes option pricing model. Under SFAS 123R, the fair value of all awards expected to vest is amortized to earnings on a straight-line basis over the requisite service or vesting period. We account for Targa Investments’ equity awards granted to our employees using the provisions of SFAS 123R. Previously, equity awards made by us prior to the October 2005 reorganization, and by our parent Targa Investments subsequent to the reorganization were accounted for using the intrinsic value method pursuant to Accounting Principles Board Opinion (“APB”) 25, “Accounting for Stock Issued to Employees.”

Prior to our adoption of SFAS 123R, we recognized compensation expense related to stock options only if the grant date fair value of the underlying stock was less than the exercise price of the option; additionally, compensation expense was recognized in connection with the issuance of non-vested common stock. We have

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applied SFAS 123R prospectively to new awards and to awards modified, repurchased, or cancelled on or after January 1, 2006. We shall continue to account for any portion of awards outstanding on January 1, 2006 using the intrinsic value method. Stock-based compensation expense is based on the awards ultimately expected to vest, and has been reduced for estimated forfeitures. The effects of applying SFAS 123R for the year ended December 31, 2006 did not have a material effect on our net income.

In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109,” which clarifies the accounting and disclosure for uncertainty in income taxes recognized in an enterprise’s financial statements. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. We continue to evaluate our tax positions, and based on our current evaluation, anticipate FIN 48 did not have a significant impact on our results of operations or financial position.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) 157 “Fair Value Measurements”. SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS 157 does not require any new fair value measurements. However, for some entities, the application of SFAS 157 will change current practice. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We have not yet determined the impact this statement will have on our results of operations or financial position.

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. SAB 108 is effective for fiscal years ending after November 15, 2006, and early application is encouraged. Our adoption of SAB 108 had no impact on our results of operations or financial position.

In February 2007, the FASB issued SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of No. 115,” which is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. 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. We are currently reviewing this new accounting standard and the impact, if any, it will have on our financial statements.

In December 2007, the FASB issued SFAS 141R,“Business Combinations”. SFAS 141R requires the acquiring entity in a business combination to recognize all (and only) the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS 141R is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We have not yet determined the impact this statement will have on our results of operations or financial position.

In December 2007, the FASB issued SFAS 160,“Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51”.SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It requires all entities to report noncontrolling (minority) interests in subsidiaries in the same way—as equity in the consolidated financial statements. In addition, SFAS 160 requires entities to account for transactions between an entity and noncontrolling interests as equity transactions. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008, with early adoption prohibited. We have not yet determined the impact this statement will have on our results of operations or financial position.

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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. In addition, we also enter into hedges for frac spreads with certain of our customers and for operational purposes. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged.

The primary purpose of our commodity risk management activities is to hedge our exposure to commodity price risk inherent in our contract mix and reduce fluctuations in our operating cash flow despite fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of September 30, 2007, we have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2007 through 2012 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are covered by our hedges is approximately 60% to 80% through 2009 and decreases over time. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs, and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) to hedge the commodity price exposure associated with additional expected equity commodity volumes without creating volumetric risk. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions using swaps, collars, purchased puts (or floors) or other hedge instruments as market conditions permit.

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

Our commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association (“ISDA”) form with customized credit and legal terms. Our principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. 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

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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.

Summary of Our Hedges

At September 30, 2007, we had the following open commodity derivative positions designated as cash flow hedges:

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu		MMBtu per day						(in thousands) Fair Value
				2007	2008	2009	2010	2011	2012
Swap	IF-HSC	$	9.08	2,740	—	—	—	—	—	$	593
Swap	IF-HSC		8.09	—	2,328	—	—	—	—		381
Swap	IF-HSC		7.39	—	—	1,966	—	—	—		(381	)
				2,740	2,328	1,966	—	—	—		593
Swap	IF-NGPL MC		8.56	8,152	—	—	—	—	—		1,836
Swap	IF-NGPL MC		8.43	—	6,964	—	—	—	—		3,958
Swap	IF-NGPL MC		8.02	—	—	6,256	—	—	—		1,415
Swap	IF-NGPL MC		7.43	—	—	—	5,685	—	—		202
Swap	IF-NGPL MC		7.34	—	—	—	—	2,750	—		72
Swap	IF-NGPL MC		7.18	—	—	—	—	—	2,750		140
				8,152	6,964	6,256	5,685	2,750	2,750		7,623
Swap	IF-Waha		7.71	30,118	—	—	—	—	—		4,123
Swap	IF-Waha		7.27	—	29,307	—	—	—	—		(101	)
Swap	IF-Waha		6.86	—	—	28,854	—	—	—		(8,412	)
Swap	IF-Waha		7.39	—	—	—	15,009	—	—		(956	)
Swap	IF-Waha		7.36	—	—	—	—	8,750	—		(135	)
Swap	IF-Waha		7.18	—	—	—	—	—	8,750		44
				30,118	29,307	28,854	15,009	8,750	8,750		(5,437	)
Swap	NY-HH		6.79	3,840	—	—	—	—	—		(178	)
Total Swaps				44,850	38,599	37,076	20,694	11,500	11,500		2,601
Floor	IF-NGPL MC		6.45	520	—	—	—	—	—		32
Floor	IF-NGPL MC		6.55	—	1,000	—	—	—	—		267
Floor	IF-NGPL MC		6.55	—	—	850	—	—	—		205
				520	1,000	850	—	—	—		504
Floor	IF-Waha		6.70	350	—	—	—	—	—		25
Floor	IF-Waha		6.85	—	670	—	—	—	—		173
Floor	IF-Waha		6.55	—	—	565	—	—	—		115
				350	670	565	—	—	—		313
Total Floors				870	1,670	1,415	—	—	—		817
										$	3,418

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NGLs

Instrument Type	Index	Avg. Price $/gal	Barrels per day						(in thousands) Fair Value
			2007	2008	2009	2010	2011	2012
Swap	OPIS-MB	0.96	10,216	—	—	—	—	—	$	(10,672	)
Swap	OPIS-MB	0.92	—	9,257	—	—	—	—		(25,737	)
Swap	OPIS-MB	0.88	—	—	8,595	—	—	—		(12,259	)
Swap	OPIS-MB	0.87	—	—	—	6,559	—	—		1,102
Swap	OPIS-MB	0.88	—	—	—	—	3,950	—		1,235
Swap	OPIS-MB	0.88	—	—	—	—	—	2,950		1,121
			10,216	9,257	8,595	6,559	3,950	2,950	$	(45,210	)

Condensate

Instrument Type	Index	Avg. Price $/Bbl	Barrels per day						(in thousands) Fair Value
			2007	2008	2009	2010	2011	2012
Swap	NY-WTI	72.82	439	—	—	—	—	—	$	(268	)
Swap	NY-WTI	70.68	—	384	—	—	—	—		(777	)
Swap	NY-WTI	69.00	—	—	322	—	—	—		(491	)
Swap	NY-WTI	68.10	—	—	—	301	—	—		(388	)
Total Swaps			439	384	322	301	—	—		(1,924	)
Floor	NY-WTI	58.60	25	—	—	—	—	—		0
Floor	NY-WTI	60.50	—	55	—	—	—	—		17
Floor	NY-WTI	60.00	—	—	50	—	—	—		37
Total Floors			25	55	50	—	—	—		54
									$	(1,870	)

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

Interest Rate Risk

We are exposed to interest rate risk primarily through our borrowing activities. As of September 30, 2007, we had approximately $1,770 million of indebtedness, including indebtedness of the Partnership, of which $250 million was at fixed interest rates and $1,520 million was at variable interest rates. Borrowings under our senior secured credit facilities, other than the senior secured synthetic letter of credit, bear interest at a rate equal to an applicable margin plus, at our option, either (a) a base rate determined by reference to the higher of (1) the prime rate of Credit Suisse and (2) the federal funds rate plus 1/2 of 1% or (b) the London Interbank Offered Rate (“LIBOR”) determined by reference to the costs of funds for dollar deposits for the interest period relevant to such borrowing adjusted for certain additional costs.

Subsequent to the senior secured credit agreement closing date, we entered into interest rate swaps for an aggregate notional amount of $350 million. The interest rate swaps effectively fix our interest rate on $350 million in borrowings to a rate of 4.8% plus the applicable LIBOR margin (2.25% at December 31, 2006). At December 31, 2006, the fair value of our interest rate swaps was $1.4 million. These interest rate swaps expired at the end of November 2007. In December, the Partnership entered into interest rate swaps for an aggregate

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notional amount of $100 million. These interest rate swaps effectively fix the Partnership’s interest rate on $100 million in borrowings to a rate at 4.14% plus the applicable LIBOR margin.

Based on LIBOR as of September 30, 2007, the annual interest expense on our variable rate debt inclusive of the effect of the interest rate swaps would increase or decrease by approximately $11.7 million if interest rates were to increase or decrease by one percentage point.

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.

Commitments and Contingencies

Please read “Business—Environmental and Other Matters” and “Business—Legal Proceedings.”

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BUSINESS

Overview

We are a leading provider of midstream natural gas and NGL services in the United States. We provide these services through our integrated platform of midstream assets. 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. Additionally, our natural gas liquids 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 believe our asset locations, including those of the Partnership, provide us access to natural gas supplies and proximity to end-use markets and leading market hubs while positioning us to capitalize on potential growth opportunities from selected areas of the Permian Basin, the continued development of deepwater and deep shelf Gulf of Mexico natural gas reserves, the increasing importation of liquefied natural gas, or LNG, to the Gulf Coast and the growth of the Barnett Shale production in north Texas. We believe our asset locations, scale, broad range of services, operational focus and competitive cost structure position us well to serve customers and to benefit from the importance of infrastructure in the growing U.S. energy market.

We were formed in 2004 by our management team, which consists of former members of senior management of several midstream and other diversified energy companies, and Warburg Pincus. Targa Resources Finance Corporation (“Targa Finance”) is a Delaware corporation and wholly owned subsidiary of Targa. Targa Finance was created solely to serve as a corporate co-obligor on the obligations of Targa and will continue to have nominal assets and no operations or revenues. We are a large-scale, integrated midstream energy company with the ability to offer a wide range of midstream services to a diverse group of natural gas and NGL producers and customers. At September 30, 2007, we had total assets of $3.6 billion. We own or operate approximately 10,000 miles of natural gas pipelines and approximately 550 miles of NGL pipelines, with natural gas gathering systems covering approximately 14,500 square miles and 21 natural gas processing plants with access to natural gas supplies in the Permian Basin, north Texas, onshore southern Louisiana and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with 16 storage, marine and transport terminals with above ground NGL storage capacity of approximately 900 MBbls, net NGL fractionation capacity of approximately 300 MBbls/d and 43 owned and operated storage wells with a net storage capacity of approximately 65 MMBbls.

Industry Overview

The midstream natural gas industry provides an essential link between the exploration and production of natural gas and the delivery of its components to end-use markets. We categorize the midstream natural gas industry into, and describe our business in, two divisions: (i) the Natural Gas Gathering and Processing division, which includes the Partnership, and (ii) the NGL Logistics and Marketing division. Our NGL Logistics and Marketing division consists of three segments: (a) Logistics Assets, (b) NGL Distribution and Marketing and (c) Wholesale Marketing. We have significant operations in both divisions and believe that we are one of the larger providers of services across each division.

Natural Gas Gathering and Processing

Natural gas gathering and processing consists of gathering, compressing, dehydrating, treating, conditioning, processing, storing, marketing and transporting natural gas and NGLs. The gathering of natural gas consists of aggregating natural gas produced from various wells through small diameter gathering lines for transportation to processing plants. Natural gas has a widely varying composition, depending on the field, the formation and the reservoir from which it is produced. The processing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor, solids and other contaminants to form (i) a stream of

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marketable natural gas, commonly referred to as residue gas, and (ii) a stream of combined NGLs, commonly referred to as “Mixed NGL” or “Y-Grade.” Once processed, the residue gas is transported to markets through pipelines that are either owned by the gatherers/processors or third-parties. End-users of residue gas include large rural, commercial and industrial customers, as well as natural gas and electric utilities serving individual consumers. We sell our residue gas either directly to such end-users or to marketers at market hubs, which are typically located in close proximity or ready access to our facilities.

NGL Logistics and Marketing

NGL logistics and marketing consists of the fractionation, storage, terminalling, transportation, distribution and marketing of NGLs. Through fractionation, the raw NGL mix produced by processing the natural gas is separated into component parts (ethane, propane, butanes and natural gasoline). Such component parts are delivered to end-users through pipelines, barges, trucks and rail cars. End-users of component NGLs include petrochemical and refining companies and propane markets for heating, cooking or crop drying applications. Retail distributors often sell to end-use propane customers.

Competitive Strengths

Large Scale, Strategically Located and Diversified Operations

Our portfolio of integrated midstream assets is strategically positioned across multiple geographic regions and producing basins where we provide products and services spanning the midstream value chain to a broad base of customers. We believe the size and scope of our portfolio of assets place us in proximity to a large number of new and existing gas producing wells in our areas of operations, allowing us to generate economies of scale within our operating regions and allowing us to attract customers by providing access to our existing facilities and to multiple end-use markets and market hubs.

• Significant scale of operations. We own or operate approximately 10,000 miles of natural gas pipelines and approximately 550 miles of NGL pipelines, with natural gas gathering systems covering approximately 14,500 square miles and 21 natural gas processing plants with access to natural gas supplies in the Permian Basin, north Texas, onshore southern Louisiana and the Gulf of Mexico. Additionally, we have an integrated NGL logistics and marketing business, with 16 storage, marine and transport terminals with an NGL above ground storage capacity of approximately 900 MBbls, net NGL fractionation capacity of approximately 300 MBbls/d and 43 owned and operated storage wells with a net storage capacity of 65 MMBbls. Due to the high cost of obtaining permits for and constructing midstream assets and the difficulty of developing the expertise necessary to operate them, the barriers to entry are high in the midstream natural gas sector on a scale competitive with ours. We believe our installed asset base complements our history of providing high-quality services.

• Multiple producing basins. Our major gathering and processing systems source natural gas volumes from four producing areas: the Permian Basin, the onshore South Louisiana basin, the offshore Gulf of Mexico basin, including the deepwater and deep shelf formations, and the Fort Worth Basin, which includes Barnett Shale production. In aggregate, these basins are a significant contributor to current domestic natural gas production, favorably positioning us to access large, diverse and important sources of domestic natural gas supply.

• Large and diverse customer base. We focus on providing high-quality services at competitive costs, which we believe has allowed us to attract and retain a large, diverse customer base. Our customer base includes active natural gas producers in our regions of operations as well as purchasers and consumers of NGLs. While we have commercial relationships with large, diversified energy companies, we also provide services to a number of other customers, which reduces our dependence on any one customer. As of September 30, 2007, other than Chevron (including CPC), no single customer accounted for more than 10% of our consolidated revenue. We expect to continue to strengthen and grow our customer

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relationships due to our broad service offerings, well-positioned assets, competitive cost of service, market access, and commitment to providing high-quality customer service.

We have an ongoing relationship with CPC (the Chevron Phillips Chemical joint venture) for feedstock supply and services provided at Mont Belvieu and Galena Park. Agreements associated with this relationship are expected to be renegotiated over time to better meet the objectives of both companies, but are expected to continue on some similar basis due to the integrated nature of facilities and the difficulty and cost associated with replicating our assets.

For a detailed discussion of our gathering and processing agreements with Chevron, see “—Significant Customers.”

• Broad service and product offering. We offer a wide range of midstream natural gas gathering and processing services and NGL logistics and marketing services. We believe the breadth and scope of our assets allow us to attract customers due to our ability to deliver products and services across the value chain and due to our well-positioned assets and markets. We believe this breadth and asset positioning, combined with our singular midstream focus, gives us a competitive advantage over other midstream companies and divisions of larger companies. In addition, we believe this diversity of assets and services diversifies cash flows by reducing our dependency on any particular line of business.

Attractive Cash Flow Characteristics

We believe our strategy, combined with our high-quality asset portfolio and strong industry fundamentals, allow us to generate attractive cash flows and achieve substantial near-term deleveraging of the business. Geographic, business and customer diversity enhances our cash flow profile. We have a favorable contract mix that is primarily fee-based or percent-of-proceeds which, along with our long-term commodity-hedging program, serves to mitigate the impact of commodity price movements on cash flow.

We have hedged the commodity price associated with a significant portion of our expected natural gas, NGL and condensate equity volumes for the years 2007 through 2012 by entering into derivative financial instruments including swaps and purchased puts (or floors). The percentages of our expected equity volumes that are covered by our hedges is approximately 60% to 80% through 2009 and decreases over time. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact of fluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate our actual NGL product composition and to approximate our actual NGL and natural gas delivery points. We intend to continue to manage our exposure to commodity prices in the future by entering into similar hedge transactions as market conditions permit.

Our maintenance capital expenditures have averaged approximately 15% of EBITDA over the last two years. We believe that our assets are well maintained and anticipate that a similar level of capital expenditures will be sufficient for us to continue to operate these assets in a prudent and cost-effective manner.

Asset Base Well-Positioned for Organic Growth

We believe our asset platform and strategic locations allow us to maintain and grow our cash flows as our supply areas continue to benefit from active exploration and development. Generally, higher oil and gas prices, such as those currently being experienced in global energy markets, result in increased domestic drilling and workover activity to increase production. The location of our assets provide us with access to stable natural gas supplies and proximity to end-use markets and liquid market hubs while positioning us to capitalize on high drilling and production activity in our basins and on emerging opportunities for Gulf Coast assets associated with LNG imports and LPG imports. Our existing infrastructure has the capacity to handle incremental volumes without significant capital investments. Finally, we believe that as U.S. demand for natural gas and NGLs continues to grow, our infrastructure will continue to increase in value as such infrastructure takes on increasing importance in meeting that demand.

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Experienced and Incentivized Management Team

Our seven senior management team members have over 200 years of combined experience operating, acquiring, integrating and improving the value of midstream natural gas assets and businesses across major supply areas including Texas, Louisiana and the Gulf Coast, and have held management positions at companies with midstream assets and commercial operations similar in scale and scope to ours. Several of the senior management team members have worked together effectively in prior roles and have complementary skills and sufficient depth to continue to manage the combined businesses and seek opportunities for operational and commercial improvements. Our management team is also incentivized to maintain and grow value as the executive management team and other senior managers own approximately 20% of the equity of Targa Investments, our parent company, on a fully diluted basis.

Business Strategy

Our strategy is focused on efficient operations, prudent risk management and growth through acquisitions and organic projects. We will implement this strategy by pursuing the following initiatives:

Enhance Cash Flows. We intend to continue to pursue new contracts, cost effectiveness and operating improvements of our assets. Such improvements in the past have, among other results, included new production and acreage commitments, reducing gas fuel, flare and loss volumes and enhancing NGL recoveries. We will also continue to enhance existing plant assets to improve and maximize capacity and throughput.

Mitigate Cash Flow Volatility. We intend to continue to operate our business in a manner that mitigates the impact of fluctuations in commodity prices on our cash flows. Key to this strategy will be continuing our natural gas, NGL and condensate hedging strategy over time.

Pursue Complementary Investments and Acquisitions. We intend to maintain a balanced and diversified portfolio of midstream energy assets and to optimize this asset base by developing organic projects and pursuing selective acquisitions that we believe will benefit from our existing infrastructure, personnel and customer relationships. We seek to make acquisitions at attractive multiples and follow a disciplined strategy focused on financial returns and strategic fit. In addition, our management has a long track record of successfully acquiring, integrating and improving the value of assets.

Provide Growth and Deleveraging Through Drop-down Strategy. In February 2007, we formed a master limited partnership, Targa Resources Partners LP (the “Partnership”), contributed North Texas to the Partnership and offered partnership units to the public. In October 2007, we sold the San Angelo System (“SAOU”) and the Louisiana System (“LOU”) to the Partnership and offered common units of the Partnership to the public. We own 25.5% of the outstanding limited partner interest of the Partnership, a 2% general partner interest and the associated incentive distribution rights. We intend to utilize the Partnership as a growth vehicle to enhance our cash flows. Our expected drop-downs to the Partnership should reduce our leverage over the next several years.

Our Business—Natural Gas Gathering and Processing Division

We gather and process natural gas from the Permian Basin in west Texas and southeast New Mexico, the offshore region of the Louisiana Gulf Coast 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. Most of the NGLs we process are supplied through our gathering systems which, in aggregate, consist of over 10,000 miles of natural gas pipelines. The remainder is supplied through third-party owned pipelines. Our processing plants include 15 facilities that we own (either wholly or jointly) and operate as well as 6 facilities in which we have an ownership interest but are operated by others. During 2006, we processed an average of approximately 1.8 Bcf per day of natural gas and produced an average of approximately 106.8 MBbl/d of NGLs, in each case, net to our ownership interests. In the first nine months of 2007, we processed an average of approximately 1.9 Bcf per day of natural gas and produced an average of approximately 105.7 MBbl/d of NGLs, in each case net to our ownership interest.

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We continually seek new supplies of natural gas, both to offset the natural declines in production from connected wells and to increase throughput volumes. We obtain additional natural gas supply in our operating areas by contracting for production from new wells or by capturing existing production currently gathered by others. Competition for new natural gas supplies is based primarily on location of assets, commercial terms, service levels and access to markets. The commercial terms of natural gas gathering and processing arrangements are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and operating costs, which are impacted by operational efficiencies and economies of scale.

We believe our extensive asset base and scope of operations in the regions in which we operate provide us with significant opportunities to add both new and existing natural gas production to our systems. We believe our size and scope give us a strong competitive position by placing us in proximity to a large number of existing and new natural gas producing wells in our areas of operations, allowing us to generate economies of scale and to provide our customers with access to our existing facilities and to multiple end-use markets and market hubs. Additionally, we believe our ability to serve our customers’ needs across the natural gas and NGL value chain further augments our ability to attract new customers and end-users.

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The following tables set forth key ownership and operational information regarding our operating gathering systems and natural gas processing plants:

Natural Gas Gathering and Processing Systems
Facility	% Owned	County/Approximate Square Miles	Approximate Gross Processing Capacity (MMcf/d)	2006 Approximate Inlet Throughput Volume (MMcf/d)	2006 Approximate NGL Production (MBbls/d)	Process Type		Approximate Fractionation Capacity (MBbl/d)
Permian Basin
Sand Hills	100.0	Crane, TX	150	121.8	14.0	Cryo	(6)	N/A
Saunders(1)	63.0	Lea, NM	70	28.7	3.7	Cryo		N/A
Eunice(1)	63.0	Lea, NM	120	56.1	6.6	Cryo		N/A
Monument(1)	63.0	Lea, NM	90	45.0	4.6	Cryo		N/A
Mertzon(2)	100.0	Irion, TX	48	30.3	5.5	Cryo		N/A
Sterling(2)	100.0	Sterling, TX	62	52.4	8.5	Cryo		N/A
Conger(2)(3)	100.0	Sterling, TX	25	N/A	N/A	Cryo		N/A
			565	334.3	42.9
Combined Gathering Area		10 counties/8,160 square miles
Louisiana Gulf Coast
Barracuda	100.0	Cameron, LA	200	124.2	3.2	Cryo		N/A
Lowry	100.0	Cameron, LA	265	219.8	4.9	Cryo		N/A
Stingray	100.0	Cameron, LA	300	148.3	2.5	RA	(7)	N/A
Yscloskey(4)	28.4	St. Bernard, LA	1,850	140.6	1.7	RA		N/A
VESCO(5)	22.9	Plaquemines, LA	300	112.3	2.9	Cryo		N/A
Calumet(4)	37.2	St. Mary, LA	1,200	172.9	4.1	RA		N/A
Bluewater(4)	21.8	Acadia, LA	425	40.5	1.2	Cryo		N/A
Terrebonne(4)	11.4	Terrebonne, LA	900	49.8	2.0	RA		N/A
Toca(4)	9.4	St. Bernard, LA	850	37.6	0.9	Cryo/RA		N/A
Iowa	9.9	Jeff. Davis, LA	500	9.6	0.3	Cryo		N/A
Sea Robin	0.8	Vermillion, LA	900	52.0	1.3	Cryo		N/A
Gillis(2)	100.0	Calcasieu, LA	180	129.2	7.9	Cryo		13.0
Acadia(2)	100.0	Acadia, LA	80	39.8	1.8	Cryo		N/A
			7,950	1,276.6	34.7			13.0
Combined Gathering Area		12 parishes/3,800 square miles
North Texas
Chico(2)	100.0	Wise, TX	265	150.5	17.6	Cryo	(6)	11.5
Shackelford(2)	100.0	Shackelford, TX	13	11.3	1.3	Cryo	(6)	N/A
			278	161.8	18.9			11.5
Combined Gathering Area		14 counties/2,500 square miles

(1) These plants are part of our Versado joint venture with Chevron, and 2006 volumes represent our 63.0% ownership interest.

(2) Included in assets of the Partnership.

(3) The Conger plant is not currently operating, but is on standby and can be quickly reactivated on short notice to meet additional needs for processing capacity.

(4) Our ownership is adjustable and subject to annual redetermination.

(5) VESCO volumes represent our 22.9% ownership interest.

(6) Cryo—Cryogenic Processing.

(7) RA—Refrigerated Absorption.

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Permian Basin Assets

The Permian Basin is characterized by long-lived, multi-horizon oil and gas reserves that have low natural production declines. Natural gas produced in the Permian Basin typically has higher NGL content, commonly referred to in the industry as rich gas. Rich gas makes processing a necessity before natural gas can be transported via interstate pipeline and provides for high NGL recovery and profitable processing margins under the percent of proceeds contracts.

Drilling and workover activity to increase oil and natural gas production in the Permian Basin has increased over the last several years, driven primarily by higher oil and natural gas prices. Workover activity is designed to allow existing wells to produce more oil and natural gas through recompletions, formation stimulation, enhanced artificial lift, enhanced oil recovery and other techniques.

We believe we are well positioned as a gatherer and processor in the Permian Basin. We have broad geographic scope, covering portions of 10 counties and approximately 8,160 square miles in southeast New Mexico and west Texas. Proximity to production and development provide us with a competitive advantage in capturing new supplies of natural gas because of our resulting competitive costs to connect new wells and to process additional natural gas in our existing processing plants. Additionally, because we operate all of our plants in this region, we are often able to redirect natural gas among several of our processing plants, allowing us to optimize processing efficiency and further improve the profitability of our operations.

Our Permian Basin operations consist of three different sets of assets: (i) west Texas, (ii) the Versado system and (iii) the San Angelo Operating Unit (the “SAOU System”).

West Texas Assets.The west Texas facilities consist of the Sand Hills plant and the West Seminole and Puckett gathering systems. The systems consist of approximately 1,300 miles of natural gas gathering pipelines. These gathering systems are low-pressure gathering systems with significant compression assets. The Sand Hills refrigerated cryogenic processing plant has residue gas connections to pipelines owned by affiliates of Enterprise Products Partners, ONEOK and El Paso.

Versado System.The Versado processing plants consist of three plants included in the Versado Gas Processors joint venture: Saunders, Eunice and Monument. Versado Gas Processors is a joint venture that is 63% owned by us and 37% owned by Chevron. These refrigerated cryogenic processing plants have 280 MMcf per day of total processing capacity in aggregate (net to our interest, 176 MMcf per day). The Versado plants have residue gas connections to pipelines owned by affiliates of El Paso, MidAmerican Energy Company and Kinder Morgan Energy Partners, L.P.

SAOU System (described under Targa Resources Partners LP below).

Louisiana Assets

Our Louisiana gathering systems and processing plants are supplied by natural gas produced from the South Louisiana basin onshore and from the shelf, deep shelf and deepwater of the Gulf of Mexico. With the strategic location of our assets in Louisiana, we have access to the Henry Hub, the largest natural gas hub in the United States, and a substantial NGL distribution system with access to markets throughout Louisiana and the southeast United States.

Our Louisiana Natural Gas Gathering and Processing assets consist of (i) coastal straddle plants and (ii) the onshore gathering and processing assets of the LOU System. Coastal straddle plants are generally situated on mainline natural gas pipelines and process volumes of natural gas collected from multiple offshore producing areas through a series of offshore gathering systems and pipelines. Our coastal straddle plants, some of which are operated by us, are located along the Louisiana Gulf Coast.

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Coastal Louisiana Straddle Plants. Our Coastal Louisiana assets consist of three wholly owned and eight partially owned straddle plants located on the Louisiana Gulf Coast. We also own and operate two offshore gathering systems, the 89-mile Pelican pipeline system, which has capacity of 125 Mmcf per day, and supplies a portion of the natural gas to the Barracuda processing facility and the 120-mile Seahawk pipeline system, which has capacity of 105 Mmcf per day and supplies a portion of the natural gas to the Lowry processing facility. The gathering systems are unregulated pipelines that gather natural gas from the shallow water central Gulf of Mexico shelf. The Seahawk gathering system that aggregates natural gas to supply the Lowry plant also gathers some natural gas from onshore South Louisiana locations. Additionally, we have an interest in the Venice gathering system, an offshore gathering system, regulated as an interstate pipeline by the FERC, which supplies a portion of the natural gas to VESCO.

Our Coastal Louisiana straddle plants process natural gas produced from shallow water central and western Gulf of Mexico natural gas wells and from deep shelf and deepwater Gulf of Mexico production via connections to third-party pipelines or through pipelines owned by us. Our Coastal Louisiana straddle plants have access to markets across the United States through the pipelines on which they are situated. These straddle plants are competitively positioned to receive natural gas produced from the Gulf of Mexico due to their pipeline interconnections and available capacity.

LOU System (described under Targa Resources Partners LP below).

Targa Resources Partners LP

The Partnership’s business consists of three sets of gathering and processing assets: (i) North Texas, (ii) the SAOU System and (iii) the LOU System.

North Texas.North Texas includes the following assets:

• the Chico system, located in the northeast part of the Fort Worth Basin, which consists of:

• approximately 1,900 miles of natural gas gathering pipelines with approximately 1,850 active connections to producing wells and central delivery points;

• a refrigerated cryogenic natural gas processing plant with throughput capacity of approximately 265 MMcf/d (for the year ended December 31, 2006 and the nine months ended September 30, 2007, the average daily plant inlet volume was approximately 151 MMcf/d and 149 MMcf/d, respectively); and

• an 11,500 Bbls/d fractionator located at the processing plant that enables the Partnership, based on market conditions, to either fractionate a portion of its raw NGL mix into separate NGL products for sale into local and other markets or deliver raw NGL mix to Mont Belvieu for fractionation primarily through Chevron’s West Texas LPG Pipeline, L.P (“WTLPG”);

• the Shackelford system, located on the western side of the Fort Worth Basin, which consists of:

• approximately 2,100 miles of natural gas gathering pipelines with approximately 800 active connections to producing wells and central delivery points;

• a cryogenic natural gas processing plant with throughput capacity of approximately 13 MMcf/d (for the year ended December 31, 2006 and the nine months ended September 30, 2007, the average daily plant inlet volume was approximately 11 MMcf/d and 11 MMcf/d, respectively); and

• a 32-mile, 10-inch diameter natural gas pipeline connecting the Shackelford and Chico systems, which we refer to as the “Interconnect Pipeline,” that is used primarily to send natural gas gathered in excess of the Shackelford system’s processing capacity to the Chico plant.

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The Shackelford plant delivers gas to Atmos Energy Corporation, or Atmos. The Chico plant can deliver residue gas to Natural Gas Pipeline Company of America, which is owned by Kinder Morgan, Inc. and serves the Midwest, specifically the Chicago market, ET Fuel System, which is owned by Energy Transfer Partners, L.P. and has access to the Waha, Carthage and Katy hubs in Texas, and Atmos.

SAOU System.The Partnership’s Permian Basin assets include the following:

• approximately 1,350 miles of gathering pipelines covering approximately 4,000 square miles in portions of ten counties near San Angelo, Texas, including:

• approximately 850 miles of low-pressure gathering systems, which allow wells that produce at progressively lower field pressures as they age to remain connected to the gathering system and to continue to produce for longer periods than otherwise possible; and

• approximately 500 miles of high pressure gathering pipelines that deliver the natural gas to its processing plants currently operating in the region. The gathering system has 27 compressor stations at several central delivery points to inject low pressure gas into these high pressure pipelines;

• approximately 3,000 active connections to producing wells and/or central delivery points;

• the Mertzon and Sterling processing plants, which are refrigerated cryogenic plants and have aggregate processing capacity of approximately 110 MMcf/d; and

• the Conger cryogenic processing plant with capacity of approximately 25 MMcf/d that is not currently operating, but can be reactivated on short notice to meet additional needs for processing capacity.

The Mertzon processing plant currently delivers residue gas to the Rancho Pipeline owned by Kinder Morgan, and NGLs produced by the plant are delivered to a pipeline owned by DCP Midstream, LLC (“DCP”) that delivers such NGLs to Targa-owned fractionators and the Mont Belvieu hub. The Sterling processing plant has residue gas connections to pipelines owned by affiliates of Atmos, El Paso Natural Gas Company, or El Paso, ONEOK and Enterprise Products/ET Fuel, and NGLs are delivered to the West Texas NGL pipeline, owned by Chevron, which also accesses the Mont Belvieu hub.

LOU System.The Partnership’s Louisiana assets include the following:

• approximately 700 miles of gathering system pipelines, covering approximately 3,800 square miles in southwest Louisiana between Lafayette and Lake Charles;

• the Gillis and Acadia processing plants, which are refrigerated cryogenic plants that have aggregate processing capacity of approximately 260 MMcf/d;

• an integrated fractionation facility at the Gillis plant with processing capacity of approximately 13 MBbls/d; and

• an approximately 60-mile intrastate pipeline system.

The LOU System’s processing plants have direct access to the Lake Charles industrial market through its intrastate pipeline system, providing the ability to deliver natural gas to industrial users and electric utilities in the Lake Charles area. As a result of the location and flexibility of its intrastate pipeline assets and the reliability of its natural gas supplies in the area, the LOU System has a leading market share in the Lake Charles area. It also has access to both interstate natural gas supplies and markets as well as access to the liquid NGL markets of the Louisiana and Texas gulf coast. For example, the Acadia plant also has the ability to deliver high-pressure residue gas to markets throughout the United States by accessing the Trunkline, Transco, Tennessee, Columbia Gulf and GulfSouth pipelines. The industrial customers that burn the Gillis plant residue gas readily burn richer (higher Btu) gas which provides the LOU System with operational and commercial flexibility to process less

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NGLs from the gas stream if unexpected operating conditions occur or if NGLs are more valuable as natural gas. Such volumes are typically under short term contracts. The above factors mitigate the commodity price risk typically associated with wellhead purchase or keep-whole contracts.

Our Business—NGL Logistics and Marketing Division

In our NGL Logistics and Marketing division, we use our platform of integrated assets to fractionate, store, terminal, transport, distribute and market NGLs typically under fee-based and margin-based arrangements. For NGLs to be used by refineries, petrochemical manufacturers, propane distributors and other industrial end-users, they must be fractionated into their component products and efficiently delivered to various points throughout the U.S. Our NGL logistics and marketing assets are generally connected to and supplied, in part, by our Natural Gas Gathering and Processing assets and are primarily located at Mont Belvieu and Galena Park near Houston, Texas and in Lake Charles, Louisiana with terminals and transportation assets across the United States. In addition, we own or commercially manage assets in a number of other states, including Alabama, Nevada, California, Florida, Mississippi, Tennessee, Kentucky and New Jersey. The geographic diversity of our assets provides us direct access to many NGL customers as well as markets via open-access regulated NGL pipelines owned by third-parties.

Our NGL Logistics and Marketing division consists of three segments: (i) Logistics Assets, (ii) NGL Distribution and Marketing and (iii) Wholesale Marketing. Our Logistics Assets segment includes the assets involved in the fractionation, storage and transportation of NGLs. Our NGL Distribution and Marketing segment markets our own NGL production and also purchases NGL products from third parties for resale. Our Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations.

Logistics Assets Segment

Fractionation. NGL fractionation facilities separate raw NGL mix into discrete NGL products: ethane, propane, butanes and natural gasoline. Raw NGL mix recovered from our Natural Gas Gathering and Processing division represents the largest source of volumes processed by our NGL fractionators.

The majority of our NGL fractionation facilities process raw NGL mix under fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, including energy costs. The operating results of our NGL fractionation business are dependent upon the volume of raw NGL mix fractionated and the level of fractionation fees charged.

We believe that sufficient volumes of raw NGL mix will be available for fractionation in commercially viable quantities for the foreseeable future due to increases in natural gas liquids production from the Fort Worth Basin, Fayetteville Shale, Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from continued production of NGLs in areas such as the Permian Basin, Mid-Continent, south Louisiana and Shelf and Deepwater Gulf of Mexico. Changes in dew point specifications implemented by individual pipelines and enacted by the FERC across the industry should result in a potential increase in volumes of raw NGL mix available for fractionation because the natural gas will require processing or conditioning to meet pipeline quality specifications. These requirements could help to establish a base volume of raw NGL mix during periods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of raw NGL mix are contractually committed to our NGL fractionation facilities.

Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain raw NGL mix and distribute NGL products is also an important competitive factor. This ability is a function of the existence of the pipeline and storage infrastructure necessary to conduct such operations. The scope and capability of our logistics assets, including our transportation and distribution systems, give us access to both substantial sources of raw NGL mix and a large number of end-use markets.

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The following table details our fractionation facilities:

Facility	% Owned	Maximum Gross Capacity (MBls per day)	2006 Net Throughput (MBls per day)
Operated Fractionation Facilities: (1)
Lake Charles Fractionators(2) (Lake Charles, LA)	100.0	55	32.8
Cedar Bayou Fractionators (Mont Belvieu, TX)	88.0	215	131.2
Equity Fractionation Facilities (non-operated):
Gulf Coast Fractionators (Mont Belvieu, TX)	38.8	105	41.5
Partnership Operated Fractionation Facilities:
Gillis Plant Fractionator (Lake Charles, LA)(3)	100.0	13	9.7
Chico Plant Fractionator (Wise, TX)(3)	100.0	12	12.0	(4)

(1) Excludes operating data for our Chico and VESCO fractionation facilities.

(2) Includes ownership through our 88% interest in Downstream Energy Ventures Co, LLC.

(3) Included in our Natural Gas Gathering and Processing division.

(4) Chico Plant Fractionator is running at full capacity.

Our fractionation assets include ownership interests in three stand-alone fractionation facilities that are strategically located on the Texas and Louisiana Gulf Coast. We operate two of the facilities, one at Mont Belvieu, Texas, and the other at Lake Charles, Louisiana. During 2006, these facilities fractionated an aggregate average of approximately 227 thousand barrels per day (net to our ownership interest). We also have an equity investment in a third fractionator, the GCF Fractionator, or GCF, located in Mont Belvieu. We are subject to a consent decree with the Federal Trade Commission, issued December 12, 1996, that, among other things, prevents us from participating in commercial decisions regarding rates paid by third parties for fractionation services at GCF. This restriction on our activity at GCF will terminate on December 12, 2016, twenty years after the date the consent order was issued. This consent decree predates our ownership of the assets.

Storage and Terminalling. In general, our storage provides warehousing of raw NGL mix, NGL products and petrochemical products in underground wells to inject and withdraw such products at various times in order to meet demand cycles. Similarly, our terminalling operations are the inbound/outbound logistics and warehousing of raw NGL mix, NGL products and petrochemical products in above-ground storage tanks. Our underground storage and terminalling facilities range in scale from serving a singular market, such as propane, to serving multiple products and markets, such as our Mont Belvieu and Galena Park facilities where we have extensive pipeline connections for mixed NGL supply and delivery of component NGLs. In addition, some of these facilities are connected to marine, rail and truck loading and unloading facilities that provide services and products to our customers. We provide long-and short-term storage and terminalling services and throughput capability to affiliates and third-party domestic customers for a fee.

We own and operate a total of 43 storage wells at our facilities with a net storage capacity of approximately 65 MMBbls, the usage of which may be limited by brine handling capacity, which is utilized to displace NGL from storage. We also have 14 wholly owned terminal facilities in Texas, Kentucky, Mississippi, Tennessee, Louisiana, Florida and New Jersey.

We operate our storage and terminalling facilities based on the needs and requirements of our customers in the NGL, petrochemical, heating and other related industries. We usually experience an increase in demand for storage and terminalling of mixed NGLs during the summer months when gas plants typically reach peak NGL production, refineries have excess NGL products and liquid petroleum gas, or LPG, imports are often highest. Likewise, demand for storage and terminalling at our propane facilities typically peak during the highest demand periods of fall, winter and early spring.

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The following tables detail our NGL storage and terminalling assets:

NGL Storage Facilities
Facility	% Owned	County/Parish State	Number of Wells		Gross Permitted Capacity (Mmbbl)
Hackberry Storage (Lake Charles)	100	Cameron, LA	12	(3)	16.3
Mont Belvieu Storage	100	Chambers, TX	20	(4)	65.0
Easton Storage (1)(2)	100	Evangeline, LA	0	(1)	—
Hattiesburg Storage	50	Forrest, MS	3		7.5
VESCO	23	Plaquemines, LA	8		10.0
Versado(2)	63	Lea, NM	0		—

(1) One of the inactive wells expected in commercial service during 2008.

(2) Out of service.

(3) Four of twelve owned wells leased to Citgo under long-term lease; one of twelve currently permitting for hydrocarbon service.

(4) We own 20 wells and operate 6 wells owned by ChevronPhillipsChemical.

Terminal Facilities
	% Owned	County/Parish State	Description	2006 Throughput (million gallons)
Galena Park Terminal	100	Harris, TX	NGL import/export terminal	1,131.3
Calvert City Terminal	100	Marshall, KY	Propane terminal	45.5
Greenville Terminal	100	Washington, MS	Marine propane terminal	25.4	(1)
Pt. Everglades Terminal	100	Broward, FL	Marine propane terminal	43.8
Tampa Terminal	100	Hillsborough, FL	Marine propane terminal	19.2
Tyler Terminal	100	Smith, TX	Propane terminal	7.6
Abilene Transport	100	Taylor, TX	Raw NGL transport terminal	8.6
Bridgeport Transport	100	Jack, TX	Raw NGL transport terminal	47.9
Gladewater Transport	100	Gregg, TX	Raw NGL transport terminal	20.6
Hammond Transport	100	Tangipahoa, LA	Transport terminal	32.3
Chattanooga Terminal	100	Hamilton, TN	Propane terminal	20.1
Mont Belvieu Terminal	100	Chambers, TX	Transport and storage terminal	3,514.5	(1)
Venice Terminal	23	Plaquemines, LA	Storage terminal	6.8
Hackberry Terminal	100	Cameron, LA	Storage terminal	531.3
Sparta Terminal	100	Sparta, NJ	Propane terminal	8.3
Hattiesburg Terminal	50	Forrest, MS	Propane terminal	170.1

(1) Volumes reflect total import and export across the dock/terminal.

Wholesale Marketing Segment

Transportation and Distribution. Our NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements of our marketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coast area. Our assets are also deployed to serve our wholesale distribution terminals, fractionation facilities, underground storage facilities, pipeline injection terminals and numerous crude oil refineries and petrochemical facilities. These distribution assets provide a variety of ways to transport and deliver products to our customers. Our transportation assets, as of September 30, 2007, include:

• approximately 800 railcars that we lease and manage;

• approximately 80 transport tractors and 100 tank trailers;

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• approximately 530 miles of gas liquids pipelines, primarily in the Gulf Coast area; and

• 21 NGL pressurized barges with more than 320,000 barrels of capacity.

Refinery Services. In our refinery services business, we typically provide NGL balancing services, in which we have contractual arrangements with refiners to purchase and/or market propane and to provide butane supply. We also contract for and use the storage, transportation and distribution assets included in our Logistics Assets segment to assist refinery customers in managing their NGL product demand and production schedules. This includes both feedstocks consumed in refinery processes and the excess NGL produced by those same refining processes. Under typical net-back contracts, we generally retain a portion of the resale price of NGL sold, subject to a fixed minimum fee per gallon on products sold. Under net-back contracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply, subject to a minimum fee per gallon. In 2006, we sold an average of 38,000 barrels of NGL per day through this refinery services business. In 2007, we have extended and expanded our refinery services contracts.

Key factors impacting the results of our refinery services business include production volumes produced, propane and butane prices, as well as our ability to perform receipt, delivery and transportation services in order to meet refinery demand.

Wholesale Propane Marketing. Our wholesale propane marketing operations include the sale of propane and related logistics services to major multi-state retailers, independent retailers and other end-users. Our propane supply primarily originates from both our refinery/gas supply contracts and our other owned or managed logistics and marketing assets. We generally sell propane at a fixed or posted price at the time of delivery and, in some circumstances, we earn margin on a net-back basis. In 2006, we sold an average of approximately 33,000 barrels of propane per day.

Our wholesale propane marketing business is significantly impacted by weather-driven demand, particularly in the winter, the price of propane in the markets we serve and our ability to deliver propane to customers to satisfy peak winter demand.

NGL Distribution and Marketing Segment

In our NGL Distribution and Marketing segment, we market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. In 2006, our distribution and marketing services business sold an average of approximately 220,000 barrels per day of NGLs to third parties in North America, not including approximately 11,000 barrels per day sold by Targa and recorded in its gathering and processing business. We generally purchase raw NGL mix from producers at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which we earn margins from purchasing and selling NGL products from producers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward physical markets. To effectively serve our customers in the NGL Distribution and Marketing segment, we contract for and use many of the assets included in our Logistics Assets segment.

Operational Risks and Insurance

We are subject to all risks inherent in the midstream natural gas business. These risks include, but are not limited to, explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights-of-way, which could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or pollution of the environment, as well as curtailment or suspension of operations at the affected facility. We maintain general public liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance

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market environment. The costs associated with these insurance coverages have increased significantly during recent periods, and may continue to do so in the future. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirements have increased substantially, and terms generally are less favorable than terms that could be obtained prior to such hurricanes. We believe that recent increases in insurance premiums, deductibles and co-insurance requirements represent the near-term impact of Hurricanes Katrina and Rita. Although we do not anticipate that insurance terms and coverage will return to levels experienced prior to such hurricanes, we do expect that, barring a recurrence of significant hurricane related losses, more favorable insurance terms and coverage will be available over the next several years.

The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates we consider commercially reasonable, particularly in the area of contingent business interruption insurance for our offshore gathering systems and, should the Terrorism Risk Insurance Extension Act of 2005 not be extended beyond December 2007, terrorism insurance.

Significant Customers

For the year ended December 31, 2006, transactions with Chevron and CPC represented approximately 28% and 20% of our consolidated revenues and consolidated product purchases, respectively. No other third party customer accounted for more than 10% of our consolidated revenues during these periods. For the nine months ended September 30, 2007, transactions with Chevron and CPC represented approximately 24% and 13% of our consolidated revenues and consolidated product purchases, respectively.

Gas Gathering and Processing Contracts with Chevron

Under gas gathering and processing agreements with us or the Versado and VESCO entities in which we have a 63.0% and 22.9% ownership interest, respectively, Chevron has dedicated, on a life-of-field basis, substantially all of the natural gas it produces from committed areas in New Mexico, Texas and the Gulf of Mexico. Under these contracts, we receive a percentage of the volumes of NGLs and residue gas attributable to the processed natural gas in Texas and New Mexico and a percentage of the volumes of NGLs or a fee depending on processing economics for the Gulf of Mexico. These contracts provide that either party has the right to periodically renegotiate the processing terms. If the parties are unable to agree, then the matter is settled by binding arbitration. These terms were renegotiated effective September 1, 2006 for substantially all of the affected production without the need for arbitration.

Refinery Services and Related Contracts With Chevron

Our master refinery services agreement for Chevron refineries was renegotiated and replaced on September 1, 2006 with liquid product purchase and sale agreements which allow us to purchase propane (and in some cases to purchase and sell butanes) for the Elk Hills, Kettleman Hills, McKittrick and Taft 1C Gas plants, the El Segundo (propane and p/p mix), Maysville (butane only), Pascagoula, Richmond and Salt Lake City refineries; time charter agreements in which we provide transportation for Chevron’s p/p mix and butane produced at the Pascagoula Refinery; and fractionation agreements in which we fractionate Chevron’s raw product and butane at our Mont Belvieu facility. These contracts have one to three year terms. We are well positioned to retain Chevron as a customer based on these contractual positions and customer relationships, our long-standing history of customer service, established relationship with each facility, criticality of the service provided, competitive rate structure, competitive-cost provision of non-traditional services and potentially high costs of replacing the infrastructure assets that we have in place to serve Chevron’s needs.

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In addition to our agreements with Chevron, we have agreements with Chevron Phillips Chemical (“CPC”), a separate joint venture affiliate of Chevron, pursuant to which we supply a significant portion of CPC’s NGL feedstock needs for petrochemical plants in the Texas gulf Coast area. Through a related services agreement, we provide storage and logistical services to CPC for feedstocks and products produced from the petrochemical plants. Under provisions of the services contract, we have given CPC notice of termination, which starts a two year termination clock to renegotiate the agreement, for the mutual benefit of both companies. Similarly, we have given notice on the feedstocks agreement, which also starts a two year clock, effective August 2007, to renegotiate this agreement for the mutual benefit of both companies. We are well positioned to retain CPC as a customer based on our long-standing history of customer service, criticality of the service provided, the integrated nature of facilities and the difficulty and high cost associated with replicating our assets.

Competition

We face strong competition in acquiring new natural gas supplies. Competition for natural gas supplies is primarily based on the location of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, reliability and access to end-use markets or liquid marketing hubs. Competitors to our gathering and processing operations include other natural gas gatherers and processors, such as major interstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. Our major competitors for natural gas supplies in our current operating regions, include Duke Energy Field Services (“DEFS”), Enterprise Products, Energy Transfer, Enbridge, JL Davis and Southern Union Gas (formerly Sid Richardson). Many of our competitors have greater financial resources than we possess. If we are unable to maintain or increase the throughput on our gathering systems or in our processing plants because of an inability to connect new supplies of gas or attract new customers, then our business and financial results could be materially adversely affected.

We also compete for NGL products to market through our NGL Logistics and Marketing division. Our competitors include major oil and gas producers who market NGL products for their own account and for others. Additionally, we compete with several other NGL marketing companies, including Enterprise Products, TEPPCO Partners, DEFS and BP p.l.c.

Additionally, we face competition for raw NGL mix supplies at our fractionation facilities. Our competitors include large oil, natural gas and petrochemical companies. The fractionators in which we own an interest in the Mont Belvieu region compete for volumes of raw NGL mix with other fractionators also located at Mont Belvieu. Among the primary competitors are Enterprise Products and ONEOK. In addition, certain producers fractionate raw NGL mix for their own account in captive facilities. Our Mont Belvieu fractionators also compete on a more limited basis with fractionators in Conway, Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. Our other fractionation facilities compete for raw NGL mix with the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. Our customers who are significant producers of raw NGL mix and NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using our services.

Regulation

Regulation of Our Interstate Natural Gas Pipelines

We are the commercial operator and part-owner (22.9 percent equity interest) of Venice Gathering System, L.L.C. (“VGS”), a natural gas pipeline that originates on the Outer Continental Shelf (“OCS”). VGS is regulated by FERC under the Natural Gas Act of 1938, or NGA, and the Natural Gas Policy Act of 1978, or NGPA. VGS operates under a FERC-approved, open-access tariff that establishes rates and terms and conditions under which the system provides services to its customers. Pursuant to FERC’s jurisdiction, existing pipeline rates and/or terms and conditions of service may be challenged by customer complaint or by FERC and proposed rate changes or changes in the terms and conditions of service may be challenged by protest.

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Generally, FERC’s authority extends to:

• Transportation of natural gas;

• rates and charges for natural gas transportation;

• certification and construction of new facilities;

• extension or abandonment of services and facilities;

• maintenance of accounts and records;

• commercial relationships and communications between pipelines and certain affiliates;

• terms and conditions of service and service contracts with customers;

• depreciation and amortization policies; and

• acquisition and disposition of facilities.

VGS holds a certificate of public convenience and necessity issued by FERC pursuant to Section 7 of the NGA permitting the construction, ownership, and operation of its interstate natural gas pipeline facilities and the provision of transportation services. This certificate authorization requires VGS to provide on a non-discriminatory basis open-access services to all customers who qualify under its FERC gas tariff. Under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment of items for regulatory purposes. Thus, the books and records of VGS may be periodically audited by FERC.

The maximum recourse rates that may be charged by VGS for its services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable. VGS is permitted to discount its firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.”

The design, construction, and operation of our natural gas pipelines are also subject to regulation by the Office of Pipeline Safety of the Department of Transportation, or DOT. The DOT has promulgated regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. In Louisiana, the Department of Natural Resources, Pipeline Division implements DOT’s safety rules. In Texas, the Railroad Commission of Texas, or RRC, implements those safety rules. In New Mexico, the New Mexico Public Regulation Commission implements the DOT’s safety rules.

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005, or the 2005 EP Act. The 2005 EP Act is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. With respect to regulation of natural gas transportation, the 2005 EP Act amends the NGA and the NGPA by increasing the criminal penalties available for violations of each Act. The 2005 EP Act also adds a new section to the NGA, which provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases the FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. Before enactment of the 2005 EP Act, FERC was only authorized to impose criminal penalties for violations of the NGA and criminal or civil penalties for violations of the NGPA. This new legislation is applicable to FERC-regulated

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entities, including VGS. EPAct 2005 also amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that present policies pursued by FERC and Congress will continue.

Affiliate Relationships. Commencing in 2003, FERC issued a series of orders adopting rules for new Standards of Conduct for Transmission Providers (Order No. 2004) which applied to interstate natural gas pipelines and to certain natural gas storage companies which provide storage services in interstate commerce. Order No. 2004 became effective in 2004. Among other matters, Order No. 2004 required interstate pipelines to operate independently from their energy affiliates, prohibited interstate pipelines from providing non-public transportation or shipper information to their energy affiliates, prohibited interstate pipelines from favoring their energy affiliates in providing service, and obligated interstate pipelines to post on their websites a number of items of information concerning the company, including its organizational structure, facilities shared with energy affiliates, discounts given for service and instances in which the company has agreed to waive discretionary terms of its tariff.

Late in 2006, the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) vacated and remanded Order No. 2004, as it relates to natural gas transportation providers. The court objected to FERC’s expansion of the prior standards of conduct to include energy affiliates, and vacated the entire rule as it relates to natural gas transportation providers. On January 9, 2007, and as clarified on March 21, 2007, FERC issued an interim rule re-promulgating on an interim basis the standards of conduct that were not challenged before the court, while FERC decides how to respond to the court’s decision on a permanent basis. The interim rule makes the standards of conduct apply to the relationship between natural gas transportation providers and their marketing affiliates, but not to energy affiliates who are not also marketing affiliates. Our only transmission provider, VGS, does not currently engage in any transactions with its market affiliates, and thus the interim rule does not currently impact VGS’ operations.

Several companies requested rehearing and clarification of the interim rule. The March 21, 2007 order on clarification granted some of the requested clarifications and stated that it would address the other requests in its proceeding establishing a permanent rule. FERC has issued a notice of proposed rulemaking, or NOPR, that proposes permanent standards of conduct that FERC states will avoid the aspects of the previous standards of conduct rejected by the court. With respect to natural gas transportation providers, the NOPR proposes (1) that the permanent standards of conduct apply only to the relationship between natural gas transportation providers and their marketing affiliates, and (2) to make permanent the changes adopted in the interim rule permitting risk management employees to be shared by natural gas transportation providers and their marketing affiliates and requiring that tariff waivers be maintained in a written waiver log and available upon request. We have no way to predict with certainty the scope of FERC’s permanent rules on the standards of conduct.

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Market Transparency NOPR. On April 19, 2007, FERC issued a notice of proposed rulemaking in which it proposed to require intrastate natural gas pipelines, which may include both gathering and transportation pipelines, to post daily on their Internet websites the volumes flowing on their systems. In addition, FERC proposed to require all buyers and sellers of more than a minimum volume of natural gas to report to FERC on an annual basis the number and total volume of their transactions. FERC has asserted that is has the jurisdiction to issue these regulations with respect to intrastate pipelines and otherwise non-jurisdictional buyers and sellers of gas in order to facilitate market transparency in the interstate natural gas market pursuant to Section 23 of the NGA, which was added by Section 316 of EPAct 2005. Initial comments were submitted on July 11, 2007, and reply comments were submitted on August 23, 2007, by industry participants. FERC has not yet issued a final rule. If adopted as proposed, our intrastate natural gas operations may incur additional costs in order to comply with the posting and reporting requirements of the rules. We cannot predict the ultimate impact of these regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other natural gas companies with whom we compete.

FERC Policy Statement on Income Tax Allowances. In 2005, FERC issued a policy statement in which it stated it will permit a pipeline to include in its cost-of-service a tax allowance to reflect actual or potential tax liability on its public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be determined by FERC on a case-by-case basis. The new policy entails rate risk due to the case-by-case review requirement. FERC’s new tax allowance policy was appealed to the D.C. Circuit. The D.C. Circuit issued an order on May 29, 2007 in which it upheld FERC’s new tax allowance policy. On August 20, 2007, the D.C. Circuit denied a request for rehearing of the May 29, 2007 decision. The period for appeals has now passed.

On December 8, 2006, FERC issued a new order addressing rates on one of the interstate oil pipelines of SFPP, L.P. (SFPP). In the new order, FERC refined its income tax allowance policy, noting that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, SFPP asked FERC to reconsider this ruling. The ultimate outcome of this proceeding is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service, which may cause the rates for Targa NGL Pipeline Company LLC, or Targa NGL, and the recourse rates for VGS to be set at a level that is different, and in some instances lower, than the level otherwise in effect.

FERC Policy Statement on Proxy Groups for Rates of Return Determinations. On July 19, 2007, FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate returns on equity for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of master limited partnerships (MLPs) in the proxy group for purposes of calculating allowed returns on equity under the Discounted Cash Flow (DCF) analysis, a change from its prior view that MLPs had not been shown to be appropriate for such inclusion. FERC proposes to apply the final policy statement to all natural gas rate cases that have not completed the hearing phase as of the date FERC issues the final policy statement. FERC received comments on the proposed policy in September 2007. FERC’s proposed policy statement is subject to change based on comments filed and therefore we cannot predict the scope of the final policy statement and its impact, if any, on VGS’ rates.

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Regulation of Our Offshore Gathering Facilities

Our Seahawk and Pelican gathering systems gather gas on the OCS. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our Seahawk and Pelican gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation under the NGA as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress.

Seahawk and Pelican are subject to the jurisdiction of the applicable Louisiana regulatory agencies to the extent that those gathering systems traverse state land and/or waters. State regulation of gathering facilities generally includes various safety, environmental, nondiscriminatory take, and common purchaser requirements, and complaint-based rate regulation. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Seahawk and Pelican are also subject to the jurisdiction of the Minerals Management Service, or MMS, since they traverse the OCS pursuant to MMS-issued easements. The MMS has issued a notice of proposed rulemaking to determine whether to revise its regulations to better ensure that pipelines subject to MMS’ jurisdiction provide open and non-discriminatory access to both owner and non-owner shippers as required under section 5(f) of the Outer Continental Shelf Lands Act. No final determination has yet been reached in this proceeding.

Regulation of Our Onshore Gathering Facilities

Our onshore natural gas gathering operations are subject to ratable take and common purchaser statutes in Louisiana, Texas, and New Mexico. The common purchaser statutes generally require our gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Our gathering facilities in New Mexico are not subject to rate regulation. Louisiana and Texas have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering in Texas and Louisiana are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

During the 2007 legislative session, the Texas State Legislature passed H.B. 3273, or Competition Bill, and H.B. 1920, or LUG Bill. The Competition Bill gives the RRC the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and intrastate transportation pipelines in formal rate proceedings. It also gives the RRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The Competition Bill also provides producers with the unilateral option to determine whether or not confidentiality provisions are included in a contract to which a producer is a party for the sale,

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transportation, or gathering of natural gas. The LUG Bill modifies the informal complaint process at the RRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested, provides producers with an annual audit right, and provides the RRC with the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. We cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our operations in Texas.

Regulation of Our Interstate Common Carrier Liquids Pipeline

Targa NGL Pipeline Company LLC, or Targa NGL, a natural gas liquids (“NGL”) pipeline that extends from Lake Charles, Louisiana to Mont Belvieu, Texas, is an interstate common carrier liquids pipeline subject to regulation by FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with FERC. Those tariffs set forth the rates we charge for providing transportation services on our interstate common carrier pipeline as well as the rules and regulations governing these services. The ICA requires, among other things, that such rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint. FERC’s recent Policy Statement on Income Tax Allowances and Policy Statement on Proxy Groups for Rates of Return Determinations are applicable to determining a just and reasonable cost of service for interstate NGL pipelines as well.

Interstate NGL pipelines may change their rates within prescribed ceiling levels that are tied to an inflation index. Shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. FERC, however, also permits cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach in certain specified circumstances.

Regulation of Our Intrastate Liquids and Natural Gas Pipelines

Our intrastate natural gas transportation pipelines are subject to regulation by applicable state regulatory commissions. Proposed and existing rates are subject to state regulation and are subject to challenge by protest and complaint, respectively. Further, the states we operate in require that services be provided on a non-discriminatory basis.

Targa Louisiana Intrastate LLC’s intrastate pipeline receives all of the natural gas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’s rates and terms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources, the pipeline qualifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from most FERC jurisdiction.

Targa Intrastate Pipeline LLC, or Targa Intrastate, owns a Texas intrastate pipeline that transports natural gas from the Shackelford processing plant to an interconnect with a pipeline owned by Atmos—Texas that in turn delivers gas to West Texas Utilities Company’s Paint Creek Power station and is regulated by the DOT. Targa Intrastate is also subject to regulation by the RRC, and has a tariff on file with the RRC.

Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge for intrastate

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transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties.

As discussed above in the context of regulation of our onshore gathering operations, the Texas Competition Bill and LUG Bill contain provisions applicable to intrastate transportation pipelines. We cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our operations in Texas.

Our intrastate NGL pipelines in Louisiana gather raw NGL streams we own from various processing plants in Louisiana to our fractionator in Lake Charles, Louisiana, where the raw NGL streams are fractionated into various products. These pipelines are not subject to FERC regulation or rate regulation by the Louisiana Department of Natural Resources, but are required to comply with DOT safety regulations.

Natural Gas Processing

Our natural gas processing operations are not presently subject to FERC regulation. However, there can be no assurance that our processing operations will continue to be exempt from FERC regulation in the future.

Our processing facilities are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and in Texas and Louisiana, if a complaint is filed, state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs. These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our processing operations.

The ability of our processing facilities and pipelines to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. On June 15, 2006, FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. FERC strongly encouraged all natural gas pipelines subject to its jurisdiction to adopt, as needed, gas quality and interchangeability standards in their FERC gas tariffs modeled on the interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (the NGC+ Work Group), or to explain how and why their tariff provisions differ. We do not believe that the adoption of the NGC+ Work Group’s gas quality interim guidelines by a pipeline that either directly or indirectly interconnects with our facilities would materially affect our operations. We have no way to predict, however, whether FERC will approve of gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline.

Sales of Natural Gas and NGLs

The price at which we buy and sell natural gas and NGLs is currently not subject to federal regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or CFTC. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.

Our sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation can be subject to extensive federal and, if a complaint is filed, state regulation. FERC is continually proposing and implementing new rules and regulations affecting the interstate transportation of natural gas, and to a lesser extent, the interstate transportation of NGLs.

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These initiatives also may indirectly affect the intrastate transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of these regulatory changes to our natural gas and NGL marketing operations, and we do not believe that we would be affected by any such FERC action materially differently than other natural gas and NGL marketers with whom we compete.

Other State and Local Regulation of Our Operations

Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters. For additional information regarding the potential impact of federal, state or local regulatory measures on our business, see “Risk Factors—Risks Related to Our Business,” included elsewhere in this offering circular.

Environmental and Other Matters

Our operation of pipelines, plants, and other facilities for gathering, compressing, treating, processing, fractionating, terminalling, storing or transporting natural gas, NGLs and other products is subject to stringent and complex federal, state, and local laws and regulations pertaining to health, safety and the environment. As with the industry generally, compliance with these laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. These laws and regulations may, among other things, require the acquisition of various permits to conduct regulated activities; require the installation of pollution control equipment or otherwise restrict the way we can handle or dispose of our wastes; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; and require remedial activities or capital expenditures to mitigate pollution conditions caused by our operations or attributable to former operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of removal or remedial obligations, and the issuance of injunctions limiting or prohibiting our activities.

We have implemented programs and policies designed to keep our pipelines, plants, and other facilities in compliance with existing environmental laws and regulations. The clear trend in environmental regulation, however, is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, referred to as “CERCLA” or the “Superfund” law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment,

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for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency, or EPA, and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. We generate materials in the course of our operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum product wastes and ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that are regulated as hazardous wastes. Certain materials generated in the exploration, development, or production of crude oil and natural gas are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and therefore be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas activities. Although we have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater), or to perform remedial activities to prevent future contamination. We are responsible for several remedial projects that have cleanup costs for which we have accrued reserves in the amount of $2.7 million as of September 30, 2007.

Air Emissions

The Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources, including processing plants and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions. We are currently reviewing the air emissions monitoring systems at certain of our facilities. We may be required to incur capital expenditures in the next few years for air emissions monitoring or air pollution control equipment as a result of our review or in connection with maintaining or obtaining operating permits and approvals for air emissions. We currently believe, however, that such requirements will not have a material adverse affect on our operations.

Our failure to comply with the requirements of the Clean Air Act and comparable state laws and regulations could subject us to monetary penalties, injunctions, restrictions on operations, and potentially criminal enforcement actions. For instance, we have been in discussions with the New Mexico Environment Department, or NMED, to resolve alleged air emissions violations at the Eunice, Monument and Saunders gas processing plants. In May 2007, the NMED initially provided us with a draft compliance order proposing to resolve certain

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of these alleged violations, which were identified in the course of an inspection of the Eunice plant conducted by the NMED in August 2005. 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 operation of flares at the Eunice, Monument and Saunders plants. We may be required to incur capital expenditures to upgrade the flares at the Eunice, Monument and Saunders plants in order to resolve these alleged violations, the amount of which currently is not reasonably ascertainable. It is also possible that the NMED may assess a penalty as part of the settlement of these violations, although no such penalty has yet been proposed by the agency.

Global Warming and Climate Control

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states, have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 inMassachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding inMassachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our services.

Water Discharges

The Federal Water Pollution Control Act of 1972, as amended, or the Clean Water Act, and analogous state laws impose restrictions and controls on the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of a permit issued by EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff. The Clean Water Act can impose substantial civil and criminal penalties for non-compliance. Any unpermitted release of pollutants, including NGLs or condensates, therefore, could result in penalties, as well as significant remedial obligations, imposed by the Clean Water Act or analogous state laws.

The Oil Pollution Act of 1990, as amended, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under OPA includes owners and operators of vessels, including barges, offshore platforms, and onshore facilities, such as our pipelines and marine terminals. Under OPA, owners and operators of vessels and shore facilities that handle, store, or transport oil are required to develop and implement oil spill response plans, and establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill for which such parties could be statutorily responsible. We believe that we are in substantial compliance with the Clean Water Act, OPA and analogous state laws.

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Endangered Species Act

The federal Endangered Species Act, as amended, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

Pipeline Safety

Our pipelines are subject to regulation by the U.S. Department of Transportation, or the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended, or NGPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation and storage of natural gas and other gases, and requires any entity that owns or operates pipeline facilities to comply with the regulations under the NGPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with existing NGPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA could result in increased costs.

Our pipelines are also subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The DOT, through the Office of Pipeline Safety, has established a series of rules, which require pipeline operators to develop and implement integrity management programs for gas transmission pipelines that, in the event of a failure, could affect “high consequence areas.” “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility, and areas where people gather that are located along the route of a pipeline. Similar rules are also in place for operators of hazardous liquid pipelines. The DOT is required by the recent Pipeline Inspections, Protection, Enforcement, and Safety Act of 2006 to issue new regulations by December 31, 2007 that set forth safety standards and reporting requirements applicable to low stress pipelines transporting hazardous liquids, including NGLs and condensate. These safety standards may include applicable integrity management program requirements.

In addition, states have adopted regulations, similar to existing DOT regulations, for intrastate gathering and transmission lines. New Mexico, Texas and Louisiana have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines transporting natural gas and NGLs. We currently estimate an annual average cost of $3.4 million for years 2007 through 2009 to perform necessary integrity management program testing on our pipelines required by existing DOT and state regulations. This estimate does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. However, we do not expect that any such costs would be material to our financial condition or results of operations.

Employee Health and Safety

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Other Laws and Regulations

As a supplier of component parts from raw NGL mixtures, including ethane, propane, normal butane, isobutane, and natural gasoline, to end-users by pipeline, rail, truck, and barge, we are further subject to

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regulation by federal transportation-related agencies such as the U.S. Surface Transportation Board (the successor federal agency to the Interstate Commerce Commission), the U.S. Department of Transportation, and the U.S. Coast Guard, as well as by analogous state agencies. These regulatory authorities have broad powers over such regulated activities as carrier operations, operational safety and employee fitness, accounting systems, tariff filings of freight rates, and financial reporting. In addition, the potential for releases and spills of these component parts in the course of our deliveries are an inherent risk that could result in potentially significant costs and liabilities. We believe that our transportation-related services are in substantial compliance with applicable laws and regulations.

In the wake of the September 11, 2001 terrorist attacks on the U.S., the Coast Guard has developed a security guidance document for marine terminals and has issued a security circular that defines appropriate countermeasures for protecting them and explains how the Coast Guard plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the Coast Guard, we have specifically identified certain of our facilities as marine terminals and therefore potential terrorist targets. In compliance with the Coast Guard guidance, we performed vulnerability analyses on such marine terminals. Future analyses of our security measures may result in additional measures and procedures, which measures or procedures have the potential for increasing costs of doing business. Regardless of the steps taken to increase security, however, we cannot provide assurance that our marine terminals will not become the subject of a terrorist attack.

In addition, the Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and on November 20, 2007 further issued an Appendix A to the interim rules that establish the chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

We may continue to hold record title to portions of certain of the Partnership’s assets until the Partnership makes the appropriate filings in the jurisdictions in which such assets are located and obtains any consents and approvals that were not obtained prior to transfer of such assets to the Partnership. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, we may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for the Partnership’s benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause our affiliates to retain title, as nominee for the Partnership’s benefit, until a future date.

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Employees

At September 30, 2007, we had approximately 230 employees at our administrative offices and approximately 660 employees at our operating facilities.

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 (“TMSLP”)), 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 14^th Court of Appeals of Houston in October 2004 and its appellate brief in December 2004.

In September 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. In October 2006, the Versado Defendants filed a motion for rehearing with the Court of Appeals. 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 $2.8 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. At the request of the Supreme Court of Texas, the Versado Defendants and Apache filed responses to the opposing party’s petition in June 2007. Pursuant to an additional request from the Supreme Court of Texas, the Versado Defendants and Apache filed briefs on the merits on October 29, 2007. The Versado Defendants and Apache filed responses to each other’s brief on December 14, 2007. The appeal is currently pending before the Supreme Court of Texas.

As a result of damage caused by Hurricane Rita, TMSLP’s West Cameron 229A platform sank in late September 2005. On November 12, 2005, the submerged wreckage was struck by an integrated tug-barge, the M/T Rebel, owned by K-Sea Transportation (“K-Sea”). As much as 25,000 barrels of No. 6 fuel oil may have entered Gulf of Mexico waters as the barge dragged part of the platform debris approximately three (3) miles from the sunken platform location. After receiving a letter from K-Sea threatening to hold TMSLP liable for all damages, TMSLP filed suit in federal district court in Galveston, Texas on November 21, 2005, seeking to hold K-Sea responsible for damage to the platform. In June 2007, the case was transferred to the federal district court in Houston, Texas.

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In January 2006, Rios Energy (“Rios”), owner of the oil being transported in the barge, intervened in the existing suit and filed a new suit in the same federal court against both TMSLP and K-Sea alleging their negligence caused the loss of and damage to Rios’ oil. On March 8, 2006, K-Sea filed a counterclaim against TMSLP seeking to recover its alleged damages in excess of $90 million. In order to resolve K-Sea’s concerns over security for its claims, we agreed to provide a guarantee to K-Sea pursuant to which we would satisfy any final, non-appealable judgment or settlement against TMSLP if TMSLP is unable to pay any judgment against it.

On December 10, 2007, after a trial on the merits, United States District Judge Sim Lake concluded that K-Sea’s negligence caused 60% of the damages suffered by K-Sea and TMSLP. Judge Lake assessed 40% fault against TMSLP. Final judgment was entered on December 14, 2007. During trial, TMSLP and Rios settled their dispute.

For purposes of the trial, K-Sea and TMSLP stipulated to the amount of damages for K-Sea in the amount of $62.3 million and for TMSLP in the amount of $400,000. The parties also agreed that prejudgment interest, if any, would accrue at the rate of 4.45% simple interest per annum commencing May 1, 2006. TMSLP anticipates that its entire liability for K-Sea’s claims, if any, is covered by insurance. TMSLP has met the self-insured retention amount under its applicable insurance policy. The parties are currently in discussions regarding TMSLP’s payment of the judgment amount.

Prior to trial, K-Sea submitted a claim under the Oil Pollution Act of 1990 (“OPA 90”) seeking reimbursement of removal costs and cleanup damages from the Oil Spill Liability Trusts Fund (“Trust Fund”). K-Sea included the same removal costs and cleanup damages as a portion of its request for relief at the trial before the federal district court. K-Sea has indicated that it will adjust its request for reimbursement from the Trust Fund to reflect any recovery of removal and cleanup damages from TMSLP but has not yet done so. In the event K-Sea receives a reimbursement from the Trust Fund, the Trust Fund may seek to recover from TMSLP some or all of any reimbursement to K-Sea. TMSLP anticipates that liability to the Trust Fund, if any, would be covered by insurance. TMSLP intends to contest liability in any action or proceeding to recover amounts reimbursed to K-Sea, but we can give no assurances regarding the outcome of any such action or proceeding.

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc., and three other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus LLC, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase certain ConocoPhillips assets, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. On October 2, 2007, the District Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for a new trial is pending before the District Court. Targa has filed a response to the motion and will contest any appeal filed by WTG, but can give no assurances regarding the outcome of the proceeding.

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MANAGEMENT

The following table sets forth certain information with respect to our executive officers and directors as of December 14, 2007.

Name	Age	Position
Rene R. Joyce	60	Chief Executive Officer and Director
Joe Bob Perkins	47	President
James W. Whalen	66	President-Finance and Administration and Director
Roy E. Johnson	63	Executive Vice President
Michael A. Heim	59	Executive Vice President and Chief Operating Officer
Jeffrey J. McParland	53	Executive Vice President and Chief Financial Officer
Paul W. Chung	47	Executive Vice President, General Counsel and Secretary
Charles R. Crisp	60	Director
Joe B. Foster	73	Director
In Seon Hwang	31	Director
Chansoo Joung	47	Director
Peter R. Kagan	39	Director
Chris Tong	51	Director

Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

Rene R. Joycehas served as a director and Chief Executive Officer of Targa since its formation in February 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. He is also a member of the supervisory directors of Core Laboratories N.V. Mr. Joyce served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Joyce served as President of onshore pipeline operations of Coral Energy, LLC, a subsidiary of Shell Oil Company, or Shell, from 1998 through 1999, and President of energy services of Coral Energy Holding, L.P., or Coral, a subsidiary of Shell which was the gas and power marketing joint venture between Shell and Tejas Gas Corporation, or Tejas, during 1999. Mr. Joyce served as President of various operating subsidiaries of Tejas, a natural gas pipeline company, from 1990 until 1998 when Tejas was acquired by Shell.

Joe Bob Perkinshas served as President of Targa since February 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. Perkins also served as a consultant in the energy industry from 2002 through 2003 and was an active partner in RTM Media (an outdoor advertising firm) during such time period. Mr. Perkins served as President and Chief Operating Officer for the Wholesale Businesses, Wholesale Group, and Power Generation Group of Reliant Resources, Inc. and its parent/predecessor companies, from 1998 to 2002, and as Vice President, Corporate Planning and Development, of Houston Industries from 1996 to 1998. He served as Vice President, Business Development, of Coral from 1995 to 1996 and as Director, Business Development, of Tejas from 1994 to 1995. Prior to 1994, Mr. Perkins held various positions with the consulting firm of McKinsey & Company and with an exploration and production company.

James W. Whalenhas served as President-Finance and Administration of Targa since January 2006 and of the general partner of the Partnership since October 2006, and as a director of Targa since May 2004 and of the general partner of the Partnership since February 2007. Since November 2005, Mr. Whalen has served as President-Finance and Administration for various Targa subsidiaries. Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and Chief Financial Officer of Parker Drilling Company. Between January 2002 and October 2002, he was the Chief Financial Officer of Diversified Diagnostic Products,

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Inc. He served as Chief Commercial Officer of Coral from February 1998 through January 2000. Previously, he served as Chief Financial Officer for Tejas from 1992 to 1998. Mr. Whalen is also a director of Equitable Resources, Inc.

Roy E. Johnsonhas served as Executive Vice President of Targa since April 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. Johnson also served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. He served as Vice President, Business Development and President of the International Group, of Tejas from 1995 to 2000. In these positions, he was responsible for acquisitions, pipeline expansion and development projects in North and South America. Mr. Johnson served as President of Louisiana Resources Company, a company engaged in intrastate natural gas transmission, from 1992 to 1995. Prior to 1992, Mr. Johnson held various positions with a number of different companies in the upstream and downstream energy industry.

Michael A. Heimhas served as Executive Vice President and Chief Operating Officer of Targa since April 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. Heim also served as a consultant in the energy industry from 2001 through 2003 providing advice to various energy companies and investors regarding their operations, acquisitions and dispositions. Mr. Heim served as Chief Operating Officer and Executive Vice President of Coastal Field Services, a subsidiary of The Coastal Corp., or Coastal, a diversified energy company, from 1997 to 2001 and President of Coastal States Gas Transmission Company from 1997 to 2001. In these positions, he was responsible for Coastal’s midstream gathering, processing, and marketing businesses. Prior to 1997, he served as an officer of several other Coastal exploration and production, marketing, and midstream subsidiaries.

Jeffrey J. McParlandhas served as Executive Vice President and Chief Financial Officer of Targa since April 2004 and of the general partner of the Partnership since October 2006, and was a consultant for the Targa predecessor company during 2003. Mr. McParland served as a director of the general partner of the Partnership between October 2006 and February 2007. Mr. McParland served as Treasurer of Targa from April 2004 until May 2007 and of the general partner of the Partnership from October 2006 until May 2007. Mr. McParland served as Secretary of Targa between February 2004 and May 2004, at which time he was elected as Assistant Secretary. Mr. McParland served as Senior Vice President, Finance, Dynegy Inc., a company engaged in power generation, the midstream natural gas business and energy marketing, from 2000 to 2002. In this position, he was responsible for corporate finance and treasury operations activities. He served as Senior Vice President, Chief Financial Officer and Treasurer of PG&E Gas Transmission, a midstream natural gas and regulated natural gas pipeline company, from 1999 to 2000. Prior to 1999, he worked in various engineering and finance positions with companies in the power generation and engineering and construction industries.

Paul W. Chunghas served as Executive Vice President, General Counsel and Secretary of Targa since May 2004 and of the general partner of the Partnership since October 2006. Mr. Chung served as Executive Vice President and General Counsel of Coral from 1999 to April 2004; Shell Trading North America Company, a subsidiary of Shell, from 2001 to April 2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was responsible for all legal and regulatory affairs. He served as Vice President and Assistant General Counsel of Tejas from 1996 to 1999. Prior to 1996, Mr. Chung held a number of legal positions with different companies, including the law firm of Vinson & Elkins L.L.P.

Charles R. Crisphas served as a director of Targa since February 2004. Mr. Crisp was President and Chief Executive Officer of Coral Energy, LLC, a subsidiary of Shell Oil Company from 1999 until his retirement in November 2000, and was President and Chief Operating Officer of Coral from January 1998 through February 1999. Prior to this, Mr. Crisp served as President of the power generation group of Houston Industries and, between 1988 and 1996, as President and Chief Operating Officer of Tejas. Mr. Crisp is also a director of AGL Resources Inc., EOG Resources Inc. and IntercontinentalExchange, Inc.

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Joe B. Fosterhas served as a director of Targa since May 2004. Mr. Foster was founder of Newfield Exploration Company and most recently served as the Non-Executive Chairman from January 2000 to May 2005, at which time he retired. He was previously Chief Executive Officer and Chairman of the Board of Newfield from May 1999 to January 2000, and President and Chief Executive Officer from 1989 to January 2000.

In Seon Hwanghas served as a director of Targa since May 2006. Mr. Hwang is a principal in the Energy Group of Warburg Pincus LLC, where he has been employed since 2004. Prior to joining Warburg Pincus, Mr. Hwang worked at GSC Partners, a distressed investment firm, from 2002 until 2004, the M&A group at Goldman Sachs from 1998 to 2000, and the Boston Consulting Group from 1997 to 1998. He is also a director of APT Generation, CoalTek, Competitive Power Ventures and Floridian Natural Gas Storage Company. He also serves on the investment committee of Sheridan Production Partners LLC.

Chansoo Jounghas served as a Director of Targa since December 2005 and of the general partner of the Partnership since February 2007. Mr. Joung is a Managing Director of Warburg Pincus LLC, where he has been employed since 2005, and became a partner of Warburg Pincus & Co. in 2005. Prior to joining Warburg Pincus, Mr. Joung was head of the Americas Natural Resources Group in the investment banking division of Goldman Sachs. He joined Goldman Sachs in 1987 and served in the Corporate Finance and Mergers and Acquisitions departments and also founded and led the European Energy Group. He is a director of APT Generation, Broad Oak Energy and Floridian Natural Gas Storage Company. He also serves on the investment committee of Sheridan Production Partners LLC.

Peter R. Kaganhas served as a director of Targa since February 2004 and of the general partner of the Partnership since February 2007. Mr. Kagan is a Managing Director of Warburg Pincus LLC, where he has been employed since 1997, and became a partner of Warburg Pincus & Co. in 2002. He is also a director of Antero Resources Corporation, Broad Oak Energy, Inc., Fairfield Energy Limited, Laredo Petroleum, MEG Energy Corp. and Universal Space Network, Inc.

Chris Tong has served as a director of Targa since January 2006. Mr. Tong is a Senior Vice President and Chief Financial Officer of Noble Energy, Inc. and has held this position since January 2005. He served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 until August 1997, and had served in other treasury positions with Tejas since August 1989.

Board of Directors

Our board of directors (the “Board”) consists of eight members. Please read “Certain Relationships and Related Party Transactions—Stockholders’ Agreement” for a description of arrangements pursuant to which directors of Targa Investments are selected.

Board Independence

We do not have securities listed on a national securities exchange or in an automated inter-dealer quotation system of a national securities association and, as such, are not subject to the director independence requirements of such an exchange or association. In addition, we are a controlled company as defined in Rule 4350(c)(5) of The NASDAQ Stock Market LLC (“NASDAQ”). If our securities were listed on NASDAQ, then, as a controlled company, we would be exempt from NASDAQ’s independence requirements as they relate to the composition of the board of directors and committees thereof. However, for audit committee purposes, we would be subject to the committee independence requirements of the Securities Exchange Act of 1934.

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The Board has made no formal determination as to the independence of our directors because we are not subject to independence requirements. Nonetheless, if NASDAQ’s independence requirements applied to us, it is likely that Messrs. Kagan, Joung, Hwang, Tong, Crisp and Foster would be determined to be independent for purposes of serving on the Board.

Board Committees

The Board has appointed three committees: an audit committee (the “Audit Committee”), a compensation committee (the “Compensation Committee”) and a risk management committee. The members of the Audit Committee are Messrs. Joung, Hwang and Tong, and the members of the Compensation Committee are Messrs. Kagan, Crisp and Foster.

The Board has made no formal determination as to the independence of our directors for purposes of committee membership because we are not subject to independence requirements. If NASDAQ’s committee independence requirements applied to us (including the applicable rules and regulations of the Exchange Act), then it is likely that Messrs. Hwang and Joung would be determined not to be independent for purposes of serving on the audit committee. Please read “Certain Relationships and Related Party Transactions—Relationships with Warburg Pincus” for a discussion of Warburg Pincus’ relationships with us.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee members whose names appear on the Compensation Committee Report above were committee members during all of fiscal year 2006. No member of the Compensation Committee is or has been a former or current executive officer of the Company. None of the Company’s executive officers served as a director or a member of a compensation committee (or other committee serving an equivalent function) of any other entity, the executive officers of which served as a director or member of the Compensation Committee during the fiscal year ended December 31, 2006. Please read “Certain Relationships and Related Party Transactions” for a description of relationships requiring disclosure by the Company under the SEC’s rules requiring disclosure of certain relationships and related-party transactions.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The following discussion and analysis contains statements regarding our and our executive officers’ future performance targets and goals. These targets and goals are disclosed in the limited context of our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance.

Overview

Targa Resources Investments Inc. (“Targa Investments”) is our indirect parent, with its only significant asset being its ownership of all of the outstanding capital stock of an intermediate holding company, whose sole asset is its ownership of all of our outstanding capital stock. As our parent, Targa Investments has ultimate decision making authority with respect to the compensation of our executive officers identified in the Summary Compensation Table (“named executive officers”). Under the terms of the Targa Investments Amended and Restated Stockholders’ Agreement, as amended (the “Stockholders’ Agreement”), compensatory arrangements with our named executive officers are required to be submitted to a vote of Targa Investments’ stockholders unless such arrangements have been approved by the Compensation Committee of Targa Investments (the “TRII Compensation Committee”). As such, the TRII Compensation Committee is responsible for overseeing the development of an executive compensation philosophy, strategy and framework for our named executive officers that is based on Targa Investments’ business priorities.

The following Compensation Discussion and Analysis describes the material elements of compensation for our named executive officers. These elements, and the TRII Compensation Committee’s decisions with respect to

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determinations on payments, are not subject to approval by our board of directors (the “Targa Board”). However, members of the Targa Board, including its compensation committee, are members of the board of directors of Targa Investments (the “Targa Investments Board”), including the TRII Compensation Committee.

Compensation Philosophy

The TRII Compensation Committee believes that total compensation of executives should be competitive with the market in which we compete for executive talent—the energy industry and midstream natural gas companies. The following compensation objectives guide the TRII Compensation Committee in its deliberations about executive compensation matters:

• Provide a competitive total compensation program that enables us to attract and retain key executives;

• Ensure an alignment between our strategic and financial performance and the total compensation received by our named executive officers;

• Provide compensation for performance relative to expectations and our peer group;

• Ensure a balance between short-term and long-term compensation while emphasizing at-risk, or variable, compensation as a valuable means of supporting our strategic goals and aligning the interests of our named executive officers with those of our shareholders; and

• Ensure that our total compensation program supports our business objectives and priorities.

As a result of this philosophy, we do not pay for perquisites for any of our named executive officers, other than parking subsidies.

The Role of Peer Groups and Benchmarking

Our chief executive officer (the “CEO”), president and chief financial officer (collectively, “Senior Management”) review compensation practices at peer companies at a general level to ensure that our total compensation is within a comparable range. In addition, when evaluating compensation levels for each named executive officer, the TRII Compensation Committee reviews publicly available compensation data for executives in our peer group, compensation surveys, and compensation levels for each named executive officer with respect to their roles with the Company and levels of responsibility, accountability and decision-making authority. Senior Management and the TRII Compensation Committee, however, do not attempt to set compensation components to meet specific benchmarks, such as salaries “above the median” or total compensation “at the 50th percentile.”

For 2006, Senior Management identified peer companies that competed with us in the midstream natural gas industry and reviewed compensation information filed by the peer companies with the Securities and Exchange Commission. The peer group reviewed by Senior Management for 2006 consisted of the following companies: Copano Energy, Crosstex Energy, Enbridge Energy Partners, Energy Transfer Partners, Oneok Partners, Plains All American Pipeline and TEPPCO Partners.

Senior Management intends to review our compensation practices and performance against peer companies on an annual basis.

Role of Senior Management in Establishing Compensation for Named Executive Officers

Typically, Senior Management consults with compensation consultants and reviews market data to determine relevant compensation levels and compensation program elements. Based on these consultations and a review of publicly available information for the peer group, Senior Management submits a proposal to the chairman of the TRII Compensation Committee. The proposal includes a recommendation of base salary, annual

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bonus and any new long term compensation to be paid or awarded to executive officers and employees. The chairman of the TRII Compensation Committee considers this proposal (which he may request Senior Management to modify based on information available to him or that he requests of Senior Management) and his resulting recommendation is then submitted to the TRII Compensation Committee for consideration. The final compensation decisions are reported to the Targa Investments Board.

Our Senior Management has no other role in determining compensation for our executive officers, but our executive officers are delegated the authority and responsibility to determine the compensation for all other employees.

Elements of Compensation for Named Executive Officers

The compensation philosophy for our executive officers centers on long-term equity awards to attract, motivate and retain our executive team. For this reason, in connection with our formation in 2004 and with the DMS Acquisition in 2005, the named executive officers were granted restricted stock and options to purchase restricted stock of Targa Investments. As a result, executive compensation has been weighted toward long-term equity awards. Our executive officers have also invested a significant portion of their personal investable assets in the equity of Targa Investments. Within this context, elements of compensation for our named executive officers are the following: (i) annual base salary; (ii) discretionary annual cash awards; (iii) contributions under our 401(k) and profit sharing plan; and (iv) participation in our health and welfare plans on the same basis as all of our other employees.

Base Salary. The base salaries for our named executive officers are set and reviewed annually by the TRII Compensation Committee. The salaries are based on historical salaries paid to our named executive officers for services rendered to us, the extent of their equity ownership in Targa Investments, market data and responsibilities of our named executive officers. Base salaries are intended to provide fixed compensation comparable to market levels for similarly situated executive officers.

Annual Cash Incentives. The discretionary annual cash awards paid to our named executive officers are designed to supplement the annual base salary of our named executive officers so that, on a combined basis, the annual cash compensation for our named executive officers yield competitive cash compensation levels and drive performance in support of our business strategies. It is Targa Investments’ general policy to pay these awards prior to the end of the first quarter of the next fiscal year. The payment of individual cash bonuses to employees, including our named executive officers, are subject to the sole discretion of the TRII Compensation Committee.

Our 2006 Annual Incentive Plan (the “Bonus Plan”) was adopted on February 2, 2006 to reward our employees for contributions towards our achievement of financial and operational goals approved by the TRII Compensation Committee and to aid us in retaining and motivating employees. Under the Bonus Plan and similar plans expected to be adopted in subsequent years, a discretionary cash bonus pool is expected to be funded annually based on our achievement of certain strategic, financial and operational objectives recommended by our CEO and approved by the TRII Compensation Committee. The Bonus Plan is administered by the TRII Compensation Committee, which considers certain recommendations by the CEO. At the end of each year, the CEO recommends to the TRII Compensation Committee the total amount of cash to be allocated to the bonus pool based upon our overall performance relative to these objectives. Upon receipt of the CEO’s recommendation, the TRII Compensation Committee, in its sole discretion, determines the total amount of cash to be allocated to the bonus pool. Additionally, the TRII Compensation Committee, in its sole discretion, determines the amount of the cash bonus award to each of our executive officers, including the CEO. The executive officers determine the amount of the cash bonus pool to be allocated to certain of our departments, groups and employees (other than our executive officers) based on the recommendation of their supervisors, managers and line officers.

For 2006, 35% of the cash bonus pool was attributable to the achievement of an EBITDA component and 65% of the cash bonus pool was attributable to the achievement of key strategic and operational objectives. The

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financial objective for 2006 was based on our achieving certain levels of EBITDA. EBITDA was selected as the financial objective for 2006 because it is used as a key supplemental financial measure by us and by external users of our financial statements such as investors, commercial banks and others, to assess our performance. The strategic and operational objectives were the following eight items: (i) selling North Texas; (ii) executing an initial public offering of a master limited partnership; (iii) repairing the coastal Louisiana plants and reestablishing associated throughput volume performance; (iv) recovering insurance proceeds for hurricane related damage; (v) renegotiating certain of our commercial contracts; (vi) increasing wellhead volumes connected to the Company’s gathering lines; (vii) monitoring and managing operating expenses and general and administrative costs; and (viii) performance of development activities, such as acquisitions, project development and other opportunities involving synergies. The Bonus Plan established goals that the TRII Compensation Committee will consider when making awards under the Bonus Plan and also established the following threshold, target and maximum levels for the Company’s bonus pool: 50% of the cash bonus pool for the threshold level; 100% for the target level and 200% for the maximum level. The funding of the cash bonus pool and the payment of individual cash bonuses to employees, including our named executive officers, are subject to the sole discretion of the TRII Compensation Committee.

Retirement Benefits. We offer eligible employees a Section 401(k) tax-qualified, defined contribution plan to enable employees to save for retirement through a tax-advantaged combination of employee and Company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. Our employees, including our named executive officers, are eligible to participate in our 401(k) plan and may elect to defer up to 30% of their annual compensation on a pre-tax basis and have it contributed to the plan, subject to certain limitations under the Code. In addition, we make the following contributions to the 401(k) Plan for the benefit of our employees, including our named executive officers: (i) 3% of the employees eligible compensation; (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the employee’s eligible compensation and (iii) a discretionary amount depending on Targa’s performance.

Health and Welfare Benefits. All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, health, life insurance, and dental coverage and disability insurance.

Perquisites. We believe that the elements of executive compensation should be tied directly or indirectly to the actual performance of the Company. It is the TRII Compensation Committee’s policy not to pay for perquisites for any of our named executive officers, other than parking subsidies.

Relation of Compensation Elements to Compensation Philosophy

Our named executive officers and other senior managers, through a combination of personal investment and equity grants, own approximately 20% of the fully diluted equity of Targa Investments. The TRII Compensation Committee believes that the elements of its compensation program fit the established overall compensation objectives in the context of management’s substantial ownership of our parent’s equity, which allows Targa to provide competitive compensation opportunities to align and drive the performance of the named executive officers in support of Targa Investments’ and our own business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by Targa Investments and us.

Application of Compensation Elements

For 2006, the TRII Compensation Committee did not award additional equity to our named executive officers.

Base Salary. In 2006, base salaries for our named executive officers were comparable to similar positions in our peer group.

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Annual Cash Incentives. In January 2007, the TRII Compensation Committee approved a cash bonus pool of 192% of the target level for the employee group, including our named executive officers, under the Bonus Plan for performance during 2006. The executive officers received bonus awards equivalent to the same percentage of target as the Company bonus pool. The TRII Compensation Committee paid near maximum level bonuses under the Bonus Plan in recognition of organizational performance in the face of multiple challenges experienced during 2006. Our named executive officers received cash bonuses under the Bonus Plan based on our achievement of overall goals in 2006 as follows:

Rene R. Joyce	$	262,000
Jeffrey J. McParland	$	204,400
Joe Bob Perkins	$	238,000
James W. Whalen	$	238,000
Michael A. Heim	$	214,000

Retirement Benefits. For 2006, the discretionary amount contributed to the 401(k) Plan equaled 2.25% of the employee’s eligible compensation.

Health and Welfare Benefits. For 2006, our named executive officers participated in our health and welfare benefit programs, including medical, health, life insurance, and dental coverage and disability insurance.

Perquisites. Consistent with our compensation philosophy, we did not pay for perquisites for any of our named executive officers during 2006, other than parking subsidies.

Changes for 2007

Annual Cash Incentives.In connection with the development of our 2007 business plan and discussion of the plan with the Targa Investments Board, Senior Management proposed a set of strategic priorities. The Targa Investments Board suggested modifications to these proposals and requested that the proposals, as modified, be used by Senior Management for their review of 2007 compensation. In January 2007, the TRII Compensation Committee approved the Targa Investments 2007 Annual Incentive Compensation Plan (the “2007 Bonus Plan”), the cash bonus plan for performance during 2007, and established the following six key business priorities: (i) involving employees in improving our businesses; (ii) proactively and aggressively investing in our businesses and developing the pipeline of projects and opportunities; (iii) bringing closure to hurricane repair and recovery; (iv) identifying and pursuing new opportunities in the downstream sector; (v) debt reduction and achievement of capital structure goals; and (vi) executing on all fronts (including the financial business plan). As with the Bonus Plan, funding of the cash bonus pool and the payment of individual cash bonuses to employees, including our named executive officers, are subject to the sole discretion of the TRII Compensation Committee.

Stock Option Exchange. In May 2007, options relating to Targa Investments’ preferred stock held by the employees, including the named executive officers, were exchanged for (i) a grant of 10 shares of Targa Investments common stock for each option and (ii) a right to receive a cash payment in the amount of $27.69 for each option.

Long-term Cash Incentives. In connection with the Partnership’s initial public offering in February 2007, Targa Investments issued to key employees and the executive officers of the General Partner cash-settled performance unit awards linked to the performance of the Partnership’s common units that will vest in August of 2010, with the amounts vesting under such awards dependent on the Partnership’s performance compared to a peer-group consisting of the Partnership and 12 other publicly traded partnerships. The peer group companies for 2007 are: Energy Transfer Partners, Oneok Partners, Copano Energy, DCP Midstream, Regency Energy Partners, Plains All American Pipeline, MarkWest Energy Partners, Williams Energy Partners, Magellan Midstream, Martin Midstream, Enbridge Energy Partners, Crosstex Energy and Targa Resources Partners LP. These performance unit awards were made pursuant to a plan adopted by Targa Investments and administered by Targa

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Resources LLC. The TRII Compensation Committee has the ability to modify the peer-group in the event a peer company is no longer determined to be one of the Partnership’s peers. The cash settlement value of each performance unit award will be the value of an equivalent Partnership common unit at the time of vesting plus associated distributions over the vesting period, which may be higher or lower than the Partnership’s common unit price at the time of the award. If the Partnership’s performance equals or exceeds the performance for the median of the group, 100% of the award will vest. If the Partnership ranks tenth in the group, 50% of the award will vest, between tenth and seventh, 50% to 100% will vest, and for a performance ranking lower than tenth, no amounts will vest. In February 2007, our named executive officers, who are also executive officers of the General Partner, received an initial award of performance units as follows: 15,000 performance units to Mr. Joyce, 8,200 performance units to Mr. McParland, 10,800 performance units to Mr. Perkins, 10,800 performance units to Mr. Whalen and 10,000 performance units to Mr. Heim.

Long-term Equity Incentives. The Partnership made equity-based awards in February 2007 in connection with its initial public offering to the General Partners’ nonmanagement and independent directors under the Partnership’s long-term incentive plan. These awards were determined by Targa Investments and approved by the board of directors of the General Partner. Each of these directors received an initial award of 2,000 restricted units, which will settle with the delivery of Partnership common units. The Partnership has made similar grants under its long-term incentive plan to our independent directors. All of these awards are subject to three year vesting, without a performance condition, and vest ratably on each anniversary of the grant. The awards are intended to align the long-term interests of executive officers and directors of the General Partner with those of the Partnership’s unitholders. The independent and non-management directors of the General Partner and the independent directors of Targa Investments currently participate in the Partnership’s plan. Over time, our officers and employees may begin to participate in the Partnership’s plan.

Compensation Committee Report

The Compensation Committee has reviewed and discussed the disclosure set forth above under the heading “Compensation Discussion and Analysis” with management and, based on this review and discussion, it has recommended to the Targa Board that the “Compensation Discussion and Analysis” be included in this registration statement on Form S-4.

The information contained in this report shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings with the Securities and Exchange Commission, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that the company specifically incorporates it by reference into a document filed under the Securities Act of 1933, as amended, or the Exchange Act.

The Compensation Committee

Peter R. Kagan, Chairman Charles R. Crisp Joe B. Foster

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EXECUTIVE COMPENSATION

The following Summary Compensation Table sets forth the compensation of our named executive officers for 2006. Additional details regarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.

Summary Compensation Table for 2006
	Year	Salary		Stock awards($)(1)		Option awards($)(1)		Non-Equity Incentive Plan Compensation		All Other Compensation (2)		Total Compensation
Rene R. Joyce Chief Executive Officer	2006	$	266,530	$	312,513	$	3,244	$	262,000	$	25,536	$	869,823
Jeffrey J. McParland Executive Vice President and Chief Financial Officer	2006		210,280		236,270		3,244		204,400		23,386		677,580
Joe Bob Perkins President	2006		244,030		260,294		3,244		238,000		23,474		769,042
James W. Whalen President—Finance and Administration	2006		244,030		227,546		—		238,000		17,539		693,515
Michael A. Heim Executive Vice President and Chief Operating Officer	2006		217,791		260,294		3,244		214,000		23,411		718,740

(1) The amounts reported in these columns reflect the aggregate dollar amounts recognized for stock awards and option awards, as applicable, for financial statement reporting purposes with respect to fiscal year 2006 (disregarding any estimate of forfeitures related to service-based vesting conditions). No stock awards or option awards granted to the named executive officers were forfeited during 2006. Detailed information about the amount recognized for specific awards is reported in the table under “Outstanding Equity Awards at 2006 Fiscal Year-End” below. For a discussion of the assumptions and methodologies used to value the awards reported in these columns, please see the discussion of stock awards and option awards contained in the Notes to Consolidated Financial Statements at Note 7 included in this registration statement.

(2) For 2006 “All Other Compensation” includes the aggregate value of matching, non-matching and discretionary contributions to our 401(k) plan and the dollar value of life insurance coverage.

Name	401(k) and Profit Sharing Plan		Dollar Value of Life Insurance		Total
Rene R. Joyce	$	22,850	$	686	$	25,536
Jeffrey J. McParland		22,850		536		23,386
Joe Bob Perkins		22,850		624		23,474
James W. Whalen		18,163		624		17,539
Michael A. Heim		22,850		561		23,411

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Grants of Plan-Based Awards

The following table and the footnotes thereto provide information regarding grants of plan-based equity and non-equity awards made to the named executive officers during 2006:

Grants of Plan Based Awards for 2006
	Estimated Future Payouts under non-equity incentive plan awards
Name	Threshold		Target		2X Target
Mr. Joyce	$	68,750	$	137,500	$	275,000
Mr. McParland		53,750		107,500		215,000
Mr. Perkins		62,500		125,000		250,000
Mr. Whalen		62,500		125,000		250,000
Mr. Heim		56,250		112,500		225,000

At the time the Bonus Plan was adopted, the estimated future payouts in the above table represented the cash bonus pool available for awards to the named executive officers under the Bonus Plan.

Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards table

A discussion of 2006 salaries and bonuses is included in “—Compensation Discussion and Analysis.”

Targa Investments 2005 Stock Incentive Plan

Stock Option Grants. Under the Targa Investments 2005 Stock Incentive Plan, as amended (the “2005 Incentive Plan”), incentive stock options and non-incentive stock options to purchase, in the aggregate, up to 5,159,786 shares of Targa Investments’ restricted stock may be granted to our employees, directors and consultants. Subject to the terms of the applicable stock option agreement, options granted under the 2005 Incentive Plan have a vesting period of four years, remain exercisable for ten years from the date of grant and have an exercise price at least equal to the fair market value of a share of restricted stock on the date of grant. Additional details relating to previously granted non-incentive stock options under the 2005 Incentive Plan are included in “—Outstanding Equity Awards at 2006 Fiscal Year-End” below.

Restricted Stock Grants. Under the 2005 Incentive Plan, up to 7,293,882 shares of restricted stock of Targa Investments may be granted to our employees, directors and consultants. Subject to the terms of the restricted stock agreement, restricted stock granted under the Incentive Plan has a vesting period of four years from the date of grant. Additional details relating to previously granted shares of restricted stock are included in “—Outstanding Equity Awards at 2006 Fiscal Year-End” below.

Targa Investments 2004 Stock Incentive Plan

Stock Option Grants. No awards have been, or may be, made under the Targa Investments 2004 Stock Incentive Plan, as assumed and amended (the “2004 Incentive Plan”), from and after December 31, 2004. The 2004 Stock Incentive Plan governs options to purchase shares of Targa Investments’ Series B Convertible Participating Preferred Stock (“Preferred Stock”). Subject to the terms of the applicable stock option agreement, options granted under the 2004 Incentive Plan have a vesting period of four years and remain exercisable for ten years from the date of grant. Additional details relating to previously granted stock options under the 2004 Incentive Plan are included in “—Outstanding Equity Awards at 2006 Fiscal Year-End” below. On May 1, 2007, employees and directors of Targa Investments surrendered all options to acquire shares of Preferred Stock in exchange for a cash payment of $27.69 and ten shares of restricted stock of Targa Investments for each option surrendered.

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Outstanding Equity Awards at 2006 Fiscal Year-End

Targa Investments indirectly owns all of our equity interests. The following table and the footnotes related thereto provide information regarding each stock option and other equity-based awards of Targa Investments outstanding as of December 31, 2006 for each of our named executive officers.

Outstanding Equity Awards at Fiscal Year-End for 2006
	Option Awards						Stock Awards
Name	Number of Securities Underlying Unexercised Options # Exercisable	Number of Securities Underlying Unexercised Options # Unexercisable		Option exercise price		Option expiration date	Number of Shares or Units of Stock That Have Not Vested		Market Value of Shares or Units of Stock That Have Not Vested(11)
Rene R. Joyce		21,772	(1)	$	0.75	10/31/2015	734,199	(7)	$	440,519
		291,376	(1)	$	3.00	10/31/2015	7,116	(8)		4,270
		246,549	(1)	$	15.00	10/31/2015
		3,006	(2)	$	3.00	12/20/2015
		2,559	(2)	$	15.00	12/20/2015
	5,046	3,365	(3)	$	72.31	04/16/2014
Jeffrey J. McParland		21,772	(1)	$	0.75	10/31/2015	555,120	(7)	$	333,072
		218,532	(1)	$	3.00	10/31/2015	5,337	(8)		3,202
		184,912	(1)	$	15.00	10/31/2015
		2,254	(2)	$	3.00	12/20/2015
		1,919	(2)	$	15.00	12/20/2015
	4,146	2,763	(3)	$	72.31	04/16/2014
Joe Bob Perkins		21,772	(1)	$	0.75	10/31/2015	611,680	(7)	$	367,008
		236,014	(1)	$	3.00	10/31/2015	5,764	(8)		3,458
		199,705	(1)	$	15.00	10/31/2015
		2,435	(2)	$	3.00	12/20/2015
		2,073	(2)	$	15.00	12/20/2015
	5,046	3,365	(3)	$	72.31	04/16/2014
James W. Whalen	90,910	136,363	(4)	$	3.00	11/01/2015	303,417	(9)	$	182,050
	76,924	115,384	(4)	$	15.00	11/01/2015	3,330	(10)		1,998
	938	1,406	(5)	$	3.00	12/20/2015
	799	1,197	(5)	$	15.00	12/20/2015
	1,509	1,005	(6)	$	72.31	05/07/2014
Michael A. Heim		21,772	(1)	$	0.75	10/31/2015	611,680	(7)	$	367,008
		236,014	(1)	$	3.00	10/31/2015	5,764	(8)		3,458
		199,705	(1)	$	15.00	10/31/2015
		2,435	(2)	$	3.00	12/20/2015
		2,073	(2)	$	15.00	12/20/2015
	5,046	3,365	(3)	$	72.31	04/16/2014

(1) Represents options to purchase shares of Targa Investments common stock. These options vest on the following schedule: 70% vest on April 30, 2008, an additional 10% vest on October 31, 2008 and the remaining options vest on October 31, 2009.

(2) Represents options to purchase shares of Targa Investments common stock. These options vest on the following schedule: 70% vest on June 20, 2008, an additional 10% vest on December 20, 2008 and the remaining options vest on December 20, 2009.

(3) Represents options to purchase shares of Targa Investments preferred stock. These options vest on the following schedule: 50% on each of April 16, 2007 and 2008. Each share of preferred stock converts into 10

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shares of common stock of Targa Investments plus an additional number of shares equal to the accreted value (purchase price plus unpaid dividends) divided by the price of the common stock in an initial public offering by Targa Investments.

(4) Represents options to purchase shares of Targa Investments common stock awarded on November 1, 2005. These options vest on the following schedule: One-third vest on each of November 1, 2007, 2008 and 2009.

(5) Represents options to purchase shares of Targa Investments common stock awarded on December 20, 2005. These options vest on the following schedule: One-third vest on each of December 20, 2007, 2008 and 2009.

(6) Represents options to purchase shares of Targa Investments preferred stock. These options vest on the following schedule: 50% on each of May 7, 2007 and 2008. Each share of restricted preferred stock converts into 10 shares of common stock of Targa Investments plus an additional number of shares equal to the accreted value (purchase price plus unpaid dividends) divided by the price of the common stock in an initial public offering by Targa Investments.

(7) Represents shares of restricted common stock of Targa Investments awarded on October 31, 2005. These shares vest on the following schedule: 70% on April 30, 2008; an additional 10% on October 31, 2008 and the remaining shares on October 31, 2009.

(8) Represents shares of restricted common stock of Targa Investments awarded on December 20, 2005. These shares vest on the following schedule: 70% on June 20, 2008; an additional 10% on December 20, 2008 and the remaining shares on December 20, 2009.

(9) Represents shares of restricted common stock of Targa Investments awarded on October 31, 2005 (2,721 shares) and November 1, 2005 (502,975 shares). These shares vest on the following schedule: One-third vest on each of October 31, 2007, 2008 and 2009 (with respect to the October 31, 2005 awards) and November 1, 2007, 2008 and 2009 (with respect to the November 1, 2005 awards).

(10) Represents shares of restricted common stock of Targa Investments awarded on December 20, 2005. These shares vest on the following schedule: One-third vest on each of December 20, 2007, 2008 and 2009.

(11) The dollar amounts shown are determined by multiplying the number of shares or units reported in the table by $0.60 (the value determined by an independent consultant pursuant to a valuation of Targa Investments’ common stock as of December 31, 2006).

Option Exercises and Stock Vested in 2006

The following table provides the amount realized during 2006 by each named executive officer upon the exercise of options and upon the vesting of restricted common stock.

Option Exercises and Stock Vested for 2006
	Stock Awards
Name	# of shares acquired on vesting	Value realized on vesting
Rene R. Joyce
Jeffrey J. McParland
Joe Bob Perkins
James W. Whalen	102,249	$	61,349	(1)
Michael A. Heim

(1) Value determined by an independent consultant pursuant to a valuation of Targa Investments common stock as of December 31, 2006. On October 31, 2006 and December 20, 2006, 101,139 and 1,110 shares, respectively, vested. The value realized on vesting used a per share price of $0.60.

Change in Control and Termination Benefits

2005 Incentive Plan.If a Change of Control or a Liquidation Event (each as defined below), or in the case of restricted stock, certain drag-along transactions, occurs during a named executive officer’s employment with us, the options granted to him under Targa Investments form of Non-Statutory Stock Option Agreement (the “Option Agreement”) and/or the restricted stock granted to him under Targa Investment’s form of Restricted

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Stock Agreement (the “Stock Agreement”) will fully vest and be exercisable (in the case of options) by him so long as he remains an employee of Targa Investments.

Options granted to a named executive officer under the Option Agreement will terminate and cease to be exercisable upon the termination of his employment with Targa Investments, except that: (i) if his employment is terminated by reason of a disability, he (or his estate or the person who acquires the options by will or the laws of descent and distribution or otherwise by reason of his death ) may exercise the options in full for 180 days following such termination; (ii) if he dies while employed by Targa Investments, his estate or the person who acquires the options by will or the laws of descent and distribution or otherwise by reason of his death, may exercise the options in full for 180 days following his death; or (iii) if he resigns or is terminated by Targa Investments without Cause (as defined below), then he (or his estate or the person who acquires the options by will or the laws of descent and distribution or otherwise by reason of his death) may exercise the options for three months following such resignation or termination, but only as to the options he was entitled to exercise as of the date his employment terminates.

Restricted stock granted to a named executive officer under the Stock Agreement will fully vest if his employment is terminated by reason of a disability or his death. If a named executive officer resigns or he is terminated by Targa Investments without Cause, then his unvested restricted stock is forfeited to Targa Investments for no consideration. If a named executive officer is terminated by Targa Investments for Cause, then all restricted stock (both vested and unvested) granted to him under the Stock Agreement is forfeited to Targa Investments for no consideration. For one year following a named executive officer’s termination of employment, Targa Investments has the right to repurchase all of his restricted stock and other Capital Stock (as defined below), after any applicable forfeitures, at a purchase price equal to, in the case of a termination by death, disability, resignation or without Cause, the then fair market value of such restricted stock and Capital Stock determined in accordance with the Stockholders Agreement, and, in the case of a termination with Cause, the lower of the Original Cost (as defined below) or the then Fair Market Value (as defined below) of such Capital Stock.

The following terms have the specified meanings for purposes of the 2005 Incentive Plan:

• Change of Control means, in one transaction or a series of related transactions, a consolidation, merger or any other form of corporate reorganization involving Targa Investments or a sale of Preferred Stock (or a sale of Targa Investments’ common stock following conversion of the Preferred Stock) by stockholders of Targa Investments with the result immediately after such merger, consolidation, corporate reorganization or sale that (A) a single person, together with its affiliates, owns, if prior to any firm commitment underwritten offering by Targa Investments of its common stock to the public pursuant to an effective registration statement under the Securities Act (x) for which the aggregate cash proceeds to be received by Targa Investments from such offering (without deducting underwriting discounts, expenses, and commissions) are at least $35,000,000, and (y) pursuant to which Targa Investments’ common stock is listed for trading on the New York Stock Exchange or is admitted to trading and quoted on the NASDAQ National Market System (a “Qualified Public Offering”), either a greater number of shares of Targa Investments’ common stock (calculated assuming that all shares of Preferred Stock have been converted at the specified conversion ratio) than Warburg Pincus and its affiliates then own or, in the context of a consolidation, merger or other corporate reorganization in which Targa Investments is not the surviving entity, more voting stock generally entitled to elect directors of such surviving entity (or in the case of a triangular merger, of the parent entity of such surviving entity) than Warburg Pincus and its affiliates then own or, if on or after a Qualified Public Offering, either a majority of Targa Investments’ common stock calculated on a fully-diluted basis (i.e. on the basis that all shares of Preferred Stock have been converted at the specified conversion ratio, that all Management Stock is outstanding, whether vested or not, and that all outstanding options to acquire Targa Investments’ common stock had been exercised (whether then exercisable or not)) or, in the context of a consolidation, merger or other corporate reorganization in which Targa Investments is not the surviving entity, a majority of the voting stock generally entitled to elect directors of such

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surviving entity (or in the case of a triangular merger, of the parent entity of such surviving entity) calculated on a fully diluted basis and (B) Warburg Pincus and its affiliates collectively own less than a majority of the initial shares of Capital Stock outstanding on October 31, 2005 owned by them (the “Initial Shares”) or, in the event such Initial Shares are converted or exchanged into other voting securities of Targa Investment or such surviving or parent entity, less than a majority of such voting securities Warburg Pincus and its affiliates would have owned had they retained all such Initial Shares;

• Management Stock means the shares of Targa Investments’ common stock granted pursuant to the terms of the 2005 Incentive Plan, any such shares transferred to a permitted transferee and any and all securities of any kind whatsoever of Targa Investments which may be issued in respect of, in exchange for, or upon conversion of such shares of common stock pursuant to a merger, consolidation, stock split, stock dividend, recapitalization of Targa Investments or otherwise.

• Liquidation Event means the voluntary or involuntary liquidation, dissolution, or winding up of the affairs of Targa Investments;provided that neither the merger or consolidation of Targa Investments with or into another entity, nor the merger or consolidation of another entity with or into Targa Investments, nor the sale of all or substantially all of the assets of Targa Investments shall be deemed to be a Liquidation Event;

• Cause means discharge by Targa Investments based on (A) an employee’s gross negligence or willful misconduct in the performance of duties, (B) conviction of a felony or other crime involving moral turpitude; (C) an employee’s willful refusal, after fifteen days’ written notice from the Targa Investments Board, to perform the material lawful duties or responsibilities required of him; (D) willful and material breach of any corporate policy or code of conduct established by Targa Investments; and (E) willfully engaging in conduct that is known or should be known to be materially injurious to Targa Investments or any of its subsidiaries;

• Capital Stock means any and all shares of capital stock of, or other equity interests in, Targa Investments, and any and all warrants, options, or other rights to purchase or acquire any of the foregoing;

• Original Cost means, with respect to a particular share of Capital Stock, the cash amount originally paid to Targa Investments to purchase such share (or if such share was issued in respect of other shares of Targa Investments issued in connection with the merger of one of Targa Investments’ subsidiaries with and into us, then the cash amount originally paid to us to purchase such other shares), subject to adjustment for subdivisions, combinations or stock dividends involving such Capital Stock, or, if no cash amount was originally paid to Targa Investments to purchase such share, then no consideration (or if such share was issued in respect of other shares of Targa Investments issued in connection with the merger of one of Targa Investments’ subsidiaries with and into us and such other shares were issued by us for no cash consideration, then no consideration); and

• Fair Market Value means the value determined by the unanimous resolution of all directors of the Targa Investments Board, provided that if the Targa Investments Board does not or is unable to make such a determination, Fair Market Value means the value determined by an investment banking firm of recognized national standing selected by a majority of the directors of the Targa Investments Board.

The following table reflects payments that would have been made to each of the named executive officers under the 2005 Incentive Plan and related agreements in the event there was a Change of Control or their employment was terminated, each as of December 31, 2006.

Name	Change of Control			Termination for death or disability
Rene R. Joyce	$	558,123	(1)	$	558,123	(1)
Jeffrey J. McParland		429,359	(2)		429,359	(2)
Joe Bob Perkins		483,802	(3)		483,802	(3)
James W. Whalen		217,905	(4)		217,905	(4)
Michael A. Heim		483,802	(5)		483,802	(5)

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(1) Of this amount, $440,519 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $4,270 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $113,334 relates to the unvested options to purchase Preferred Stock granted on April 16, 2004.

(2) Of this amount, $333,071 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $3,202 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $93,086 relates to the unvested options to purchase Preferred Stock granted on April 16, 2004.

(3) Of this amount, $367,009 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $3,459 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $113,334 relates to the unvested options to purchase Preferred Stock granted on April 16, 2004.

(4) Of this amount, $978 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $181,071 relates to the unvested shares of restricted stock of Targa Investments granted on November 1, 2005; $1,998 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $33,858 relates to the unvested options to purchase Preferred Stock granted on May 7, 2004.

(5) Of this amount, $367,009 relates to the unvested shares of restricted stock of Targa Investments granted on October 31, 2005; $3,459 relates to the unvested shares of restricted stock of Targa Investments granted on December 20, 2005; and $113,334 relates to the unvested options to purchase Preferred Stock granted on April 16, 2004.

Other Agreements

In connection with the DMS acquisition on October 31, 2005, we entered into bonus agreements (the “Bonus Agreements”) with Messrs. Crisp, Foster, Heim, Joyce, McParland, Perkins and Whalen and adopted the Targa Resources, Inc. Bonus Plan (the “Change of Control Bonus Plan”) applicable to eligible employees, including Messrs. Joyce, McParland, Perkins and Heim, that provide these named executive officers certain benefits upon a Change of Control. In addition, on July 12, 2006, in order to ensure managerial transition in the face of a potential transaction, the TRII Compensation Committee approved the Targa Investments Change of Control Executive Officer Severance Program (the “TRII Severance Program”) in which all of our named executive officers were participants.

Bonus Agreements. Under the Bonus Agreements, following a Change of Control or a death or disability, our named executive officers and directors are entitled to receive the following lump sum cash bonus amounts: Mr. Crisp-$20,800; Mr. Foster-$21,802; Mr. Heim-$717,537; Mr. Joyce—$717,537; Mr. McParland-$574,028; Mr. Perkins-$717,537; and Mr. Whalen-$21,802.

Change of Control Bonus Plan. The Change of Control Bonus Plan provides a lump sum cash bonus payment in case there is a Change of Control or the plan is terminated. The bonus pool will be $2 million if the weighted average sale price with respect to Targa Investments’ preferred stock sold by Warburg Pincus between November 1, 2005 and the change of control is equal to or greater than $100 per share. The bonus pool will be $0 if the weighted average sale price is equal to or less than $72.31 per share. The bonus pool will be a prorated amount between $0 and $2 million if the weighted average sale price is between $72.31 and $100 per share.

TRII Severance Program. This program provides separation benefits to our executive officers who voluntarily terminate their employment or whose employment is terminated in connection with a change of control of Targa. In such event, executive officers will receive a lump sum cash payment, subsidized medical coverage for up to two years and minimal transition assistance. The lump sum cash payment will be paid in an amount equal to (i) two multiplied by fifty percent of the executive officer’s annual base pay in effect on the date

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immediately preceding the change of control, multiplied by (ii) a fraction, the numerator of which is the number of days during the period beginning on the first day of such fiscal year and ending on the date of such termination, and the denominator of which is three hundred sixty-five.

The following table reflects payments that would have been made to each of the named executive officers in the event there was a change of control or, following a change of control, their employment was terminated, each as of December 31, 2006. For purposes of potential payments under the Change of Control Bonus Plan, we assume the named executive officers would have received payments in an amount equal to the actual payments they received under the Change of Control Bonus Plan in August 2007 in connection with the termination of the Change of Control Bonus Plan. Payments under the Bonus Agreements, Change of Control Bonus Plan and TRII Severance Program are cumulative.

Name	Change of Control and death or disability prior to a Change of Control Payment under Change of Control Bonus Plan and Bonus Agreements			Termination following a Change in Control Payment under the TRII Severance Program
Rene R. Joyce	$	794,151	(1)	$	293,000	(6)
Jeffrey J. McParland		650,642	(2)		239,798	(7)
Joe Bob Perkins		794,151	(3)		262,798	(8)
James W. Whalen		21,802	(4)		268,552	(9)
Michael A. Heim		794,151	(5)		249,798	(10)

(1) Of this amount, $717,537 relates to the Bonus Agreement and $76,614 relates to the Change of Control Bonus Plan.

(2) Of this amount, $574,028 relates to the Bonus Agreement and $76,614 relates to the Change of Control Bonus Plan.

(3) Of this amount, $717,537 relates to the Bonus Agreement and $76,614 relates to the Change of Control Bonus Plan.

(4) This amount relates to the Bonus Agreement.

(5) Of this amount, $717,537 relates to the Bonus Agreement and $76,614 relates to the Change of Control Bonus Plan.

(6) This amount includes an estimated amount of up to $17,552 for our share of health care coverage costs to allow the officer and covered family members to continue coverage under our plans on the same terms as all employees for a period of up to two years. In addition, this amount includes an $1,000 estimated value of the officer’s computer and telecom equipment provided by us that would be transferred to him upon his termination.

(7) This amount includes an estimated amount of up to $23,798 for our share of health care coverage costs to allow the officer and covered family members to continue coverage under our plans on the same terms as all employees for a period of up to two years. In addition, this amount includes an $1,000 estimated value of the officer’s computer and telecom equipment provided by us that would be transferred to him upon his termination.

(8) This amount includes an estimated amount of up to $23,798 for our share of health care coverage costs to allow the officer and covered family members to continue coverage under our plans on the same terms as all employees for a period of up to two years. In addition, this amount includes an $1,000 estimated value of the officer’s computer and telecom equipment provided by us that would be transferred to him upon his termination.

(9) This amount includes an estimated amount of up to $17,552 for our share of health care coverage costs to allow the officer and covered family members to continue coverage under our plans on the same terms as all employees for a period of up to two years. In addition, this amount includes an $1,000 estimated value of the officer’s computer and telecom equipment provided by us that would be transferred to him upon his termination.

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(10) This amount includes an estimated amount of up to $23,798 for our share of health care coverage costs to allow the officer and covered family members to continue coverage under our plans on the same terms as all employees for a period of up to two years. In addition, this amount includes an $1,000 estimated value of the officer’s computer and telecom equipment provided by us that would be transferred to him upon his termination.

The following table reflects the total payments that would have been made to each of the named executive officers in the event there was a change of control, the employment of a named executive officer was terminated following a change of control, or the employment of a named executive officer was terminated due to a death or disability, each as of December 31, 2006. Payments under the 2005 Incentive Plan are cumulative with payments under the Bonus Agreements and the Change of Control Bonus Plan in the case of a Change of Control and are cumulative with payments under the Bonus Agreements in the case of termination due to death or disability prior to a Change of Control. Payments under the TRII Severance Program are cumulative with payments under the 2005 Incentive Plan, the Bonus Agreements and the Change of Control Bonus Plan in the case of a termination following a Change of Control.

Name	Change of Control under the 2005 Incentive Plan, the Bonus Agreements and the Change of Control Bonus Plan		Termination following a Change of Control under the TRII Severance Program		Termination for death or disability prior to a Change of Control under the Bonus Agreements and the 2005 Incentive Plan
Rene R. Joyce	$	1,352,274	$	293,000	$	1,275,660
Jeffrey J. McParland		1,080,001		239,798		1,003,377
Joe Bob Perkins		1,277,953		262,798		1,201,339
James W. Whalen		239,707		268,552		239,707
Michael A. Heim		1,277,953		249,798		1,201,339

Termination of Change in Control and Termination Benefits

In connection with Targa Investment’s entry into a credit facility in August 2007, which funded a distribution to Targa Investment’s investors, the Targa Board elected to terminate the Bonus Agreements and the Change of Control Bonus Plan and to trigger the payments due under the agreements and plan. The TRII Severance Program wasterminated without any payments to the named executive officers when the Targa Investments Board determined the need to ensure managerial transition in the case of a Change of Control was no longer necessary.

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DIRECTOR COMPENSATION

The following table sets forth the compensation earned by our non-employee directors for the year ended December 31, 2006:

Director Compensation for 2006
Name	Fees Earned or paid in cash($)		Stock awards($)(1)			Option awards($)(1)			Total($)
Charles R. Crisp	$	28,000	$	42,398	(2)	$	2,847	(2)	$	73,245
Joe B. Foster		28,000		42,398	(3)		2,847	(3)		73,245
In Seon Hwang		—		—			—			—
Chansoo Joung		—		—			—			—
Peter R. Kagan		—		—			—			—
Chris Tong		40,000		49,402	(4)		6,381	(4)		95,783

(1) The amounts reported in these columns reflect the aggregate dollar amounts recognized for stock awards and option awards, as applicable, for financial statement reporting purposes with respect to fiscal year 2006 (disregarding any estimate of forfeitures related to service-based vesting conditions). No stock awards or option awards granted to the directors were forfeited during 2006. For a discussion of the assumptions and methodologies used to value the awards reported in these columns, please see the discussion of stock awards and option awards contained in the Notes to Consolidated Financial Statements at Note 7 included in this registration statement.

(2) The grant date fair value of the 95,395 shares of common stock and 87,018 options to purchase shares of common stock granted to Mr. Crisp on October 31, 2005 is $110,658 and $7,430, respectively. This value was determined by an independent consultant pursuant to a FAS 123R valuation of Targa Investments common stock as of October 31, 2005. At December 31, 2006, Mr. Crisp held 9,709 shares of preferred stock, 95,395 shares of common stock, 2,514 options to purchase shares of preferred stock and 87,018 options to purchase shares of common stock.

(3) The grant date fair value of the 95,395 shares of common stock and 87,018 options to purchase shares of common stock granted to Mr. Foster on October 31, 2005 is $110,658 and $7,430, respectively. This value was determined by an independent consultant pursuant to a FAS 123R valuation of Targa Investments common stock as of October 31, 2005. At December 31, 2006, Mr. Foster held 28,591 shares of preferred stock, 95,395 shares of common stock, 2,514 options to purchase shares of preferred stock and 87,018 options to purchase shares of common stock.

(4) The grant date fair value of the 72,564 shares of common stock and 51,672 option to purchase shares of common stock granted to Mr. Tong on January 26, 2006 is $84,174 and $10,872, respectively. This value was determined by an independent consultant pursuant to a FAS 123R valuation of Targa Investments common stock as of January 26, 2006. At December 31, 2006, Mr. Tong held 72,564 shares of common stock and 51,672 options to purchase shares of common stock.

Narrative to Director Compensation Table

Beginning on February 2, 2006, each independent director receives an annual cash retainer of $20,000, the chairman of the Audit Committee receives an additional annual retainer of $8,000 and the chairmen of all other committees receive an additional annual retainer of $2,500. All of our independent directors receive $1,500 for each Board meeting attended and an additional $1,000 for each committee meeting attended (if not at a regularly scheduled board meeting). Payment of independent director fees is generally made twice annually, at the second regularly scheduled meeting of the Board and the final meeting of the Board for the fiscal year. All independent directors are reimbursed for out-of-pocket expenses incurred in attending Board and committees.

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Prior to February 2, 2006, our independent directors received an annual cash retainer of $10,000 but did not receive additional compensation for attending Board and committee meetings or for serving as chairmen of any Board committee.

A director who is also an employee receives no additional compensation for services as a director. Accordingly, the Summary Compensation Table reflects total compensation received by Messrs. Joyce and Whalen for services performed for us and our subsidiaries. In addition, a director who is also employed by Warburg Pincus receives no compensation for services as a director.

Our independent directors are eligible to receive awards under the Partnership’s long term incentive plan. The board of directors of the Partnership’s general partner (the “General Partner”) makes decisions with respect to awards under the Partnership’s long term incentive plan.

Changes for 2007

In response to market developments identified by Apogee, a compensation consultant, the TRII Compensation Committee approved changes to director compensation for the 2007 fiscal year. For 2007, each independent director (other than the Warburg directors) receives an annual cash retainer of $34,000 and the chairman of the Audit Committee receives an additional annual retainer of $15,000. All of our independent directors (other than the Warburg directors) receive $1,500 for each Audit Committee and Compensation Committee meeting attended. No additional fees are paid for attending board meetings. Payment of independent director fees is generally made twice annually, at the second regularly scheduled meeting of the Board and the final meeting of the Board for the fiscal year. All independent directors (other than the Warburg directors) are reimbursed for out-of-pocket expenses incurred in attending Board and committee meetings.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Stockholders’ Agreement

Stockholders of Targa Investments, our indirect parent, including our named executive officers, certain of our directors, Warburg Pincus and Merrill Lynch, are party to the Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated October 31, 2005, as amended (the “Stockholders’ Agreement”). The Stockholders’ Agreement (i) provides certain holders of Targa Investments’ preferred stock with preemptive rights relating to certain issuances of securities by Targa Investments or its subsidiaries, (ii) imposes restrictions on the disposition and transfer of securities of Targa Investments, (iii) establishes vesting and forfeiture provisions for securities held by our management, (iv) provides Targa Investments with the option to repurchase its securities held by our management and directors upon the termination of their employment or service to Targa Investments in certain circumstances, and (v) imposes on Targa Investments the obligation to furnish financial information to Warburg Pincus and Merrill Lynch as long as they maintain a certain ownership level in Targa Investments’ securities.

The Stockholders’ Agreement also requires the stockholders party thereto to vote to elect to the Board of Directors of Targa Investments two individuals that are executive officers of Targa Investments (one of whom shall be the chief executive officer of Targa Investments unless otherwise agreed by the majority holders), five individuals that will be designated by Warburg Pincus and one individual (two individuals if there are only four Warburg nominees or three individuals if there are only three Warburg nominees) who shall be independent that will be selected by Warburg Pincus, after consultation with the chief executive officer of Targa Investments and approved by the majority holders.

Relationships with Warburg Pincus

Warburg Pincus beneficially owns approximately 74% of the outstanding voting stock of our parent on a fully diluted basis. Warburg Pincus is able to elect members of our board of directors, appoint new management and approve any action requiring the approval of our stockholders, including amendment of our certificate of incorporation and mergers or sales of substantially all of our assets. The directors elected by Warburg Pincus will be able to make decisions affecting our capital structure, including decisions to issue additional capital stock, implement stock repurchase programs and declare dividends.

Relationships with Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”)

Equity

An affiliate of Merrill Lynch holds a non-voting equity interest in the general partner of Warburg Pincus Private Equity VIII, L.P. and Warburg Pincus Private Equity IX, L.P., the principal shareholders of Targa Investments. Merrill Lynch Ventures L.P. 2001, an affiliate of Merrill Lynch, owns approximately 6.5% of the outstanding voting stock of our parent on a fully diluted basis.

Financial Services

Merrill Lynch was an initial purchaser of the notes, and acted as our financial advisor with respect to our purchase of all the equity interests in DMS. An affiliate of Merrill Lynch is a lender and an agent under our senior secured credit facilities.

Hedging Arrangements

We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas, NGL, and condensate over periods ending in 2010, and we have agreed to pay Merrill Lynch floating prices based on

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published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with Merrill Lynch as of December 31, 2006:

Period	Commodity	Instrument Type	Daily Volumes		Average Price			Index
Jan 2007	Natural gas	Basis Swap	20,000	MMBtu		Receive IF-HH minus $0.01, pay GD-HH
Jan 2007—Dec 2007	Natural gas	Swap	26,118	MMBtu	$	7.65	per MMBtu	IF-Waha
Jan 2008—Dec 2008	Natural gas	Swap	25,765	MMBtu		7.23	per MMBtu	IF-Waha
Jan 2009—Dec 2009	Natural gas	Swap	25,474	MMBtu		6.82	per MMBtu	IF-Waha
Jan 2010—Dec 2010	Natural gas	Swap	3,289	MMBtu		7.39	per MMBtu	IF-Waha
Jan 2007—Dec 2007	NGLs	Swap	5,998	barrels		0.82	per gallon	OPIS-MB
Jan 2008—Dec 2008	NGLs	Swap	5,847	barrels		0.79	per gallon	OPIS-MB
Jan 2009—Dec 2009	NGLs	Swap	5,547	barrels		0.76	per gallon	OPIS-MB
Jan 2007—Dec 2007	Condensate	Swap	319	barrels		75.27	per barrel	NY-WTI
Jan 2008—Dec 2008	Condensate	Swap	264	barrels		72.66	per barrel	NY-WTI
Jan 2009—Dec 2009	Condensate	Swap	202	barrels		70.60	per barrel	NY-WTI
Jan 2010—Dec 2010	Condensate	Swap	181	barrels		69.28	per barrel	NY-WTI

At December 31, 2006, the fair value of these open positions is a liability of $2.8 million. During 2006, Merrill Lynch paid us $6.8 million in commodity derivative settlements. There were no commodity derivative settlements with Merrill Lynch prior to 2006.

Commercial Relationships

In April 2004, we entered into a base agreement for the purchase and sale of natural gas with Entergy-Koch Trading, LP, pursuant to which Entergy-Koch Trading, LP typically purchases natural gas for fuel at its affiliated cogeneration facility in Lake Charles. On November 1, 2004, MLCI acquired Entergy-Koch, LP and became a successor to this agreement. Pricing terms under the agreement are governed by reference to specified index prices plus a premium.

Other Relationships

On December 16, 2004, we acquired a 40% ownership interest in Bridgeline. During 2005 we had net purchases of natural gas of $11.4 million from Bridgeline. During the period from December 16, 2004 to December 31, 2004, we purchased $1.4 million of natural gas from Bridgeline. These transactions were at market prices consistent with those paid to non-affiliate entities. We sold our interest in Bridgeline in August 2005.

Initial Public Offering of Partnership

On February 14, 2007, the Partnership completed its initial public offering (the “IPO”) and borrowed $294.5 million under its newly established credit facility. In return for our contribution of North Texas to the Partnership we received a 2% general partner interest and a 36.6% limited partner interest in the Partnership and cash proceeds of $665.7 million. We used the proceeds received from contributing North Texas to the Partnership and cash on hand to retire in full the outstanding balance (including accrued interest) of our $700 million senior secured asset sale bridge loan facility.

Purchase and Sale Agreement

On September 18, 2007, we entered into a purchase and sale agreement (the “Purchase Agreement”) with the Partnership pursuant to which the Partnership acquired SAOU and LOU (the “Acquired Businesses”) for aggregate consideration of $705 million, subject to certain adjustments, consisting of $698.0 million in cash and

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the issuance to the Partnership’s general partner of 275,511 general partner units, enabling the general partner to maintain its general partner interest in the Partnership. On September 25 and 26, 2007, we completed transactions to terminate certain out of the money NGL hedges associated with the Acquired Businesses and to enter into new hedges for approximately the same volume and term at then current market prices. Pursuant to the Purchase Agreement, these hedging transactions resulted in a $24.2 million increase to the purchase price we received for the Acquired Businesses. Pursuant to the Purchase Agreement, we have indemnified the Partnership from and against (i) all losses that it incurs arising from any breach of our representations, warranties or covenants in the Purchase Agreement, (ii) certain environmental matters and (iii) certain litigation matters. The Partnership has indemnified us from and against all losses that we incur arising from or out of (i) the business or operations of Targa Resources Texas GP LLC, Targa Texas, Targa Louisiana and Targa Louisiana Intrastate LLC (whether relating to periods prior to or after the closing of the acquisition of the Acquired Businesses) to the extent such losses are not matters for which we have indemnified the Partnership or (ii) any breach of the Partnership’s representations, warranties or covenants in the Purchase Agreement. Certain of our indemnification obligations are subject to an aggregate deductible of $10 million and a cap equal to $80 million. In addition, these parties’ reciprocal indemnification obligations for certain tax liability and losses are not subject to the deductible and cap.

Omnibus Agreement

Concurrently with the closing of the acquisition of the Acquired Businesses, the Partnership amended and restated its omnibus agreement (as amended and restated, the “Omnibus Agreement”) with us, its general partner (one of our subsidiaries) and others that addresses the reimbursement of its general partner for costs incurred on its behalf, competition and indemnification matters. Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, are terminable by us at our option if the Partnership’s general partner is removed without cause and units held by the general partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement will also terminate in the event of a change of control of the Partnership or its general partner.

Reimbursement of Operating and General and Administrative Expense

Under the Omnibus Agreement, the Partnership reimburses us for the payment of certain operating expenses, including compensation and benefits of operating personnel, and for the provision of various general and administrative services for the Partnership’s benefit. With respect to North Texas, the Partnership reimburses us for the following expenses:

• general and administrative expenses, which are capped at $5 million annually for three years, subject to increases based on increases in the Consumer Price Index and subject to further increases in connection with expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses with the concurrence of its conflicts committee; thereafter, the Partnership’s general partner will determine the general and administrative expenses to be allocated to the Partnership in accordance with the partnership agreement; and

• operations and certain direct expenses, which are not subject to the $5 million cap for general and administrative expenses.

With respect to the Acquired Businesses, the Partnership reimburses us for the following expenses:

• general and administrative expenses, which are not capped, allocated to the Acquired Businesses according to our allocation practice; and

• operating and certain direct expenses, which are not capped.

Pursuant to these arrangements, we perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. The Partnership

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reimburses us for the direct expenses to provide these services as well as other direct expenses we incur on the Partnership’s behalf, such as compensation of operational personnel performing services for the Partnership’s benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.

General and administrative costs will continue to be allocated to the Acquired Businesses according to our allocation practice.

Competition

We are not restricted, under either the Partnership’s partnership agreement or the Omnibus Agreement, from competing with the Partnership. We may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets.

Indemnification

Under the Omnibus Agreement, we will indemnify the Partnership until February 14, 2010 against certain potential environmental claims, losses and expenses associated with the operation of North Texas and occurring before February 14, 2007 that are not reserved on the books of the Predecessor Business as of February 14, 2007. Our maximum liability for this indemnification obligation does not exceed $10.0 million and we do not have any obligation under this indemnification until the Partnership’s aggregate losses exceed $250,000. The Partnership has agreed to indemnify us against environmental liabilities related to North Texas arising or occurring after February 14, 2007.

Additionally, we will indemnify the Partnership for losses attributable to rights-of-way, certain consents or governmental permits, preclosing litigation relating to North Texas and income taxes attributable to pre-IPO operations that are not reserved on the books of the Predecessor Business as of February 14, 2007. We do not have any obligation under these indemnifications until the Partnership’s aggregate losses exceed $250,000. The Partnership will indemnify us for all losses attributable to the post-IPO operations of North Texas. Our obligations under this additional indemnification survive until February 14, 2010, except that the indemnification for income tax liabilities will terminate upon the expiration of the applicable statute of limitations.

Agreements Governing the Drop-Down Transactions

We have entered into various documents and agreements that effected the drop-down transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds therefrom. These agreements were not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, were not effected on terms at least as favorable to the parties to these agreements as they could have obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid from the proceeds of transaction.

Contracts with Affiliates

NGL and Condensate Purchase Agreement for the North Texas System. The Partnership has entered into an NGL and high pressure condensate purchase agreement pursuant to which (i) it is obligated to sell all volumes of NGLs (other than high-pressure condensate) that it owns or controls to our subsidiary, Targa Liquids Marketing and Trade (“TLMT”) and (ii) it has the right to sell to TLMT or third parties the volumes of high-pressure condensate that it owns or controls, in each case at a price based on the prevailing market price less transportation, fractionation and certain other fees. This agreement has an initial term of 15 years and automatically extends for a term of five years, unless the agreement is otherwise terminated by either party. Furthermore, either party may elect to terminate the agreement if either party ceases to be one of our affiliates.

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NGL Purchase Agreements for the Acquired Businesses. The SAOU System has entered into an NGL purchase agreement pursuant to which it is obligated to sell all volumes of mixed NGLs, or raw product, that it owns or controls to TLMT at a price based on either TLMT’s sales price to third parties or the prevailing market price, less transportation, fractionation and certain other fees. The LOU System has entered into an NGL purchase agreement pursuant to which (i) it has the right to sell to TLMT the volumes of raw product that it owns or controls at a commercially reasonable price agreed by the parties, and (ii) it is obligated to sell all volumes of fractionated NGL components that it owns or controls at a price based on TLMT’s sales price to third parties or the prevailing market price, less transportation, fractionation and certain other fees. Both NGL purchase agreements have an initial term of one year and automatically extend for additional terms of one year, unless the agreements are otherwise terminated by either party.

Natural Gas Purchase Agreements. Both North Texas and the Acquired Businesses have entered into natural gas purchase agreements at a price based on Targa Gas Marketing LLC’s (“TGM”) sale price for such natural gas, less TGM’s costs and expenses associated therewith. These agreements have an initial term of 15 years and automatically extend for a term of five years, unless the agreements are otherwise terminated by either party. Furthermore, either party may elect to terminate the agreements if either party ceases to be one of our affiliates. In addition, we manage the Acquired Businesses’ natural gas sales to third parties under contracts that remain in the name of the Acquired Businesses.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table is based on our records and reports filed with the Commission and sets forth the beneficial ownership of our common stock and equity securities of our subsidiaries that are held by:

• each person who beneficially owns 5% or more of our outstanding common stock (only with respect to our common stock);

• all of the directors of Targa Resources, Inc.;

• each named executive officer of Targa Resources, Inc.; and

• all directors and executive officers of Targa Resources, Inc. as a group.

	Targa Resources, Inc.			Targa Resources Partners LP							Targa Resources Investments Inc.
Name of Beneficial Owner(1)	Common Stock Beneficially Owned	Percentage of Common Stock Beneficially Owned		Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned	Subordinated Units Beneficially Owned(3)	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Common and Subordinated Units Beneficially Owned		Series B Preferred Stock	Restricted Common Stock		Percentage of Series B Preferred Stock Beneficially Owned		Percentage of Restricted Common Stock Beneficially Owned
Targa Resources Investments Inc.	1,000	100	%	—	—	—	—		—		—	—		—		—
Rene R. Joyce	—	—		20,000	*	223,648	1.94	%	*		56,208	825,425		*		11.2	%
Joe Bob Perkins	—	—		7,100	*	190,216	1.65	%	*		47,632	701,554		*		9.5	%
Michael A. Heim	—	—		2,500	*	176,382	1.53	%	*		39,192	701,554		*		9.5	%
Jeffrey J. McParland	—	—		1,500	*	154,478	1.34	%	*		32,856	629,547		*		8.5	%
James W. Whalen	—	—		36,151.67	*	151,020	1.31	%	*		14,978	790,740	(4)	*		10.3	%
Charles R. Crisp	—	—		3,100	*	34,585	*		*		9,709	120,535		*		1.6	%
Joe B. Foster	—	—		6,700	*	65,711	*		*		28,591	120,535		*		1.6	%
In Seon Hwang(2)	—	—		—	*	—	—		*		—	—		—		—
Chansoo Joung(2)	—	—		2,000	*	—	—		*		—	—		—		—
Peter R. Kagan(2)	—	—		2,000	*	—	—		*		—	—		—		—
Chris Tong	—	—		4,400	*	11,528	*		*		—	72,564		*		*
All directors and executive officers as a group (13 persons)	—	—		85,451.67	*	1,338,428	11.54	%	3.21	%	268,723	5,249,094		4.2	%	68.7	%

* Less than 1%.

(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1000 Louisiana, Suite 4300, Houston, Texas 77002. The nature of the beneficial ownership for all the equity securities is sole voting and investment power.

(2) Warburg Pincus Private Equity VIII, L.P. (“WP VIII”) and Warburg Pincus Private Equity IX, L.P. (“WP IX”) in the aggregate beneficially own 73.6% of Targa Resources Investments Inc. The general partner of WP VIII is Warburg Pincus Partners, LLC (“WP Partners LLC”) and the general partner of WP IX is Warburg Pincus IX, LLC, of which WP Partners LLC is sole member. Warburg Pincus & Co. (“WP”) is the managing member of WP Partners LLC. WP VIII and WP IX are managed by Warburg Pincus LLC (“WP LLC”). The address of the Warburg Pincus entities is 466 Lexington Avenue, New York, New York 10017. Chansoo Joung and Peter R. Kagan, two of our directors, are each a general partner of WP and a Managing Director and member of WP LLC. In Seon Hwang, one of our directors, is a principal of WP LLC. Charles R. Kaye and Joseph P. Landy are Managing General Partners of WP and Managing Members of WP LLC and may be deemed to control the Warburg Pincus entities. Messrs. Joung, Kagan, Hwang, Kaye and Landy disclaim beneficial ownership of all shares held by the Warburg Pincus entities.

(3) The subordinated units of the Partnership presented as being beneficially owned by our directors and executive officers represent the number of units held indirectly by Targa Resources Investments Inc. that are attributable to such directors and officers based on their ownership of equity interests in Targa Resources Investments Inc. Targa Resources Investments Inc. indirectly holds all 11,528,231 subordinated units of the Partnership.

(4) Of this amount, 254,354 shares of restricted common stock reflect options that are currently exercisable for shares of restricted common stock.

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DESCRIPTION OF NEW NOTES

Targa Resources, Inc. and Targa Resources Finance Corporation will issue the new notes, and the old notes were issued, under an Indenture (the “Indenture”) among themselves, the Subsidiary Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”). The terms of the notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939 (the “Trust Indenture Act”). You can find the definitions of certain capitalized terms used in this description under the subheading “Certain Definitions”. In this description, the “Company” refers to Targa Resources, Inc. and not to any of its subsidiaries. The “Co-Issuer” refers to Targa Resources Finance Corporation, a subsidiary of the Company and co-issuer of the notes. The Co-Issuer has no material assets.

If the exchange offer contemplated by this prospectus is consummated, old notes that remain outstanding after the completion of the exchange offer, together with the new notes, will be treated as a single class of securities under the Indenture. Otherwise unqualified references herein to “notes” shall, unless the context requires otherwise, include the old notes and the new notes, and all references to specified percentages in aggregate principal amount of the notes shall be deemed to mean, at any time after the exchange offer is completed, such percentage in aggregate principal amount of the old notes and the new notes then outstanding.

The terms of the new notes will be substantially identical to the terms of the old notes, except that the new notes:

• will have been registered under the Securities Act;

• will not be subject to transfer restrictions applicable to the old notes; and

• will not have the benefit of the registration rights agreement applicable to the old notes.

The following description is only a summary of the material provisions of the notes and the Indenture. We urge you to read the Indenture because it, and not this description, defines your rights as a holder of notes. A copy of the Indenture is available upon request from us as set forth under “Where You Can Find More Information.”

Brief Description of the Notes

Like the old notes, the new notes:

• will be unsecured senior obligations of the Company and the Co-Issuer;

• will rank pari passu in right of payment with all existing and future Senior Indebtedness, including Indebtedness under our Senior Credit Facilities, of the Company and the Co-Issuer;

• will be effectively subordinated to all Secured Indebtedness of the Company or the Co-Issuer to the extent of the value of the collateral securing such Indebtedness, including Indebtedness under the Senior Credit Facilities;

• will be structurally subordinated to all existing and future claims of creditors (including trade creditors) and holders of Preferred Stock of Subsidiaries of the Company and the Co-Issuer that do not guarantee the notes, including any Permitted MLPs and Permitted GPs;

• will rank senior in right of payment to any future Subordinated Indebtedness of the Company and the Co-Issuer; and

• will be guaranteed on a senior unsecured basis by the Subsidiary Guarantors that guarantee the Senior Credit Facilities.

Principal, Maturity and Interest

The Company and the Co-Issuer issued the old notes with a maximum aggregate principal amount of $250.0 million. The Company and the Co-Issuer again may issue additional notes under the Indenture from time

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to time after this offering (the “Additional Notes”). Any offering of Additional Notes is subject to the covenant described below under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”. Any old notes that remain outstanding after the completion of the exchange offer, any new notes issued in connection with the exchange offer and any Additional Notes subsequently issued under the Indenture will be treated as a single class for all purposes under the Indenture, including waivers, amendments, redemptions and offers to purchase.

Unless the context requires otherwise, references to “notes” include any Additional Notes that are actually issued.

Interest on the new notes will accrue at the rate of 8 ¹/2% per annum and be payable in cash semi-annually in arrears on May 1 and November 1, commencing May 1, 2008. The Company and the Co-Issuer will make each interest payment to the Holders of record of the notes on the immediately preceding April 15 and October 15. Interest on the new notes will accrue from the most recent date to which interest has been paid on the old notes. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. The notes will mature on November 1, 2013. The new notes will be issued, and the old notes were issued, in denominations of $2,000 and any integral multiples of $1,000 in excess of $2,000.

Subsidiary Guarantees

Each Subsidiary Guarantor, as a primary obligor and not merely as a surety, jointly and severally, irrevocably and unconditionally guarantees the Company’s and the Co-Issuer’s obligations under the Indenture and the notes on a senior unsecured basis. All the Restricted Subsidiaries (other than the Co-Issuer, NCLB Liquids Inc., Warren Petroleum Company, LLC and Targa Bridgeline LLC) guarantee the notes. Each Subsidiary Guarantee of the notes is a general unsecured obligation of the applicable Subsidiary Guarantor, ranks pari passu in right of payment with all existing and future unsecured Senior Indebtedness of such Subsidiary Guarantor, is effectively subordinated to all Secured Indebtedness of such Subsidiary Guarantor, including such Subsidiary Guarantor’s guarantee of the Senior Credit Facilities, to the extent of the value of the collateral securing such Indebtedness and ranks senior in right of payment to any future Subordinated Indebtedness of such Subsidiary Guarantor. The Subsidiary Guarantee of each Subsidiary Guarantor is structurally subordinated to all existing and future claims of creditors (including trade creditors) and holders of Preferred Stock of Subsidiaries of such Subsidiary Guarantor that do not guarantee the notes, including any Permitted MLPs and Permitted GPs.

Each Subsidiary Guarantee contains a provision intended to limit the Subsidiary Guarantor’s liability thereunder to the maximum amount that it could incur without causing the incurrence of obligations under its Subsidiary Guarantee to be a fraudulent transfer. This provision may not, however, be effective to protect a Subsidiary Guarantee from being voided under fraudulent transfer law or may reduce the Subsidiary Guarantor’s obligation to an amount that effectively makes its Subsidiary Guarantee worthless. See “Risk Factors—Risks Related to the Exchange Offer and the Notes and our Capital Structure—Federal and state statutes may allow courts, under specific circumstances, to void the guarantees and subordinate claims in respect of the guarantees.”

Each Subsidiary Guarantor may consolidate with or merge into or sell all or substantially all its assets to (A) the Company or another Subsidiary Guarantor without limitation or (B) any other Persons upon the terms and conditions set forth in the Indenture. See “Certain Covenants—Merger, Consolidation or Sale of All or Substantially All Assets”.

The Subsidiary Guarantee of a Subsidiary Guarantor will automatically and unconditionally be released and discharged upon:

(1) (a) the sale, disposition or other transfer (including through merger or consolidation) of all of the Capital Stock (or any sale, disposition or other transfer of Capital Stock following which such Subsidiary

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Guaran tor is no longer a Restricted Subsidiary), or all or substantially all the assets, of such Subsidiary Guarantor (other than a sale, disposition or other transfer to a Restricted Subsidiary) if such sale, disposition or other transfer is made in compliance with the applicable provisions of the Indenture;

(b) such Subsidiary Guarantor becoming a Partially Owned Operating Company;

(c) the designation by the Company of such Subsidiary Guarantor as an Unrestricted Subsidiary in accordance with the provisions of the Indenture set forth under “Certain Covenants—Limitation on Restricted Payments” and the definition of “Unrestricted Subsidiary”;

(d) the release or discharge of such Subsidiary Guarantor from its guarantee of Indebtedness under the Senior Credit Facilities or the guarantee that resulted in the obligation of such Subsidiary Guarantor to guarantee the notes, if such Subsidiary Guarantor would not then otherwise be required to guarantee the notes pursuant to the covenant described under “Certain Covenants—Limitation on Guarantees of Indebtedness by Restricted Subsidiaries” (treating any guarantees of such Subsidiary Guarantor that remain outstanding as incurred at least 30 days prior to such release or discharge); or

(e) the exercise by the Company and the Co-Issuer of their legal defeasance option or their covenant defeasance option, as described under “Legal Defeasance and Covenant Defeasance” or if the Company’s and the Co-Issuer’s obligations under the Indenture are discharged in accordance with the terms of the Indenture; and

(2) in the case of clause (1) (a) above, the release or discharge of such Subsidiary Guarantor from its guarantee, if any, of and all pledges and security, if any, granted in connection with, the Senior Credit Facilities and any other Indebtedness of the Company or any Restricted Subsidiary.

Ranking

Secured Indebtedness versus Notes

Payments of principal of, and premium, if any, and interest on, the notes and the payment of any Subsidiary Guarantee rank pari passu in right of payment with all Senior Indebtedness of the Company, the Co-Issuer or the relevant Subsidiary Guarantor, as the case may be, including the obligations of the Company and such Subsidiary Guarantor under the Senior Credit Facilities. However, the notes and Subsidiary Guarantees are effectively subordinated in right of payment to all of the existing and future Secured Indebtedness of the Company, the Co-Issuer or the relevant Subsidiary Guarantor, as the case may be, to the extent of the value of the assets securing such Indebtedness.

In addition, certain of our Hedging Obligations with respect to natural gas and natural gas liquids constitute Secured Indebtedness. To the extent prices of these commodities increase, the amount of this Secured Indebtedness could increase significantly. We expect to incur additional secured Hedging Obligations as part of our ongoing commodity risk management activities.

Although the Indenture contains limitations on the amount of additional Senior Indebtedness that the Company and its Restricted Subsidiaries may incur and the amount of additional Secured Indebtedness the Company, the Co-Issuer and the Subsidiary Guarantors may incur, under certain circumstances the amount of such Senior Indebtedness and Secured Indebtedness could be substantial.

See “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “Certain Covenants—Liens”.

Liabilities of Subsidiaries versus Notes

All of our operations are conducted through our Subsidiaries. Some of our Subsidiaries are not guaranteeing the notes, and Subsidiary Guarantees may be released under certain circumstances, as described under

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“Subsidiary Guarantees.” In addition, our future Subsidiaries may not be required to guarantee the notes, and Permitted MLPs and Permitted GPs will not be required to guarantee the notes. Claims of creditors of such non-guarantor Subsidiaries, Permitted MLPs and Permitted GPs, including trade creditors and creditors holding indebtedness or guarantees issued by such non-guarantor Subsidiaries, Permitted MLPs and Permitted GPs, and claims of holders of Preferred Stock of such non-guarantor Subsidiaries, Permitted MLPs and Permitted GPs generally will have priority with respect to the assets and earnings of such non-guarantor Subsidiaries, Permitted MLPs and Permitted GPs over the claims of our creditors, including Holders. Accordingly, the notes will be structurally subordinated to claims of creditors (including trade creditors) and holders of Preferred Stock, if any, of such non-guarantor Subsidiaries, Permitted MLPs and Permitted GPs.

Mandatory Redemption; Offer to Purchase; Open Market Purchases

The Company and the Co-Issuer are not required to make any mandatory redemption or sinking fund payments with respect to the notes. However, under certain circumstances, the Company and the Co-Issuer may be required to offer to purchase notes as described under “Repurchase at the Option of Holders”.

The Company and the Co-Issuer may from time to time acquire notes by means other than a redemption, whether by tender offer, in open market purchases, through negotiated transactions or otherwise, in accordance with applicable securities laws.

Optional Redemption

Except as described below, the notes are not redeemable at the Company’s or the Co-Issuer’s option prior to November 1, 2009. From and after November 1, 2009, the Company or the Co-Issuer may redeem the notes, in whole or in part, upon notless than 30 nor more than 60 days’ prior notice at the redemption prices (expressed as percentages of principal amount) set forth below,plus accrued and unpaid interest, and Additional Interest, if any, thereon to the applicable redemption date, subject to the right of Holders of record on the relevant record date to receive interest due on the relevant interest payment date, if redeemed during the twelve-month period beginning on November 1 of each of the years indicated below:

Year	Percentage
2009	104.250	%
2010	102.125	%
2011 and thereafter	100.000	%

Prior to November 1, 2008, the Company or the Co-Issuer may, at its option, redeem up to 35% of the sum of the original aggregate principal amount of notes (and the original principal amount of any Additional Notes) issued under the Indenture at a redemption price equal to 108.500% of the aggregate principal amount thereof,plus accrued and unpaid interest thereon to the redemption date, subject to the right of Holders on the relevant record date to receive interest due on the relevant interest payment date, with the net cash proceeds of one or more Equity Offerings of the Company or any direct or indirect parent of the Company to the extent such net proceeds are contributed to the Company;provided that:

• at least 65% of the sum of the aggregate principal amount of notes originally issued under the Indenture and the original principal amount of any Additional Notes issued under the Indenture remain outstanding immediately after the occurrence of each such redemption; and

• each such redemption occurs within 90 days of the date of closing of each such Equity Offering.

At any time prior to November 1, 2009, the Company or the Co-Issuer may also redeem all or a part of the notes, upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to 100% of the principal amount of notes redeemedplus the Applicable Premium as of, and accrued and unpaid interest to, the redemption date, subject to the rights of Holders on the relevant record date to receive interest due on the relevant interest payment date.

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Selection and Notice

If the Company is redeeming less than all of the notes at any time, the Trustee will select the notes to be redeemed (a) if the notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which such notes are listed, or (b) if the notes are not so listed, on apro rata basis to the extent practicable;provided that no notes of $2,000 or less shall be redeemed in part.

Notices of redemption shall be mailed by first-class mail, postage prepaid, at least 30 days but not more than 60 days before the redemption date to each Holder at such Holder’s registered address, except that notices of redemption may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the Indenture. If any note is to be redeemed in part only, any notice of redemption that relates to such note shall state the portion of the principal amount thereof to be redeemed.

A new note in principal amount equal to the unredeemed portion of any outstanding note redeemed in part will be issued in the name of the Holder thereof upon cancellation of the outstanding note. Notes called for redemption become due and payable on the date fixed for redemption. On and after the redemption date, unless the Company or the Co-Issuer defaults in payment of the redemption price, interest shall cease to accrue on notes or portions thereof called for redemption.

Book-Entry, Delivery and Form

Except as set forth below, the new notes will be issued in registered, global form in minimum denominations of $2,000 and integral multiples of $1,000 in excess of $2,000.

One or more Global Notes will be deposited upon issuance with the Trustee as custodian for The Depository Trust Company (“DTC”) and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant in DTC as described below.

Except as set forth below, Global Notes may be transferred only to another nominee of DTC or to a successor of DTC or its nominee, in whole and not in part. Except in the limited circumstances described below, beneficial interests in Global Notes may not be exchanged for notes in certificated form and owners of beneficial interests in Global Notes will not be entitled to receive physical delivery of notes in certificated form. See “—Exchange of Global Notes for Certificated Notes”.

Transfers of beneficial interests in Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants, which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC is provided solely as a matter of convenience. These operations and procedures are solely within the control of DTC and are subject to changes by it. We take no responsibility for these operations and procedures and urge investors to contact DTC or its participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company organized under the laws of the State of New York, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the Initial

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Purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised us that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of Participants with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in Global Notes).

Investors in Global Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in Global Notes who are not Participants may hold their interests therein indirectly through organizations that are Participants in DTC. All interests in a Global Note may be subject to the procedures and requirements of DTC. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own and the ability to transfer beneficial interests in a Global Note to Persons that are subject to those requirements will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge those interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of those interests, may be affected by the lack of a physical certificate evidencing those interests.

Except as described below, owners of an interest in Global Notes will not have notes registered in their names, will not receive physical delivery of definitive notes in registered certificated form (“Certificated Notes”) and will not be considered the registered owners or “Holders” thereof under the Indenture for any purpose.

Payments in respect of the principal of, premium, and interest on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered Holder under the Indenture. Under the terms of the Indenture, the Company, the Co-Issuer and the Trustee will treat the Persons in whose names the notes, including Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Company, the Co-Issuer, the Trustee nor any agent of the Company, the Co-Issuer or the Trustee has or will have any responsibility or liability for:

(1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interests in Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on that payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary

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practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the Trustee, the Company or the Co-Issuer. Neither the Company, the Co-Issuer nor the Trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and the Company, the Co-Issuer and the Trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds.

DTC has advised us that it will take any action permitted to be taken by a Holder only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of the portion of the aggregate principal amount of the notes as to which that Participant or those Participants has or have given the relevant direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for notes in certificated form, and to distribute those notes to its Participants.

Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in Global Notes among Participants, it is under no obligation to perform those procedures, and may discontinue or change those procedures at any time. Neither the Company, the Co-Issuer nor the Trustee nor any of their respective agents will have any responsibility for the performance by DTC or its Participants or Indirect Participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(1) DTC (a) notifies the Company and the Co-Issuer that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and, in each case, a successor depositary is not appointed;

(2) the Company and the Co-Issuer, at their option, notify the Trustee in writing that it elects to cause the issuance of Certificated Notes; or

(3) there has occurred and is continuing a Default with respect to the notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the Trustee by or on behalf of DTC in accordance with the Indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in a Global Note will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures).

Same Day Settlement and Payment

The Company and the Co-Issuer will make payments in respect of the notes represented by Global Notes (including payments of principal, premium, if any, and interest) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. The Company and the Co-Issuer will make all payments of principal of, and premium, if any, and interest on, Certificated Notes by wire transfer of immediately available funds to the accounts specified by the Holders of the Certificated Notes or, if no account is specified, by mailing a check to each Holder’s registered address. The new notes represented by Global Notes are expected to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in notes represented by the Global Notes will, therefore, be required by DTC to be settled in immediately available funds.

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Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, the Company and the Co-Issuer will make an offer to purchase all of the notes pursuant to the offer described below (the “Change of Control Offer”) at a price in cash (the “Change of Control Payment”) equal to 101% of the aggregate principal amount thereofplus accrued and unpaid interest to the date of purchase, subject to the right of Holders of record on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, the Company and the Co-Issuer will send notice of such Change of Control Offer by first-class mail, with a copy to the Trustee, to each Holder to the address of such Holder appearing in the security register with a copy to the Trustee, with the following information:

(1) a Change of Control Offer is being made pursuant to the covenant entitled “Change of Control,” and all notes properly tendered pursuant to such Change of Control Offer will be accepted for payment;

(2) the purchase price and the purchase date, which will be no earlier than 30 days nor later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”);

(3) any note not properly tendered will remain outstanding and continue to accrue interest;

(4) unless the Company or the Co-Issuer defaults in the payment of the Change of Control Payment, all notes accepted for payment pursuant to the Change of Control Offer will cease to accrue interest on the Change of Control Payment Date;

(5) Holders electing to have any notes purchased pursuant to a Change of Control Offer will be required to surrender the notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of the notes completed, to the paying agent specified in the notice at the address specified in the notice prior to the close of business on the third Business Day preceding the Change of Control Payment Date;

(6) Holders will be entitled to withdraw their tendered notes and their election to require the Company or the Co-Issuer to purchase such notes;provided that the paying agent receives, not later than the close of business on the last day of the offer period, a telegram, telex, facsimile transmission or letter setting forth the name of the Holder, the principal amount of notes tendered for purchase, and a statement that such Holder is withdrawing its tendered notes and its election to have such notes purchased; and

(7) Holders whose notes are being purchased only in part will be issued another note equal in principal amount to the unpurchased portion of the notes surrendered, which unpurchased portion must be equal to $2,000 or an integral multiple of $1,000 in excess of $2,000.

While the notes are in global form and the Company or the Co-Issuer makes an offer to purchase all of the notes pursuant to the Change of Control Offer, a Holder may exercise its option to elect for the purchase of the notes through the facilities of DTC, subject to its rules and regulations.

The Company and the Co-Issuer will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws or regulations are applicable in connection with the repurchase of the notes pursuant to a Change of Control Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the Indenture, the Company and the Co-Issuer will comply with the applicable securities laws and regulations and shall not be deemed to have breached its obligations described in the Indenture by virtue thereof.

On the Change of Control Payment Date, the Company and the Co-Issuer will, to the extent permitted by law,

(1) accept for payment all notes or portions thereof properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the aggregate Change of Control Payment in respect of all notes or portions thereof so tendered; and

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(3) deliver, or cause to be delivered, to the Trustee for cancellation the notes so accepted together with an Officers’ Certificate stating that such notes or portions thereof have been tendered to and purchased by the Company and the Co-Issuer.

The paying agent will promptly mail to each Holder the Change of Control Payment for such notes, and the Trustee will promptly authenticate and mail to each Holder another note equal in principal amount to the unpurchased portion of the notes surrendered;provided that each such other note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess of $2,000. The Company and the Co-Issuer will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The Senior Credit Facilities, and future credit agreements or other agreements to which the Company becomes a party, may provide that certain change of control events with respect to the Company (including a Change of Control) would constitute a default thereunder and prohibit the Company from purchasing any notes as a result of a Change of Control. In the event a Change of Control occurs at a time when the Company is prohibited from purchasing the notes, the Company could seek the consent of its lenders to permit the purchase of the notes or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain such consent or repay such borrowings, the Company will remain prohibited from purchasing the notes. In such case, the Company’s failure to purchase tendered notes would constitute an Event of Default under the Indenture. If the Company experiences a change of control that triggers a default under the Senior Credit Facilities or cross defaults under other Indebtedness, the Company could seek a waiver of such defaults or seek to refinance the Indebtedness outstanding under the Senior Credit Facilities and such other Indebtedness. In the event the Company does not obtain such a waiver or refinance the Indebtedness outstanding under the Senior Credit Facilities and such other Indebtedness, such defaults could result in amounts outstanding under the Senior Credit Facilities and such other Indebtedness being declared due and payable. Our ability to pay cash to the Holders following the occurrence of a Change of Control may be limited by our then existing financial resources. Therefore, sufficient funds may not be available when necessary to make any required repurchases.

The Company and the Co-Issuer will not be required to make a Change of Control Offer following a Change of Control if a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and the Co-Issuer and purchases all notes validly tendered and not withdrawn under such Change of Control Offer. A Change of Control Offer may be made in advance of a Change of Control, conditional upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Change of Control Offer.

The Change of Control purchase feature of the notes may in certain circumstances make more difficult or discourage a sale or takeover of the Company and, thus, the removal of incumbent management. The Change of Control purchase feature is a result of negotiations between the Company, the Co-Issuer and the Initial Purchasers. We have no present intention to engage in a transaction involving a Change of Control, although it is possible that we could decide to do so in the future. Subject to the limitations discussed below, we could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of Indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on our ability to incur additional Indebtedness are contained in the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”. Such restrictions can be waived with the consent of the holders of a majority in principal amount of the notes then outstanding. Except for the limitations contained in such covenant, however, the Indenture will not contain any covenants or provisions that may afford Holders protection in the event of a highly leveraged transaction.

The definition of “Change of Control” includes a disposition of all or substantially all of the assets of the Company or the Co-Issuer to any Person. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in

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certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the assets of the Company or the Co-Issuer. As a result, it may be unclear as to whether a Change of Control has occurred and whether a Holder may require the Company or the Co-Issuer to make an offer to repurchase the notes as described above.

The provisions under the Indenture relative to the Company’s and the Co-Issuer’s obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified with the written consent of the Holders of a majority in principal amount of the notes.

Asset Sales

The Indenture provides that the Company will not, and will not permit any Restricted Subsidiary to, cause, make or suffer to exist an Asset Sale, unless:

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Sale at least equal to the fair market value (as determined in good faith by the Company) of the assets sold or otherwise disposed of; and

(2) except in the case of a Permitted Asset Swap, at least 75% of the consideration therefor received by the Company or such Restricted Subsidiary, as the case may be, is in the form of cash or Cash Equivalents;provided that the amount of

(a) any liabilities (as shown on the Company’s or such Restricted Subsidiary’s most recent balance sheet or in the notes thereto) of the Company or such Restricted Subsidiary, other than liabilities that are by their terms subordinated to the notes, that are assumed by the transferee of any such assets (or a third party on behalf of the transferee) and for which the Company or such Restricted Subsidiary has been validly released by all creditors in writing,

(b) any securities, notes or other obligations or assets received by the Company or such Restricted Subsidiary from such transferee that are converted by the Company or such Restricted Subsidiary into cash (to the extent of the cash received) within 180 days following the closing of such Asset Sale and

(c) any Designated Noncash Consideration received by the Company or such Restricted Subsidiary in such Asset Sale having an aggregate fair market value, taken together with all other Designated Noncash Consideration received pursuant to this clause (c) that is at that time outstanding, not to exceed the greater of (x) $100.0 million and (y) 4.0% of Total Assets at the time of the receipt of such Designated Noncash Consideration, with the fair market value of each item of Designated Noncash Consideration being measured at the time received and without giving effect to subsequent changes in value,

shall be deemed to be cash for purposes of this provision and for no other purpose.

Within 365 days after any of the Company’s or any Restricted Subsidiary’s receipt of the Net Proceeds of any Asset Sale, the Company or such Restricted Subsidiary may, at its option, apply the Net Proceeds from such Asset Sale:

(1) to permanently reduce

(x) Obligations under the Senior Credit Facilities or any other Senior Indebtedness, in each case, of the Company or any Subsidiary Guarantor, and, in the case of Obligations under the Revolving Credit Facility, the Funded Synthetic Letter of Credit Facility or other similar Indebtedness, to correspondingly reduce commitments with respect thereto (other than Obligations owed to the Company or a Restricted Subsidiary);provided that if the Company or any Restricted Subsidiary shall so reduce Obligations under any Senior Indebtedness that is not Secured Indebtedness, the Company or such Subsidiary Guarantor shall, equally and ratably, reduce Obligations under the notes by, at its option, (A) redeeming the notes to the extent they are then redeemable as provided under “—Optional

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Redemption”, (B) making an offer (in accordance with the procedures set forth below for an Asset Sale Offer) to all Holders to purchase their notes at 100% of the principal amount thereof,plus the amount of accrued and unpaid interest and Additional Interest, if any, on the principal amount of the notes to be repurchased or (C) purchasing notes through open market purchases (to the extent such purchases are at a price equal to or higher than 100% of the principal amount thereof) in a manner that complies with the Indenture and applicable securities law; or

(y) Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor, other than Indebtedness owed to the Company or another Restricted Subsidiary; or

(2) to an investment in (a) any one or more businesses;provided that such investment in any business is in the form of the acquisition of Capital Stock and results in the Company or any Restricted Subsidiary owning an amount of the Capital Stock of such business such that it constitutes a Restricted Subsidiary, (b) properties, (c) capital expenditures and (d) acquisitions of other assets, that in each of (a), (b), (c) and (d) are used or useful in a Similar Business or replace the businesses, properties and assets that are the subject of such Asset Sale.

Any Net Proceeds from any Asset Sale that are not invested or applied in accordance with the preceding paragraph within 365 days from the date of the receipt of such Net Proceeds will be deemed to constitute “Excess Proceeds”;provided that if during such 365-day period the Company or a Restricted Subsidiary enters into a definitive binding agreement committing it to apply such Net Proceeds in accordance with the requirements of clause (2) of the immediately preceding paragraph after such 365th day, such 365-day period will be extended with respect to the amount of Net Proceeds so committed, but such extension will in no event be for a period longer than 180 days until such Net Proceeds are required to be applied in accordance with such agreement (or, if earlier, the date of termination of such agreement). When the aggregate amount of Excess Proceeds exceeds $35.0 million, the Company shall make an offer to all Holders and, if required by the terms of any Senior Indebtedness, to the holders of such Senior Indebtedness (other than with respect to Hedging Obligations) (an “Asset Sale Offer”), to purchase the maximum aggregate principal amount of notes and such Senior Indebtedness that is an integral multiple of $1,000 that may be purchased out of the Excess Proceeds at an offer price in cash in an amount equal to 100% of the principal amount thereof,plus accrued and unpaid interest, and Additional Interest, if any, to the date fixed for the closing of such offer, in accordance with the procedures set forth in the Indenture. The Company will commence an Asset Sale Offer with respect to Excess Proceeds within ten Business Days after the date that Excess Proceeds exceed $35.0 million by mailing the notice required pursuant to the terms of the Indenture, with a copy to the Trustee. The Company may satisfy the foregoing obligations with respect to any Net Proceeds from an Asset Sale by making an Asset Sale Offer with respect to such Net Proceeds prior to the expiration of the relevant 365 days (or such longer period provided above) or with respect to Excess Proceeds of $35.0 million orless.

To the extent that the aggregate amount of notes and such Senior Indebtedness tendered pursuant to an Asset Sale Offer isless than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate purposes, subject to other covenants contained in the Indenture. If the aggregate principal amount of notes or the Senior Indebtedness surrendered by such holders thereof exceeds the amount of Excess Proceeds, the Trustee shall select or cause to be selected the notes and such Senior Indebtedness to be purchased on apro rata basis based on the accreted value or principal amount of the notes or such Senior Indebtedness tendered. Upon completion of any such Asset Sale Offer, the amount of Excess Proceeds related to such Asset Sale Offer shall be reset at zero.

Pending the final application of any Net Proceeds pursuant to this covenant, the Company or the applicable Restricted Subsidiary may apply such Net Proceeds temporarily to reduce Indebtedness outstanding under a revolving credit facility or otherwise invest such Net Proceeds in any manner not prohibited by the Indenture.

The procedures for an Asset Sale Offer will be substantially the same as for a Change of Control Offer. The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws

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and regulations thereunder to the extent such laws or regulations are applicable in connection with the repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and shall not be deemed to have breached its obligations described in the Indenture by virtue thereof.

The Senior Credit Facilities will limit, and future credit agreements or other agreements to which the Company becomes a party may limit or prohibit, the Company from purchasing any notes as a result of an Asset Sale Offer. In the event the Company is required to make an Asset Sale Offer at a time when the Company is prohibited from purchasing the notes, the Company could seek the consent of its lenders to permit the purchase of the notes or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain such consent or repay such borrowings, the Company will remain prohibited from purchasing the notes. In such case, the Company’s failure to purchase tendered notes would constitute an Event of Default under the Indenture.

The provisions under the Indenture relative to the Company’s obligation to make an offer to repurchase the notes as a result of an Asset Sale may be waived or modified with the written consent of the Holders of a majority in principal amount of the notes.

Transactions Involving MLPs and GPs

The Indenture provides that the Company will not, and will not permit any Restricted Subsidiary to, cause or make a MLP Asset Transfer or a MLP Equity Transfer, unless:

(1) in the case of a MLP Asset Transfer, after such MLP Asset Transfer and as a result thereof, the Company and its Restricted Subsidiaries shall have received an amount of cash attributable to such MLP Asset Transfer (as a result of (i) the receipt of cash proceeds as all or a portion of the consideration for such MLP Asset Transfer or (ii) the repayment of intercompany indebtedness, owed by a Subsidiary of the Company, transferred or assumed as part of such MLP Asset Transfer) at least equal to 75% of the fair market value (as determined in good faith by the Company based on values that could be obtained in an arms’ length transaction) of (a) the assets and property transferred or (b) in the case of a transfer of any Equity Interests of a Person, such Person at the time of such MLP Asset Transfer (it being understood that, in the case of a transfer ofless than all of the Equity Interests of a Person, the value of such Person shall be determined at the time of the first MLP Asset Transfer constituting part of such MLP Asset Transfer (as if all the Equity Interests in such Person shall have been transferred at the time of such first MLP Asset Transfer and the cash requirement set forth in this clause shall be satisfied on that basis in connection with such first MLP Asset Transfer) and there shall be no such additional cash attributable to such MLP Asset Transfer required for any subsequent transfer of Equity Interests of such Person constituting part of the MLP Asset Transfer) (in each case of the foregoing clauses (a) and (b), assuming such assets or Person, as applicable, operate as a going concern), with the balance of the consideration received by the Company and its Restricted Subsidiaries for such MLP Asset Transfer consisting solely of Equity Interests in the applicable MLP;provided, however, that in the event that the fair market value of the assets, property and Person transferred in connection with a MLP Asset Transfer exceed $100.0 million in the aggregate, the Company or such Restricted Subsidiary, as the case may be, shall have received a written opinion from an Independent Financial Advisor to the effect that such MLP Asset Transfer is fair, from a financial standpoint, to the Company and its Restricted Subsidiaries;

(2) in the case of a MLP Equity Transfer (other than a MLP Equity Transfer to the extent it is made to satisfy the proviso to the definition of “Minimum Cash Consideration,” in which case only the requirements of such proviso need be satisfied), the Company or a Restricted Subsidiary receives net proceeds in connection therewith in an amount at least equal to the fair market value of the Equity Interests that are transferred in such MLP Equity Transfer and at least 75% of the consideration for such MLP Equity Transfer received by the Company and its Restricted Subsidiaries is in the form of cash.

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(3) the Company and the Restricted Subsidiaries are in compliance with the terms of the Indenture and the documentation governing the Senior Credit Facilities, and such MLP Asset Transfer or MLP Equity Transfer, as the case may be, would not result in a breach or violation of, or constitute a default under the Indenture or any of the documentation governing the Senior Credit Facilities; and

(4) such MLP Asset Transfer would not result in the related MLP or any MLP Subsidiary being required to assume the obligations of the Company or such Restricted Subsidiary under the terms of any of the Company’s or such Restricted Subsidiary’s Indebtedness

(any such MLP Asset Transfer or MLP Equity Transfer that complies with clauses (1) through (4) above being referred to as a “Permitted MLP Transfer”). All Equity Interests received by the Company or any Restricted Subsidiary as a result of any Permitted MLP Transfer that is a MLP Asset Transfer shall be held by the Company or such Restricted Subsidiary, as the case may be, until such time as any such Equity Interest is sold, conveyed, transferred or otherwise disposed of pursuant to this covenant.

The Indenture also provides that the Company will not, and will not permit any Restricted Subsidiary or MLP GP to, cause or make a GP Equity Transfer unless:

(1) (x) in the case of a GP Equity Transfer by the Company or a Restricted Subsidiary, the Company or a Restricted Subsidiary receives in connection therewith cash (which may include the repayment in cash of Indebtedness owing to the Company or such Restricted Subsidiary) at substantially the same time of such GP Equity Transfer in an amount at least equal to the greater of (i) $50.0 million (with this clause (i) applicable only in the case of a GP Equity Transfer undertaken in connection with the initial public offering of a MLP GP) and (ii) the fair market value of the Equity Interests subject to such GP Equity Transfer or (y) in the case of a GP Equity Transfer by a MLP GP, the net proceeds received by such MLP GP in such GP Equity Transfer, which shall be at least equal to the fair market value of the Equity Interests subject to such GP Equity Transfer, are used to pay a dividend to the holders of Equity Interests of such MLP GP or to purchase, redeem, defease or otherwise acquire or retire for value any Equity Interests in such MLP GP;provided, however, that the Company or a Restricted Subsidiary shall receive at least apro rata portion of such dividend or at least apro rata portion of the payment for such purchase, redemption, defeasance, acquisition or retirement, except that such requirement shall not apply with respect to payments for the purchase, redemption, defeasance or retirement for value of Equity Interests (other than Disqualified Stock) of any MLP GP held by any future, present or former employee, director, manager or consultant of such MLP GP, any of its Subsidiaries or any of its direct or indirect parent companies pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement;

(2) the Company is in compliance with the terms of the Indenture and the documentation governing the Senior Credit Facilities, and such GP Equity Transfer would not result in a breach or violation of, or constitute a default under the Indenture or any of the documentation governing the Senior Credit Facilities;

(3) the related MLP GP’s sole business is to act as the general partner of the applicable Permitted MLP and engage in activities ancillary thereto and such MLP GP owns no assets (other than (i) ownership interests in such Permitted MLP and Capital Stock (other than Disqualified Stock) of the Company, (ii) temporarily holding assets to be transferred or distributed in connection with a Permitted MLP Transfer or Permitted GP Transfer or distributions from a Permitted MLP, (iii) current assets sufficient to satisfy its ordinary course operating expenses, including such expenses after it has become a publicly traded company, and other assets necessary for its existence and operation as a public company and (iv) the reserves referred to in clause (4) below); and

(4) the related GP is required by its partnership agreement to distribute all cash and Cash Equivalents that it receives from time to time to its partners on apro rata basis, subject to the establishment of such reserves as management of such related GP determines are appropriate for general, administrative and operating expenses in the ordinary course of its business and as are prudent to maintain for the proper conduct of its business or to provide for future distributions, in each case in accordance with the terms of the

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organizational documents of the related GP;provided that such organizational documents are, in the reasonable judgment of the Company, in a form that is customary for similar entities whose primary function is to serve as general partners of entities operating as master limited partnerships;

(any such GP Equity Transfer that complies with clauses (1) through (4) above being referred to as a “Permitted GP Transfer”). All Equity Interests in the related GP from time to time owned, directly or indirectly, by the Company shall be held by the Company or a Restricted Subsidiary until such time as any such Equity Interest is sold, conveyed, transferred or otherwise disposed of pursuant to this covenant.

For purposes of calculating the fair market value of any assets or property transferred to any Person, any Person and any Equity Interests in a Person with respect to any MLP Asset Transfer, MLP Equity Transfer or Permitted GP Transfer, any Indebtedness that is owed by such Person to the Company or any Restricted Subsidiary shall be disregarded and shall not be reflected in such calculation to reduce the fair market value of such assets or property, Person or Equity Interests in such Person, as the case may be.

Within 365 days after any Permitted MLP Transfer, Permitted GP Transfer or Extraordinary Distribution has occurred, the Company or the applicable Restricted Subsidiary, as the case may be, may, at its option, apply the Net Proceeds from such Permitted MLP Transfer, Permitted GP Transfer or Extraordinary Distribution to permanently reduce:

(1) Indebtedness under the Term Loan Facility and Asset Sale Bridge Facility;

(2) Obligations under other Senior Indebtedness of the Company or any Subsidiary Guarantor and, in the case of Obligations under the Revolving Credit Facility and the Funded Synthetic Letter of Credit Facility, to correspondingly reduce commitments with respect thereto (other than Obligations owed to the Company or a Restricted Subsidiary);provided that if the Company or any Restricted Subsidiary shall so reduce Obligations under any Senior Indebtedness that is not Secured Indebtedness, the Company or such Restricted Subsidiary shall, equally and ratably, reduce Obligations under the notes by, at its option, (A) redeeming the notes to the extent they are redeemable as provided under “—Optional Redemption”, (B) making an offer (in accordance with the procedures set forth below for a MLP Offer) to all Holders to purchase their notes at 100% of the principal amount thereof,plus the amount of accrued and unpaid interest on the principal amount of the notes to be repurchased, or (C) purchasing notes through open market purchases (to the extent such purchases are at a price equal to or higher than 100% of the principal amount thereof) in a manner that complies with the Indenture and applicable securities law; or

(3) Indebtedness of a Restricted Subsidiary that is not a Subsidiary Guarantor, other than Indebtedness owed to the Company or another Restricted Subsidiary.

Notwithstanding the foregoing, the Company or such Restricted Subsidiary may apply up to 50% of the Net Proceeds from any Permitted MLP Transfer (other than the Initial MLP Transfer), any Permitted GP Transfer or any Extraordinary Distribution to make a Permitted MLP Investment;provided that if during such 365-day period, the Company or a Restricted Subsidiary enters into a definitive binding agreement committing it to apply such Net Proceeds to make a Permitted MLP Investment after such 365th day, such 365-day period will be extended with respect to the amount of Net Proceeds so committed (but such extension will in no event be for a period longer than 180 days) until such Net Proceeds are required to be applied in accordance with such agreement (or, if earlier, the date of termination of such agreement).

If any Net Proceeds received are not invested or applied in accordance with the preceding paragraph within 365 days from the date of the receipt of such Net Proceeds (or such longer period provided for in such paragraph), then the Company shall make an offer to all Holders and, if required by the terms of any other Senior Indebtedness, to the holders of such other Senior Indebtedness (other than with respect to Hedging Obligations) (an “MLP Offer”), to purchase the maximum aggregate principal amount of notes and such other Senior Indebtedness that is an integral multiple of $1,000 that may be purchased out of the excess Net Proceeds at an offer price in cash in an amount equal to 100% of the principal amount thereof,plus accrued and unpaid interest,

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and Additional Interest, if any, to the date fixed for the closing of such offer, in accordance with the procedures set forth in the Indenture. The Company will commence a MLP Offer with respect to such Net Proceeds within ten Business Days after the date that excess Net Proceeds exceed $10.0 million by mailing the notice required pursuant to the terms of the Indenture, with a copy to the Trustee.

To the extent that the aggregate amount of notes and such other Senior Indebtedness tendered pursuant to a MLP Offer isless than the excess Net Proceeds from the Permitted MLP Transfer, Permitted GP Transfer or Extraordinary Distribution, the Company may use any remaining excess Net Proceeds for general corporate purposes, subject to other covenants contained in the Indenture. If the aggregate principal amount of notes and the other Senior Indebtedness surrendered by such holders thereof exceeds the amount of such excess Net Proceeds, the Trustee shall select or cause to be selected the notes and such other Senior Indebtedness to be purchased on apro rata basis based on the principal amount (or accreted value, if applicable) of the notes or such other Senior Indebtedness tendered. Upon completion of any such MLP Offer, the amount of such excess Net Proceeds related to such MLP Offer shall be reset at zero.

Pending the final application of any Net Proceeds pursuant to this covenant, the Company or the applicable Restricted Subsidiary may apply such Net Proceeds temporarily to reduce Indebtedness outstanding under a revolving credit facility or otherwise invest such Net Proceeds in any manner not prohibited by the Indenture.

The procedures for a MLP Offer will be substantially the same as for a Change of Control Offer. The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws or regulations are applicable in connection with the repurchase of notes pursuant to a MLP Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the Indenture, the Company will comply with the applicable securities laws and regulations and shall not be deemed to have breached its obligations described in the Indenture by virtue thereof.

The provisions under the Indenture relative to the Company’s obligation to make an offer to repurchase the notes as a result of a Permitted MLP Transfer, Permitted GP Transfer or Extraordinary Distribution may be waived or modified with the written consent of the Holders of a majority in principal amount of the notes.

Certain Covenants

Set forth below are summaries of certain covenants contained in the Indenture.

Limitation on Restricted Payments

The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly:

(1) declare or pay any dividend or make any distribution on account of the Company’s or any Restricted Subsidiary’s Equity Interests, including any dividend or distribution payable in connection with any merger or consolidation other than

(A) dividends or distributions by the Company payable in Equity Interests (other than Disqualified Stock) of the Company or in options, warrants or other rights to purchase such Equity Interests (other than Disqualified Stock) or

(B) dividends or distributions by a Restricted Subsidiary so long as, in the case of any dividend or distribution payable on or in respect of any class or series of securities issued by a Restricted Subsidiary other than a Wholly-Owned Subsidiary, the Company or a Restricted Subsidiary receives at least itspro rata share of such dividend or distribution in accordance with its Equity Interests in such class or series of securities;

(2) purchase, redeem, defease or otherwise acquire or retire for value any Equity Interests of the Company or any direct or indirect parent of the Company, including in connection with any merger or consolidation;

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(3) make any principal payment on, or redeem, repurchase, defease or otherwise acquire or retire for value in each case, prior to any scheduled repayment, sinking fund payment or maturity, any Subordinated Indebtedness, other than

(x) Indebtedness permitted under clauses (j)(1) and (j)(2) of the covenant described under “—Limitations on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” or

(y) the purchase, repurchase or other acquisition of Subordinated Indebtedness purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase or acquisition; or

(4) make any Restricted Investment;

(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as “Restricted Payments”), unless, at the time of such Restricted Payment:

(a) no Default shall have occurred and be continuing or would occur as a consequence thereof;

(b) immediately after giving effect to such transaction on apro forma basis, the Company could incur $1.00 of additional Indebtedness under the provisions of the first paragraph of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”; and

(c) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and the Restricted Subsidiaries after October 31, 2005 pursuant to the first paragraph of this covenant or clauses (1), (2) (with respect to the payment of dividends on Refunding Capital Stock pursuant to clause (b) thereof only), (6)(C), (8) and (12) of the next succeeding paragraph (and excluding, for the avoidance of doubt, all other Restricted Payments made pursuant to the next succeeding paragraph), isless than the sum, without duplication, of

(1) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from September 1, 2005 to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment, or, in the case such Consolidated Net Income for such period is a deficit, minus 100% of such deficit;provided that if, at the time of a proposed Restricted Payment under the first paragraph of this covenant, the Consolidated Leverage Ratio of the Company and its Restricted Subsidiaries isless than 3.50: 1.00, for purposes of calculating availability of amounts hereunder for such Restricted Payment only, the reference to 50% in this clause (1) above shall be deemed to be 75%,plus

(2) 100% of the aggregate net cash proceeds and the fair market value, as determined in good faith by the Company, of marketable securities or other property received by the Company after October 31, 2005 (less the amount of such net cash proceeds to the extent such amount has been relied upon to permit the incurrence of Indebtedness, or issuance of Disqualified Stock or Preferred Stock pursuant to clause (u)(ii) of the second paragraph of “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”) from the issue or sale of

(x) Equity Interests of the Company, including Retired Capital Stock (as defined below), but excluding cash proceeds and the fair market value, as determined in good faith by the Company, of marketable securities or other property received from the sale of

(A) Equity Interests to any future, present or former employees, managers, directors or consultants of the Company, any direct or indirect parent company of the Company or any of the Company’s Subsidiaries after October 31, 2005 to the extent such amounts have been applied to Restricted Payments made in accordance with clause (4) of the next succeeding paragraph and

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(B) Designated Preferred Stock and to the extent actually contributed to the Company, Equity Interests of the Company’s direct or indirect parent companies (excluding contributions of the proceeds from the sale of Designated Preferred Stock of such companies or contributions to the extent such amounts have been applied to Restricted Payments made in accordance with clause (4) of the next succeeding paragraph) or

(y) debt securities of the Company that have been converted into or exchanged for such Equity Interests of the Company;

provided that this clause (2) shall not include the proceeds from (a) Refunding Capital Stock (as defined below), (b) Equity Interests of the Company or debt securities of the Company that have been converted into or exchanged for Equity Interests of the Company sold to a Restricted Subsidiary or the Company, as the case may be, (c) Disqualified Stock or debt securities that have been converted into or exchanged for Disqualified Stock or (d) Excluded Contributions,plus

(3) 100% of the aggregate amount of cash and the fair market value, as determined in good faith by the Company, of marketable securities or other property contributed to the capital of the Company after October 31, 2005 (less the amount of such net cash proceeds to the extent such amount has been relied upon to permit the incurrence of Indebtedness or issuance of Disqualified Stock or Preferred Stock pursuant to clause (u)(ii) of the second paragraph of “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”) (other than by a Restricted Subsidiary and other than by any Excluded Contributions), plus

(4) to the extent not already included in Consolidated Net Income, 100% of the aggregate amount received in cash and the fair market value, as determined in good faith by the Company, of marketable securities or other property received after October 31, 2005 by means of

(A) the sale or other disposition (other than to the Company or a Restricted Subsidiary) of Restricted Investments made by the Company or any Restricted Subsidiary and repurchases and redemptions of such Restricted Investments from the Company or any Restricted Subsidiary and repayments of loans or advances that constitute Restricted Investments by the Company or any Restricted Subsidiary or

(B) the sale (other than to the Company or a Restricted Subsidiary) of the Capital Stock of an Unrestricted Subsidiary or a distribution from an Unrestricted Subsidiary (other than in each case to the extent the Investment in such Unrestricted Subsidiary was made by the Company or a Restricted Subsidiary pursuant to clauses (9) or (13) of the next succeeding paragraph or to the extent such Investment constituted a Permitted Investment) or a dividend from an Unrestricted Subsidiary,plus

(5) in the case of the redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary after October 31, 2005, the fair market value of the Investment in such Unrestricted Subsidiary, as determined by the Company in good faith or if, in the case of an Unrestricted Subsidiary, such fair market value may exceed $100.0 million, in writing by an Independent Financial Advisor, at the time of the redesignation of such Unrestricted Subsidiary as a Restricted Subsidiary, other than an Unrestricted Subsidiary to the extent the Investment in such Unrestricted Subsidiary was made by the Company or a Restricted Subsidiary pursuant to clauses (9) or (13) of the next succeeding paragraph or to the extent such Investment constituted a Permitted Investment.

The foregoing provisions will not prohibit:

(1) the payment of any dividend or distribution within 60 days after the date of declaration thereof, if at the date of declaration such payment would have complied with the provisions of the Indenture;

(2) (a) the redemption, repurchase, retirement or other acquisition of any Equity Interests (“Retired Capital Stock”) or Subordinated Indebtedness of the Company or any Equity Interests of any direct or indirect parent company of the Company, in exchange for, or out of the proceeds of the substantially

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concurrent sale (other than to a Restricted Subsidiary) of, Equity Interests of the Company (in each case, other than any Disqualified Stock) (“Refunding Capital Stock”) and (b) if immediately prior to the retirement of Retired Capital Stock, the declaration and payment of dividends thereon was permitted under clause (6) of this paragraph, the declaration and payment of dividends on the Refunding Capital Stock (other than Refunding Capital Stock the proceeds of which were used to redeem, repurchase, retire or otherwise acquire any Equity Interests of any direct or indirect parent company of the Company) in an aggregate amount per year no greater than the aggregate amount of dividends per annum that was declarable and payable on such Retired Capital Stock immediately prior to such retirement;

(3) the defeasance, redemption, repurchase or other acquisition or retirement of Subordinated Indebtedness of the Company or a Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, new Indebtedness of such Person that is incurred in compliance with the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” so long as

(A) the principal amount of such new Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Subordinated Indebtedness being so defeased, redeemed, repurchased, acquired or retired for value,plus the amount of any reasonable premium required to be paid under the terms of the instrument governing the Subordinated Indebtedness being so defeased, redeemed, repurchased, acquired or retired and any reasonable fees and expenses incurred in connection with the issuance of such new Indebtedness;

(B) such Indebtedness is subordinated to the notes at least to the same extent as such Subordinated Indebtedness so defeased, redeemed, repurchased, acquired or retired;

(C) such Indebtedness has a final scheduled maturity date equal to or later than the final scheduled maturity date of the Subordinated Indebtedness being so defeased, redeemed, repurchased, acquired or retired; and

(D) such Indebtedness has a Weighted Average Life to Maturity equal to or greater than the remaining Weighted Average Life to Maturity of the Subordinated Indebtedness being so defeased, redeemed, repurchased, acquired or retired;

(4) a Restricted Payment to pay for the repurchase, retirement or other acquisition or retirement for value of Equity Interests (other than Disqualified Stock) of the Company or any of its direct or indirect parent companies held by any future, present or former employee, director, manager or consultant of the Company, any of its Subsidiaries or any of its direct or indirect parent companies pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement;provided that the aggregate Restricted Payments made under this clause (4) do not exceed in any calendar year $10.0 million (with unused amounts in any calendar year being carried over to succeeding calendar years subject to a maximum (without giving effect to the following proviso) of $20.0 million in any calendar year);provided, further, that such amount in any calendar year may be increased by an amount not to exceed

(A) the cash proceeds from the sale of Equity Interests (other than Disqualified Stock) of the Company and, to the extent contributed to the Company, Equity Interests of any of the Company’s direct or indirect parent companies, in each case to members of management, directors, managers or consultants of the Company, any of its Subsidiaries or any of its direct or indirect parent companies that occurs after October 31, 2005, to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to the payment of Restricted Payments by virtue of clause (c) of the preceding paragraph,plus

(B) the cash proceeds of key man life insurance policies received by the Company and the Restricted Subsidiaries after October 31, 2005,less

(C) the amount of any Restricted Payments previously made pursuant to clauses (A) and (B) of this clause (4);

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andprovided, further, that cancellation of Indebtedness owing to the Company from members of management, directors, managers or consultants of the Company, any of its direct or indirect parent companies or any Restricted Subsidiary in connection with a repurchase of Equity Interests of the Company or any of its direct or indirect parent companies will not be deemed to constitute a Restricted Payment for purposes of this covenant or any other provision of the Indenture;

(5) the declaration and payment of dividends to holders of any class or series of Disqualified Stock of the Company or any Restricted Subsidiary issued in accordance with the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” to the extent such dividends are included in the definition of Fixed Charges;

(6) (A) the declaration and payment of dividends to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) issued by the Company after October 31, 2005;

(B) the declaration and payment of dividends to a direct or indirect parent company of the Company, the proceeds of which will be used to fund the payment of dividends to holders of any class or series of Designated Preferred Stock (other than Disqualified Stock) of such parent company issued after October 31, 2005;provided that the amount of dividends paid pursuant to this clause (B) shall not exceed the aggregate amount of cash actually contributed to the Company from the sale of such Designated Preferred Stock; or

(C) the declaration and payment of dividends on Refunding Capital Stock that is Preferred Stock in excess of the dividends declarable and payable thereon pursuant to clause (2) of this paragraph;

provided, however, in the case of each of (A), (B) and (C) of this clause (6), that for the most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date of issuance of such Designated Preferred Stock or the declaration of such dividends on Refunding Capital Stock that is Preferred Stock, after giving effect to such issuance or declaration on apro forma basis, the Company and the Restricted Subsidiaries on a consolidated basis would have had a Fixed Charge Coverage Ratio of at least 2.00 to 1.00;

(7) repurchases of Equity Interests deemed to occur upon exercise of stock options or warrants if such Equity Interests represent a portion of the exercise price of such options or warrants;

(8) the declaration and payment of dividends on the Company’s common stock following the first public offering of the Company’s common stock or the common stock of any of its direct or indirect parent companies after October 31, 2005, of up to 6% per annum of the net proceeds received by or contributed to the Company in or from any such public offering, other than public offerings with respect to the Company’s common stock registered on Form S-4 or Form S-8 and other than any public sale constituting an Excluded Contribution;

(9) Restricted Payments that are made with Excluded Contributions;

(10) the declaration and payment of dividends by the Company to, or the making of loans to, its direct parent company in amounts required for the Company’s direct or indirect parent companies to pay

(A) franchise taxes and other fees, taxes and expenses required to maintain their corporate existence;

(B) Federal, state and local income taxes, to the extent such income taxes are attributable to the income of the Company and the Restricted Subsidiaries and, to the extent of the amount actually received from its Unrestricted Subsidiaries, in amounts required to pay such taxes to the extent attributable to the income of such Unrestricted Subsidiaries;

(C) customary salary, bonus and other benefits payable to officers and employees of any direct or indirect parent company of the Company to the extent such salaries, bonuses and other benefits are attributable to the ownership or operation of the Company and the Restricted Subsidiaries;

(D) general corporate overhead expenses of any direct or indirect parent company of the Company to the extent such expenses are attributable to the ownership or operation of the Company and the Restricted Subsidiaries; and

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(E) reasonable fees and expenses incurred in connection with any unsuccessful debt or equity offering by such direct or indirect parent company of the Company;

(11) any Restricted Payments used to fund the Transactions and the fees and expenses related thereto, including those owed to Affiliates, in each case to the extent permitted by the covenant described under “—Transactions with Affiliates”;

(12) the repurchase, redemption or other acquisition or retirement for value of any Subordinated Indebtedness pursuant to provisions similar to those described under “Repurchase at the Option of Holders—Change of Control”, “—Asset Sales” and “—Transactions Involving MLPs and GPs”;provided that prior to such repurchase, redemption or other acquisition the Company (or a third party to the extent permitted by the Indenture) shall have made a Change of Control Offer, Asset Sale Offer or MLP Offer, as the case may be, with respect to the notes and shall have repurchased all notes validly tendered and not withdrawn in connection with such Change of Control Offer, Asset Sale Offer or MLP Offer;

(13) Investments in Unrestricted Subsidiaries having an aggregate fair market value, taken together with all other Investments made pursuant to this clause (13) that are at the time outstanding, without giving effect to the sale of an Unrestricted Subsidiary to the extent the proceeds of such sale do not consist of cash or marketable securities, not to exceed the greater of (x) $100.0 million and (y) 4.0% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value);

(14) distributions or payments of Receivables Fees;

(15) the distribution, as a dividend or otherwise (and the declaration of such dividend), of shares of Capital Stock of, or Indebtedness owed to the Company or a Restricted Subsidiary by, (a) any Person designated as an Unrestricted Subsidiary after October 31, 2005 pursuant to the terms of the Indenture (other than any of the Unrestricted Subsidiaries referred to in clause (1) of the first paragraph of the definition of “Unrestricted Subsidiary” and any successor thereto) or (b) any Permitted MLP or Permitted GP;provided that at the time of such dividend or distribution, with respect to this clause (b) only, and after givingpro formaeffect thereto, the Consolidated Leverage Ratio would beless than 2.75:1.0;

(16) Restricted Payments in an amount that, when taken together with all other Restricted Payments made pursuant to this clause (16) does not exceed the sum of (x) 50% of the amount by which the Net Proceeds from the North Texas Asset Sale exceed $700.0 million but areless than or equal to $850.0 million and (y) 25% of the amount by which the Net Proceeds from the North Texas Asset Sale exceed $850.0 million;provided that first $700.0 million of Net Proceeds from the North Texas Asset Saleplus the balance of the Net Proceeds described in subclauses (x) and (y) above shall have been applied in accordance with the covenant described under “Repurchase at the Option of Holders—Asset Sales” and the amount of Indebtedness permitted to be incurred under clause (b) of the second paragraph of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” shall, as a consequence thereof, have been reduced to the extent provided therein; and

(17) other Restricted Payments taken together with all other Restricted Payments made pursuant to this clause (17), not to exceed $75.0 million;

provided, however, that at the time of, and after giving effect to, any Restricted Payment permitted under clauses (15), (16) and (17) no Default shall have occurred and be continuing or would occur as a consequence thereof.

As of the time of issuance of the old notes, all of the Company’s Subsidiaries were Restricted Subsidiaries other than Versado Gas Processors L.L.C., Downstream Energy Ventures, Co., L.L.C. and Cedar Bayou Fractionaters, LP. The Company will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the last sentence of the definition of “Unrestricted Subsidiary”. For purposes of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by the Company and the

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Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investments”. Such designation will be permitted only if a Restricted Payment in such amount would be permitted at such time, whether pursuant to the first paragraph of this covenant or under clauses (9), (13), or (17), or pursuant to the definition of “Permitted Investments”, and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Unrestricted Subsidiaries will not be subject to any of the restrictive covenants set forth in the Indenture.

Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock

The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, (collectively, “incur” and collectively, an “incurrence”) with respect to any Indebtedness (including Acquired Indebtedness), and the Company will not issue any shares of Disqualified Stock and will not permit any Restricted Subsidiary to issue any shares of Disqualified Stock or Preferred Stock;provided that the Company may incur Indebtedness (including Acquired Indebtedness) or issue shares of Disqualified Stock, and any Restricted Subsidiary may incur Indebtedness (including Acquired Indebtedness), issue shares of Disqualified Stock or issue shares of Preferred Stock, if the Fixed Charge Coverage Ratio on a consolidated basis for the Company’s and its Restricted Subsidiaries’ most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or Preferred Stock is issued would have been at least 2.00 to 1.00, determined on apro forma basis (including apro formaapplication of the net proceeds therefrom), as if the additional Indebtedness had been incurred, or the Disqualified Stock or Preferred Stock had been issued, as the case may be, and the application of the proceeds therefrom had occurred at the beginning of such four-quarter period;provided that the amount of Indebtedness (including Acquired Indebtedness), Disqualified Stock and Preferred Stock that may be incurred or issued, as applicable pursuant to the foregoing by Restricted Subsidiaries that are not Subsidiary Guarantors shall not exceed $75.0 million at any one time outstanding.

The foregoing limitations will not apply to any of the following items (collectively, “Permitted Debt”):

(a) Indebtedness incurred pursuant to the Revolving Credit Facility by the Company or any Restricted Subsidiary;provided that immediately after giving effect to any such incurrence, the aggregate principal amount of all Indebtedness incurred under this clause (a) and then outstanding does not exceed $250.0 millionless up to $50.0 million in the aggregate of all principal payments with respect to such Indebtedness made pursuant to the second paragraph under “Repurchase at Option of Holders—Asset Sales” or pursuant to the fourth paragraph under “Repurchase at Option of Holders—Transactions Involving MLPs and GPs”;

(b) Indebtedness incurred pursuant to the Term Loan Facility and the Asset Sale Bridge Term Loan Facility by the Company or any Restricted Subsidiary;provided that immediately after giving effect to any such incurrence, the aggregate principal amount of all Indebtedness incurred under this clause (b) and then outstanding does not exceed $1,950.0 millionless the sum of (x) all principal payments with respect to such Indebtedness made pursuant to the second paragraph under “Repurchase at Option of Holders—Asset Sales” with the first $700.0 million of the Net Proceeds from the North Texas Asset Sale and (y) up to $200.0 million in the aggregate of all other principal payments with respect to such Indebtedness made pursuant to the second paragraph under “Repurchase at Option of Holders—Asset Sales” or the fourth paragraph under “Repurchase at Option of Holders—Transactions Involving MLPs and GPs”;

(c) Indebtedness incurred pursuant to the Funded Synthetic Letter of Credit Facility by the Company or any Restricted Subsidiary;provided that immediately after giving effect to any such incurrence, the aggregate principal amount of all Indebtedness incurred under this clause (c) and then outstanding does not exceed $300.0 millionless up to $50.0 million in the aggregate of all principal payments with respect to such Indebtedness made pursuant to the second paragraph under “Repurchase at Option of Holders—Asset Sales” or the fourth paragraph under “Repurchase at Option of Holders—Transactions Involving MLPs and GPs”;

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(d) additional Indebtedness incurred by the Company or any Restricted Subsidiary under clauses (a), (b) or (c) above;provided that immediately after giving effect to such incurrence, the aggregate principal amount of all Indebtedness incurred under this clause (d) and then outstanding does not exceed the sum of $200.0 millionless up to $60.0 million in the aggregate of all principal payments with respect to such Indebtedness made pursuant to the second paragraph under “Repurchase at Option of Holders—Asset Sales” or the fourth paragraph under “Repurchase at Option of Holders—Transactions Involving MLPs and GPs”;

(e) the incurrence by the Company, Co-Issuer and any Subsidiary Guarantor of Indebtedness represented by the old notes (including any Subsidiary Guarantees thereof) and the new notes and related exchange guarantees to be issued in exchange for the old notes and the Subsidiary Guarantees pursuant to the Registration Rights Agreement (other than any Additional Notes);

(f) Existing Indebtedness (other than Indebtedness described in clauses (a), (b), (c), (d) and (e));

(g) Indebtedness (including Capitalized Lease Obligations), Disqualified Stock and Preferred Stock incurred by the Company or any of the Restricted Subsidiaries, to finance the development, construction, purchase, lease, repairs, additions or improvement of property (real or personal), equipment or other fixed or capital assets that are used or useful in a Similar Business, whether through the direct purchase of assets or the Capital Stock of any Person owning such assets (including any refinancing or replacement thereof);provided that the aggregate amount of Indebtedness, Disqualified Stock and Preferred Stock incurred pursuant to this clause (g) does not exceed the greater of (x) $75.0 million and (y) 3.0% of Total Assets at any one time outstanding;

(h) Indebtedness incurred by the Company or any Restricted Subsidiary constituting reimbursement obligations with respect to letters of credit issued in the ordinary course of business, including letters of credit in respect of workers’ compensation claims, or other Indebtedness with respect to reimbursement type obligations regarding workers’ compensation claims;provided that upon the drawing of such letters of credit or the incurrence of such Indebtedness, such obligations are reimbursed within 30 days following such drawing or incurrence;

(i) Indebtedness arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or a Subsidiary, other than guarantees of Indebtedness incurred by any Person acquiring all or any portion of such business, assets or Subsidiary for the purpose of financing such acquisition;provided that

(1) such Indebtedness is not reflected on the balance sheet of the Company or any Restricted Subsidiary (contingent obligations referred to in a footnote to financial statements and not otherwise reflected on the balance sheet will not be deemed to be reflected on such balance sheet for purposes of this clause (i)(1)) and

(2) the maximum assumable liability in respect of all such Indebtedness shall at no time exceed the gross proceeds including monkish proceeds (the fair market value of such noncash proceeds being measured at the time received and without giving effect to any subsequent changes in value) actually received by the Company and its Restricted Subsidiaries in connection with such disposition;

(j) Indebtedness of

(1) the Company to a Restricted Subsidiary (other than a GP or the general partner of a GP);provided that any such Indebtedness owing to a Restricted Subsidiary that is not a Subsidiary Guarantor is subordinated in right of payment to the notes;provided, further, that any subsequent issuance or transfer of any Capital Stock or any other event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such Indebtedness (except to the Company or another Restricted Subsidiary) shall be deemed, in each case, to be an incurrence of such Indebtedness and

(2) Indebtedness of a Restricted Subsidiary to the Company or another Restricted Subsidiary (other than a GP or the general partner of a GP);provided that if a Subsidiary Guarantor incurs such

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Indebtedness to a Restricted Subsidiary that is not a Subsidiary Guarantor, such Indebtedness is subordinated in right of payment to the Subsidiary Guarantee of such Subsidiary Guarantor;provided, further, that any subsequent issuance or transfer of Capital Stock or any other event that results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any subsequent transfer of any such Indebtedness (except to the Company or another Restricted Subsidiary) shall be deemed, in each case, to be an incurrence of such Indebtedness;

(k) shares of Preferred Stock of a Restricted Subsidiary issued to the Company or another Restricted Subsidiary;provided that any subsequent issuance or transfer of any Capital Stock or any other event which results in any such Restricted Subsidiary ceasing to be a Restricted Subsidiary or any other subsequent transfer of any such shares of Preferred Stock (except to the Company or another Restricted Subsidiary) shall be deemed in each case to be an issuance of such shares of Preferred Stock;

(l) Hedging Obligations (excluding Hedging Obligations entered into for speculative purposes) for the purpose of limiting: (A) interest rate risk with respect to any Indebtedness that is permitted by the terms of the Indenture to be outstanding, (B) exchange rate risk with respect to any currency exchange or (C) commodity pricing risk with respect to any commodity;

(m) obligations in respect of performance, bid, appeal and surety bonds and completion guarantees and similar obligations provided by the Company or any Restricted Subsidiary in the ordinary course of business;

(n) (x) any guarantee by the Company or a Restricted Subsidiary of Indebtedness or other Obligations of any Restricted Subsidiary, so long as the incurrence of such Indebtedness by such Restricted Subsidiary is permitted under the terms of the Indenture or (y) any guarantee by a Restricted Subsidiary of Indebtedness of the Company permitted to be incurred under the terms of the Indenture;provided that such guarantee is incurred in accordance with the covenant described below under “—Limitation on Guarantees of Indebtedness by Restricted Subsidiaries”;

(o) the incurrence by the Company or any Restricted Subsidiary of Indebtedness, Disqualified Stock or Preferred Stock that serves to extend, replace, refund, refinance, renew or defease any Indebtedness, Disqualified Stock or Preferred Stock incurred as permitted under the first paragraph of this covenant and clauses (e) and (f) above, this clause (o) and clauses (p) and (u)(ii) below or any Indebtedness, Disqualified Stock or Preferred Stock issued to so extend, replace, refund, refinance, renew or defease such Indebtedness, Disqualified Stock or Preferred Stock including additional Indebtedness, Disqualified Stock or Preferred Stock incurred to pay premiums and fees in connection therewith (the “Refinancing Indebtedness”) prior to its respective maturity;provided, however, that such Refinancing Indebtedness:

(1) has a Weighted Average Life to Maturity at the time such Refinancing Indebtedness is incurred which is notless than the remaining Weighted Average Life to Maturity of the Indebtedness, Disqualified Stock or Preferred Stock being extended, replaced, refunded, refinanced, renewed or defeased,

(2) to the extent such Refinancing Indebtedness extends, replaces, refunds, refinances, renews or defeases (i) Indebtedness subordinated to the notes or any Subsidiary Guarantee, such Refinancing Indebtedness is subordinated to the notes or such Subsidiary Guarantee at least to the same extent as the Indebtedness being extended, replaced, refunded, refinanced, renewed or defeased or (ii) Disqualified Stock or Preferred Stock, such Refinancing Indebtedness must be Disqualified Stock or Preferred Stock, respectively and

(3) shall not include

(x) Indebtedness, Disqualified Stock or Preferred Stock of a Subsidiary that is not a Subsidiary Guarantor that refinances Indebtedness, Disqualified Stock or Preferred Stock of the Company,

(y) Indebtedness, Disqualified Stock or Preferred Stock of a Subsidiary that is not a Subsidiary Guarantor that refinances Indebtedness, Disqualified Stock or Preferred Stock of a Subsidiary Guarantor or

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(z) Indebtedness, Disqualified Stock or Preferred Stock of the Company or a Restricted Subsidiary that refinances Indebtedness, Disqualified Stock or Preferred Stock of an Unrestricted Subsidiary;

(p) Indebtedness, Disqualified Stock or Preferred Stock (y) of the Company or any of its Restricted Subsidiaries incurred to finance the acquisition of any Person or assets or (z) of Persons that are acquired by the Company or any Restricted Subsidiary or merged into the Company or a Restricted Subsidiary in accordance with the terms of the Indenture;provided that either

(1) after giving effect to such acquisition or merger, either

(A) the Company would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first sentence of this covenant; or

(B) the Fixed Charge Coverage Ratio of the Company and its Restricted Subsidiaries on a consolidated basis is greater than immediately prior to such acquisition or merger; or

(2) such Indebtedness, Disqualified Stock or Preferred Stock (a) is not Secured Indebtedness and is Subordinated Indebtedness, (b) is not incurred while a Default exists and no Default shall result therefrom, (c) does not mature (and is not mandatorily redeemable in the case of Disqualified Stock or Preferred Stock) and does not require any payment of principal prior to the final maturity of the notes and (d) in the case of clause (z) above only, is not incurred in contemplation of such acquisition or merger;

(q) Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business;provided that such Indebtedness is extinguished within two Business Days of its incurrence;

(r) Indebtedness of the Company or any Restricted Subsidiary supported by a letter of credit issued pursuant to the Senior Credit Facilities, in a principal amount not in excess of the stated amount of such letter of credit;

(s) Indebtedness, Disqualified Stock or Preferred Stock of a Restricted Subsidiary incurred to finance or assumed in connection with an acquisition which, when aggregated with the principal amount of all other Indebtedness, Disqualified Stock and Preferred Stock incurred under this clause (s) and then outstanding (including any refinancing or replacement thereof), does not exceed $50.0 million (it being understood that any Indebtedness, Disqualified Stock and Preferred Stock incurred pursuant to this clause (s) shall cease to be deemed incurred or outstanding for purposes of this clause (s) but shall be deemed incurred pursuant to the first paragraph of this covenant from and after the first date on which the Company or such Restricted Subsidiary could have incurred such Indebtedness, Disqualified Stock or Preferred Stock under the first paragraph of this covenant without reliance on this clause (s));

(t) Indebtedness incurred by a Foreign Subsidiary which, when aggregated with the principal amount of all other Indebtedness incurred pursuant to this clause (t) and then outstanding, does not exceed 5.0% of Foreign Subsidiary Total Assets (it being understood that any Indebtedness, Disqualified Stock and Preferred Stock incurred pursuant to this clause (t) shall cease to be deemed incurred or outstanding for purposes of this clause (t) but shall be deemed incurred pursuant to the first paragraph of this covenant from and after the first date on which the Company or such Restricted Subsidiary could have incurred such Indebtedness, Disqualified Stock or Preferred Stock pursuant to the first paragraph of this covenant without reliance on this clause (t));

(u) Indebtedness, Disqualified Stock and Preferred Stock of the Company or any Restricted Subsidiary not otherwise permitted hereunder in an aggregate principal amount or liquidation preference, which, when aggregated with the principal amount and liquidation preference of all other Indebtedness, Disqualified Stock and Preferred Stock incurred pursuant to this clause (u) and then outstanding, does not at any one time outstanding exceed the sum of

(i) $125.0 million (it being understood that any Indebtedness, Disqualified Stock and Preferred Stock incurred pursuant to this clause (u)(i) shall cease to be deemed incurred or outstanding for

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purposes of this clause (u)(i) but shall be deemed incurred for purposes of the first paragraph of this covenant from and after the first date on which the Company or such Restricted Subsidiary could have incurred such Indebtedness, Disqualified Stock or Preferred Stock pursuant to the first paragraph of this covenant without reliance on this clause (u)(i));plus

(ii) 200% of the net cash proceeds received by the Company since after October 31, 2005 from the issue or sale of Equity Interests of the Company or cash contributed to the capital of the Company (in each case other than proceeds of Disqualified Stock or sales of Equity Interests to the Company or any of its Subsidiaries) as determined in accordance with clauses (c)(2) and (c)(3) of the first paragraph of the covenant described under “—Limitation on Restricted Payments” to the extent such net cash proceeds or cash have not been applied pursuant to such clauses to make Restricted Payments or to make other investments, payments or exchanges pursuant to the second paragraph of the covenant described under “—Limitation on Restricted Payments” or to make Permitted Investments (other than Permitted Investments specified in clauses (a) and (c) of the definition thereof);

(v) Indebtedness consisting of Indebtedness issued by the Company or any Restricted Subsidiary to current or former officers, directors and employees thereof, their respective estates, spouses or former spouses, in each case to finance the repurchase, retirement or other acquisition or retirement of Equity Interests of the Company or any direct or indirect parent company of the Company to the extent permitted pursuant to clause (4) of the second paragraph under “—Limitation on Restricted Payments”; and

(w) Indebtedness of the Company or a Restricted Subsidiary to a GP or a general partner of a GP, in each case that is a Restricted Subsidiary;provided that the principal amount of such Indebtedness may not exceed the actual cash loaned by such GP or such general partner, as applicable, to the Company or such Restricted Subsidiary (except to the extent that interest accrued thereon is added to the principal amount thereof) and such Indebtedness

(1) is not convertible into, or putable or exchangeable for, any other security other than a security that would satisfy the requirement of this clause (w);

(2) does not mature or become mandatorily redeemable, putable or subject to a purchase offer, pursuant to a sinking fund obligation or otherwise, or become redeemable at the option of the holder thereof, in whole or in part, in each case prior to the date that is 91 days after the notes are no longer outstanding (such 91st day being the “Permitted Date”),

(3) does not require or permit the payment of cash interest or any other payment of cash with respect to such Indebtedness until the Permitted Date; and

(4) is subordinated to the notes on the terms provided for in the Indenture, including a prohibition against enforcing any rights with respect to such Indebtedness prior to the Permitted Date;

provided that any subsequent issuance or transfer of Capital Stock (including a GP Equity Transfer) or any other event which results in any such GP or such general partner, as applicable, ceasing to be a Restricted Subsidiary or any subsequent transfer of any such Indebtedness (except to the Company or another Restricted Subsidiary) shall be deemed in each case to be an incurrence of such Indebtedness.

For purposes of determining compliance with this covenant, in the event that an item of Indebtedness, Disqualified Stock or Preferred Stock meets the criteria of more than one of the categories of Permitted Debt described in clauses (a) through (v) above or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company, in its sole discretion, will classify or reclassify or later divide, classify or reclassify such item of Indebtedness, Disqualified Stock or Preferred Stock (or any portion thereof) and will only be required to include the amount and type of such Indebtedness, Disqualified Stock or Preferred Stock in one or more of the above clauses;provided that all Indebtedness outstanding under the Senior Credit Facilities on October 31, 2005 will be deemed to have been incurred on such date in reliance on the exception in clauses (a), (b) and (c) of the definition of Permitted Debt.

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The accrual of interest, the accretion of accreted value and the payment of interest in the form of additional Indebtedness, Disqualified Stock or Preferred Stock will not be deemed to be an incurrence of Indebtedness, Disqualified Stock or Preferred Stock for purposes of this covenant.

For purposes of determining compliance with any U.S. dollar-denominated restriction on the incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency will be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was incurred, in the case of term debt, or first committed, in the case of revolving credit debt;provided that if such Indebtedness is incurred to extend, replace, refund, refinance, renew or defease other Indebtedness denominated in a foreign currency, and such extension, replacement, refunding, refinancing, renewal or defeasance would cause the applicable U.S. dollar denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such extension, replacement, refunding, refinancing, renewal or defeasance such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being extended, replaced, refunded, refinanced, renewed or defeased.

The principal amount of any Indebtedness incurred to extend, replace, refund, refinance, renew or defease other Indebtedness, if incurred in a different currency from the Indebtedness being extended, replaced, refunded, refinanced, renewed or defeased, shall be calculated based on the currency exchange rate applicable to the currencies in which such respective Indebtedness is denominated that is in effect on the date of such extension, replacement, refunding, refinancing, renewal or defeasance.

Liens

The Company will not, and will not permit the Co-Issuer or any of the Subsidiary Guarantors to, directly or indirectly, create, incur, assume or suffer to exist any Lien (except Permitted Liens) that secures obligations under any Indebtedness on any asset or property of the Company or any Subsidiary Guarantor now owned or hereafter acquired, or any income or profits therefrom, or assign or convey any right to receive income therefrom, unless:

(1) in the case of Liens securing Subordinated Indebtedness, the notes or the applicable Subsidiary Guarantee of a Subsidiary Guarantor, as the case may be, are secured by a Lien on such property or assets that is senior in priority to such Liens; and

(2) in all other cases, the notes or the applicable Subsidiary Guarantee of a Subsidiary Guarantor, as the case may be, are equally and ratably secured;

provided that any Lien that is granted to secure the notes under this covenant shall be discharged at the same time as the discharge of the Lien that gave rise to the obligation to so secure the notes.

Merger, Consolidation or Sale of All or Substantially All Assets

The Company may not consolidate or merge with or into or wind up into (whether or not the Company is the surviving entity), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to any Person unless:

(1) the Company is the surviving company or the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a Person organized or existing under the laws of the United States of America, any state thereof, the District of Columbia, or any territory thereof (the Company or such Person, as the case may be, being herein called the “Successor Company”);

(2) the Successor Company, if other than the Company, expressly assumes all the obligations of the Company under the Indenture and the notes pursuant to supplemental indentures or other documents or instruments in form reasonably satisfactory to the Trustee;

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(3) immediately after such transaction, no Default exists;

(4) immediately after givingpro formaeffect to such transaction, as if such transaction had occurred at the beginning of the applicable four-quarter period,

(A) the Successor Company would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first sentence of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” or

(B) the Fixed Charge Coverage Ratio for the Successor Company and the Restricted Subsidiaries on a consolidated basis would be greater than such ratio for the Company and the Restricted Subsidiaries immediately prior to such transaction;

(5) each Subsidiary Guarantor, unless it is the other party to the transactions described above, in which case clause (A)(2) of the second succeeding paragraph shall apply, shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person’s obligations under the Indenture and the notes;

(6) the Company shall have delivered to the Trustee an Officers’ Certificate and an opinion of counsel, each stating that such consolidation, merger or transfer and such supplemental indentures, if any, comply with the Indenture; and

(7) if the Successor Company will not be a corporation following any such merger, consolidation, winding up, sole assignment, transfer, lease, conveyance or other disposition, the Company shall have delivered to the Trustee an opinion of counsel to the effect that the Holders will not recognize income, gain or loss for Federal income tax purposes as a result of such transaction and will be subject to Federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such transaction had not occurred.

The Successor Company will succeed to, and be substituted for, the Company under the Indenture and the notes. Notwithstanding the foregoing clauses (3) and (4),

(a) any Restricted Subsidiary (other than the Co-Issuer) may consolidate with, merge into or transfer all or part of its properties and assets to the Company and

(b) the Company may merge with an Affiliate of the Company incorporated solely for the purpose of reincorporating the Company in another state of the United States of America or converting into a different form of business entity so long as the amount of Indebtedness of the Company and the Restricted Subsidiaries is not increased thereby.

Subject to certain limitations described in the Indenture governing release of a Subsidiary Guarantee upon the sale, disposition or transfer of a Subsidiary Guarantor, each Subsidiary Guarantor will not, and the Company will not permit any Subsidiary Guarantor to, consolidate or merge with or into or wind up into (whether or not such Subsidiary Guarantor is the surviving entity), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets in one or more related transactions to, any Person unless

(A) (1) such Subsidiary Guarantor is the surviving entity or the Person formed by or surviving any such consolidation or merger (if other than such Subsidiary Guarantor) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a corporation or other entity organized or existing under the laws of the United States of America, any state thereof, the District of Columbia, or any territory thereof (such Subsidiary Guarantor or such Person, as the case may be, being herein called the “Successor Person”);

(2) the Successor Person, if other than such Subsidiary Guarantor, expressly assumes all the obligations of such Subsidiary Guarantor under the Indenture and such Subsidiary Guarantor’s Subsidiary Guarantee, pursuant to supplemental indentures or other documents or instruments in form reasonably satisfactory to the Trustee;

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(3) immediately after such transaction, no Default exists; and

(4) the Company shall have delivered to the Trustee an Officers’ Certificate and an opinion of counsel, each stating that such consolidation, merger or transfer and such supplemental indentures, if any, comply with the Indenture; or

(B) the transaction is made in compliance with the covenant described under “Repurchase at the Option of Holders—Asset Sales” or “Repurchase at the Option of Holders—Transactions Involving MLPs and GPs”, as applicable.

Subject to certain limitations described in the Indenture, the Successor Person will succeed to, and be substituted for, such Subsidiary Guarantor under the Indenture and, such Subsidiary Guarantor’s Subsidiary Guarantee. Notwithstanding the foregoing, any Subsidiary Guarantor may merge into or transfer all or part of its properties and assets to another Subsidiary Guarantor or the Company.

The Co-Issuer may not, and the Company will not permit the Co-Issuer to, consolidate or merge with or into or wind up into (whether or not the Co-Issuer is the surviving corporation), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets in one or more related transactions, to any Person unless:

(1) the Co-Issuer is the surviving entity or the Person formed by or surviving any such consolidation or merger (if other than the Co-Issuer) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a corporation organized and existing under the laws of the United States of America, any state thereof or the District of Columbia, or any territory thereof (the Co-Issuer or such Person, as the case may be, being herein called, the “Successor Co-Issuer”);

(2) the Successor Co-Issuer, if other than the Co-Issuer, expressly assumes all the obligations of the Co-Issuer under the Indenture and the notes pursuant to supplemental indentures or other documents or instruments in form reasonably satisfactory to the Trustee;

(3) immediately after such transaction, no Default exists; and

(4) the Company shall have delivered to the Trustee an Officers’ Certificate and an opinion of counsel, each stating that such consolidation, merger or transfer and such supplemental indenture, if any, comply with the Indenture.

A Successor Co-Issuer will succeed to, and be substituted for, the Co-Issuer under the Indenture and the notes.

Notwithstanding the foregoing, the Acquisition will be permitted without compliance with this “Merger, Consolidation or Sale of All or Substantially All Assets” covenant.

For purposes of this covenant, the sale, lease, conveyance, assignment, transfer or other disposition of all or substantially all of the properties and assets of one or more Subsidiaries of the Company, which properties and assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties and assets of the Company and its Subsidiaries on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties and assets of the Company.

Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

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Transactions with Affiliates

The Company will not, and will not permit any Restricted Subsidiary to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of the Company (each of the foregoing, an “Affiliate Transaction”) involving aggregate payments or consideration in excess of $10.0 million, unless

(a) such Affiliate Transaction is on terms that are not materiallyless favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person and

(b) the Company delivers to the Trustee with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate payments or consideration in excess of $30.0 million, a Board Resolution adopted by the majority of the members of the Board of Directors of the Company approving such Affiliate Transaction and set forth in an Officers’ Certificate certifying that such Affiliate Transaction complies with clause (a) above.

The foregoing provisions will not apply to the following:

(1) Transactions between or among the Company and/or any of the Restricted Subsidiaries;

(2) Restricted Payments permitted by the provisions of the Indenture described above under the covenant “—Limitation on Restricted Payments” and the definition of “Permitted Investments”;

(3) the payment of (x) management, consulting, monitoring and advisory fees and related expenses to the Sponsor not to exceed $7.5 million in the aggregate per calendar year and (y) any termination or other fee payable to the Sponsor upon a change of control or initial public equity offering of the Company or any direct or indirect parent company thereof, which fees, in the case of this clause (y) only, are approved by a majority of the members of the Board of Directors of the Company in good faith;

(4) the payment of reasonable and customary fees paid to, and indemnities provided on behalf of, officers, directors, managers, employees or consultants of the Company, any of its direct or indirect parent companies or any Restricted Subsidiary;

(5) payments by the Company or any Restricted Subsidiary to the Sponsor and the Co-Investor for any financial advisory, financing, underwriting or placement services or in respect of other investment banking activities, including in connection with acquisitions or divestitures, which payments are approved by a majority of the members of the Board of Directors of the Company in good faith;

(6) transactions in which the Company or any Restricted Subsidiary, as the case may be, delivers to the Trustee a letter from an Independent Financial Advisor stating that such transaction is fair to the Company or such Restricted Subsidiary from a financial point of view or meets the requirements of clause (a) of the preceding paragraph;

(7) payments or loans (or cancellations of loans) to employees or consultants of the Company, any of its direct or indirect parent companies or any Restricted Subsidiary and employment agreements, stock option plans and other compensatory arrangements with such employees or consultants that are, in each case, approved by the Company in good faith, including the special bonus payments described under “Certain Relationships and Related Transactions” in this offering circular;

(8) any agreement, instrument or arrangement as in effect as of October 31, 2005, or any amendment thereto (so long as any such amendment is not disadvantageous to the Holders in any material respect as compared to the applicable agreement as in effect on October 31, 2005 as reasonably determined in good faith by the Company);

(9) the existence of, or the performance by the Company or any of the Restricted Subsidiaries of its obligations under the terms of, any stockholders agreement or its equivalent (including any registration

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rights agreement or purchase agreement related thereto) to which it is a party as of October 31, 2005 and any similar agreements which it may enter into thereafter;provided, however, that the existence of, or the performance by the Company or any Restricted Subsidiary of obligations under any future amendment to any such existing agreement or under any similar agreement entered into after October 31, 2005 shall only be permitted by this clause (9) to the extent that the terms of any such existing agreement together with all amendments thereto, taken as a whole, or new agreement are not otherwise more disadvantageous to the Holders in any material respect than the terms of the original agreement in effect on October 31, 2005 as reasonably determined in good faith by the Company;

(10) the Transactions and the payment of all fees and expenses related to the Transactions, in each case as disclosed in the Offering Circular;

(11) transactions with customers, clients, suppliers, or purchasers or sellers of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the Indenture that are fair to the Company and the Restricted Subsidiaries, in the reasonable determination of the Board of Directors or the senior management of the Company, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party;

(12) the issuance of Equity Interests (other than Disqualified Stock) of the Company to any Permitted Holder or to any director, manager, officer, employee or consultant of the Company or any direct or indirect parent company thereof;

(13) sales of accounts receivable, or participations therein, in connection with any Receivables Facility;

(14) investments by the Sponsor and the Co-Investor in securities of the Company or any of its Restricted Subsidiaries so long as (i) the investment is being offered generally to other investors on the same or more favorable terms and (ii) the investment constitutesless than 5.0% of the proposed or outstanding issue amount of such class of securities; and

(15) any Permitted MLP Transfer and any Permitted GP Transfer.

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary that is not a Subsidiary Guarantor to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any consensual encumbrance or consensual restriction on the ability of any such Restricted Subsidiary to:

(a) (1) pay dividends or make any other distributions to the Company or any Restricted Subsidiary on its Capital Stock or with respect to any other interest or participation in, or measured by, its profits, or

(2) pay any Indebtedness owed to the Company or any Restricted Subsidiary;

(b) make loans or advances to the Company or any Restricted Subsidiary; or

(c) sell, lease or transfer any of its properties or assets to the Company or any Restricted Subsidiary, except (in each case) for such encumbrances or restrictions existing under or by reason of:

(1) contractual encumbrances or restrictions in effect on October 31, 2005, including pursuant to the Senior Credit Facilities and the related documentation (including security documents and intercreditor agreements) and Hedging Obligations;

(2) the Indenture and the notes and the Subsidiary Guarantees of the notes issued thereunder;

(3) purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions of the nature discussed in clause (c) above on the property so acquired;

(4) applicable law or any applicable rule, regulation or order;

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(5) any agreement or other instrument of a Person acquired by the Company or any Restricted Subsidiary in existence at the time of such acquisition (but not created in connection therewith or in contemplation thereof), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired;

(6) contracts for the sale of assets, including customary restrictions with respect to a Subsidiary pursuant to an agreement that has been entered into for the sale or disposition of all or substantially all of the Capital Stock or assets of such Subsidiary;

(7) Secured Indebtedness otherwise permitted to be incurred pursuant to the covenants described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “—Liens” that limit the right of the debtor to dispose of the assets securing such Indebtedness;

(8) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(9) other Indebtedness, Disqualified Stock or Preferred Stock of Restricted Subsidiaries permitted to be incurred after October 31, 2005 pursuant to the provisions of the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(10) customary provisions in joint venture agreements, asset sale agreements, sale-lease back agreements and other similar agreements;

(11) customary provisions contained in leases and other agreements entered into in the ordinary course of business;

(12) restrictions in connection with any Receivables Facility that are, in the good faith determination of the Company, necessary or advisable to effect such Receivables Facility;

(13) any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by such Restricted Subsidiary pending such sale or other disposition;

(14) restrictions or conditions contained in any trading, netting, operating, construction, service, supply, purchase, sale or other agreement to which the Company or any of its Restricted Subsidiaries is a party entered into in the ordinary course of business;provided that such agreement prohibits the encumbrance of solely the property or assets of the Company or such Restricted Subsidiary that are the subject of such agreement, the payment rights arising thereunder and/or the proceeds thereof and does not extend to any other asset or property of the Company or such Restricted Subsidiary or the assets or property of any other Restricted Subsidiary; and

(15) any encumbrances or restrictions of the type referred to in clauses (a), (b) and (c) above imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in clauses (1) through (14) above;provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of the Company, not materially more restrictive with respect to such encumbrance and other restrictions than those prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing;provided,further, that with respect to contracts, instruments or obligations existing on October 31, 2005, any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are not materially more restrictive with respect to such encumbrances and other restrictions than those contained in such contracts, instruments or obligations as in effect on October 31, 2005.

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Limitation on Guarantees of Indebtedness by Restricted Subsidiaries

The Company will not permit any of its Wholly-Owned Subsidiaries that are Restricted Subsidiaries (and non-Wholly-Owned Subsidiaries if such non-Wholly-Owned Subsidiaries guarantee other capital markets debt securities), other than a Subsidiary Guarantor or a Foreign Subsidiary, to guarantee the payment of any Indebtedness of the Company or any other Subsidiary Guarantor unless:

(1) such Restricted Subsidiary within 30 days executes and delivers a supplemental indenture to the Indenture providing for a Subsidiary Guarantee by such Restricted Subsidiary, except that with respect to a guarantee of Indebtedness of the Company or any Subsidiary Guarantor that is by its express terms subordinated in right of payment to the notes or such Subsidiary Guarantor’s Subsidiary Guarantee, any such guarantee by such Restricted Subsidiary with respect to such Indebtedness shall be subordinated in right of payment to such Subsidiary Guarantee substantially to the same extent as such Indebtedness is subordinated to the notes;

(2) such Restricted Subsidiary waives and will not in any manner whatsoever claim or take the benefit or advantage of, any rights of reimbursement, indemnity or subrogation or any other rights against the Company or any other Restricted Subsidiary as a result of any payment by such Restricted Subsidiary under its Subsidiary Guarantee; and

(3) such Restricted Subsidiary shall deliver to the Trustee an opinion of counsel to the effect that:

(a) such Subsidiary Guarantee has been duly executed and authorized; and

(b) such Subsidiary Guarantee constitutes a valid, binding and enforceable obligation of such Restricted Subsidiary, except insofar as enforcement thereof may be limited by bankruptcy, insolvency or similar laws (including, without limitation, all laws relating to fraudulent transfers) and except insofar as enforcement thereof is subject to general principles of equity;

provided that this covenant shall not be applicable to any guarantee of any Restricted Subsidiary that existed at the time such Person became a Restricted Subsidiary and was not incurred in connection with, or in contemplation of such Person becoming a Restricted Subsidiary.

Limitation on Sale and Lease-Back Transactions

The Company will not, and will not permit any Restricted Subsidiary to, enter into any Sale and Lease-Back Transaction with respect to any property unless (i) the Company or such Restricted Subsidiary would be entitled to (A) incur additional Indebtedness in an amount equal to the Attributable Debt with respect to such Sale and Lease-Back Transaction pursuant to the covenant described under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and (B) create a Lien on such property securing such Attributable Debt under the definition of “Permitted Liens”; (ii) the consideration received by the Company or any Restricted Subsidiary in connection with such Sale and Lease-Back Transaction is at least equal to the fair market value (as determined in good faith by the Company) of such property; and (iii) the Company applies the proceeds of such transaction in compliance with the covenant described under “Repurchase at the Option of Holders—Asset Sales”.

Limitations on Co-Issuer

The Company will not cease to beneficially own (as defined in Rules 13d-3 and 13d-5 under the Exchange Act), directly or indirectly, 100% of the Voting Stock of the Co-Issuer. The Co-Issuer will be designated as a Restricted Subsidiary of the Company at all times and will not own any material assets or other property, other than Indebtedness or other obligations owing to the Co-Issuer by the Company and its Restricted Subsidiaries, or engage in any trade or conduct any business other than treasury, cash management, hedging and cash pooling activities and activities incidental thereto. The Co-Issuer will not incur any material liabilities or obligations other than its obligations pursuant to the notes or the indenture and other Indebtedness permitted to be incurred by the Co-Issuer under “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and

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Preferred Stock” and “—Liens” and liabilities and obligations pursuant to business activities permitted by this covenant. Notwithstanding anything to the contrary herein, the Co-Issuer may be a co-obligor or guarantor with respect to Indebtedness if the Company is an obligor of such Indebtedness and the net proceeds of such Indebtedness are received by the Company or one or more of the Company’s Subsidiary Guarantors.

The Company will not sell or otherwise dispose of any shares of Capital Stock of the Co-Issuer and will not permit the Co-Issuer, directly or indirectly, to sell or otherwise dispose of any shares of its Capital Stock.

Reports and Other Information

Whether or not required by the SEC, so long as any notes are outstanding, the Company will furnish to the Holders of notes or post on the Company Website (and furnish to the Trustee):

(1) within the time period specified in the SEC’s rules and regulations (as in effect on October 31, 2005) for non-accelerated filers with respect to Form 10-K and within 60 days from the end of the applicable fiscal quarter with respect to Form 10-Q, all quarterly and annual financial information that would be required to be contained in a filing by a non-accelerated filer with the SEC on Forms 10-Q and 10-K (or any successor or comparable forms) if the Company were required to file such forms, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and, with respect to the annual information only, a report on the annual financial statements by the Company’s certified independent accountants; and

(2) within 10 calendar days from any event that triggers the requirement for such filing under the SEC’s rules and regulations, all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports.

Notwithstanding anything to the contrary set forth herein (i) the obligations of the Company with respect to clauses (1) and (2) of the previous paragraph will not extend to (x) any information the provision of which is, in the reasonable judgment of the Company, unduly burdensome to the Company and, in lieu of such information, the Company will furnish information comparable to that included in the Offering Circular or (y) any information for historical periods covered by the financial information in this Offering Circular to the extent such information is not included in this Offering Circular,

(ii) with respect to any quarterly or annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q, 10-K or on Form 8-K with respect to any period, or event occurring, prior to the Company’s second quarter in fiscal year 2006, such information shall be comparable to the corresponding information included in the Offering Circular and (iii) with respect to the furnishing of reports pursuant to clause (2) of the preceding paragraph, prior to the beginning of the Company’s second quarter in fiscal year 2006, such information shall be filed within 15 calendar days from the event that triggers the requirement for such filing under the SEC’s rules and regulations.

Notwithstanding the foregoing, the Company shall not be required to include in any information furnished hereunder a management’s report on internal controls over financial reporting or an auditor’s attestation thereon unless the Company is required under the SEC’s rules and regulations to include such report and attestation in its filings with the SEC.

In addition, whether or not required by the SEC, the Company will (subject to the immediately preceding paragraph) make the information and reports referred to in clauses (1) and (2) of the first paragraph of this covenant available to securities analysts and prospective investors upon request. For purposes of this covenant, the term “Company Website” means the collection of web pages that may be accessed on the World Wide Web using the URL address http://www.targaresources.com or such other address as the Company may from time to time designate in writing to the Trustee.

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The Company has also agreed that, for so long as any old notes remain outstanding, it will furnish to Holders of old notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

In addition, if at any time any direct or indirect parent company of the Company becomes a guarantor of the notes (there being no obligation of such parent to do so), the reports, information and other documents required to be filed and furnished to the Holders pursuant to this covenant may, at the option of the Company, be filed by and be those of such parent rather than the Company;provided that the same is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent, on the one hand, and the information relating to the Company and its Restricted Subsidiaries on a standalone basis, on the other hand.

Notwithstanding the foregoing, such requirements shall be deemed satisfied prior to the commencement of the Registered Exchange Offer or the effectiveness of the Shelf Registration Statement by the filing with the SEC of the Exchange Offer Registration Statement and/or Shelf Registration Statement, and any amendments thereto, with such financial information that satisfies Regulation S-X of the Securities Act.

Events of Default and Remedies

The following events constitute Events of Default under the Indenture:

(1) default in payment when due and payable, upon redemption, acceleration or otherwise, of payments of principal of, or premium, if any, on the notes issued under the Indenture;

(2) default for 30 days or more in the payment when due of interest on or with respect to the notes issued under the Indenture;

(3) failure by the Company, the Co-Issuer or any Subsidiary Guarantor for 60 days after receipt of written notice given by the Trustee or the Holders of at least 30% in principal amount of the notes then outstanding and issued under the Indenture to comply with any of its other agreements in the Indenture or the notes;

(4) default under any mortgage, indenture or instrument under which there is issued or by which there is secured or evidenced any Indebtedness for money borrowed by the Company, the Co-Issuer or any Restricted Subsidiary or the payment of which is guaranteed by the Company, the Co-Issuer or any Restricted Subsidiary, other than Indebtedness owed to the Company, the Co-Issuer or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists or is created after the issuance of the notes, if both

(A) such default either

(i) results from the failure to pay any principal of such Indebtedness at its stated final maturity (after giving effect to any applicable grace periods) or

(ii) relates to an obligation other than the obligation to pay principal of any such Indebtedness at its stated final maturity and results in the holder or holders of such Indebtedness causing such Indebtedness to become due prior to its stated maturity and

(B) the principal amount of such Indebtedness, together with the principal amount of any other such Indebtedness in default for failure to pay principal at stated final maturity (after giving effect to any applicable grace periods), or the maturity of which has been so accelerated, aggregate $50.0 million or more at any one time outstanding;

(5) failure by the Company, the Co-Issuer or any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) to pay final judgments aggregating in excess of $50.0 million, which final judgments remain unpaid, undischarged and unstayed for a period of more than

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60 days after such judgment becomes final, and in the event such judgment is covered by insurance, an enforcement proceeding has been commenced by any creditor upon such judgment or decree which is not promptly stayed;

(6) certain events of bankruptcy or insolvency with respect to the Company, the Co-Issuer or any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary); or

(7) the Subsidiary Guarantee of any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) shall for any reason cease to be in full force and effect or be declared null and void or any responsible officer of any Subsidiary Guarantor that is a Significant Subsidiary (or the responsible officers of any group of Subsidiaries that together would constitute a Significant Subsidiary), as the case may be, denies that it has any further liability under its Subsidiary Guarantee or gives notice to such effect, other than by reason of the termination of the Indenture or the release of any such Subsidiary Guarantee in accordance with the Indenture.

If any Event of Default (other than of a type specified in clause (6) above) occurs and is continuing under the Indenture, the Trustee or the Holders of at least 30% in principal amount of the then outstanding notes issued under the Indenture may declare the principal, premium, if any, interest and any other monetary obligations on all the then outstanding notes issued under the Indenture to be due and payable immediately.

Upon the effectiveness of such declaration, such principal of and premium, if any, and interest on the notes will be due and payable immediately. Notwithstanding the foregoing, in the case of an Event of Default arising under clause (6) of the first paragraph of this section, all outstanding notes will become due and payable without further action or notice. The Indenture provides that the Trustee may withhold from Holders notice of any continuing Default, except a Default relating to the payment of principal of and premium, if any, and interest on the notes if it determines that withholding notice is in their interest. In addition, the Trustee will have no obligation to accelerate the notes if in the best judgment of the Trustee acceleration is not in the best interest of the Holders of such notes.

The Indenture provides that the Holders of a majority in aggregate principal amount of the then outstanding notes issued thereunder by notice to the Trustee may, on behalf of the Holders of all of such notes, waive any existing Default and its consequences under the Indenture, except a continuing Default in the payment of principal of and premium, if any, or interest on any such notes held by a non-consenting Holder. In the event of any Event of Default specified in clause (4) above, such Event of Default and all consequences thereof (excluding any resulting payment default) shall be annulled, waived and rescinded automatically and without any action by the Trustee or the Holders if, within 20 days after such Event of Default arose,

(x) the Indebtedness or guarantee that is the basis for such Event of Default has been discharged,

(y) the holders thereof have rescinded or waived the acceleration, notice or action (as the case may be) giving rise to such Event of Default or

(z) if the default that is the basis for such Event of Default has been cured.

Except to enforce the right to receive payments of principal of and premium, if any, and interest on the notes when due, no Holder may pursue any remedy with respect to the Indenture or the notes unless:

(1) such Holder has previously given the Trustee notice that an Event of Default is continuing;

(2) Holders of at least 30% in principal amount of the outstanding notes have requested the Trustee to pursue the remedy;

(3) such Holders have offered the Trustee reasonable security or indemnity against any loss, liability or expense;

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(4) the Trustee has not complied with such request within 60 days after the receipt thereof and the offer of security or indemnity; and

(5) Holders of a majority in principal amount of the outstanding notes have not given the Trustee a direction inconsistent with such request within such 60-day period.

The Indenture provides that we are required to deliver to the Trustee annually a statement regarding compliance with the Indenture, and we are required, within five Business Days, upon becoming aware of any Default, to deliver to the Trustee a statement specifying such Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of the Company, the Co-Issuer or any Subsidiary Guarantor shall have any liability for any obligations of the Company, the Co-Issuer or the Subsidiary Guarantors under the notes, the Subsidiary Guarantees and the Indenture or for any claim based on, in respect of, or by reason of such obligations or their creation;provided that the foregoing shall not limit any Subsidiary Guarantor’s obligations under its Subsidiary Guarantee. Each Holder by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. Such waiver may not be effective to waive liabilities under the Federal securities laws and it is the view of the SEC that such a waiver is against public policy.

Legal Defeasance and Covenant Defeasance

Most of the obligations of the Company, the Co-Issuer and the Subsidiary Guarantors under the Indenture will terminate and will be released upon payment in full of all of the notes issued under the Indenture. The Company and the Co-Issuer may, at their option and at any time, elect to have all of their obligations discharged with respect to the notes issued under the Indenture and have each Subsidiary Guarantor’s obligation discharged with respect to its Subsidiary Guarantee (“Legal Defeasance”) and cure all then existing Events of Default except for

(1) the rights of Holders of notes issued under the Indenture to receive payments in respect of the principal of, premium, if any, and interest on the notes when such payments are due solely out of the trust created pursuant to the Indenture,

(2) the Company’s and the Co-Issuer’s obligations with respect to the notes issued under the Indenture concerning issuing temporary notes, registration of such notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust,

(3) the rights, powers, trusts, duties and immunities of the Trustee, and the Company’s and the Co-Issuer’s obligations in connection therewith and

(4) the Legal Defeasance provisions of the Indenture.

In addition, the Company and the Co-Issuer may, at their option and at any time, elect to have their obligations and those of each Subsidiary Guarantor released with respect to certain covenants that are described in the Indenture (“Covenant Defeasance”) and thereafter any omission to comply with such obligations shall not constitute a Default with respect to the notes. In the event a Covenant Defeasance occurs, certain events (not including bankruptcy, receivership, rehabilitation and insolvency events pertaining to the Company or the Co-Issuer) described under “Events of Default and Remedies” will no longer constitute an Event of Default with respect to the notes.

In order to exercise either Legal Defeasance or Covenant Defeasance with respect to the notes issued under the Indenture:

(1) the Company and the Co-Issuer must irrevocably deposit with the Trustee, in trust, for the benefit of the Holders, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in such

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amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, and interest due on the notes issued under the Indenture on the stated maturity date or on the redemption date, as the case may be, of such principal, premium, if any, or interest on the notes;

(2) in the case of Legal Defeasance, the Company and the Co-Issuer shall have delivered to the Trustee an opinion of counsel in the United States of America reasonably acceptable to the Trustee confirming that, subject to customary assumptions and exclusions,

(A) the Company and the Co-Issuer have received from, or there has been published by, the United States of America Internal Revenue Service a ruling or

(B) since the original issuance of the notes, there has been a change in the applicable U.S. Federal income tax law,

in either case to the effect that, and based thereon such opinion of counsel in the United States of America shall confirm that, subject to customary assumptions and exclusions, the Holders will not recognize income, gain or loss for U.S. Federal income tax purposes as a result of such Legal Defeasance and will be subject to U.S. Federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Company and the Co-Issuer shall have delivered to the Trustee an opinion of counsel in the United States of America reasonably acceptable to the Trustee confirming that, subject to customary assumptions and exclusions, the Holders will not recognize income, gain or loss for U.S. Federal income tax purposes as a result of such Covenant Defeasance and will be subject to such tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default (other than that resulting from borrowing funds to be applied to make such deposit and the granting of Liens in connection therewith) shall have occurred and be continuing on the date of such deposit;

(5) such Legal Defeasance or Covenant Defeasance shall not result in a breach or violation of, or constitute a default under any of the Senior Credit Facilities or any other material agreement or instrument (other than the Indenture) to which, the Company, the Co-Issuer or any Subsidiary Guarantor is a party or by which the Company, the Co-Issuer or any Subsidiary Guarantor is bound;

(6) the Company and the Co-Issuer shall have delivered to the Trustee an opinion of counsel in the United States of America to the effect that, as of the date of such opinion and subject to customary assumptions and exclusions, following the deposit, the trust funds will not be subject to the effect of any applicable bankruptcy, insolvency, reorganization or similar laws affecting creditors’ rights generally under any applicable U.S. Federal or state law, and that the Trustee has a perfected security interest in such trust funds for the ratable benefit of the Holders;

(7) the Company and the Co-Issuer shall have delivered to the Trustee an Officers’ Certificate stating that the deposit was not made by the Company or the Co-Issuer with the intent of defeating, hindering, delaying or defrauding any creditors of the Company, the Co-Issuer or any Subsidiary Guarantor or others; and

(8) the Company and the Co-Issuer shall have delivered to the Trustee an Officers’ Certificate and an opinion of counsel in the United States of America (which opinion of counsel may be subject to customary assumptions and exclusions) each stating that all conditions precedent provided for or relating to the Legal

Defeasance or the Covenant Defeasance, as the case may be, have been complied with.

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Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when

(a) either (1) all such notes theretofore authenticated and delivered, except lost, stolen or destroyed notes which have been replaced or paid and notes for whose payment money has theretofore been deposited in trust, have been delivered to the Trustee for cancellation; or

(2) all such notes not theretofore delivered to such Trustee for cancellation have become due and payable by reason of the making of a notice of redemption or otherwise, will become due and payable within one year or are to be called for redemption within one year under arrangements satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Company and the Co-Issuer, the Company, the Co-Issuer or any Subsidiary Guarantor has irrevocably deposited or caused to be deposited with such Trustee as trust funds in trust solely for the benefit of the Holders, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in such amounts as will be sufficient without consideration of any reinvestment of interest to pay and discharge the entire indebtedness on such notes not theretofore delivered to the Trustee for cancellation for principal, premium, if any, and accrued interest to the date of maturity or redemption, as the case may be;

(b) no Default (other than that resulting from borrowing funds to be applied to make such deposit and the granting of Liens in connection therewith) with respect to the Indenture or the notes issued thereunder shall have occurred and be continuing on the date of such deposit or shall occur as a result of such deposit and such deposit will not result in a breach or violation of, or constitute a default under, the Senior Credit Facilities or any other agreement or instrument to which the Company, the Co-Issuer or any Subsidiary Guarantor is a party or by which the Company or any Subsidiary Guarantor is bound;

(c) the Company and the Co-Issuer have paid or caused to be paid all sums payable by it under the Indenture; and

(d) the Company and the Co-Issuer have delivered irrevocable instructions to the Trustee under the Indenture to apply the deposited money toward the payment of such notes at maturity or the redemption date, as the case may be.

In addition, the Company and the Co-Issuer must deliver an Officers’ Certificate and an opinion of counsel to the Trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Transfer and Exchange

A Holder may transfer or exchange notes in accordance with the Indenture. The Registrar and the Trustee may require a Holder, among other things, to furnish appropriate endorsements and transfer documents and the Company and the Co-Issuer may require a Holder to pay any taxes and fees required by law or permitted by the Indenture. The Company and the Co-Issuer are not required to transfer or exchange any note selected for redemption. Also, the Company and the Co-Issuer are not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

The registered Holder of a note will be treated as the owner of the note for all purposes.

Amendment, Supplement and Waiver

Except as provided in the next two succeeding paragraphs, the Indenture, any related Subsidiary Guarantee and the notes issued thereunder may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the notes then outstanding and issued under the Indenture, including consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes, and any existing Default or compliance with any provision of the Indenture or the notes issued thereunder may be waived with the consent

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of the Holders of a majority in principal amount of the then outstanding notes issued under the Indenture, other than notes beneficially owned by the Company or its Affiliates (including consents obtained in connection with a purchase of or tender offer or exchange offer for notes).

The Indenture provides that, without the consent of each Holder affected, an amendment or waiver may not, with respect to any notes issued under the Indenture and held by a non-consenting Holder:

(1) reduce the principal amount of notes whose Holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any such note or alter or waive the provisions with respect to the redemption of the notes (other than provisions relating to the covenants described above under “Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest on any note;

(4) waive a Default in the payment of principal of or premium, if any, or interest on the notes issued under the Indenture, except a rescission of acceleration of the notes by the Holders of at least a majority in aggregate principal amount of the notes then outstanding and a waiver of the payment default that resulted from such acceleration, or in respect of a covenant or provision contained in the Indenture or any Subsidiary Guarantee that cannot be amended or modified without the consent of all Holders;

(5) make any note payable in money other than that stated in the notes;

(6) make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of Holders to receive payments of principal of or premium, if any, or interest on the notes;

(7) make any change in the ranking of the notes that would adversely affect the Holders;

(8) modify the Subsidiary Guarantees of any Significant Subsidiary (or any group of Subsidiaries that together would constitute a Significant Subsidiary) in any manner adverse to the Holders;

(9) make any change in these amendment and waiver provisions; or

(10) impair the right of any Holder to receive payment of principal of, or interest on, such Holder’s notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such Holder’s notes.

Notwithstanding the foregoing, without the consent of any Holder, the Company, the Co-Issuer any Subsidiary Guarantor (with respect to a Subsidiary Guarantee or the Indenture to which it is a party) and the Trustee may amend or supplement the Indenture, any Subsidiary Guarantee or the notes:

(1) to cure any ambiguity, omission, mistake, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to comply with the covenant relating to mergers, consolidations and sales of assets and to provide for the assumption of the Company’s, the Co-Issuer’s or any Subsidiary Guarantor’s obligations to Holders in connection therewith;

(4) to make any change that would provide any additional rights or benefits to the Holders or that does not adversely affect the legal rights under the Indenture of any such Holder;

(5) to add covenants for the benefit of the Holders or to surrender any right or power conferred upon the Company or a Subsidiary Guarantor;

(6) to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

(7) to evidence and provide for the acceptance and appointment under the Indenture of a successor Trustee pursuant to the requirements thereof;

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(8) to provide for the issuance of exchange notes or private exchange notes, which are identical to exchange notes except that they are not freely transferable;

(9) to add a Subsidiary Guarantor or other guarantor under the Indenture;

(10) to conform the text of the Indenture, Subsidiary Guarantees or the notes to any provision of the “Description of the Notes” in the Offering Circular to the extent that such provision in the “Description of the Notes” was intended to be a verbatim recitation of a provision of the Indenture, the Subsidiary Guarantees or the notes; or

(11) to make any amendment to the provisions of the Indenture relating to the transfer and legending of notes;provided that (a) compliance with the Indenture as so amended would not result in notes being transferred in violation of the Securities Act or any applicable securities law and (b) such amendment does not materially and adversely affect the rights of Holders to transfer notes.

The consent of the Holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment.

Notices

Notices given by publication will be deemed given on the first date on which publication is made and notices given by first-class mail, postage prepaid, will be deemed given five calendar days after mailing.

Concerning the Trustee

The Indenture contains certain limitations on the rights of the Trustee, should it become a creditor of the Company or the Co-Issuer, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest while a default exists it must eliminate such conflict within 90 days, apply to the SEC for permission to continue or resign.

The Indenture provides that the Holders of a majority in principal amount of the outstanding notes issued thereunder have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The Indenture provides that in case an Event of Default shall occur (which shall not be cured), the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent person in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder, unless such Holder shall have offered to the Trustee security and indemnity satisfactory to it against any loss, liability or expense.

Governing Law

The laws of the State of New York govern the Indenture, the notes and any Subsidiary Guarantee.

Certain Definitions

Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full definition of all such terms, as well as any other capitalized terms used herein for which no definition is provided. For purposes of the Indenture, unless otherwise specifically indicated, (1) the term “consolidated” with respect to any Person refers to such Person consolidated with its Restricted Subsidiaries (other than Partially Owned Operating Subsidiaries and any Subsidiary thereof), and excludes from such consolidation any Unrestricted Subsidiary, Permitted MLP and Permitted GP as if such Unrestricted Subsidiary, Permitted MLP or Permitted GP were not an Affiliate of such Person and (2) the term “including” means “including, without limitation”.

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“Acquired Indebtedness” means, with respect to any specified Person,

(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Restricted Subsidiary of such specified Person, including Indebtedness incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person, and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“Acquisition” means the acquisition of Equity Interests contemplated by the PIPA.

“Additional Interest” means all liquidated damages then owing pursuant to the Registration Rights Agreement.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlling”, “controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise.

“Applicable Premium” means, with respect to any Note on any redemption date, the greater of:

(1) 1.0% of the principal amount of such Note; or

(2) the excess, if any, of:

(a) the present value at such redemption date of (i) the redemption price of such Note at November 1, 2009 (such redemption price being set forth in the table appearing above under “—Optional Redemption”),plus (ii) all required interest payments due on such Note through November 1, 2009 (excluding accrued but unpaid interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption dateplus 50 basis points; over

(b) the principal amount of such Note.

“Asset Sale��� means

(1) the sale, conveyance, transfer or other disposition, whether in a single transaction or a series of related transactions, of property or assets (including by way of a Sale and Lease-Back Transaction) of the Company or any Restricted Subsidiary (each referred to in this definition as a “disposition”); and

(2) the issuance or sale of Equity Interests of any Restricted Subsidiary, whether in a single transaction or a series of related transactions, in each case, other than:

(a) a disposition of cash, Cash Equivalents or Investment Grade Securities or obsolete or worn out equipment, vehicles or other similar assets in the ordinary course of business or any disposition of inventory or goods held for sale in the ordinary course of business;

(b) the disposition of all or substantially all of the assets of the Company in a manner permitted pursuant to the provisions described above under “Certain Covenants—Merger, Consolidation or Sale of All or Substantially All Assets” or any disposition that constitutes a Change of Control pursuant to the Indenture;

(c) the making of any Permitted Investment or the making of any Restricted Payment that is not prohibited by the covenant described under “Certain Covenants—Limitation on Restricted Payments”;

(d) any disposition of assets or issuance or sale of Equity Interests of any Restricted Subsidiary in any transaction or series of transactions with an aggregate fair market value ofless than $20.0 million;

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(e) any disposition of property or assets or issuance of securities by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary;

(f) to the extent allowable under Section 1031 of the Internal Revenue Code of 1986, any exchange of like property (excluding any boot thereon) for use in a Similar Business;

(g) the lease, assignment or sub-lease of any real or personal property in the ordinary course of business;

(h) any issuance or sale of Equity Interests in, or Indebtedness or other securities of, an Unrestricted Subsidiary;

(i) foreclosures on assets;

(j) sales of accounts receivable, or participations therein, in connection with any Receivables Facility;

(k) the unwinding of any Hedging Obligations; and

(l) a MLP Asset Transfer, MLP Equity Transfer or GP Equity Transfer.

“Asset Sale Bridge Term Loan Facility” means the asset sale credit facility provided under the Credit Agreement, entered into as of October 31, 2005, among the Company, the lenders party thereto in their capacity as lenders and Credit Suisse, as Administrative Agent, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, replacements, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that extend, replace, refund, refinance, renew or defease any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”).

“Attributable Debt” in respect of a Sale and Lease-Back Transaction means, as at the time of determination, the present value (discounted at the interest rate borne by the notes, compounded annually) of the total obligations of the lessee for rental payments during the remaining term of the lease included in such Sale and Lease-Back Transaction (including any period for which such lease has been extended);provided,however, that if such Sale and Lease-Back Transaction results in a Capitalized Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capitalized Lease Obligation”.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation;

(2) with respect to a partnership, the board of directors of the general partner of the partnership; and

(3) with respect to any other Person, the board or committee of such Person serving a similar function.

“Board Resolution” means with respect to the Company or the Co-Issuer, a duly adopted resolution of the Board of Directors of the Company or the Co-Issuer, as the case maybe, or any respective committee thereof.

“Business Day” means each day that is not a Legal Holiday.

“Capital Stock” means

(1) in the case of a corporation, corporate stock,

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock,

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(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited), and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

“Capitalized Lease Obligation” means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at such time be required to be capitalized and reflected as a liability on a balance sheet (excluding the footnotes thereto) in accordance with GAAP.

“Cash Equivalents” means

(1) United States of America dollars,

(2) (a) Canadian dollars; or

(b) in the case of any Foreign Subsidiary that is a Restricted Subsidiary, such local currencies held by it from time to time in the ordinary course of business,

(3) securities issued or directly and fully and unconditionally guaranteed or insured by the government of the United States of America or any agency or instrumentality thereof the securities of which are unconditionally guaranteed as a full faith and credit obligation of such government with maturities of 24 months orless from the date of acquisition,

(4) certificates of deposit, time deposits and eurodollar time deposits with maturities of one year orless from the date of acquisition, bankers’ acceptances with maturities not exceeding one year and overnight bank deposits, in each case with any commercial bank having capital and surplus in excess of $250.0 million,

(5) repurchase obligations for underlying securities of the types described in clauses (3) and (4) entered into with any financial institution meeting the qualifications specified in clause (4) above,

(6) commercial paper rated at least P-1 by Moody’s or at least A-1 by S&P and in each case maturing within 12 months after the date of issuance thereof,

(7) investment funds investing at least 95% of their assets in securities of the types described in clauses (1) through (6) above,

(8) readily marketable direct obligations issued by any state of the United States of America or any political subdivision thereof having one of the two highest rating categories obtainable from either Moody’s or S&P with maturities of 24 months orless from the date of acquisition and

(9) Indebtedness or Preferred Stock issued by Persons with a rating of “A” or higher from S&P or “A2” or higher from Moody’s with maturities of 12 months orless from the date of acquisition.

Notwithstanding the foregoing, Cash Equivalents shall include amounts denominated in one or more currencies other than those set forth in clauses (1) and (2) above;provided that such amounts are converted into the currencies set forth in clauses (1) and (2) above as promptly as practicable and in any event within ten Business Days following the receipt of such amounts.

“Change of Control” means the occurrence of any of the following:

(1) the sale, lease or transfer, in one or a series of related transactions, of all or substantially all of the assets of the Company and its Subsidiaries, taken as a whole, to any Person other than a Permitted Holder; or

(2) the Company becomes aware of (by way of a report or any other filing pursuant to Section 13(d) of the Exchange Act, proxy, vote, written notice or otherwise) the acquisition by any Person or group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), including any group acting for the purpose of acquiring, holding or disposing of securities (within the

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meaning of Rule 13d-5(b)(1) under the Exchange Act, or any successor provision), other than the Permitted Holders, in a single transaction or in a series of related transactions, by way of merger, consolidation or other business combination or purchase of beneficial ownership (within the meaning of Rule 13d-3 under the Exchange Act, or any successor provision) of 50% or more of the total voting power of the Voting Stock of the Company or any of its direct or indirect parent companies.

“Co-Investor” means Merrill Lynch Ventures L.P. 2001 and its Affiliates.

“Co-Issuer” means Targa Resources Finance Corporation, a Delaware corporation, and its successors.

“Company” has the meaning set forth in the first paragraph under “General”;provided that when used in the context of determining the fair market value of an asset or liability under the Indenture, “Company” shall, unless otherwise expressly stated, be deemed to mean the Board of Directors of the Company when the fair market value of such asset or liability is equal to or in excess of $50.0 million.

“Consolidated Current Liabilities” as of the date of determination means the aggregate amount of liabilities of the Company and its consolidated Restricted Subsidiaries which may properly be classified as current liabilities (including taxes accrued as estimated), on a consolidated basis, after eliminating (1) all intercompany items between the Company and any Restricted Subsidiary and (2) all current maturities of long-term Indebtedness, all as determined in accordance with GAAP consistently applied.

“Consolidated Depreciation and Amortization Expense” means with respect to any Person for any period, the total amount of depreciation and amortization expense, including the amortization of deferred financing fees and other related noncash charges of such Person and its Restricted Subsidiaries for such period on a consolidated basis and otherwise determined in accordance with GAAP.

“Consolidated Interest Expense” means, with respect to any Person for any period, the sum, without duplication, of:

(a) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, to the extent such expense was deducted in computing Consolidated Net Income (including (i) amortization of original issue discount resulting from the issuance of Indebtedness atless than par, (ii) all commissions, discounts and other fees and charges owed with respect to letters of credit or bankers’ acceptances including fees in connection with the Funded Synthetic Letter of Credit Facility or similar facility, (iii) noncash interest payments (but excluding any noncash interest expense attributable to the movement in the mark-to-market valuation of Hedging Obligations or other derivative instruments pursuant to GAAP), (iv) the interest component of Capitalized Lease Obligations and (v) net payments, if any, pursuant to interest rate Hedging Obligations with respect to Indebtedness, and excluding (A) Additional Interest, (B) amortization of deferred financing fees, debt issuance costs, commissions, fees and expenses, (C) any expensing of bridge, commitment and other financing fees (other than those described in clause (ii) above), (D) commissions, discounts, yield and other fees and charges (including any interest expense) related to any Receivables Facility) and (E) any redemption premiums paid in connection with the Transactions,plus

(b) consolidated capitalized interest of such Person and its Restricted Subsidiaries for such period, whether paid or accrued,less

(c) interest income for such period.

For purposes of this definition, interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by such Person to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP.

“Consolidated Leverage Ratio”, with respect to any Person as of any date of determination, means the ratio of (x) Consolidated Total Indebtedness of such Person as of the end of the most recent fiscal quarter for which internal

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financial statements are available immediately preceding the date on which such event for which such calculation is being made shall occur to (y) the aggregate amount of EBITDA of such Person for the period of the most recently ended four full consecutive fiscal quarters for which internal financial statements are available immediately preceding the date on which such event for which such calculation is being made shall occur, in each case with suchpro formaadjustments to Consolidated Total Indebtedness and EBITDA as are appropriate and consistent with thepro formaadjustment provisions set forth in the definition of Fixed Charge Coverage Ratio.

“Consolidated Net Income” means, with respect to any Person for any period, the aggregate of the Net Income, of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, and otherwise determined in accordance with GAAP;provided that, without duplication,

(1) any net after-tax extraordinary, non-recurring or unusual gains or losses (less all fees and expenses relating thereto) or expenses (including relating to severance, relocation, one-time compensation charges and the Transactions) shall be excluded,

(2) the Net Income for such period shall not include the cumulative effect of a change in accounting principles during such period, whether effected through a cumulative effect adjustment or a retroactive application in each case in accordance with GAAP,

(3) any net after-tax income (loss) from disposed or discontinued operations and any net after-tax gains or losses on disposal of disposed or discontinued operations shall be excluded,

(4) any net after-tax gains or losses (less all fees and expenses relating thereto) attributable to asset dispositions or the sale or other disposition of any Capital Stock of any Person other than in the ordinary course of business, as determined in good faith by the Company, shall be excluded,

(5) the Net Income for such period of any Person that is not a Subsidiary, or is an Unrestricted Subsidiary, a Permitted MLP or a Permitted GP, or that is accounted for by the equity method of accounting, shall be excluded;provided that Consolidated Net Income of the Company shall be increased by (a) the amount of dividends, distributions or other payments from any Person that is not a Subsidiary, any Unrestricted Subsidiary or any Person that is accounted for by the equity method of accounting (in each case, other than a Permitted MLP or Permitted GP or any Subsidiary thereof) and (b) the amount of any dividends, distributions or other payments from a Permitted MLP or a Permitted GP, in each case only to the extent made out of the operating surplus of such Permitted MLP or such Permitted GP, in each of clauses (a) and (b) above, that are actually paid in cash (or to the extent converted into cash) to the referent Person or a Restricted Subsidiary thereof in respect of such period (subject in the case of dividends, distributions or other payments made to a Restricted Subsidiary to the limitations contained in clause (6) below),

(6) solely for the purpose of determining the amount available for Restricted Payments under clause (c)(1) of the first paragraph of “Certain Covenants—Limitation on Restricted Payments”, the Net Income for such period of any Restricted Subsidiary (other than any Subsidiary Guarantor) shall be excluded if the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of its Net Income is not at the date of determination wholly permitted without any prior governmental approval (which has not been obtained) or, directly or indirectly, by the operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule, or governmental regulation applicable to that Restricted Subsidiary or its stockholders, unless such restriction with respect to the payment of dividends or similar distributions has been legally waived;provided that Consolidated Net Income of the Company will be increased by the amount of dividends or other distributions or other payments actually paid in cash (or to the extent converted into cash) to the Company or a Restricted Subsidiary thereof in respect of such period, to the extent not already included therein,

(7) any increase in amortization or depreciation or other noncash charges resulting from the application of purchase accounting in relation to the Transactions or any acquisition that is consummated after October 31, 2005, net of taxes, shall be excluded,

(8) any net after-tax income (loss) from the early extinguishment of Indebtedness or Hedging Obligations or other derivative instruments shall be excluded,

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(9) any impairment charge or asset write-off, in each case pursuant to GAAP, and the amortization of intangibles arising pursuant to GAAP shall be excluded, and

(10) any noncash compensation expense recorded from grants of stock appreciation or similar rights, stock options, restricted stock or other rights to officers, directors or employees shall be excluded.

Notwithstanding the foregoing, for the purpose of the covenant described under “Certain Covenants—Limitation on Restricted Payments” only (other than clause (c)(4) thereof), there shall be excluded from Consolidated Net Income any income arising from any sale or other disposition of Restricted Investments made by the Company and the Restricted Subsidiaries, any repurchases and redemptions of Restricted Investments from the Company and the Restricted Subsidiaries, any repayments of loans and advances that constitute Restricted Investments by the Company or any Restricted Subsidiary, any sale of the stock of an Unrestricted Subsidiary or any distribution or dividend from an Unrestricted Subsidiary, in each case only to the extent such amounts increase the amount of Restricted Payments permitted under such covenant pursuant to clause (c)(4) thereof.

“Consolidated Net Tangible Assets” as of any date of determination, means the total amount of assets (less accumulated depreciation and amortization, allowances for doubtful receivables, other applicable reserves and other properly deductible items) which would appear on a consolidated balance sheet of the Company and its consolidated Restricted Subsidiaries, determined on a consolidated basis in accordance with GAAP, and after giving effect to purchase accounting and after deducting therefrom Consolidated Current Liabilities and, to the extent otherwise included, the amounts of:

(1) minority interests in consolidated Subsidiaries held by Persons other than the Company or a Restricted Subsidiary;

(2) excess of cost over fair value of assets of businesses acquired, as determined in good faith by the Board of Directors;

(3) any revaluation or other write-up in book value of assets subsequent to October 31, 2005 as a result of a change in the method of valuation in accordance with GAAP consistently applied;

(4) unamortized debt discount and expenses and other unamortized deferred charges, goodwill, patents, trademarks, service marks, trade names, copyrights, licenses, organization or developmental expenses and other intangible items;

(5) treasury stock;

(6) cash set apart and held in a sinking or other analogous fund established for the purpose of redemption or other retirement of Capital Stock to the extent such obligation is not reflected in Consolidated Current Liabilities; and

(7) Investments in and assets of Unrestricted Subsidiaries, Permitted MLPs and Permitted GPs.

“Consolidated Total Indebtedness” means, as of any date of determination, an amount equal to the sum of (1) the aggregate amount of all outstanding Indebtedness of the Company and the Restricted Subsidiaries on a consolidated basis consisting of Indebtedness for borrowed money, Obligations in respect of Capitalized Lease Obligations, Attributable Debt in respect of Sale and Lease-Back Transactions and debt obligations evidenced by bonds, notes, debentures or similar instruments or letters of credit or bankers’ acceptances (and excluding (x) any undrawn letters of credit and (y) all obligations relating to Receivables Facilities), and (2) the aggregate amount of all outstanding Disqualified Stock of the Company and all Disqualified Stock and Preferred Stock of the Restricted Subsidiaries (excluding items eliminated in consolidation), with the amount of such Disqualified Stock and Preferred Stock, equal to the greater of their respective voluntary or involuntary liquidation preferences and Maximum Fixed Repurchase Prices, in each case determined on a consolidated basis in accordance with GAAP.

For purposes hereof, the “Maximum Fixed Repurchase Price” of any Disqualified Stock or Preferred Stock that does not have a fixed repurchase price shall be calculated in accordance with the terms of such Disqualified

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Stock or Preferred Stock as if such Disqualified Stock or Preferred Stock were purchased on any date on which Consolidated Total Indebtedness shall be required to be determined pursuant to the Indenture, and if such price is based upon, or measured by, the fair market value of such Disqualified Stock or Preferred Stock, such fair market value shall be determined reasonably and in good faith by the Company.

“Contingent Obligations” means, with respect to any Person, any obligation of such Person guaranteeing any leases, dividends or other obligations that do not constitute Indebtedness (the “primary obligations”) of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of such Person, whether or not contingent,

(1) to purchase any such primary obligation or any property constituting direct or indirect security therefor,

(2) to advance or supply funds

(A) for the purchase or payment of any such primary obligation or

(B) to maintain working capital or equity capital of the primary obligor or otherwise to maintain the net worth or solvency of the primary obligor, or

(3) to purchase property, securities or services primarily for the purpose of assuring the owner of any such primary obligation of the ability of the primary obligor to make payment of such primary obligation against loss in respect thereof.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Designated Noncash Consideration” means the fair market value of noncash consideration received by the Company or a Restricted Subsidiary in connection with an Asset Sale that is so designated as Designated Noncash Consideration pursuant to an Officers’ Certificate, setting forth the basis of such valuation, executed by an executive vice president and the principal financial officer of the Company,less the amount of cash or Cash Equivalents received in connection with a subsequent sale of such Designated Noncash Consideration.

“Designated Preferred Stock” means Preferred Stock of the Company or any parent company thereof (in each case other than Disqualified Stock) that is issued for cash (other than to a Restricted Subsidiary) and is so designated as Designated Preferred Stock, pursuant to an Officers’ Certificate executed by an executive vice president and the principal financial officer of the Company or the applicable parent company thereof, as the case may be, on the issuance date thereof, the cash proceeds of which are excluded from the calculation set forth in clause (c) of the first paragraph of the “Certain Covenants—Limitation on Restricted Payments” covenant.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which, by its terms, or by the terms of any security into which it is convertible or for which it is putable or exchangeable, or upon the happening of any event, matures or is mandatorily redeemable (other than solely for Capital Stock that is not Disqualified Stock), other than as a result of a change of control or asset sale, pursuant to a sinking fund obligation or otherwise, or is redeemable at the option of the holder thereof, other than as a result of a change of control or asset sale, in whole or in part, in each case prior to the date that is 91 days after the earlier of the maturity date of the notes and the date the notes are no longer outstanding;provided that if such Capital Stock is issued to any plan for the benefit of employees of the Company or its Subsidiaries or by any such plan to such employees, such Capital Stock shall not constitute Disqualified Stock solely because it may be required to be repurchased by the Company or its Subsidiaries in order to satisfy applicable statutory or regulatory obligations.

“Domestic Subsidiary” means, with respect to any Person, any Restricted Subsidiary of such Person other than (i) a Foreign Subsidiary or (ii) a Domestic Subsidiary of a Foreign Subsidiary, but, in each case, including any Subsidiary that guarantees or otherwise provides direct credit support for any indebtedness of the Company.

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“Downstream Business” means that portion of the business of the Company that is primarily engaged in fractionating, storing, terminalling, transporting, distributing and marketing natural gas liquids, including the following principal assets: Houston Area, Louisiana Area, NGL Marketing, and Wholesale Marketing and Commercial Transportation (each term, as defined in the PIPA).

“EBITDA” means, with respect to any Person for any period, the Consolidated Net Income of such Person for such period,

(1) increased by (without duplication):

(a) provision for taxes based on income or profits,plus franchise or similar taxes, of such Person for such period deducted in computing Consolidated Net Income,plus

(b) consolidated Fixed Charges of such Person for such period to the extent the same was deducted in computing Consolidated Net Income,plus

(c) Consolidated Depreciation and Amortization Expense of such Person for such period to the extent such depreciation and amortization were deducted in computing Consolidated Net Income,plus

(d) any expenses or charges related to any Equity Offering, Permitted Investment, acquisition, disposition, recapitalization or the incurrence of Indebtedness permitted to be incurred by the Indenture including a refinancing thereof (whether or not successful) and any amendment or modification to the terms of any such transactions, including such fees, expenses or charges related to the Transactions, including the offering of the notes and the Senior Credit Facilities, in each case, deducted in computing Consolidated Net Income,plus

(e) the amount of any restructuring charge or reserve deducted in such period in computing Consolidated Net Income, including any one-time costs incurred in connection with acquisitions after October 31, 2005,plus

(f) any write offs, write downs or other noncash charges reducing Consolidated Net Income for such period, excluding any such charge that represents an accrual or reserve for a cash expenditure for a future period,plus

(g) the amount of any minority interest expense deducted in calculating Consolidated Net Income,plus

(h) the amount of management, monitoring, consulting and advisory fees and related expenses paid (or any accruals related to such fees or related expenses) during such period to the Sponsor to the extent permitted under “Certain Covenants—Transactions with Affiliates”,plus

(i) the amount of net cost savings projected by the Company in good faith to be realized as a result of specified actions taken during such period (calculated on apro forma basis as though such cost savings had been realized on the first day of such period), net of the amount of actual benefits realized during such period from such actions;provided that (x) such cost savings are reasonably identifiable and factually supportable, (y) such actions are taken within 36 months after October 31, 2005 and (z) the aggregate amount of cost savings added pursuant to this clause (i) shall not exceed $35.0 million for any four consecutive quarter period (which adjustments may be incremental topro formaadjustments made pursuant to the second paragraph of the definition of “Fixed Charge Coverage Ratio”),plus

(j) any costs or expenses incurred by the Company or a Restricted Subsidiary pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement or any stock subscription or shareholder agreement, to the extent that such costs or expenses are funded with cash proceeds contributed to the capital of the Company or net cash proceeds of issuance of Equity Interests of the Company (other than Disqualified Stock that is Preferred Stock) in each case, solely to the extent that such cash proceeds are excluded from the calculation set forth in clause (c) of the first paragraph under “Certain Covenants—Limitation on Restricted Payments”;

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(2) decreased by (without duplication) noncash gains increasing Consolidated Net Income of such Person for such period, excluding any gains that represent the reversal of any accrual of, or cash reserve for, anticipated cash charges in any prior period (other than such cash charges that have been added back to Consolidated Net Income in calculating EBITDA in accordance with this definition); and

(3) decreased or increased, as applicable, by (without duplication):

(a) any net gain or loss resulting in such period from Hedging Obligations and the application of Statement of Financial Accounting Standards #133;

(b) any net gain or loss resulting in such period from currency translation gains or losses related to currency remeasurements of Indebtedness (including any net loss or gain resulting from hedge agreements for currency exchange risk); and

(c) the amount of gain or loss resulting in such period from a sale of receivables and related assets to a Receivables Subsidiary in connection with a Receivables Facility.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock, but excluding any debt security that is convertible into, or exchangeable for, Capital Stock.

“Equity Offering” means any underwritten primary public offering of common stock or Preferred Stock of the Company or any of its direct or indirect parent companies (excluding Disqualified Stock), other than

(a) public offerings with respect to the Company’s or any direct or indirect parent company’s common stock or Preferred Stock registered on Form S-4 or Form S-8;

(b) any such offering that constitutes an Excluded Contribution; and

(c) an issuance to any Subsidiary of the Company.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Excluded Contribution” means net cash proceeds, marketable securities or Qualified Proceeds received by the Company from

(a) contributions to its common equity capital, and

(b) the sale (other than to a Subsidiary of the Company or to any management equity plan or stock option plan or any other management or employee benefit plan or agreement of the Company) of Capital Stock (other than Disqualified Stock and Designated Preferred Stock) of the Company,

in each case designated as Excluded Contributions pursuant to an Officers’ Certificate executed by an executive vice president and the principal financial officer of the Company on the date such capital contributions are made or the date such Equity Interests are sold, as the case may be, which are excluded from the calculation set forth in clause (c) of the first paragraph under “Certain Covenants— Limitation on Restricted Payments”.

“Existing Indebtedness” means Indebtedness of the Company or the Restricted Subsidiaries in existence on October 31, 2005,plus interest accruing thereon.

“Extraordinary Distribution” means any dividends or distributions made by a Permitted MLP or Permitted GP other than any dividends or distributions out of the operating surplus of such Permitted MLP or Permitted GP.

“Fixed Charge Coverage Ratio” means, with respect to any Person for any period, the ratio of EBITDA of such Person for such period to the Fixed Charges of such Person for such period. In the event that the Company or any Restricted Subsidiary incurs, assumes, guarantees redeems, retires or extinguishes any Indebtedness (other

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than Indebtedness incurred under any revolving credit facility that has been permanently repaid and has not been replaced) or issues or redeems Disqualified Stock or Preferred Stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated but prior to or simultaneously with the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio shall be calculated givingpro formaeffect to such incurrence, assumption, guarantee, redemption, retirement or extinguishment of Indebtedness, or such issuance or redemption of Disqualified Stock or Preferred Stock, as if the same had occurred at the beginning of the applicable four-quarter period (the “reference period”).

For purposes of making the computation referred to above, Investments, acquisitions, dispositions, mergers, consolidations and disposed operations (as determined in accordance with GAAP) that have been made by the Company or any Restricted Subsidiary during the four-quarter reference period or subsequent to such reference period and on or prior to or simultaneously with the Calculation Date shall be calculated on apro forma basis assuming that all such Investments, acquisitions, dispositions, mergers, consolidations and disposed operations (and the change in any associated fixed charges and the change in EBITDA resulting therefrom) had occurred on the first day of the reference period. If since the beginning of such period any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) shall have made any Investment, acquisition, disposition, merger, consolidation or disposed operation that would have required adjustment pursuant to this definition, then the Fixed Charge Coverage Ratio shall be calculated givingpro formaeffect thereto for such period as if such Investment, acquisition, disposition, merger, consolidation or disposed operation had occurred at the beginning of the reference period.

For purposes of this definition, wheneverpro formaeffect is to be given to a transaction, thepro formacalculations shall be made in good faith by a responsible financial or accounting officer of the Company. If any Indebtedness bears a floating rate of interest and is being givenpro formaeffect, the interest on such Indebtedness shall be calculated as if the rate in effect on the Calculation Date had been the applicable rate for the entire period (taking into account any Hedging Obligations applicable to such Indebtedness). Interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by a responsible financial or accounting officer of the Company to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP. For purposes of making the computation referred to above, interest on any Indebtedness under a revolving credit facility computed on apro forma basis shall be computed based upon the average daily balance of such Indebtedness during the applicable period. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company may designate.

“Fixed Charges” means, with respect to any Person for any period, the sum of

(a) Consolidated Interest Expense of such Person for such period,

(b) all cash dividend payments (excluding items eliminated in consolidation) on any series of Preferred Stock made during such period, and

(c) all cash dividend payments (excluding items eliminated in consolidation) on any series of Disqualified Stock made during such period.

“Foreign Subsidiary” means, with respect to any Person, any Restricted Subsidiary of such Person that is not organized or existing under the laws of the United States of America, any state thereof, the District of Columbia, or any territory thereof.

“Foreign Subsidiary Total Assets” means the total amount of all assets of Foreign Subsidiaries of the Company and the Restricted Subsidiaries, determined on a consolidated basis in accordance with GAAP as shown on the most recent balance sheet of the Company.

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“Funded Synthetic Letter of Credit Facility” means the funded synthetic letter of credit facility provided under the Credit Agreement, entered into as of October 31, 2005, among the Company, the lenders party thereto in their capacity as lenders thereunder and Credit Suisse, as Administrative Agent, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, replacements, renewals, restatements, refundings or refinancings thereof (provided that any such extensions, replacements, renewals, refundings or refinancings are in the form of a synthetic letter of credit facility, a revolving credit facility or a similar credit facility entered into to support hedging or cash collateral obligations), including any such replacement, refunding or refinancing that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”).

“GAAP” means generally accepted accounting principles in the United States of America that were in effect on October 31, 2005.

“Government Securities” means securities that are

(a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or

(b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America,

which, in either case, are not callable or redeemable at the option of the issuers thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such Government Securities or a specific payment of principal of or interest on any such Government Securities held by such custodian for the account of the holder of such depository receipt;provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the Government Securities or the specific payment of principal of or interest on the Government Securities evidenced by such depository receipt.

“GP” means the Person that is the general partner of a MLP.

“GP Equity Transfer” means the sale, conveyance, transfer or other disposition of any Equity Interest in a MLP GP in connection with, or following, the initial public offering of a MLP GP.

“guarantee” means a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner (including letters of credit and reimbursement agreements in respect thereof), of all or any part of any Indebtedness or other obligations, and, when used as a verb, shall have a corresponding meaning.

“Hedging Obligations” means, with respect to any Person, the obligations of such Person under currency exchange, interest rate or commodity swap agreements, currency exchange, interest rate or commodity cap agreements and currency exchange, interest rate or commodity collar agreements and other agreements or arrangements, in each case designed to protect such Person against fluctuations in currency exchange, interest rates or commodity prices.

“Holder” means the Person in whose name a Note is registered on the registrar’s books.

“Indebtedness” means, with respect to any Person,

(a) any indebtedness (including principal and premium) of such Person, whether or not contingent

(1) in respect of borrowed money,

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(2) evidenced by bonds, notes, debentures or similar instruments or letters of credit or bankers’ acceptances (or, without double counting, reimbursement agreements in respect thereof),

(3) representing the balance deferred and unpaid of the purchase price of any property (including Capitalized Lease Obligations), except any such balance that constitutes a trade payable or similar obligation to a trade creditor, in each case accrued in the ordinary course of business, or

(4) representing any Hedging Obligations,

if and to the extent that any of the foregoing Indebtedness (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet (excluding the footnotes thereto) of such Person prepared in accordance with GAAP,

(b) to the extent not otherwise included, any obligation by such Person to be liable for, or to pay, as obligor, guarantor or otherwise, on the obligations of the type referred to in clause (a) of another Person (whether or not such items would appear upon the balance sheet of such obligor or guarantor), other than by endorsement of negotiable instruments for collection in the ordinary course of business,

(c) to the extent not otherwise included, the obligations of the type referred to in clause (a) of another Person secured by a Lien on any asset owned by such Person, whether or not such obligations are assumed by such Person and whether or not such obligations would appear upon the balance sheet of such Person;provided that the amount of such Indebtedness will be the lesser of the fair market value of such asset at such date of determination and the amount of Indebtedness so secured, and

(d) Attributable Debt in respect of Sale and Lease-Back Transactions;

provided, however, that notwithstanding the foregoing, Indebtedness will be deemed not to include (A) Contingent Obligations incurred in the ordinary course of business, (B) Obligations under or in respect of the Receivables Facilities and (C) Obligations of a GP of a Permitted MLP with respect to Indebtedness of such Permitted MLP arising by operation of law due to such GP’s position as a general partner of such Permitted MLP (or corresponding Obligations of any general partner of such GP arising by operation of law due to such entity’s position as a general partner of such GP);provided,however, that such Obligations or Indebtedness are non-recourse to the Company or any of its Restricted Subsidiaries (other than such GP and, if such GP is a limited partnership, the general partner of such GP,provided that (x) the sole business of such general partner of such GP is to act as the general partner of such GP and engage in activities ancillary thereto and (y) and such general partner of such GP owns no assets (other than (i) ownership interests in such GP or in the Permitted MLP of which such GP is the MLP GP or Capital Stock (other than Disqualified Stock) of the Company and Indebtedness owed to such general partner of such GP that is incurred pursuant to clause (w) of the second paragraph of the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”, (ii) temporarily holding assets to be transferred or distributed in connection with a Permitted MLP Transfer or a Permitted GP Transfer or distributions from a Permitted MLP or a Permitted GP and (iii) current assets sufficient to satisfy its ordinary course operating expenses)).

“Indenture” means the Senior Indenture, dated as of October 31, 2005, among the Company, the Co-Issuer as issuer, certain of its Subsidiaries, as guarantors and Wells Fargo Bank, National Association, as trustee.

“Independent Financial Advisor” means an accounting, appraisal, investment banking firm or consultant to Persons engaged in Similar Businesses of nationally recognized standing that is, in the good faith judgment of the Company, qualified to perform the task for which it has been engaged and that is independent of the Company and its Affiliates.

“Initial MLP Asset Transfer” means, at the option of the Company:

(1) one or more MLP Asset Transfers of (x) the assets constituting the Downstream Business or (y) all or a portion of the Equity Interests in one or more Persons that hold the Downstream Business;provided that no previous MLP Asset Transfer has occurred (except those described in this clause (1)); or

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(2) the initial MLP Asset Transfer and any subsequent MLP Asset Transfer to the applicable MLP of property or assets (including any Equity Interests) with respect to which the EBITDA attributable to such property or assets (treating such property or assets as if they were owned by a single Person) for the most recently ended four full fiscal quarters ending at least 45 days prior to the date of the most recent MLP Asset Transfer does not exceed $95.0 million in the aggregate;provided that any such MLP Asset Transfers do not include any of the Downstream Business;

in each case made in connection with an initial public offering of Equity Interests of such MLP (or, in the case of an Initial MLP Asset Transfer comprising more than one MLP Asset Transfers, the first such MLP Asset Transfer made in connection with such an initial public offering).

“Initial Purchasers” means Credit Suisse First Boston LLC, Merrill, Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co., Banc of America Securities LLC, Lehman Brothers Inc. and Wachovia Capital Markets, LLC.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s and BBB- (or the equivalent) by S&P, or an equivalent rating by any other Rating Agency.

“Investment Grade Securities” means:

(1) securities issued or directly and fully guaranteed or insured by the government of the United States of America or any agency or instrumentality thereof (other than Cash Equivalents),

(2) debt securities or debt instruments with a rating of BBB- or higher by S&P or Baa3 or higher by Moody’s or the equivalent of such rating by such rating organization, or, if no rating of S&P or Moody’s then exists, the equivalent of such rating by any other nationally recognized securities rating agency, but excluding any debt securities or instruments constituting loans or advances among the Company and its Subsidiaries,

(3) investments in any fund that invests exclusively in investments of the type described in clauses (1) and (2), which fund may also hold immaterial amounts of cash pending investment and/or distribution and

(4) corresponding instruments in countries other than the United States of America customarily utilized for high quality investments.

“Investments” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of loans (including guarantees), advances or capital contributions (including by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others, but excluding accounts receivable, trade credit, advances to customers, commission, travel and similar advances to officers and employees, in each case made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities issued by any other Person and investments that are required by GAAP to be classified on the balance sheet (excluding the footnotes) of such Person in the same manner as the other investments included in this definition to the extent such transactions involve the transfer of cash or other property. For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “Certain Covenants—Limitation on Restricted Payments”,

(1) “Investments” shall include the portion (proportionate to the Company’s equity interest in such Subsidiary) of the fair market value of the net assets of a Subsidiary of the Company at the time that such Subsidiary is designated an Unrestricted Subsidiary;provided that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company shall be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to

(x) the Company’s “Investment” in such Subsidiary at the time of such redesignation,less

(y) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the fair market value of the net assets of such Subsidiary at the time of such redesignation; and

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(2) any property transferred to or from an Unrestricted Subsidiary shall be valued at its fair market value at the time of such transfer, in each case as determined in good faith by the Company.

“Legal Holiday” means a Saturday, a Sunday or a day on which banking institutions are not required to be open in the State of New York.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction;provided that in no event shall an operating lease be deemed to constitute a Lien.

“Minimum Cash Consideration” with respect to the Initial MLP Asset Transfer means 40% of the fair market value of (a) the assets and property transferred or (b) in the case of a transfer of any Equity Interests of a Person, such Person at the time of such Initial MLP Asset Transfer (it being understood that, in the case of a transfer ofless than all of the Equity Interests of a Person, the fair market value of such Person shall be determined at the time of the first MLP Asset Transfer constituting part of such Initial MLP Asset Transfer (as if all the Equity Interests in such Person had been transferred at the time of such first MLP Asset Transfer and the Minimum Cash Consideration requirement shall have to be satisfied on that basis in connection with such first MLP Asset Transfer) and there shall be no Minimum Cash Consideration required for any subsequent transfer of Equity Interests of such Person constituting part of the same Initial MLP Asset Transfer) (in each of the foregoing clauses (a) and (b), assuming such assets or Person, as applicable, operate as a going concern);provided that up to 50% of the Minimum Cash Consideration may consist of Equity Interests in the applicable MLP so long as such Equity Interests are converted into or exchanged for, within 365 days of the Initial MLP Asset Transfer, cash equal to at least the fair market value of such Equity Interests on the date of the Initial MLP Asset Transfer. For purposes of this definition, (x) with respect to any assets, property or Person constituting part of the Downstream Business subject to such Initial MLP Asset Transfer, the fair market value thereof shall be determined in good faith by the Company based on values that could be obtained in arms’ length transactions, but in no event shall such fair market value be lower than an amount equal to the product of (a) the EBITDA (calculated, without giving effect to clause (5) of the definition of “Consolidated Net Income”, to include thepro rata share of the EBITDA of any Unrestricted Subsidiary included in such Downstream Business) attributable to such Downstream Business for the four fiscal quarter period most recently ended prior to the date of the Initial MLP Asset Transfer for which internal financial statements are available as of such date (as set forth in a certificate of the chief financial officer of the Company delivered to the Trustee) and (B) 8.5 (provided,however that, if the Company determines that such fair market value is lower than such minimum amount, the fair market value of such assets, property or Person constituting part of the Downstream Business subject to such Initial MLP Asset Transfer shall be determined by an Independent Financial Advisor) and (y) with respect to any other assets, property or Equity Interests of a Person constituting the subject of such Initial MLP Asset Transfer, the fair market value of such assets, property or Person, as applicable, shall be determined by an Independent Financial Advisor.

“MLP” means any master limited partnership.

“MLP Asset Transfer” means the direct or indirect sale, conveyance, transfer or other disposition of property or assets (including any Equity Interests of any Person) by the Company or any Restricted Subsidiary to one or more MLPs or MLP Subsidiaries.

“MLP Equity Transfer” means the sale, conveyance, transfer or other disposition of any Equity Interest in a MLP.

“MLP GP” means a GP that is a general partner of a Permitted MLP.

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“MLP Subsidiary” means each Subsidiary of a MLP.

“Moody’s” means Moody’s Investors Service, Inc. and any successor to its rating agency business.

“Net Income” means, with respect to any Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of Preferred Stock dividends.

“Net Proceeds” means the aggregate cash proceeds received by the Company or any Restricted Subsidiary in respect of any Asset Sale, Permitted MLP Transfer, Permitted GP Transfer or Extraordinary Distribution, including any cash received upon the sale or other disposition of any Designated Noncash Consideration received in any Asset Sale, net of the direct costs relating to such Asset Sale, Permitted MLP Transfer or Permitted GP Transfer and the sale or disposition of such Designated Noncash Consideration, including legal, accounting and investment banking fees, and brokerage and sales commissions, any relocation expenses incurred as a result thereof, taxes paid or payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements), amounts required to be applied to the repayment of principal, premium, if any, and interest on Indebtedness required (other than by the second paragraph of “Repurchase at the Option of Holders—Asset Sales” and other than by the fourth paragraph of “Repurchase at the Option of Holders—Transactions Involving MLPs and GPs”) to be paid as a result of such transaction and, in the case of an Asset Sale, Permitted MLP Transfer or Permitted GP Transfer, any deduction of appropriate amounts to be provided by the Company or a Restricted Subsidiary as a reserve in accordance with GAAP against any liabilities associated with the asset disposed of in such transaction and retained by the Company or a Restricted Subsidiary after such sale or other disposition thereof, including pension and other post-employment benefit liabilities and liabilities related to environmental matters or against any indemnification obligations associated with such transaction.

“North Texas Asset Sale” means the Asset Sale by the Company of the North Texas Assets as contemplated and described in the Offering Circular.

“North Texas Assets” means (a) the Chico natural gas processing plant, (b) the Shackelford natural gas processing plant and (c) the associated gathering system connected to both plants, in each case acquired by the Company from Dynegy Midstream Services, Limited Partnership pursuant to the PIPA.

“Obligations” means any principal (including reimbursement obligations with respect to letters of credit whether or not drawn), interest (including, to the extent legally permitted, all interest accrued thereon after the commencement of any insolvency or liquidation proceeding at the rate, including any applicable post-default rate, specified in the applicable agreement), premium (if any), guarantees of payment, fees, indemnifications, reimbursements, expenses, damages and other liabilities payable under the documentation governing any Indebtedness;provided that Obligations with respect to the notes shall not include fees or indemnification in favor of the Trustee and any other third parties other than the Holders.

“Offering Circular” means the Offering Circular dated October 18, 2005 with respect to the offering of the old notes.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the Chief Financial Officer, the President, any Executive Vice President, Senior Vice President or Vice President, the Treasurer or the Secretary of the Company or the Co-Issuer.

“Officers’ Certificate” means a certificate signed on behalf of the Company or the Co-Issuer by two Officers of the Company or the Co-Issuer, as the case may be, one of whom must be the principal executive officer, the principal financial officer, the treasurer or the principal accounting officer of the Company or the Co-Issuer, as the case may be, that meets the requirements set forth in the Indenture.

“Partially Owned Operating Company” means any Person that (i) is transferred to a MLP or a MLP Subsidiary in connection with a Permitted MLP Transfer and (ii) holds operating assets and as to which the Company or any Restricted Subsidiary continues to own Equity Interests.

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“Permitted Asset Swap” means the concurrent purchase and sale or exchange of Related Business Assets or a combination of Related Business Assets and cash or Cash Equivalents between the Company or any of its Restricted Subsidiaries and another Person that is not the Company or any of its Restricted Subsidiaries;provided that any cash or Cash Equivalents received must be applied in accordance with the covenant described under “Repurchase at the Option of Holders—Asset Sales”.

“Permitted GP” means any MLP GP as to which a Permitted GP Transfer has occurred, including any successor Person to such MLP GP.

“Permitted Holders” means each of the Sponsor, the Co-Investor and members of management of the Company (or its direct parent) who were holders of Equity Interests of the Company (or any of its direct or indirect parent companies) on October 31, 2005 and any group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision) of which any of the foregoing are members;provided that, in the case of such group and without giving effect to the existence of such group or any other group, such Sponsor, the Co-Investor and such members of management, collectively, have beneficial ownership of more than 50% of the total voting power of the Voting Stock of the Company or any of its direct or indirect parent companies. Any Person or group whose acquisition of beneficial ownership constitutes a Change of Control in respect of which a Change of Control Offer is made in accordance with the requirements of the Indenture will thereafter, together with its Affiliates, constitute an additional Permitted Holder.

“Permitted Investments” means:

(a) any Investment in the Company or any Restricted Subsidiary (other than a Partially Owned Operating Company);

(b) any Investment in cash and Cash Equivalents or Investment Grade Securities;

(c) (i) any Investment by the Company or any Restricted Subsidiary of the Company in a Person that is engaged in a Similar Business if as a result of such Investment

(1) such Person becomes a Restricted Subsidiary of the Company or

(2) such Person, in one transaction or a series of related transactions, is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company and

(ii) any Investment held by such Person;

(d) any Investment in securities or other assets not constituting cash, Cash Equivalents or Investment Grade Securities received in connection with (i) an Asset Sale or Permitted MLP Transfer made pursuant to the provisions of the covenants described under “Repurchase at the Option of Holders—Asset Sales” and “—Transactions Involving MLPs and GPs” or (ii) any other disposition of assets (other than a Permitted MLP Transfer or Permitted GP Transfer) not constituting an Asset Sale;

(e) any Investment existing on October 31, 2005 or made pursuant to legally binding written commitments in existence on October 31, 2005;

(f) loans and advances to, and guarantees of Indebtedness of, employees not in excess of $10.0 million outstanding at any one time, in the aggregate;

(g) any Investment acquired by the Company or any Restricted Subsidiary

(1) in exchange for any other Investment or accounts receivable held by the Company or any such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the Person in which such other Investment is made or which is the obligor with respect to such accounts receivable or

(2) as a result of a foreclosure by the Company or any Restricted Subsidiary with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;

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(h) Hedging Obligations permitted under clause (l) of the covenant described in “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(i) loans and advances to officers, directors and employees for business-related travel expenses, moving expenses and other similar expenses, in each case incurred in the ordinary course of business or consistent with past practice or to fund such Person’s purchase of Equity Interests of the Company or any direct or any indirect parent company thereof under compensation plans approved by the Board of Directors of the Company in good faith;

(j) Investments the payment for which consists of Equity Interests of the Company or any of its direct or indirect parent companies (exclusive of Disqualified Stock);provided that such Equity Interests will not increase the amount available for Restricted Payments under clause (c) of the first paragraph under the covenant described in “Certain Covenants—Limitation on Restricted Payments”;

(k) guarantees of Indebtedness permitted under the covenant described in “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and performance guarantees in the ordinary course of business;

(l) any transaction to the extent it constitutes an investment that is permitted and made in accordance with the provisions of the second paragraph of the covenant described under “Certain Covenants—Transactions with Affiliates” (except transactions described in clauses (2), (6) and (11) of such paragraph);

(m) Investments consisting of purchases and acquisitions of inventory, supplies, material or equipment or the licensing or contribution of intellectual property pursuant to joint marketing arrangements with other Persons;

(n) Investments relating to a Receivables Facility;provided that in the case of Receivables Facilities established after October 31, 2005, such Investments are necessary or advisable (in the good faith determination of the Company) to effect such Receivables Facility;

(o) additional Investments having an aggregate fair market value, taken together with all other Investments made pursuant to this clause (o) that are at that time outstanding, not to exceed the greater of (x) $125.0 million and (y) 5.0% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value); and

(p) any Investments in a Permitted MLP or a GP;provided that such Investment results from a Permitted MLP Transfer that is a MLP Asset Transfer or a Permitted GP Transfer.

“Permitted Liens” means, with respect to any Person:

(1) Liens to secure Indebtedness incurred under clauses (a), (b), (c), (d) of the second paragraph of the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and any related Obligations;

(2) pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws or similar legislation, or good faith deposits, prepayments or cash pledges to secure bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure public or statutory obligations of such Person or deposits of cash or U.S. government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import duties or for the payment of rent, in each case incurred in the ordinary course of business;

(3) Liens imposed by law, such as landlords’, carriers’, warehousemens’, mechanics’, materialmens’, repairmens’, construction contractors’ Liens and other similar Liens, in each case, for sums not yet overdue for a period of more than 30 days or being contested in good faith by appropriate proceedings or other Liens arising out of judgments or awards against such Person with respect to which such Person shall then be proceeding with an appeal or other proceedings for review if adequate reserves with respect thereto are maintained on the books of such Person in accordance with GAAP;

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(4) Liens for taxes, assessments or other governmental charges or claims not yet overdue for a period more of than 30 days or payable or subject to penalties for nonpayment or which are being contested in good faith by appropriate proceedings diligently conducted if adequate reserves with respect thereto are maintained on the books of such Person in accordance with GAAP;

(5) Liens in favor of issuers of performance and surety bonds or bid bonds or with respect to other regulatory requirements or letters of credit issued pursuant to the request of and for the account of such Person in the ordinary course of its business;

(6) minor survey exceptions, minor encumbrances, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning or other restrictions as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties, in each case, which were not incurred in connection with Indebtedness and which do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of such Person;

(7) Liens existing on October 31, 2005;

(8) Liens on property or shares of stock of a Person at the time such Person becomes a Subsidiary;provided that such Liens are not created or incurred in connection with, or in contemplation of, such other Person becoming such a Subsidiary;provided,further, that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary;

(9) Liens on property at the time the Company or a Restricted Subsidiary acquired the property, including any acquisition by means of a merger or consolidation with or into the Company or any Restricted Subsidiary;provided that such Liens are not created or incurred in connection with, or in contemplation of, such acquisition;provided,further, that the Liens may not extend to any other property owned by the Company or any Restricted Subsidiary;

(10) Liens securing Indebtedness or other obligations of a Restricted Subsidiary owing to the Company or another Restricted Subsidiary permitted to be incurred in accordance with the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;

(11) Liens on specific items of inventory or other goods and proceeds of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(12) leases and subleases granted to others in the ordinary course of business which do not materially interfere with the ordinary conduct of the business of the Company or any of the Restricted Subsidiaries and do not secure any Indebtedness;

(13) Liens arising from financing statement filings under the Uniform Commercial Code or similar state laws regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(14) Liens in favor of the Company or any Subsidiary Guarantor;

(15) Liens on inventory or equipment of the Company or any Restricted Subsidiary granted in the ordinary course of business to the Company’s client at which such inventory or equipment is located;

(16) Liens on accounts receivable and related assets incurred in connection with a Receivables Facility;

(17) Liens to secure any refinancing, refunding, extension, renewal or replacement (or successive refinancing, refunding, extensions, renewals or replacements) as a whole, or in part, of any Indebtedness secured by any Lien referred to in the foregoing clauses (7), (8) and (9) and the following clause (18);provided that (x) such new Lien shall be limited to all or part of the same property that secured the original Lien (plus improvements on such property), and (y) the Indebtedness secured by such Lien at such time is not increased to any amount greater than the sum of (A) the outstanding principal amount or, if greater, committed amount of the Indebtedness described under clauses (7), (8), (9) and the following clause (18) at

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the time the original Lien became a Permitted Lien under the Indenture, and (B) an amount necessary to pay any fees and expenses, including premiums, related to such refinancing, refunding, extension, renewal or replacement;

(18) Liens securing Indebtedness permitted to be incurred pursuant to clauses (g), (l), (s), (t) and (u)(i) of the second paragraph under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;provided that (i) Liens securing Indebtedness permitted to be incurred pursuant to clause (s) are solely on acquired property or the assets of the acquired entity, as the case may be, and (ii) Liens securing Indebtedness permitted to be incurred pursuant to clause (t) extend only to the assets of Foreign Subsidiaries;

(19) deposits in the ordinary course of business to secure liability to insurance carriers;

(20) Liens securing judgments for the payment of money not constituting an Event of Default under clause (5) under the caption “Events of Default and Remedies”, so long as such Liens are adequately bonded and any appropriate legal proceedings that may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(21) Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods in the ordinary course of business;

(22) Liens (i) of a collection bank arising under Section 4-210 of the Uniform Commercial Code on items in the course of collection, (ii) attaching to commodity trading accounts or other commodity brokerage accounts incurred in the ordinary course of business and (iii) in favor of banking institutions arising as a matter of law encumbering deposits (including the right of set-off) and which are within the general parameters customary in the banking industry;

(23) Liens that are contractual rights of set-off (i) relating to the establishment of depository relations with banks not given in connection with the issuance of Indebtedness, (ii) relating to pooled deposit or sweep accounts of the Company or any of its Restricted Subsidiaries to permit satisfaction of overdraft or similar obligations incurred in the ordinary course of business of the Company and its Restricted Subsidiaries or (iii) relating to purchase orders and other agreements entered into with customers of the Company or any of its Restricted Subsidiaries in the ordinary course of business;

(24) other Liens securing obligations incurred in the ordinary course of business which obligations do not exceed $35.0 million at any one time outstanding;

(25) from and after the date that the notes have Investment Grade Ratings from both Rating Agencies, Liens securing Indebtedness in an aggregate principal amount which, together with the aggregate outstanding principal amount of all other Indebtedness secured by Liens pursuant to this clause (25) and pursuant to clauses (1), (8), (9) and (24) above and clause (28) below, does not exceed 15% of Consolidated Net Tangible Assets;

(26) Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to commodity trading accounts or other brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

(27) Liens deemed to exist in connection with Investments in repurchase agreements permitted under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”;provided that such Liens do not extend to any assets other than those assets that are the subject of such repurchase agreement; and

(28) Liens incurred in respect of any Indebtedness permitted to be incurred pursuant to the covenant described under “Certain Covenants—Limitation on Incurrence of Indebtedness of Issuance of Disqualified Stock and Preferred Stock”;provided that, at the time of incurrence and after givingpro formaeffect thereto, the Secured Debt Ratio would be no greater than 4.00:1.00.

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“Permitted MLP” means any MLP to which the Company or a Restricted Subsidiary shall have made a Permitted MLP Transfer either directly to such MLP or to a Subsidiary of such MLP, including any successor Person to such MLP.

“Permitted MLP Investment” means an investment in (1) any one or more businesses;provided that such investment in any business is in the form of the acquisition of Capital Stock and results in the Company or any Restricted Subsidiary owning an amount of the Capital Stock of such business such that it constitutes a Restricted Subsidiary, (2) properties, (3) capital expenditures and (4) acquisitions of long lived assets, that in each of (1), (2), (3) and (4), are used or useful in a Similar Business.

“Person” means any individual, corporation, limited liability company, partnership, joint venture, association, joint stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

“PIPA” means the Partnership Interest Purchase Agreement, dated as of August 2, 2005, by and between Dynegy, Inc., Dynegy Holdings Inc., Dynegy Midstream Holdings, Inc. and Dynegy Midstream G.P., Inc., as Sellers, and Targa Resources, Inc., Targa Resources Partners OLP LP, and Targa Midstream GP, LLC, as Buyers, as the same may be amended prior to October 31, 2005.

“Preferred Stock” means any Equity Interest with preferential rights of payment of dividends or upon liquidation, dissolution, or winding up.

“Qualified Proceeds” means assets that are used or useful in, or Capital Stock of any Person engaged in, a Similar Business;provided that the fair market value of any such assets or Capital Stock shall be determined by the Company in good faith.

“Rating Agencies” means Moody’s and S&P or if Moody’s or S&P or both shall not make a rating of the notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company, which shall be substituted for Moody’s or S&P or both, as the case may be.

“Receivables Facility” means one or more receivables financing facilities, as amended, supplemented, modified, extended, replaced, renewed, restated, refunded or refinanced from time to time, the Indebtedness of which is non-recourse (except for standard representations, warranties, covenants and indemnities made in connection with such facilities) to the Company and its Restricted Subsidiaries pursuant to which the Company or any of its Restricted Subsidiaries sells its accounts receivable to either (a) a Person that is not a Restricted Subsidiary or (b) a Receivables Subsidiary that in turn sells its accounts receivable to a Person that is not a Restricted Subsidiary.

“Receivables Fees” means distributions or payments made directly or by means of discounts with respect to any participation interest issued or sold in connection with, and other fees paid to a Person that is not a Restricted Subsidiary in connection with, any Receivables Facility.

“Receivables Subsidiary” means any Subsidiary formed solely for the purpose of engaging, and that engages only, in one or more Receivables Facilities.

“Registration Rights Agreement” means the Registration Rights Agreement, dated as of October 31, 2005, among the Company, the Co-Issuer, the Subsidiary Guarantors and the Initial Purchasers.

“Related Business Assets” means assets (other than cash or Cash Equivalents) used or useful in a Similar Business;provided that any assets received by the Company or a Restricted Subsidiary in exchange for assets transferred by the Company or a Restricted Subsidiary shall not be deemed to be Related Business Assets if they consist of securities of a Person, unless upon receipt of the securities of such Person, such Person would become a Restricted Subsidiary.

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“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” means, at any time, any direct or indirect Subsidiary of the Company (including the Co-Issuer and any Foreign Subsidiary) that is not then (i) an Unrestricted Subsidiary;provided that upon the occurrence of an Unrestricted Subsidiary ceasing to be an Unrestricted Subsidiary, such Subsidiary shall be included in the definition of “Restricted Subsidiary” or (ii) a Permitted MLP, Permitted GP or a Subsidiary of a Permitted MLP or Permitted GP (other than a Partially Owned Operating Company);provided that any such Partially Owned Operating Company will be a Restricted Subsidiary solely for purposes of the covenants described under “Certain Covenants— Limitation on Restricted Payments”, “—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” and “—Liens”.

“Revolving Credit Facility” means the revolving credit facility provided under the Credit Agreement, entered into as of October 31, 2005, among the Company, the lenders party thereto in their capacity as lenders thereunder and Credit Suisse, as Administrative Agent, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, replacements, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that extend, replace, refund, refinance, renew or defease any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” above).

“S&P” means Standard and Poor’s, a division of The McGraw-Hill Companies, Inc., and any successor to its rating agency business.

“Sale and Lease-Back Transaction” means any arrangement with any Person providing for the leasing by the Company or any Restricted Subsidiary of any real or tangible personal property, which property has been or is to be sold or transferred by the Company or such Restricted Subsidiary to such Person in contemplation of such leasing.

“SEC” means the Securities and Exchange Commission.

“Secured Debt Ratio”, as of any date of determination, means the ratio of (a) Consolidated Total Indebtedness of the Company and the Restricted Subsidiaries that is secured by Liens as of the end of the most recent fiscal quarter for which internal financial statements are available immediately preceding the date on which such event for which such calculation is being made shall occur to (b) the aggregate amount of EBITDA for the then most recent four fiscal quarters ending with the fiscal quarter referred to in clause (a), in each case with suchpro formaadjustments to Consolidated Total Indebtedness and EBITDA as are appropriate and consistent with thepro formaadjustment provisions set forth in the definition of Fixed Charge Coverage Ratio.

“Secured Indebtedness” means any Indebtedness secured by a Lien.

“Securities Act” means the Securities Act of 1933, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Senior Credit Facilities” means the Revolving Credit Facility, the Term Loan Facility, the Funded Synthetic Letter of Credit Facility and the Asset Sale Bridge Term Loan Facility.

“Senior Indebtedness” means with respect to any Person:

(1) all Indebtedness of such Person, whether outstanding on October 31, 2005 or thereafter incurred; and

187

(2) all other Obligations of such Person (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization relating to such Person whether or not post-filing interest is allowed in such proceeding) in respect of Indebtedness described in clause (1) above

unless, in the case of clauses (1) and (2), the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Indebtedness or other Obligations are subordinate in right of payment to the notes or the Subsidiary Guarantee of such Person, as the case may be;provided that Senior Indebtedness shall not include:

(1) any obligation of such Person to the Company or any Subsidiary or to any joint venture in which the Company or any Restricted Subsidiary has an interest;

(2) any liability for Federal, state, local or other taxes owed or owing by such Person;

(3) any accounts payable or other liability to trade creditors in the ordinary course of business (including guarantees thereof as instruments evidencing such liabilities);

(4) any Indebtedness or other Obligation of such Person that is subordinate or junior in any respect to any other Indebtedness or other Obligation of such Person; or

(5) that portion of any Indebtedness that at the time of Incurrence is Incurred in violation of the Indenture.

“Significant Subsidiary” means any Restricted Subsidiary of the Company that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such regulation is in effect on the date hereof.

“Similar Business” means any business conducted by the Company and its Restricted Subsidiaries on October 31, 2005 or any business that is similar, reasonably related, incidental or ancillary thereto.

“Sponsor” means Warburg Pincus LLC and its Affiliates.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subordinated Indebtedness” means

(a) with respect to the Company, any Indebtedness of the Company that is by its terms subordinated in right of payment to the notes, and

(b) with respect to any Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor that is by its terms subordinated in right of payment to the Subsidiary Guarantee of such Subsidiary Guarantor.

“Subsidiary” means, with respect to any Person,

(1) any corporation, association, or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time of determination owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof and

(2) any partnership, joint venture, limited liability company or similar entity of which

(x) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof whether in the form of membership, general, special or limited partnership or otherwise, and

188

(y) such Person or any Restricted Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

“Subsidiary Guarantee” means the guarantee by any Subsidiary Guarantor of the Company’s and the Co-Issuer’s Obligations under the Indenture and the notes.

“Subsidiary Guarantor” means each Restricted Subsidiary of the Company that executed the Indenture as a guarantor on October 31, 2005 and each other Restricted Subsidiary of the Company that thereafter guarantees the notes pursuant to the terms of the Indenture.

“Term Loan Facility” means the term loan credit facility provided under the Credit Agreement, entered into as of October 31, 2005, among the Company, the lenders party thereto in their capacity as lenders and Credit Suisse, as Administrative Agent, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, replacements, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that extend, replace, refund, refinance, renew or defease any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock”).

“Total Assets” means the total amount of all assets of the Company and the Restricted Subsidiaries (other than the North Texas Assets), determined on a consolidated basis in accordance with GAAP as shown on the most recent balance sheet of the Company.

“Transactions” means the Acquisition, including the payment of the merger consideration in connection therewith, the investments by the Sponsor, the Co-Investor, members of management and any other co-investors, the issuance of the notes and the execution of, and borrowings on October 31, 2005 under, the Senior Credit Facilities as in effect on October 31, 2005, the pledge and security arrangements in connection with the foregoing, the refinancing of certain Indebtedness in connection with the foregoing and the related transactions described in this offering circular, in particular as described under the section thereof entitled “The Transactions”.

“Treasury Rate” means, as of any redemption date, the yield to maturity as of such redemption date of United States of America Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two Business Days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to November 1, 2009;provided,however, that if the period from the redemption date to November 1, 2009, isless than one year, the weekly average yield on actually traded United States of America Treasury securities adjusted to a constant maturity of one year will be used.

“Trustee” means Wells Fargo Bank, National Association until a successor replaces it and, thereafter, means the successor.

“Unrestricted Subsidiary” means

(1) Versado Gas Processors L.L.C., Downstream Ventures, Co., L.L.C. and Cedar Bayou Fractionaters, LP,

(2) any Subsidiary of the Company that at the time of determination is an Unrestricted Subsidiary (as designated by the Company, as provided below) and

(3) any Subsidiary of an Unrestricted Subsidiary;

provided that no Permitted MLP, Permitted GP, Subsidiary of a Permitted MLP or Permitted GP and no Co-Issuer will be an Unrestricted Subsidiary.

189

The Company may designate any Subsidiary of the Company (including any existing Subsidiary and any newly acquired or newly formed Subsidiary but excluding any of the entities referred to in the proviso of the immediately following paragraph) to be an Unrestricted Subsidiary unless such Subsidiary or any of its Subsidiaries owns any Equity Interests or Indebtedness of, or owns or holds any Lien on, any property of, the Company or any Subsidiary of the Company (other than any Subsidiary of the Subsidiary to be so designated);provided that

(a) any Unrestricted Subsidiary must be an entity of which shares of the capital stock or other equity interests (including partnership interests) entitled to cast at least a majority of the votes that may be cast by all shares or equity interests having ordinary voting power for the election of directors or other governing body are owned, directly or indirectly, by the Company,

(b) such designation complies with the covenant described under “Certain Covenants— Limitation on Restricted Payments” and

(c) each of

(1) the Subsidiary to be so designated and

(2) its Subsidiaries

has not at the time of designation, and does not thereafter, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable with respect to any Indebtedness pursuant to which the lender has recourse to any of the assets of the Company or any Restricted Subsidiary.

The Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary;provided that, immediately after giving effect to such designation, no Default shall have occurred and be continuing and either

(1) the Company could incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test described in the first paragraph under “Certain Covenants—Limitation on Incurrence of Indebtedness and Issuance of Disqualified Stock and Preferred Stock” or

(2) the Fixed Charge Coverage Ratio for the Company and its Restricted Subsidiaries would be greater than such ratio for the Company and its Restricted Subsidiaries immediately prior to such designation, in each case on apro forma basis taking into account such designation.

Any such designation by the Company shall be notified by the Company to the Trustee by promptly filing with the Trustee a copy of any applicable Board Resolution giving effect to such designation and an Officers’ Certificate certifying that such designation complied with the foregoing provisions.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness, Disqualified Stock or Preferred Stock, as the case may be, at any date, the quotient obtained by dividing

(1) the sum of the products of the number of years from the date of determination to the date of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Disqualified Stock or Preferred Stock multiplied by the amount of such payment, by

(2) the sum of all such payments.

“Wholly-Owned Subsidiary” of any Person means a Subsidiary of such Person, 100% of the outstanding Capital Stock or other ownership interests of which (other than directors’ qualifying shares) shall at the time be owned by such Person or by one or more Wholly-Owned Subsidiaries of such Person.

190

FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of certain federal income tax consequences relevant to the exchange of exchange notes for outstanding notes, but does not purport to be a complete analysis for all potential tax effects. The summary is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of exchange notes. The description does not consider the effect of any applicable foreign, state, local or other tax laws or estate or gift tax considerations. Each holder is encouraged to consult, and depend on, his own tax advisor in analyzing the particular tax consequences of exchanging such holder’s outstanding notes for new notes, including the applicability and effect of any federal, state, local and foreign tax laws.

The exchange of exchange notes for outstanding notes will not be a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder will have the same adjusted issue price, adjusted basis and holding period in the exchange notes as it had in the outstanding notes immediately before the exchange.

PLAN OF DISTRIBUTION

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for outstanding notes where such outstanding notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until March 19, 2008, all dealers effecting transactions in the new notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of the new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to this exchange offer may be sold from time to time in one or more transaction in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to this exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of the new notes and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of 180 days after the expiration date of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer (including the expenses of one counsel for the holders of the outstanding notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the outstanding notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

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LEGAL MATTERS

The validity of the new notes offered in this exchange offer and the related guarantees will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements of Targa Resources, Inc. as of December 31, 2006 and 2005 and for each of the two years in the period ended December 31, 2006 included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Dynegy Midstream Services, Limited Partnership for the ten month period ended October 31, 2005 and as of December 31, 2004 and 2003 and for each of the two years in the period ended December 31, 2004 included in this Prospectus, have been so incorporated in reliance on the reports (which includes explanatory paragraphs relating to significant transactions with related parties) of PricewaterhouseCoopers LLP, independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows of Targa Resources, Inc. for the year ended December 31, 2004, appearing in this Prospectus and Registration Statement, and the combined financial statements of the Midstream Operations sold to Targa Resources, Inc. at April 15, 2004, December 31, 2003 and 2002 and for the 106-day period ended April 15, 2004, and years ended December 31, 2003 and 2002 appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-4 with respect to the notes being offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the notes offered by this prospectus, please review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained from the public reference section of the SEC at prescribed rates, or accessed at the SEC’s website atwww.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room.

Following the completion of the exchange offer, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. We have agreed that, whether or not we are required to do so under the applicable rules and regulations, for so long as any of the notes remain outstanding we will comply with the reporting requirements of the Exchange Act and will file the applicable reports and information with the SEC, unless the SEC will not accept such filings. If the SEC will not accept these filings, we will post the reports referred to above on our website. Our website is located atwww.targaresources.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website, as soon as reasonably practicable after those reports and other information are filed with or furnished to the SEC. Information on our website is not a part of this prospectus. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: Targa Resources, Inc., Attention: Investor Relations, 1000 Louisiana, Suite 4300, Houston, Texas 77002, (713) 584-1000.

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In addition, for so long as any of the notes remain outstanding, we have agreed to make available to any prospective purchaser of the notes or beneficial owner of the notes, in connection with any sale thereof, the information required by Rule 144A(d)(4) under the Securities Act.

FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements” as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this prospectus 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;

• 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;

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

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

• the level and success of natural gas drilling around our assets, and our success in connecting natural gas supplies to our gathering and processing systems;

• general economic, market and business conditions; and

• the risks described under the heading “Risk Factors” in this prospectus.

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 prospectus will prove to be accurate. Some of these and other risks and uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described under the heading Risk Factors in this prospectus. 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 prospectus 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.

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INDEX TO FINANCIAL STATEMENTS

TARGA RESOURCES, INC.
Reports of Independent Registered Public Accounting Firms	F-2
Consolidated Balance Sheets as of December 31, 2006 and 2005	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004	F-5
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2006, 2005 and 2004	F-6
Consolidated Statement of Changes in Stockholders’ Equity for the Years Ended December 31, 2006, 2005 and 2004	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004	F-8
Notes to Consolidated Financial Statements	F-9
TARGA RESOURCES, INC. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006	F-53
Consolidated Statements of Operations for the Nine Months Ended September 30, 2007 and 2006	F-54
Consolidated Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2007 and 2006	F-55
Consolidated Statement of Changes in Stockholder’s Equity for the Nine Months Ended September 30, 2007 and December 31, 2006	F-56
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006	F-57
Notes to Unaudited Consolidated Financial Statements	F-58
PREDECESSOR OF TARGA RESOURCES, INC. (CONOCOPHILLIPS COMPANY’S MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.)
Report of Independent Registered Public Accounting Firm	F-84
Combined Statements of Operations for the 106-day period from January 1 to April 15, 2004 and the Years Ended December 31, 2003 and 2002	F-85
Combined Balance Sheets at April 15, 2004 and December 31, 2003 and 2002	F-86
Combined Statements of Cash Flows for the 106-day period from January 1 to April 15, 2004 and the Years Ended December 31, 2003 and 2002	F-87
Combined Statement of Parent Company Investments at April 15, 2004 and December 31, 2003 and 2002	F-88
Notes to Combined Financial Statements	F-89
DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP
Report of Independent Registered Public Accounting Firm	F-98
Consolidated Statement of Operations for the Ten Months Ended October 31, 2005	F-99
Consolidated Statement of Cash Flows for the Ten Months Ended October 31, 2005	F-100
Consolidated Statement of Changes in Partners’ Capital for the Ten Months Ended October 31, 2005	F-101
Notes to Consolidated Financial Statements	F-102
Report of Independent Registered Public Accounting Firm	F-113
Consolidated Balance Sheets as of December 31, 2004 and 2003	F-114
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002	F-115
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002	F-116
Consolidated Statement of Changes in Partners’ Capital for the Years Ended December 31, 2004, 2003 and January 1, 2002	F-117
Notes to Consolidated Financial Statements	F-118

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors of Targa Resources, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income (loss), of changes in stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Targa Resources, Inc. and its subsidiaries (the “Company”) at December 31, 2006 and 2005, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/    PricewaterhouseCoopers LLP

Houston, Texas

March 30, 2007

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Targa Resources, Inc.

We have audited the accompanying consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows of Targa Resources, Inc. (the “Company”) for the year ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. The financial statements of Bridgeline Holdings L.P. (“Bridgeline”), a joint venture in which the Company has a total interest of 40%, for the year ended December 31, 2004, have been audited by other auditors whose report has been furnished to us; insofar as our opinion on the consolidated financial statements relates to the amounts included for Bridgeline, it is based solely on their report.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of the operations and the cash flows of Targa Resources, Inc. for the year ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

/S/    ERNST & YOUNG LLP

Houston, Texas

May 20, 2005, except for Notes 8 and 20, as to

which the date is September 29, 2005

F-3

TARGA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2006			2005
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	142,739		$	41,427
Trade receivables, net of allowances of $781 and $800		528,864			516,879
Inventory		116,956			159,833
Deferred income taxes		—			10,472
Assets from risk management activities		34,255			1,220
Other current assets		36,843			97,744
Total current assets		859,657			827,575
Property, plant, and equipment, at cost		2,651,375			2,474,157
Accumulated depreciation		(186,848	)		(37,554	)
Property, plant, and equipment, net		2,464,527			2,436,603
Unconsolidated investments		40,212			62,337
Deferred income taxes		—			7,038
Long-term assets from risk management activities		15,851			150
Other assets		77,778			62,883
Total assets	$	3,458,025		$	3,396,586
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	271,696		$	367,166
Accrued liabilities		301,540			166,468
Current maturities of debt		712,500			12,500
Liabilities from risk management activities		6,611			29,851
Deferred income taxes		11,383			—
Total current liabilities		1,303,730			575,985
Long-term debt, less current maturities		1,471,875			2,184,375
Long-term liabilities from risk management activities		17,731			62,969
Deferred income taxes		23,950			—
Other long-term obligations		24,941			26,166
Minority interest		101,528			112,714
Commitments and contingencies (Note 11)
Stockholders’ equity:
Common stock ($0.001 par value, 1,000 shares authorized, 1,000 shares issued and outstanding at December 31, 2006 and 2005)		—			—
Additional paid-in capital		472,423			470,608
Retained earnings (accumulated deficit)		6,164			(17,250	)
Accumulated other comprehensive income (loss)		35,683			(18,981	)
Total stockholders’ equity		514,270			434,377
Total liabilities and stockholders’ equity	$	3,458,025		$	3,396,586

See notes to consolidated financial statements

F-4

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004
	(In thousands)
Revenues	$	6,132,881		$	1,829,027		$	602,376
Costs and expenses:
Product purchases		5,440,832			1,631,963			544,918
Operating expenses		224,169			52,090			15,253
Depreciation and amortization		149,687			27,141			10,631
General and administrative		82,351			28,275			11,149
		5,897,039			1,739,469			581,951
Operating income		235,842			89,558			20,425
Other income (expense):
Interest expense, net		(180,189	)		(39,856	)		(6,406	)
Equity in earnings of unconsolidated investments		9,968			(3,776	)		2,370
Gain on sale of investment in Bridgeline Holdings, L.P.		—			18,008			—
Loss on mark-to-market derivative contracts		—			(73,950	)		—
Loss on debt extinguishment		—			(3,375	)		—
Minority interest		(25,998	)		(7,361	)		—
Income (loss) before income taxes		39,623			(20,752	)		16,389
Income tax (expense) benefit:
Current		(34	)		(205	)		—
Deferred		(16,175	)		6,742			(5,227	)
		(16,209	)		6,537			(5,227	)
Net income (loss)		23,414			(14,215	)		11,162
Dividends on redeemable preferred stock		—			(7,167	)		(5,829	)
Net income (loss) to common stock	$	23,414		$	(21,382	)	$	5,333

See notes to consolidated financial statements

F-5

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004
	(In thousands)
Net income (loss)	$	23,414		$	(14,215	)	$	11,162
Other comprehensive income (loss)
Commodity hedging contracts:
Change in fair value		120,283			(40,159	)		1,292
Reclassification adjustment for settled periods		(31,243	)		7,450			1,207
Related income taxes		(35,376	)		12,203			(874	)
Interest rate swaps:
Change in fair value		2,606			(249	)		—
Reclassification adjustment for settled periods		(1,005	)		80			—
Related income taxes		(639	)		63			—
Foreign currency items:
Foreign currency translation adjustment		59			9			—
Related income taxes		(21	)		(3	)		—
Equity in other comprehensive income changes of
Bridgeline Holdings, L.P.		—			149			(149	)
Related income taxes		—			(52	)		52
		54,664			(20,509	)		1,528
Comprehensive income (loss)	$	78,078		$	(34,724	)	$	12,690

See notes to consolidated financial statements

F-6

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

	Common Stock					Additional Paid-in Capital			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total
	Shares		Amount
	(In thousands)
Initial contribution	—		$	—		$	2,078		$	(1,201	)	$	—		$	877
Contributions	—			—			2,550			—			—			2,550
Issuance of redeemable preferred stock	—			—			(3,750	)		—			—			(3,750	)
Issuance of nonvested common stock	1,610			2			14			—			—			16
Amortization of deferred compensation	—			—			485			—			—			485
Other comprehensive income	—			—			—			—			1,528			1,528
Dividends on redeemable preferred stock	—			—			—			(5,829	)		—			(5,829	)
Net income	—			—			—			11,162			—			11,162
Balance, December 31, 2004	1,610			2			1,377			4,132			1,528			7,039
Tax benefit on vesting of common stock	—			—			3,878			—			—			3,878
Amortization of deferred compensation	—			—			497			—			—			497
Dividends on redeemable preferred stock	—			—			—			(7,167	)		—			(7,167	)
Retirement of preferred stock	—			—			148,046			—			—			148,046
Contribution of parent	—			—			315,630			—			—			315,630
Equity reorganization	(1,609	)		(2	)		2			—			—			—
Contribution of noncash compensation	—			—			1,178			—			—			1,178
Other comprehensive loss	—			—			—			—			(20,509	)		(20,509	)
Net loss	—			—			—			(14,215	)		—			(14,215	)
Balance, December 31, 2005	1			—			470,608			(17,250	)		(18,981	)		434,377
Tax expense on vesting of common stock	—			—			7			—			—			7
Distribution to parent	—			—			(969	)		—			—			(969	)
Contribution of noncash compensation	—			—			2,777			—			—			2,777
Other comprehensive income	—			—			—			���			54,664			54,664
Net income	—			—			—			23,414			—			23,414
Balance, December 31, 2006	1		$	—		$	472,423		$	6,164		$	35,683		$	514,270

See notes to consolidated financial statements

F-7

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31, 2006			Year Ended December 31, 2005			Year Ended December 31, 2004
	(In thousands)
Cash flows from operating activities
Net income (loss)	$	23,414		$	(14,215	)	$	11,162
Items not affecting cash flows from operating activities:
Depreciation		149,563			27,017			10,537
Deferred income tax expense (benefit)		16,175			(6,742	)		5,227
Amortization of debt issue costs		13,001			6,746			956
Amortization of intangibles		124			124			94
Amortization of discount on senior subordinated second lien notes		—			527			113
Accretion of asset retirement obligations		888			232			40
Noncash compensation		2,777			1,675			485
Inventory valuation adjustment		13,103			—			—
Provision for uncollectible accounts		(860	)		—			—
Equity in earnings of unconsolidated investments		(9,968	)		3,776			(2,370	)
Distributions from unconsolidated investments		2,306			387			—
Minority interest		25,998			7,361			—
Minority interest distributions		(37,184	)		—			—
Gain on sale of investment in Bridgeline Holdings, L.P.		—			(18,008	)		—
Risk management activities		(24,618	)		—			—
Loss on mark-to-market derivative contracts		—			73,950			—
Loss on sale of assets		169			—			—
Other		—			975			(95	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		(2,052	)		(97,135	)		(77,843	)
Inventory		23,407			(16,756	)		(381	)
Accounts payable and other liabilities		37,043			138,941			85,210
Net cash provided by operating activities		233,286			108,855			33,135
Cash flows from investing activities
Purchases of property, plant and equipment		(136,325	)		(21,976	)		(250,187	)
Acquisition of Dynegy Midstream Services, L.P., net of cash acquired		(340	)		(2,403,544	)		—
Proceeds from property insurance		27,221			—			—
Investment in unconsolidated affiliates		(9,102	)		(6,032	)		(101,275	)
Proceeds from sale of investment in Bridgeline Holdings, L.P.		—			117,000			—
Payment of premium on commodity derivative		—			(13,600	)		—
Other		734			(764	)		(1,772	)
Net cash used in investing activities		(117,812	)		(2,328,916	)		(353,234	)
Cash flows from financing activities
Senior secured credit facilities:
Borrowings		—			1,998,000			168,000
Repayments		(12,500	)		(177,125	)		(42,000	)
Proceeds from issuance of senior unsecured notes		—			250,000			—
Proceeds from issuance of term loan		—			—			45,000
Proceeds from issuance of senior subordinated second lien notes		—			—			31,360
Repayment of term loan		—			(45,000	)		—
Repayment of senior subordinated second lien notes		—			(32,000	)		—
Distributions to Targa Resources Investments Inc.		(969	)		315,630			—
Parent contributions (distributions)		—			—			2,550
Proceeds from issuance of redeemable preferred stock		—			—			131,300
Proceeds from issuance of common stock		—			—			16
Costs incurred in connection with financing arrangements		(693	)		(58,884	)		(5,550	)
Net cash provided by (used in) financing activities		(14,162	)		2,250,621			330,676
Net increase in cash and cash equivalents		101,312			30,560			10,577
Cash and cash equivalents, beginning of period		41,427			10,867			290
Cash and cash equivalents, end of period	$	142,739		$	41,427		$	10,867

See notes to consolidated financial statements

F-8

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations of the Company

Organization

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.

On April 16, 2004, the common stock of Pipeco Development Company, Inc. (“Pipeco”) was contributed to Targa in exchange for 37,500 shares of preferred stock. Both Targa and Pipeco were considered “entities under common control” as defined under accounting principles generally accepted in the United States (“GAAP”) and, as such, this transaction was recorded in a manner similar to that required for a pooling of interests, whereby the recorded assets and liabilities of Targa and Pipeco were carried forward to the combined consolidated corporation at their recorded amounts.

Prior to April 16, 2004, certain investors in Targa had previous ownership in Pipeco, a Delaware corporation, formerly known as Targa Resources, Inc. and Warburg Pincus VIII Development Company, Inc. Pipeco was the entity that performed due diligence and other acquisition-specific activities associated with the asset acquisitions from ConocoPhillips Corporation (“ConocoPhillips”).

We commenced initial operations on April 16, 2004, with the purchase from ConocoPhillips of certain midstream natural gas assets located in West Texas and South Louisiana. In these financial statements and notes therein, all references to the “predecessor” are to these assets, presented on a going-concern basis, as if the assets had existed as an entity separate from ConocoPhillips.

On December 16, 2004, we acquired an aggregate 40% equity ownership in Bridgeline Holdings, L.P., and Bridgeline LLC (collectively, “Bridgeline”). We accounted for our investment in Bridgeline using the equity method of accounting. On August 5, 2005, we sold our interest in Bridgeline to Chevron Corporation (“Chevron”) for $117.0 million. We recognized a pre-tax gain of $18.0 million from the sale.

On October 31, 2005, we acquired Dynegy Inc.’s (“Dynegy”) midstream natural gas business for approximately $2,452 million. Under the terms of the agreement, we acquired Dynegy’s ownership interests in Dynegy Midstream Services Limited Partnership (“DMS”), which held Dynegy’s natural gas gathering and processing assets, as well as its natural gas liquids (“NGL”) fractionation, terminalling, storage, transportation, distribution and marketing assets.

Prior to the closing of the DMS acquisition, we engaged in a corporate reorganization pursuant to which we became a second-tier, wholly-owned subsidiary of our newly-formed parent holding company, Targa Resources Investments Inc. (“Targa Investments”). In the reorganization, our stockholders exchanged their shares of Targa common stock, Targa stock options and Targa Series A Convertible Participating Preferred Stock for shares of Targa Investments having the same terms as the Targa stock, and our preferred stock was retired.

Immediately after the reorganization, the only significant asset of Targa Investments was its ownership of 100% of the outstanding capital stock of an intermediate holding company, whose sole asset was its ownership of 100% of our outstanding capital stock, which consisted entirely of common stock. Following the reorganization, and in connection with the closing of the DMS acquisition, Targa Investments exchanged its outstanding common stock and preferred stock for a new series of preferred stock and issued new common stock to our management. In addition, certain investors and members of our management contributed cash to Targa Investments to purchase additional preferred stock in Targa Investments. Approximately $316 million of such cash was contributed to us concurrent with the closing of the DMS acquisition.

F-9

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Operations

Our business operations consist of natural gas gathering and processing, and the fractionating, storing, terminalling, transporting, distributing and marketing of NGLs. Please see Note 15—Segment Information for a description of our segments and segment operations.

Basis of Presentation. The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2006 and 2005, and the results of our operations, cash flows and changes in stockholders’ equity for the years ended December 31, 2006, 2005 and 2004. Certain reclassifications have been made to the prior year balances to conform to the current year presentation.

Note 2—Significant Accounting Policies

Asset Retirement Obligations. We account for asset retirement obligations in accordance with Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) 143,“Asset Retirement Obligations.”SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity is required to capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

In March 2005, the FASB issued Financial Interpretation (“FIN”) 47,“Accounting for Conditional Asset Retirement Obligations.”This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in SFAS 143. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about potential future cash outflows for these obligations and more consistent recognition of these liabilities. Our adoption of FIN 47 on December 31, 2005 had no effect on our financial position, results of operations, or cash flows.

The following table reflects the changes in our asset retirement obligations during the periods shown:

(in thousands)	Year Ended December 31, 2006			Year Ended December 31, 2005		Year Ended December 31, 2004
Asset retirement obligations—beginning of period	$	14,104		$	630	$	—
Liabilities incurred		—			12,828		590
Liabilities settled		(6	)		—		—
Change in cash flow estimate
Purchase price adjustment (1)		(3,330	)		—		—
Other		(35	)		414		—
Accretion expense		888			232		40
Asset retirement obligations—end of period	$	11,621		$	14,104	$	630

(1) See Note 3.

F-10

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Cash and Cash Equivalents. Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

Comprehensive Income. Comprehensive income includes net income and other comprehensive income, which includes unrealized gains and losses on derivative instruments that are designated as hedges, our equity interest in the other comprehensive income changes of unconsolidated investments accounted for under the equity method and unrealized foreign exchange gains and losses.

Concentration of Credit Risk. Financial instruments which potentially subject Targa to concentrations of credit risk consist primarily of trade accounts receivable and derivative instruments. Management believes the risk is limited, as our customers represent a broad and diverse group of energy marketers and end users.

We extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that our established credit criteria are met.

Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required.

Significant Commercial Relationships

For the year ended December 31, 2006, transactions with Chevron and its subsidiaries represented approximately 15% and 19% of our consolidated revenues and consolidated product purchases, respectively. No other counterparty accounted for more than 10% of our consolidated revenues or consolidated product purchases during 2006.

For the year ended December 31, 2005, transactions with Chevron and its subsidiaries represented approximately 10% and 12% of our consolidated revenues and consolidated product purchases, respectively. In addition, approximately 11% of our consolidated revenues were derived from transactions with ConocoPhillips and its subsidiaries. No other counterparty accounted for more than 10% of our consolidated revenues or consolidated product purchases during 2005.

For the year ended December 31, 2004, transactions with ConocoPhillips, Enterprise Products, PPG Industries, and CITGO represented approximately 17%, 16%, 16% and 12%, respectively, of our consolidated revenues and transactions with Newfield Exploration and Cimarex Energy represented approximately 12% and 10%, respectively, of our consolidated product purchases. No other counterparty accounted for more than 10% of our consolidated revenues or consolidated product purchases during 2004.

Consolidation Policy. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities after the elimination of all material intercompany accounts and transactions.

F-11

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on our equity method investees’ balance sheet in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

Debt Issue Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and charged to interest expense over the term of the related debt. During the fourth quarter of 2005, $2.7 million of previously unamortized debt issue costs were charged to expense when the related debt was paid off prior to the normal termination of the related borrowing agreements.

Earnings per Share. Upon completion of our equity reorganization in 2005, our capital stock consisted of one thousand shares of common stock, owned by our parent company. As such, earnings per share information would not be meaningful and is not presented herein.

Environmental Liabilities. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.

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

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

Income Taxes. We follow the guidance in SFAS 109,“Accounting for Income Taxes”, which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.

We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all

F-12

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no reserve has been established. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.

Intangible Assets. Intangible assets consist of the value of customer and supplier contracts and relationships obtained in the acquisition from ConocoPhillips. These assets are amortized over the estimated useful lives of the related gathering systems on a straight-line basis. Amortization expense was $0.1 million for each of the years ended December 31, 2006, 2005 and 2004.

We review intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. This review consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. If such a review should indicate that the carrying amount of intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value.

Inventories. Product inventories consist primarily of NGLs. Most product inventories turn over monthly, but some inventory, primarily propane, is held during the year for strategic purposes to meet anticipated heating season requirements of our customers. Product inventories are valued at the lower of cost or market using the average cost method.

Quantities of natural gas over-delivered or under-delivered related to operational balancing agreements are recorded monthly as inventory or as a payable using weighted average prices at the time the imbalance was created. Monthly, gas imbalances receivable are valued at the lower of cost or market, gas imbalances payable are valued at replacement cost. These imbalances are typically settled in the following month with deliveries or receipts of natural gas. Certain contracts require cash settlement of imbalances on a current basis. Under these contracts, imbalance cash-outs are recorded as a sale or purchase of natural gas, as appropriate.

Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceeds their net realizable value. These non-cash adjustments are charged to product purchases within operating costs and expenses in the period they are recognized, with the related cash impact in the subsequent period. For the year ended December 31, 2006 we recognized $13.1 million of lower of cost or market adjustments.

Inventory consisted of the following at the dates indicated:

	December 31,
	2006		2005
	(in thousands)
Natural gas liquids	$	116,568	$	159,366
Natural gas		—		396
Materials and supplies		388		71
	$	116,956	$	159,833

F-13

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Minority Interest. Minority interest represents third-party ownership interests in the net assets of our subsidiaries that are joint ventures. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third party investor’s interest in our consolidated balance amounts shown as minority interest. In the statement of operations, minority interest reflects the allocation of joint venture earnings to third party investors. Distributions to and contributions from minority interests represent cash payments and cash contributions, respectively, from such third-party investors.

Price Risk Management (Hedging). We account for derivative instruments in accordance with SFAS 133,“Accounting for Derivative Instruments and Hedging Activities”, as amended. Under SFAS 133, all derivative instruments not qualifying for the normal purchases and sales exception are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge, or is not designated as a hedge, the unrealized gain or loss on the derivative is recognized currently in earnings. If a derivative qualifies for hedge accounting and is designated as a hedge, the effective portion of the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (“OCI”), a component of stockholders’ equity, and reclassed to revenues or interest expense in the period the hedged forecasted transaction is recognized.

The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge accounting is discontinued prospectively when a hedge instrument becomes ineffective. Gains and losses deferred in OCI related to cash flow hedges for which hedge accounting has been discontinued remain unchanged until the related product has been delivered. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in other revenues immediately.

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. Hedge effectiveness is measured on a quarterly basis. Any ineffective portion of the unrealized gain or loss is recognized in earnings in the current period. See Note 9.

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

Asset Group	Range of Years
Natural gas gathering systems and processing facilities	15 to 25
Fractionation, terminalling and natural gas liquids storage facilities	25
Transportation equipment and barges	5 to 10
Office and miscellaneous equipment	3 to 7

Expenditures for maintenance and repairs are generally expensed as incurred. However, expenditures for refurbishments that extend the useful lives of assets or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset.

Our determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand for hydrocarbons in the markets served by our assets, normal

F-14

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

wear and tear of the facilities, and the extent and frequency of maintenance programs. From time to time, we utilize consultants and other experts to assist us in assessing the remaining lives of the crude oil or natural gas production in the basins we serve.

We may capitalize certain costs directly related to the construction of assets, including internal labor costs, interest and engineering costs. Upon disposition or retirement of property, plant and equipment, any gain or loss is charged to operations.

In accordance with SFAS 144,“Accounting for the Impairment or Disposal of Long-Lived Assets,”we evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We continually monitor our businesses and the market and business environments to identify indicators that may suggest an asset may not be recoverable.

We evaluate an asset for recoverability by comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows we recognize an impairment loss to write down the carrying amount of the asset to its fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition of an impairment loss in our Consolidated Statements of Operations.

Revenue Recognition. Our primary types of sales and service activities reported as operating revenue include:

• sales of natural gas, NGLs and condensate;

• natural gas processing, from which we generate revenue through the compression, gathering, treating, and processing of natural gas; and

• fractionation, storage, terminalling and transportation of NGLs, from which we generate fee-based revenue.

In general, we recognize revenue when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery has occurred or services have been rendered, (3) the price is fixed or determinable and (4) collectibility is reasonably assured.

For processing services, we receive either fees or a percentage of commodities as payment for these services, depending on the type of contract. Under percent-of-proceeds contracts, we are paid for our services by keeping a percentage of the NGLs extracted and the residue gas resulting from processing natural gas. In percent-of-proceeds arrangements, we remit either a percentage of the proceeds received from the sales of residue gas and NGLs or a percentage of the residue gas or NGLs at the tailgate of the plant to the producer. Under the terms of percent-of-proceeds and similar contracts, we may purchase the producer’s share of the processed commodities for resale or deliver the commodities to the producer at the tailgate of the plant. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we keep the NGLs extracted and return the processed natural gas or value of the natural gas to the producer. Natural gas or NGLs that

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

we receive for services or purchase for resale are in turn sold and recognized in accordance with the criteria outlined above. Under fee-based contracts, we receive a fee based on throughput volumes.

We generally report revenues gross in the combined statements of operations, in accordance with Emerging Issues Task Force (“EITF”) Issue No. 99-19,“Reporting Revenue Gross as a Principal versus Net as an Agent.”Except for fee-based contracts, we act as the principal in these transactions where we receive natural gas or NGLs, take title to the commodities, and incur the risks and rewards of ownership.

Stock-Based Compensation. On January 1, 2006, we adopted SFAS 123R,“Share-Based Payment,”using the modified prospective method, which resulted in the provisions of SFAS 123R being applied to our consolidated financial statements on a going-forward basis beginning in fiscal year 2006. Prior periods have not been adjusted and, therefore, the results for 2006 are not necessarily comparable to the same period in prior years. However, the impact to prior periods was not material. SFAS 123R requires companies to recognize stock-based awards granted to employees as compensation expense on a fair value basis. Under the fair value recognition provisions of SFAS 123R, stock-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the service period, which generally represents the vesting period, and includes an estimate of the awards that will be forfeited. We calculate the fair value of stock options using the Black-Scholes option pricing model, and the fair value of restricted stock is based on intrinsic value.

Use of Estimates. The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect our reported financial position and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) estimating unbilled revenues and operating and general and administrative costs (2) developing fair value assumptions, including estimates of future cash flows and discount rates, (3) analyzing tangible and intangible assets for possible impairment, (4) estimating the useful lives of our assets and (5) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.

Recent Accounting Pronouncements. We adopted SFAS 154,“Accounting Changes and Error Corrections,”on January 1, 2006. SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections.

On April 1, 2006 we adopted the consensus on EITF 04-13,“Accounting for Purchases and Sales of Inventory With the Same Counterparty.”EITF 04-13 requires that two or more inventory transactions with the same counterparty should be viewed as a single non-monetary transaction, if the transactions were entered into in contemplation of one another. Exchanges of inventory between entities in the same line of business should be accounted for at fair value or recorded at carrying amounts, depending on the classification of such inventory. Our adoption of EITF 04-13 had no effect on our consolidated results of operations, financial position, or cash flows.

In July 2006, the FASB issued Interpretation 48,“Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109”(“FIN 48”), which clarifies the accounting and disclosure for uncertainty in income taxes recognized in an enterprise’s financial statements. FIN 48 seeks to reduce the diversity in practice associated with certain aspects of the recognition and measurement related to accounting for income taxes. This interpretation is effective for fiscal years beginning after December 15, 2006. We continue to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

evaluate our tax positions, and based on our current evaluation, anticipate FIN 48 will not have a significant impact on our results of operations or financial position.

In September 2006, the FASB issued SFAS 157“Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”), and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in these accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS 157 does not require any new fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We have not yet determined the impact this statement will have on our results of operations or financial position.

In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. We began to apply the guidance in SAB 108 on October 1, 2006. SAB 108 had no effect on our results of operations or financial position.

In February 2007, the FASB issued SFAS 159,“The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of No. 115”, which is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. 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. We are currently reviewing this new accounting standard and the impact, if any, it will have on our financial statements.

Note 3—Acquisitions

Acquisition of DMS

On October 31, 2005, we acquired Dynegy’s midstream natural gas business for approximately $2,452 million, including certain acquisition-related costs. Under the terms of the agreement, we acquired Dynegy’s ownership interests in DMS, which held Dynegy’s natural gas gathering and processing assets, and its NGL fractionation, terminalling, storage, transportation, distribution and marketing assets. We acquired DMS to expand our natural gas gathering and processing asset base in Texas, Louisiana and New Mexico, and to gain greater access to marketing and distribution channels for our produced NGL.

We have accounted for the acquisition under the purchase method of accounting in accordance with SFAS 141,“Business Combinations.”We retained a third party to perform certain valuation services in relation to the DMS acquisition. These services included providing a report stating an opinion of the fair value of certain tangible and intangible assets, unconsolidated equity interests, and product inventory. The third party applied standard valuation approaches and methodologies utilizing publicly available economic and pricing data, historical DMS operations and financial data, and assumptions provided by our management. The third party’s analyses, opinions, and conclusions were developed and its report was prepared in conformity with the Uniform Standards of Professional Appraisal Practice.

Certain of the DMS property, plant and equipment sustained damage from the effects of Hurricane Katrina and Hurricane Rita. Our final purchase price allocation reflects our estimate of the damage incurred and the amount we expect to recover from property damage insurance claims.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The purchase price and the final allocation to assets and liabilities based on their estimated fair values as of October 31, 2005 are shown below (in thousands):

	Preliminary			Adjustments			Final
Purchase price:
Cash purchase price	$	2,350,000		$	—		$	2,350,000
Cash collateral		90,703			—			90,703
Acquisition-related costs incurred		11,399			340			11,739
Total purchase price	$	2,452,102		$	340		$	2,452,442
Fair value of assets acquired and liabilities assumed:
Current assets, including cash of $33,508	$	605,641		$	(3,726	)	$	601,915
Property, plant and equipment		2,192,659			38,844			2,231,503
Unconsolidated investments		59,303			(38,108	)		21,195
Other assets		3,059			—			3,059
Current liabilities		(279,636	)		—			(279,636	)
Other long-term liabilities		(23,571	)		3,330			(20,241	)
Minority interest		(105,353	)		—			(105,353	)
Total purchase price	$	2,452,102		$	340		$	2,452,442

During the allocation period we recorded the following adjustments to the preliminary purchase price allocation:

• A $0.3 million increase in acquisition-related costs, which consisted mainly of legal and accounting fees;

• A $7.7 million reduction in inventory to reflect the resolution of disputed NGL volumes in storage at a third party facility as of the acquisition closing date. The net reduction to inventory volumes was approximately 0.2 million barrels;

• A $2.9 million increase in current assets to reflect the recognition of inventory sold to Chevron prior to the DMS acquisition, but not invoiced until 2006.

• A $3.3 million reduction of our asset retirement obligation to reflect an adjustment to our original estimate of pipeline abandonment costs;

• A $1.1 million increase in receivables to record a receivable for a contract dispute settled prior to the acquisition closing date; and

• A $38.1 million reduction in the valuation of our investment in unconsolidated subsidiaries to reflect an adjustment to our original estimate of the fair value of our equity investment in Venice Energy Services Company LLC (“VESCO”) as a result of pre-acquisition hurricane damage.

The offset to each of these adjustments was in property, plant, and equipment.

Acquisition of Equity Interest in Bridgeline

In December 2004, we purchased a 40% ownership interest in Bridgeline from Enron North America Corporation (“Enron”) and certain of its affiliates, for $101.3 million, including certain acquisition-related costs. Bridgeline was originally formed by Enron and certain affiliates of Chevron to own and operate certain natural gas pipeline and storage facilities in southern Louisiana.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

On August 5, 2005, we sold our interest in Bridgeline to Chevron for $117.0 million. We recognized a pre-tax gain of $18.0 million from the sale. We used the proceeds from this sale primarily for debt repayment, including repayment in full of a $45 million term loan related to Bridgeline.

Acquisition of Assets from ConocoPhillips

In April 2004, we purchased various midstream assets located in Texas and Louisiana from ConocoPhillips for $247 million in cash, including certain acquisition-related costs.

The Texas assets consist of an integrated gathering and processing system with low- and high-pressure lines, gathering natural gas from wellhead and central delivery locations in the Permian Basin, covering parts of eight counties from San Angelo to Big Spring. The Louisiana assets consist of an integrated gathering and processing system from Lake Charles to Lafayette, gathering from wells and central delivery facilities.

The final purchase price was allocated to the following assets based on their fair values as of April 16, 2004 (in thousands):

Gathering and processing systems	$	194,493
Processing plants		43,943
Other property and equipment		6,252
Customer and supplier contracts		2,359
	$	247,047

Pro Forma Information (Unaudited)

The following table presents selected unaudited pro forma financial information incorporating the historical (pre-merger) results of the DMS acquisition and the acquisition of assets from ConocoPhillips. Since the DMS acquisition closed on October 31, 2005, our Consolidated Statements of Operations do not include any earnings from DMS prior to November 1, 2005.

The following pro forma information for the year ended December 31, 2005 has been presented as if the DMS acquisition had been completed on January 1, 2005. The pro forma information is based upon data currently available and includes certain estimates and assumptions made by management. As a result, this pro forma information is not necessarily indicative of our financial results had the transactions actually occurred on this date. Likewise, the following unaudited pro forma information is not necessarily indicative of our future financial results.

	(in thousands)
Revenues	$	5,420,027
Product purchases		(4,991,232	)
Depreciation and amortization		(175,533	)
Gain on sale of assets		9,900
Other operating expense		(48,575	)
Operating income		214,587
Interest expense, net		(179,557	)
Other expense		(90,071	)
Income tax benefit		19,037
Net loss	$	(36,004	)

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 4—Property, Plant, and Equipment

Our property, plant, and equipment and accumulated depreciation were as follows at the dates indicated:

	December 31,
	2006			2005
	(in thousands)
Natural gas gathering systems		1,326,337			1,261,016
Processing and fractionation facilities		831,302			759,768
Terminalling and natural gas liquids storage facilities		208,193			188,398
Transportation assets		149,663			145,435
Other property and equipment		42,013			36,856
Land		50,428			48,636
Construction in progress		43,439			34,048
		2,651,375			2,474,157
Accumulated depreciation		(186,848	)		(37,554	)
	$	2,464,527		$	2,436,603

Note 5—Unconsolidated Investments

At December 31, 2006 and 2005, our unconsolidated investments included a 22.9% ownership interest in Venice Energy Services Company, LLC (“VESCO”), a venture that operates a natural gas liquids processing and extraction facility in the Gulf Coast region and a 38.8% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast. In August 2005 we sold our interest in Bridgeline.

We acquired these equity method investments in the DMS acquisition. These ventures maintain independent capital structures and have financed their operations either on a non-recourse basis to us or through their ongoing commercial activities.

The following table shows our unconsolidated investments at the dates indicated.

	December 31,
	2006		2005
	(in thousands)
Natural Gas Gathering and Processing
VESCO	$	20,610	$	48,933
Logistics Assets
GCF		19,602		13,404
	$	40,212	$	62,337

The recorded value of our equity investments was reduced approximately $38.1 million during 2006 as a result of a revision to our original purchase price allocation (see Note 3).

Our equity in the net assets of VESCO and GCF exceeded our acquisition date investment account by approximately $20.3 million and $5.2 million, respectively. The difference is being amortized over the estimated remaining life of the net assets on a straight-line basis, and is included as a component of our equity in earnings of unconsolidated investments.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

	Year Ended December 31,
	2006		2005			2004
	(in thousands)
Equity in earnings of:
VESCO	$	7,214	$	572		$	—
GCF		2,754		383			—
Bridgeline		—		(4,731	)		2,370
	$	9,968	$	(3,776	)	$	2,370
Contributions to VESCO	$	9,102	$	5,990		$	—
Distributions from GCF	$	2,306	$	387		$	—

Our equity in earnings of VESCO for 2006 and 2005 includes $2.9 million and $1.4 million, respectively, for partially settled business interruption insurance claims. For 2005, our equity in earnings of VESCO and GCF includes only our share of their results for the two months ended December 31, 2005.

The following table shows summarized financial information of our unconsolidated investments for the periods indicated (in thousands):

	Year Ended December 31,
	2006				2005					2004
	GCF		VESCO		GCF		VESCO(1)			Bridgeline(2)
Revenues	$	46,545	$	126,695	$	48,024	$	146,974		$	2,328,209
Cost of sales and operations		40,325		103,602		41,195		149,847			2,328,274
Income (loss) from operations		6,220		23,093		6,829		(151,852	)		(65	)
Net income (loss)		6,622		23,093		6,973		(151,852	)		(556	)

	As of December 31,
	2006				2005
	GCF		VESCO		GCF		VESCO
Current assets	$	12,181	$	47,749	$	8,070	$	39,448
Property, plant and equipment, net		52,258		102,028		55,220		53,144
Other assets		—		328		—		275
Total assets		64,439		150,105		63,290		92,867
Current liabilities		1,206		20,444		729		26,801
Long-term liabilities		—		7,851		—		7,101
Owners’ equity		63,233		121,810		62,561		58,965
Total liabilities and owners’ equity		64,439		150,105		63,290		92,867

(1) VESCO’s results include a $136.0 million non-cash impairment charge related to hurricane damage suffered in August.

(2) We sold our interests in Bridgeline in August 2005. Results of operations information for 2005 is not available.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 6—Debt Obligations

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

	December 31,
	2006			2005
	(in thousands)
Senior secured term loan facility, variable rate, due October 2012(1)	$	1,234,375		$	1,246,875
Senior secured asset sale bridge loan facility, variable rate, due October 2007(1)(2)		700,000			700,000
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)		—			—
Total principal amount		2,184,375			2,196,875
Current maturities		(712,500	)		(12,500	)
Long-term debt	$	1,471,875		$	2,184,375
Irrevocable standby letters of credit outstanding(3)	$	227,571		$	213,556

(1) These facilities became effective with the closing of the DMS acquisition on October 31, 2005. The entire $250 million available under the senior secured revolving credit facility may also be utilized for letters of credit.

(2) See Note 19.

(3) These letters of credit were issued under our $300 million senior secured synthetic letter of credit facility, which terminates in October 2012.

Information Regarding Variable Interest Rates Paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our significant consolidated variable-rate debt obligations during 2006:

	Range of Interest Rates Paid	Weighted Average Interest Rate Paid
Senior secured term loan facility	6.59% to 7.75%	7.03%
Senior secured asset sale bridge loan facility	6.83% to 7.62%	7.26%

Consolidated Debt Maturity Table

The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter (in thousands):

2007	$	712,500
2008		12,500
2009		12,500
2010		12,500
2011		12,500
Thereafter		1,421,875
	$	2,184,375

See also Note 19—Subsequent Events.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Description of Debt Obligations

Senior Secured Credit Facility

On October 31, 2005, we entered into a senior secured credit agreement with a syndicate of financial institutions and other institutional lenders. The senior secured credit facility provides senior secured financing of $2,500 million, consisting of:

• a $1,250 million senior secured term loan facility;

• a $700 million senior secured asset sale bridge loan facility;

• a $250 million senior secured revolving credit facility; and

• a $300 million senior secured synthetic letter of credit facility.

The entire amount of the senior secured revolving credit facility is available for letters of credit and includes a limited borrowing capacity for borrowings on same-day notice referred to as swingline loans. The lenders under the senior secured synthetic letter of credit facility pre-funded the entire amount of their respective commitments by depositing such amounts in a designated deposit account that is held by the administrative agent and which is used to support letters of credit.

We may add one or more incremental term loan facilities, and/or one or more incremental synthetic letter of credit facilities and/or increase the commitments under the senior secured revolving credit facility in an aggregate amount for all such increases of up to $400 million, subject to the satisfaction of certain conditions. No commitments for such incremental facilities have been requested by the Company or offered by the lenders and no lender under the senior secured credit facility will be obligated to provide any incremental credit extensions unless it so agrees.

Borrowings under the senior secured credit facilities, other than the senior secured synthetic letter of credit facility, will bear interest at a rate equal to an applicable margin plus, at our option, either (a) a base rate determined by reference to the higher of (1) the prime rate of Credit Suisse and (2) the federal funds rate plus ¹/2 of 1% or (b) LIBOR as determined by reference to the costs of funds for dollar deposits for the interest period relevant to such borrowing adjusted for certain statutory reserves. At December 31, 2006, the applicable margin for borrowings under the senior secured revolving credit facility is 1.25% with respect to base rate borrowings and 2.25% with respect to LIBOR borrowings. Upon repayment of the senior secured asset sale bridge loan facility, the margin for borrowings under the senior secured revolving credit facility will be 1.00% with respect to base rate borrowings and 2.00% with respect to LIBOR borrowings. The applicable margin for borrowings under the senior secured revolving credit facility may fluctuate based upon the Company’s leverage ratio as defined in the credit agreement.

We are required to pay a facility fee, quarterly in arrears, to the lenders under the senior secured synthetic letter of credit facility equal to (i) 2.25% of the amount on deposit in the designated deposit account (2.00% following repayment of the $700 million senior secured asset sale bridge loan facility) plus (ii) the administrative cost incurred by the deposit account agent for such quarterly period.

In addition to paying interest on outstanding principal under the senior secured credit facilities, we are required to pay a commitment fee equal to 0.50% of the currently unutilized commitments thereunder. The commitment fee rate may fluctuate based upon the Company’s leverage ratios.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The senior secured credit agreement requires us to prepay loans outstanding under the senior secured term loan facility and the senior secured asset sale bridge loan facility, subject to certain exceptions, with:

• 50% of our annual excess cash flow (which percentage will be reduced to 25% if our total leverage ratio is no more than 4.00 to 1.00 and to 0% if our total leverage ratio is no more than 3.00 to 1.00 commencing with the fiscal year end December 31, 2006);

• 100% of the net cash proceeds of all non-ordinary course asset sales, transfers, or other dispositions of property, subject to certain exceptions;

• 100% of the net cash proceeds of any incurrence of debt, other than debt permitted under the senior secured credit agreement.

Prepayments, other than voluntary prepayments of outstanding amounts under the senior secured revolving credit facility, will be applied first, to the senior secured asset sale bridge loan facility and second, to the term loan facility (and applied to reduce remaining amortization payments of the term loan facility in chronological order of maturity). We may voluntarily reduce the unutilized portion of the commitments and prepay outstanding loans under the senior secured credit facilities at any time without premium or penalty, other than customary “breakage” costs with respect to LIBOR loans.

We are required to repay the term loan facility in quarterly principal amounts of 0.25% of the original principal amount, with the remaining amount payable October 31, 2012. Principal amounts outstanding under the senior secured asset sale bridge loan facility are due and payable in full on October 31, 2007.

Principal amounts outstanding under the senior secured revolving credit facility are due and payable in full on October 31, 2011.

Principal amounts outstanding under the senior secured synthetic letter of credit facility are due and payable in full on October 31, 2012.

All obligations under the senior secured credit agreement and certain secured hedging arrangements are unconditionally guaranteed, subject to certain exceptions, by each of our existing and future domestic restricted subsidiaries, referred to, collectively, as the guarantors.

All obligations under the senior secured credit facilities and certain secured hedging arrangements, and the guarantees of those obligations, are secured by substantially all of the following assets, subject to certain exceptions:

• a pledge of the capital stock and other equity interests held by us or any guarantor (except that we will not pledge more than 65% of the voting stock and other voting equity interests of any foreign subsidiary); and

• a security interest in, and mortgages on, our and our guarantors’ tangible and intangible assets.

The senior secured credit agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness (including guarantees and hedging obligations) or issue preferred stock; create liens on assets; enter into sale and leaseback transactions; engage in mergers or consolidations; sell assets; pay dividends and make distributions or repurchase capital stock and other equity interests; make investments, loans or advances; make capital expenditures; repay, redeem or repurchase certain indebtedness; make certain acquisitions; engage in certain transactions with affiliates; amend certain debt and other material agreements; change our lines of business; and impose certain restrictions on restricted subsidiaries that are not guarantors, including restrictions on the ability of such subsidiaries that are not guarantors to pay dividends.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In addition, beginning with the quarter ended March 31, 2006, the senior secured credit agreement required us to maintain certain specified maximum total leverage ratios and certain specified minimum interest coverage ratios.

The senior secured credit agreement will permit us to transfer, on one or more occasions:

• assets (including equity interests of a subsidiary or other entity) to one or more MLPs and/or one or more subsidiaries of any MLP; and

• equity interests in an MLP, or, in certain circumstances, the general partner of an MLP.

In each case we are required to comply with certain limitations, including minimum cash consideration requirements.

$250 Million Senior Notes Offering

On October 31, 2005 we completed the private placement under Rule 144A and Regulation S of the Securities Act of 1933 of $250 million in aggregate principal amount of eight year senior unsecured notes (“the Notes”). Proceeds from the Notes plus borrowings under our senior secured credit facility were used to repay pre-existing debt and fund a portion of the DMS acquisition.

The Notes:

• are our unsecured senior obligations;

• rank pari passu in right of payment with all our existing and future senior indebtedness, including indebtedness under our new senior secured credit facility;

• are effectively subordinated to all our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including indebtedness under the senior secured credit facilities;

• are structurally subordinated to all existing and future claims of creditors (including trade creditors) and holders of preferred stock of our subsidiaries that do not guarantee the Notes;

• rank senior in right of payment to any of our future subordinated indebtedness;

• are guaranteed on a senior unsecured basis by the subsidiary guarantors that guarantee the senior secured credit facilities; and

• are subject to registration with the SEC pursuant to a registration rights agreement.

Interest on the Notes accrues at the rate of 8 ¹/2% per annum and is payable in cash semi-annually in arrears on May 1 and November 1, commencing May 1, 2006. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months. Additional interest may accrue on the Notes in certain circumstances pursuant to a registration rights agreement.

On and after November 1, 2009, we may redeem all or part of the Notes at our option, at 104.250% of the principal amount for the twelve-month period beginning November 1, 2009, at 102.125% of the principal amount for the twelve-month period beginning November 1, 2010, and at 100% of the principal amount thereafter. In each case, accrued and unpaid interest is payable to the date of redemption. In addition, before November 1, 2009, we may redeem all or part of the Notes at the make-whole price set forth under the indenture. At any time prior to November 1, 2008, we may redeem up to 35% of the Notes with the net cash proceeds of certain equity offerings at a redemption price equal to 108.500% of the aggregate principal amount thereof,plusaccrued and unpaid interest thereon to the redemption date.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 7—Stock and Other Compensation Plans

Accounting for Equity Awards

Effective January 1, 2006, we began to account for Targa Investments’ equity awards granted to our employees using the provisions of SFAS 123R. SFAS 123R requires us to recognize compensation expense related to equity awards based on the grant date fair value of the award. The fair value of an award of nonvested common stock is measured at its fair value as if it were vested and issued on the grant date. The fair value of a stock option award is estimated using the Black-Scholes option pricing model. Under SFAS 123R, the fair value of all awards expected to vest is amortized to earnings on a straight-line basis over the requisite service period.

Prior to our adoption of SFAS 123R, we recognized compensation expense related to stock options only if the grant date fair value of the underlying stock was greater than the exercise price of the option. Our recognition of compensation expense in connection with awards of nonvested common stock did not change under SFAS 123R.

We apply SFAS 123R prospectively to new stock option awards and to stock option awards modified, repurchased, or cancelled on or after January 1, 2006. We shall continue to account for the nonvested portion of stock option awards outstanding on January 1, 2006 using the intrinsic value method. Stock-based compensation expense is based on the awards ultimately expected to vest, and has been reduced for estimated forfeitures. The effects of applying SFAS 123R during the year ended December 31, 2006 did not have a material effect on our net income.

For the years ended December 31, 2005 and 2004, on a pro forma basis, the effect on our net income of using the fair value method of SFAS 123 instead of the intrinsic-value method allowed previously was not material.

Stock Options

Under Targa Investments’ 2005 Incentive Compensation Plan (“the Plan”), options to purchase a fixed number of shares of its stock may be granted to our employees, directors and consultants. Generally, options granted under the Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.

The fair value of each option granted since our adoption of SFAS 123R was estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including (i) expected term of the options of ten years, (ii) a risk-free interest rate of 4.5%, (iii) expected dividend yield of 0%, and (iv) expected stock price volatility on Targa Investments’ common stock of 23.8%. Our selection of the risk-free interest rate was based on published yields for U.S. government securities with comparable terms. Because Targa Investments is a non-public company, 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 calculated fair value of options granted during the twelve months ended December 31, 2006 is $0.21 per share.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table shows stock option activity for periods indicated:

	Number of Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (In Years)
Outstanding at beginning of period	—		$	—
Granted	909,002			8.50
Outstanding at December 31, 2004	909,002		$	8.50
Granted	5,148,114			7.65
Converted to options on Series B preferred stock	(949,002	)		8.50
Outstanding at December 31, 2005	5,108,114		$	7.64
Granted	51,672			8.50
Cancelled	(54,474	)		8.50
Outstanding at December 31, 2006	5,105,312		$	7.64	8.85
Exercisable at December 31, 2006	1,120,440		$	7.23	8.85

We recognized $0.1 million, $0.1 million and $0 of compensation expense associated with stock options during the years ended December 31, 2006, 2005 and 2004, respectively. As of December 31, 2006, we expect to incur an additional $0.1 million of expense related to non-vested stock options over a weighted-average period of approximately two years.

Non-vested Common Stock

Under the Plan, Targa Investments can also issue non-vested (i.e., restricted) common stock to our employees, directors and consultants. Except for 73,049 previously awarded shares that were forfeited during 2006, all 6.2 million shares of restricted common stock provided for under the Plan are outstanding as of December 31, 2006.

Restricted stock awards entitle recipients to exchange restricted common shares for unrestricted common shares (at no cost to them) once the defined vesting period expires, subject to certain forfeiture provisions. The restrictions on the non-vested shares generally lapse four years from the date of grant. Compensation expense is recognized on a straight-line basis over the vesting period. The fair value of non-vested stock is measured on the grant date using the estimated market price of Targa Investments common stock on such date.

The following table provides a summary of Targa Investments’ non-vested common stock for the periods indicated:

	Year Ended December 31,
	2006			2005			2004
Outstanding at beginning of period		5,501,132			1,287,805			—
Granted		72,564			6,105,818			1,609,756
Vested		(612,799	)		(1,892,491	)		(321,951	)
Forfeited		(73,049	)		—			—
Outstanding at end of period		4,887,848			5,501,132			1,287,805
Weighted average grant date fair value per share	$	1.16		$	1.16		$	0.62

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The total fair value of non-vested common shares that vested during the year ended December 31, 2006 was $0.7 million. We recognized $2.7 million, $1.6 million and $0.5 million of compensation expense associated with the vesting of restricted stock during the years ended December 31, 2006, 2005 and 2004, respectively. As of December 31, 2006, we expect to incur an additional $3.3 million of expense related to non-vested shares issued to our employees, over a weighted-average period of approximately the next two years.

Other Compensation Plans

We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute an amount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our sole discretion. All Targa contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $6.0 million, $2.4 million and $0.7 million during 2006, 2005 and 2004, respectively.

Note 8—Stockholders’ Equity

At December 31, 2004, we had outstanding 1,350,500 shares of Series A Convertible Participating Preferred Stock (the “Series A stock”), 1,609,756 shares of common stock, and 949,002 options on common stock. In order for our financial statements to be compliant with Securities and Exchange Commission Regulation S-X, our Series A Stock is required to be classified outside of stockholders’ equity. Our previously issued financial statements reported the Series A Stock as a component of stockholders’ equity.

Prior to the closing of the DMS acquisition, we engaged in a corporate reorganization pursuant to which we became a second-tier, wholly owned subsidiary of our newly-formed parent holding company, Targa Resources Investments Inc. (“Targa Investments”). In the reorganization, our stockholders exchanged their shares of Targa common stock, Targa stock options, and Targa Series A Convertible Participating Preferred Stock for shares of Targa Investments having the same terms as the Targa stock, and our Series A stock was retired.

Immediately after the reorganization, the only significant asset of Targa Investments was its ownership of 100% of the outstanding capital stock of an intermediate holding company, whose sole asset was its ownership of 100% of our outstanding capital stock, which consists of one thousand shares of common stock.

Following the reorganization, and in connection with the closing of the DMS acquisition, Targa Investments issued a new series of preferred stock in exchange for its outstanding common stock and preferred stock and issued new common stock to our management. In addition, certain Targa Investments investors and members of our management purchased additional equity interests in Targa Investments for cash. Approximately $316 million of such cash was contributed to us by Targa Investments concurrent with the closing of the DMS acquisition.

Additionally, outstanding options on our common stock were exchanged for options on Targa Investments’ Series B preferred stock.

Note 9—Derivative Instruments and Hedging Activities

At December 31, 2006, OCI included $58.8 million ($34.8 million, net of tax) of unrealized net gains on commodity hedges, and $1.4 million ($0.8 million, net of tax) of unrealized net gains on interest rate hedges.

At December 31, 2005, OCI included $30.2 million ($18.9 million, net of tax) of unrealized net losses on commodity hedges, and $0.2 million ($0.1 million, net of tax) of unrealized losses on interest rate hedges.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

During 2006, deferred net gains on commodity hedges of $31.2 million were reclassified from OCI and credited to income as an increase in revenues, and deferred net gains on interest rate hedges of $1.0 million were reclassified from OCI and credited to income as a reduction in interest expense.

During 2005, deferred net losses of $7.5 million were reclassified from OCI and charged to expense as a reduction in revenues, and deferred net losses on interest rate hedges of $0.1 million were reclassified from OCI and charged to expense as an increase in interest expense. Adjustments for hedge ineffectiveness decreased revenues by $0.4 million in 2005.

On August 2, 2005, concurrent with the announcement of the DMS acquisition, we entered into certain swap transactions in respect of incremental natural gas and NGL sales volumes expected to occur during the years 2006 through 2009. We paid a premium of $17 million in order to limit any payment that might otherwise be payable to the counterparty on termination of the swap transactions as a result of a failure to close the DMS acquisition. Upon the closing of the DMS acquisition, the counterparty refunded $3.4 million of the premium. During the period from August 2, 2005 until the DMS acquisition closing date, the swap transactions did not qualify for hedge accounting treatment under SFAS 133. As such, in addition to expensing the $13.6 million net premium paid, we recognized a mark-to-market loss of $60.4 million. The swap transactions were designated as hedges on October 31, 2005.

During the year ended December 31, 2004, deferred net losses on commodity hedges of $1.2 million were reclassified from OCI and charged to expense as a reduction in revenues, and adjustments for hedge ineffectiveness increased revenues by $0.1 million.

As of December 31, 2006, $43.8 million ($25.9 million, net of tax) of deferred net gains on commodity hedges and $1.4 million ($0.9 million, net of tax) of deferred net gains on interest rate hedges recorded in OCI are expected to be reclassified to earnings during the next twelve months.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At December 31, 2006, our open derivatives designated as hedges consist of the following:

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu		MMBtu per Day				Fair Value
				2007	2008	2009	2010
								(in thousands)
Swap	IF-HSC	$	9.08	2,740	—	—	—	$	2,371
Swap	IF-HSC		8.09	—	2,328	—	—		272
Swap	IF-HSC		7.39	—	—	1,966	—		(128	)
				2,740	2,328	1,966	—		2,515
Swap	IF-NGPL MC		8.56	8,152	—	—	—		7,262
Swap	IF-NGPL MC		8.43	—	6,964	—	—		3,444
Swap	IF-NGPL MC		8.02	—	—	6,256	—		1,677
Swap	IF-NGPL MC		7.43	—	—	—	5,685		932
				8,152	6,964	6,256	5,685		13,315
Swap	IF-Waha		7.71	30,118	—	—	—		14,445
Swap	IF-Waha		7.27	—	29,307	—	—		(1,499	)
Swap	IF-Waha		6.86	—	—	28,854	—		(4,729	)
Swap	IF-Waha		7.38	—	—	—	3,809		514
				30,118	29,307	28,854	3,809		8,731
Total Swaps				41,010	38,599	37,076	9,494		24,561
Floor	IF-NGPL MC		6.45	520	—	—	—		200
Floor	IF-NGPL MC		6.55	—	1,000	—	—		342
Floor	IF-NGPL MC		6.55	—	—	850	—		246
				520	1,000	850	—		788
Floor	IF-Waha		6.70	350	—	—	—		137
Floor	IF-Waha		6.85	—	670	—	—		231
Floor	IF-Waha		6.55	—	—	565	—		154
				350	670	565	—		522
Total Floors				870	1,670	1,415	—		1,310
Basis Swap Jan 2007 Rec IF-HH minus $0.01, pay GD-HH, 899,000 MMBtu									7
								$	25,878
NGLs
Instrument Type	Index	Avg. Price $/gal		Barrels per Day				Fair Value
				2007	2008	2009	2010
								(in thousands)
Swap	OPIS-MB	$	0.87	8,414	—	—	—	$	697
Swap	OPIS-MB		0.83	—	8,007	—	—		(1,489	)
Swap	OPIS-MB		0.80	—	—	7,495	—		(3,447	)
Swap	OPIS-MB		0.88	—	—	—	1,759		606
				8,414	8,007	7,495	1,759	$	(3,633	)

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Condensate

Instrument Type	Index	Avg. Price $/Bbl		Barrels per day				Fair Value
				2007	2008	2009	2010
								(in thousands)
Swap	NY-WTI	$	72.82	439	—	—	—	$	1,225
Swap	NY-WTI		70.68	—	384	—	—		415
Swap	NY-WTI		69.00	—	—	322	—		183
Swap	NY-WTI		68.10	—	—	—	301		152
Total Swaps				439	384	322	301		1,975
Floor	NY-WTI	$	58.60	25	—	—	—		19
Floor	NY-WTI		60.50	—	55	—	—		83
Floor	NY-WTI		60.00	—	—	50	—		84
Total Floors				25	55	50	—		186
				464	439	372	301	$	2,161

These derivatives have been designated as cash flow hedges of forecasted purchases and sales of commodities expected to be owned by us.

Customer Derivatives

Period	Commodity	Instrument Type	Daily Volumes	Average Price		Index	Fair Value
			(In thousands)				(In thousands)
Purchases
Jan 2007—Dec 2007	Natural gas	Swap	6,382 MMBtu	$	7.94 per MMBtu	NY-HH	$	(3,296	)
Sales
Jan 2007—Dec 2007	Natural gas	Fixed price sale	6,382 MMBtu	$	7.91 per MMBtu	—		3,223
							$	(73	)

These are commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements. They have been marked to market.

We also have interest rate swaps with a notional amount of $350 million. The interest rate swaps effectively fix our interest rate on $350 million in borrowings under our senior secured term loan facility to a rate of 4.8% plus the applicable LIBOR margin (2.25% at December 31, 2006) through November 2007. At December 31, 2006, the fair value of our interest rate swaps was $1.4 million.

F-31

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following shows the balance sheet classification of the fair value of open commodity and interest rate derivatives at the dates indicated.

	December 31,
	2006			2005
	(in thousands)
Current assets	$	34,255		$	1,220
Noncurrent assets		15,851			150
Current liabilities		(6,611	)		(29,851	)
Noncurrent liabilities		(17,731	)		(62,969	)
	$	25,764		$	(91,450	)

Note 10—Income Taxes

We provide for income taxes using the asset and liability method. Accordingly, deferred taxes are recorded for the differences between the tax and book bases of assets and liabilities that will reverse in future periods.

Our provisions for income taxes for the periods indicated are as follows (in thousands):

	Targa Resources, Inc.
	Year Ended December 31, 2006		Year Ended December 31, 2005			Year Ended December 31, 2004
Current expense	$	34	$	205		$	—
Deferred expense (benefit)		16,175		(6,742	)		5,227
	$	16,209	$	(6,537	)	$	5,227

F-32

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our deferred income tax assets and liabilities at December 31, 2006 and 2005 consist of differences related to the timing of recognition of certain types of costs as follows:

	December 31,
	2006			2005
	(in thousands)
Deferred tax assets:
Net operating loss	$	182,145		$	33,909
Commodity hedging contracts and other		—			34,193
Asset retirement obligation		484			414
		182,629			68,516
Deferred tax liabilities:
Investments(1)		(168,396	)		(26,910	)
Net property, plant, and equipment		(40,572	)		(24,096	)
Commodity hedging contracts and other		(8,994	)		—
		(217,962	)		(51,006	)
Net deferred tax asset (liability)	$	(35,333	)	$	17,510
Federal	$	(26,784	)	$	16,275
Foreign		199			72
State		(8,748	)		1,163
	$	(35,333	)	$	17,510
Balance sheet classification of deferred tax assets (liabilities):
Current asset	$	—		$	10,472
Long-term asset		—			7,038
Current liability		(11,383	)		—
Long-term liability		(23,950	)		—
	$	(35,333	)	$	17,510

(1) Our deferred tax liability attributable to investments includes outside basis differences in assets and liabilities of our wholly-owned partnerships and our equity method investments.

At December 31, 2006, for federal income tax purposes, we had carryforwards of approximately $453.5 million of regular tax net operating losses (“NOL”). The NOL carryforwards expire between 2023 and 2027.

F-33

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Set forth below is reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes and the income tax provision in the accompanying consolidated statements of operations for the periods indicated (in thousands):

	Targa Resources, Inc.
	Years Ended December 31,
	2006			2005			2004
U.S. federal income tax provision at statutory rate	$	13,868		$	(7,263	)	$	5,736
State income taxes		2,743			211			—
Other		(402	)		515			(509	)
Income tax provision	$	16,209		$	(6,537	)	$	5,227

Note 11—Commitments and Contingencies

Certain property and equipment is leased under non-cancelable leases that require fixed monthly rental payments and expire at various dates through 2099. Surface and underground access for gathering, processing, and distribution assets that are located on property not owned by us is obtained through right-of-way agreements, which require annual rental payments and expire at various dates through 2099. Future non-cancelable commitments related to these obligations and our asset retirement obligations are presented below (in millions):

	2007		2008		2009		2010		2011		2012+
Operating leases	$	17.6	$	13.9	$	9.3	$	8.2	$	8.1	$	30.5
Capacity payments		2.6		2.5		2.4		0.8		—		—
Asset retirement obligations		—		—		—		—		—		11.6
	$	20.2	$	16.4	$	11.7	$	9.0	$	8.1	$	42.1

Total expenses related to operating leases and capacity payments were $11.8 million and $2.7 million, respectively, for 2006, $1.9 million and $0.1 million, respectively, for 2005, and $0.3 million and $0.2 million, respectively, for 2004.

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 96-1, “Environmental Remediation Liabilities.” Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

Prior to our purchase of the Acadia plant site and other assets from ConocoPhillips, the Acadia plant site, located in Louisiana, was identified as having benzene, toluene, ethyl benzene and xylene contamination, collectively (“BTEX”). The BTEX contamination was reported by ConocoPhillips to the Louisiana Department of Environmental Quality (“LDEQ”) who identified ConocoPhillips as a potentially responsible party. ConocoPhillips has begun remediation activities in coordination with the LDEQ, and is negotiating a cooperative

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

agreement with the LDEQ regarding environmental assessment and remedial activities at the site. Under the terms of our purchase and sales agreement, ConocoPhillips retains the liability for the BTEX remediation and for all third party costs or claims relating to, arising out of, or connected with corrective actions/remediation of the BTEX contamination. As a result, we have not recorded a liability for environmental remediation as it relates to the BTEX contamination.

Prior to our purchase of DMS from Dynegy, the LDEQ issued a Compliance Order charging VESCO (a joint venture in which DMS owns a 22.9% interest) with failure to initiate quarterly leak monitoring of valve emission sources at the Venice Stabilizer Plant (VSP) as part of VESCO’s Title V air permit issued in December 1997. On May 14, 2004 LDEQ issued a Notice of Potential Penalty (NOPP) seeking additional information from VESCO. We have been engaged in discussions with LDEQ about a monetary penalty relating to the alleged violations and whether it is proper for LDEQ to apply its penalty matrix calculations in this proceeding. In March 2007, the LDEQ tentatively agreed that a penalty amount, not exceeding $250,000, would resolve the matter described above as well as resolving two other alleged violations at other Gulf Coast plants. Discussions are continuing with the LDEQ on the form of the settlement and associated consent order.

Our environmental liability at December 31, 2006 and 2005 was $2.3 million and $2.5 million, respectively. Our December 31, 2006 liability consisted of $0.8 million for gathering system leaks and $1.5 million for ground water assessment and remediation.

Litigation Summary

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 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 (“DMS”) 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 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 indexes that were allegedly manipulated. At trial, the plaintiff’s claim with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the trial court and abated for a future trial, and the jury found in favor of the plaintiff on the lost gas claim, awarding approximately $1.6 million in damages. In May 2004, the Versado Defendants’ motion to set aside this jury verdict was granted by the court and the jury award to the plaintiff was vacated. The plaintiff filed its notice of appeal with the 14th Court of Appeals (“COA”) in October 2004 and its appellate brief in December 2004.

In September 2006, the COA 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 Versado Defendants to approximately $2.7 million. In October 2006, the Versado Defendants filed a motion for rehearing with the COA. In October 2006, the COA requested Apache to file a response to the Versado Defendants motion for rehearing and Versado Defendants filed a Reply to that response. After rehearing, the COA affirmed its decision reinstating the original jury verdict in Apache’s favor. With interest and attorneys fees that verdict stands at approximately $2.8 million.

F-35

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

In March 2007, the restraint in the severed lawsuit referenced above was released and the severed case is proceeding. The Versado Defendants have filed a motion for partial summary judgment on the index manipulation claims.

As a result of damage caused by Hurricane Rita, Targa Midstream Services LP’s (“TMSLP”, a wholly owned subsidiary of Targa) West Cameron 229A platform sank in late September 2005. On November 12, 2005, the submerged wreckage was struck by an integrated tug-barge, the M/T Rebel, owned by K-Sea Transportation. As much as 25,000 barrels of No. 6 fuel oil may have entered the Gulf of Mexico waters as the barge dragged part of the platform debris approximately three (3) miles from the sunken platform location. After receiving a letter from K-Sea threatening to hold us liable for all damages, TMSLP filed suit in federal district court in Galveston on November 21, 2005, seeking to hold K-Sea responsible for damage to the platform.

In January 2006, Rios Energy, owner of the oil being transported in the barge intervened in the existing suit and filed a new suit in the same federal court against both TMSLP and K-Sea alleging their negligence caused the loss of and damage to Rios’ oil. On March 8, 2006, K-Sea filed a counterclaim against TMSLP seeking to recover its alleged damages in excess of $90 million. In February 2007, K-Sea filed actions against TMSLP under admiralty law, seeking to secure any judgment K-Sea obtains in an amount equal to 1.5 times K-Sea’s claimed damages, or $135 million. Although TMSLP believes the validity of the actions seeking attachment of its assets were without merit, in order to resolve K-Sea’s concerns over security for its claims, we agreed to provide a guarantee to K-Sea pursuant to which we would satisfy any final, non-appealable judgment or settlement against TMSLP if TMSLP is unable to pay in such an event. Discovery is proceeding in the underlying claim, counterclaim and Rios Energy lawsuit. TMSLP intends to vigorously contest liability herein but can give no assurances regarding the outcome of the initial proceeding, the counterclaim or the Rios Energy lawsuit.

On December 8, 2005, WTG Gas Processing filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc., and three other Targa entities and Warburg Pincus, seeking damages from the defendants. The suit alleges that Targa and Warburg Pincus, along with ConocoPhillips and Morgan Stanley, tortuously interfered with (i) a contract WTG claims to have had to purchase certain ConocoPhillips assets, and (ii) with prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. Discovery, with the exception of expert discovery on damages, is largely complete. Our motion for summary judgment is scheduled for oral argument on April 10, 2007. Targa intends to vigorously contest liability herein but can give no assurances regarding the outcome of the proceeding.

Note 12—Related-Party Transactions

Relationships with Warburg Pincus

Warburg Pincus beneficially owns approximately 75% of the outstanding voting stock of our parent. Warburg Pincus is able to elect members of our board of directors, appoint new management and approve any action requiring the approval of our stockholders, including amendment of our certificate of incorporation and mergers or sales of substantially all of our assets. The directors elected by Warburg Pincus will be able to make decisions affecting our capital structure, including decisions to issue additional capital stock, implement stock repurchase programs and declare dividends.

F-36

TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Relationships with Merrill Lynch, Pierce, Fenner & Smith Incorporated (“Merrill Lynch”)

Equity

An affiliate of Merrill Lynch holds a non-voting equity interest in the general partner of Warburg Pincus Private Equity VIII, L.P. and Warburg Pincus Private Equity IX, L.P., the principal shareholders of Targa Investments. On October 31, 2005, Merrill Lynch Ventures L.P. 2001, an affiliate of Merrill Lynch, purchased an equity interest in our parent holding company, Targa Investments, for $50 million in cash, which was then contributed to us by Targa Investments in connection with our equity reorganization.

Financial Services

Merrill Lynch was an initial purchaser of the notes, and acted as our financial advisor with respect to our purchase of all the equity interests in DMS. An affiliate of Merrill Lynch is a lender and an agent under our existing senior secured credit facilities.

Hedging Arrangements

We have entered into various commodity derivative transactions with Merrill Lynch Commodities Inc. (“MLCI”), an affiliate of Merrill Lynch. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas, NGL, and condensate over periods ending in 2010, and we have agreed to pay Merrill Lynch floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with Merrill Lynch as of December 31, 2006:

Period	Commodity	Instrument Type	Daily Volumes	Average Price	Index
Jan 2007	Natural gas	Basis Swap	20,000 MMBtu	Receive IF-HH minus $0.01, pay GD-HH
Jan 2007 – Dec 2007	Natural gas	Swap	26,118 MMBtu	$7.65 per MMBtu	IF-Waha
Jan 2008 – Dec 2008	Natural gas	Swap	25,765 MMBtu	7.23 per MMBtu	IF-Waha
Jan 2009 – Dec 2009	Natural gas	Swap	25,474 MMBtu	6.82 per MMBtu	IF-Waha
Jan 2010 – Dec 2010	Natural gas	Swap	3,289 MMBtu	7.39 per MMBtu	IF-Waha
Jan 2007 – Dec 2007	NGLs	Swap	5,998 barrels	0.82 per gallon	OPIS-MB
Jan 2008 – Dec 2008	NGLs	Swap	5,847 barrels	0.79 per gallon	OPIS-MB
Jan 2009 – Dec 2009	NGLs	Swap	5,547 barrels	0.76 per gallon	OPIS-MB
Jan 2007 – Dec 2007	Condensate	Swap	319 barrels	75.27 per barrel	NY-WTI
Jan 2008 – Dec 2008	Condensate	Swap	264 barrels	72.66 per barrel	NY-WTI
Jan 2009 – Dec 2009	Condensate	Swap	202 barrels	70.60 per barrel	NY-WTI
Jan 2010 – Dec 2010	Condensate	Swap	181 barrels	69.28 per barrel	NY-WTI

At December 31, 2006, the fair value of these open positions is a liability of $2.8 million. During 2006, Merrill Lynch paid us $6.8 million in commodity derivative settlements. There were no commodity derivative settlements with Merrill Lynch prior to 2006.

Commercial Relationships

In April 2004, we entered into a base agreement for the purchase and sale of natural gas with Entergy-Koch Trading, LP, pursuant to which Entergy-Koch Trading, LP typically purchases natural gas for fuel at its affiliated cogeneration facility in Lake Charles. On November 1, 2004, MLCI acquired Entergy-Koch, LP and became a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

successor to this agreement. Pricing terms under the agreement are governed by reference to specified index prices plus a premium.

Other Relationships

On December 16, 2004, we acquired a 40% ownership interest in Bridgeline. During 2005 we had net purchases of natural gas of $11.4 million from Bridgeline. During the period from December 16, 2004 to December 31, 2004, we purchased $1.4 million of natural gas from Bridgeline. These transactions were at market prices consistent with those paid to non-affiliate entities. We sold our interest in Bridgeline in August 2005.

Note 13—Fair Value of Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS 107,“Disclosures About Fair Value of Financial Instruments.”The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Derivative financial instruments included in our financial statements are stated at fair value. The carrying amounts and fair values of our other financial instruments are as follows as of December 31, 2006:

	Carrying Amount		Fair Value
	(In thousands)
Senior secured term loan facility, variable rate	$	1,234,375	$	1,240,547
Senior secured asset sale bridge loan facility, variable rate		700,000		700,000
Senior unsecured notes, 8 1/2% fixed rate		250,000		251,875

The carrying value of the senior secured asset sale bridge loan facility approximates its fair value, as its remaining term is less than one year and its interest rate is based on prevailing market rates. The fair value of the senior secured term loan facility and the senior unsecured notes are based on quoted market prices based on trades of such debt.

Note 14—Supplemental Cash Flow Disclosure

Cash activity related to interest on indebtedness, income taxes and business interruption insurance were:

	Year Ended December 31, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004
	(In thousands)
Cash payments for interest	$	170,928	$	22,266	$	5,086
Cash payments for income taxes	$	59	$	166	$	—
Cash receipts from business interruption insurance	$	14,926	$	—	$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 15—Segment Information

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

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 NGL and fractionating, storing, and transporting of finished NGL. 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 West Louisiana.

Our NGL Distribution and Marketing segment markets our own natural gas liquids production and also purchased natural gas liquids products in selected United States markets. We also had the right to purchase or market substantially all of ChevronTexaco’s natural gas liquids pursuant to a Master Natural Gas Liquids Purchase Agreement.

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, purchasing natural gas liquids products from refinery customers and selling 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.

Eliminations and Other 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our reportable segment information is shown in the following tables (in thousands):

	Year Ended December 31, 2006
	Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues	$	1,486,081	$	63,813		$	3,315,535	$	1,267,452	$	—		$	6,132,881
Intersegment revenues		1,104,938		114,700			423,234		63,106		(1,705,978	)		—
Revenues		2,591,019		178,513			3,738,769		1,330,558		(1,705,978	)		6,132,881
Product purchases		2,064,436		3			2,496,448		879,945		—			5,440,832
Intersegment product purchases		2,939		(3	)		1,229,673		440,646		(1,673,255	)		—
Product purchases		2,067,375		—			3,726,121		1,320,591		(1,673,255	)		5,440,832
Operating expenses		118,123		103,992			2,044		10		—			224,169
Intersegment operating expenses		617		32,106			—		—		(32,723	)		—
Operating expenses		118,740		136,098			2,044		10		(32,723	)		224,169
Operating margin	$	404,904	$	42,415		$	10,604	$	9,957	$	—		$	467,880
General and administrative	$	40,471	$	14,074		$	9,504	$	17,820	$	482		$	82,351
Equity in earnings of unconsolidated investments	$	7,214	$	2,754		$	—	$	—	$	—		$	9,968
Identifiable assets	$	2,375,589	$	542,718		$	352,900	$	158,015	$	28,803		$	3,458,025
Unconsolidated investments		20,610		19,602			—		—		—			40,212
Capital expenditures		115,261		23,167			—		—		4,474			142,902

	Year Ended December 31, 2005
	Gas Gathering and Processing			Logistics Assets		NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues	$	1,198,228		$	7,374	$	346,193	$	277,232	$	—		$	1,829,027
Intersegment revenues		110,830			17,624		128,470		22,088		(279,012	)		—
Revenues		1,309,058			24,998		474,663		299,320		(279,012	)		1,829,027
Product purchases		1,148,469			—		330,751		152,743		—			1,631,963
Intersegment product purchases		(2,892	)		—		137,791		142,014		(276,913	)		—
Product purchases		1,145,577			—		468,542		294,757		(276,913	)		1,631,963
Operating expenses		35,064			16,870		93		63		—			52,090
Intersegment operating expenses		46			2,053		—		—		(2,099	)		—
Operating expenses		35,110			18,923		93		63		(2,099	)		52,090
Operating margin	$	128,371		$	6,075	$	6,028	$	4,500	$	—		$	144,974
General and administrative	$	16,377		$	2,472	$	1,523	$	2,335	$	5,568		$	28,275
Equity in earnings of unconsolidated investments	$	(4,159	)	$	383	$	—	$	—	$	—		$	(3,776	)
Identifiable assets	$	2,233,051		$	547,370	$	290,521	$	202,546	$	123,098		$	3,396,586
Unconsolidated investments		48,933			13,404		—		—		—			62,337
Capital expenditures		11,605			3,252		—		—		7,119			21,976

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	Year Ended December 31, 2004
	Gas Gathering and Processing		Logistics Assets		NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other		Total
Revenues	$	602,376	$	—	$	—	$	—	$	—	$	602,376
Intersegment revenues		—		—		—		—		—		—
Revenues		602,376		—		—		—		—		602,376
Product purchases		544,918		—		—		—		—		544,918
Intersegment product purchases		—		—		—		—		—		—
Product purchases		544,918		—		—		—		—		544,918
Operating expenses		15,253		—		—		—		—		15,253
Intersegment operating expenses		—		—		—		—		—		—
Operating expenses		15,253		—		—		—		—		15,253
Operating margin	$	42,205	$	—	$	—	$	—	$	—	$	42,205
General and administrative	$	7,698	$	—	$	—	$	—	$	3,451	$	11,149
Equity in earnings of unconsolidated investments	$	2,370	$	—	$	—	$	—	$	—	$	2,370
Identifiable assets	$	429,085	$	—	$	—	$	—	$	14,128	$	443,213
Unconsolidated investments		103,496		—		—		—		—		103,496
Capital expenditures		2,633		—		—		—		2,866		5,499

The following table is a reconciliation of operating margin to net income for each period presented (in thousands):

	Year Ended December 31, 2006		Year Ended December 31, 2005			Year Ended December 31, 2004
Operating margin	$	467,880	$	144,974		$	42,205
Less:
Depreciation and amortization expense		149,687		27,141			10,631
General and administrative expense		82,351		28,275			11,149
Interest expense, net		180,189		39,856			6,406
Other, net		16,030		70,454			(2,370	)
Income tax expense (benefit)		16,209		(6,537	)		5,227
Net income (loss)	$	23,414	$	(14,215	)	$	11,162

Note 16—Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGL and crude oil. As such, our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas,

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NGL, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of natural gas, NGL and condensate transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGL and condensate handled by our facilities. A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.

Credit Risk due to Industry Concentrations

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

Counterparty Risk with Respect to Financial Instruments

Where we are exposed to credit risk in our financial instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral and we do not anticipate nonperformance by our counterparties.

Casualties and Other Risks

We maintain coverage in various insurance programs, which provide us with property damage, business interruption and other coverages which are customary for the nature and scope of our operations. The financial impact of storm events such as Hurricanes Katrina and Rita has affected many insurance carriers, and may affect their ability to meet their obligation or trigger limitations in certain insurance coverages. At present, there is no indication of any of our insurance carriers being unable or unwilling to meet its coverage obligations.

We believe that we maintain adequate insurance coverage, although insurance will not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our obligations under various agreements with our lenders.

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 17—Quarterly Financial Data (Unaudited)

The following table shows summary financial data for 2006 and 2005:

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter		Year
	(in thousands)
Year Ended December 31, 2006
Revenues	$	1,499,345		$	1,605,389		$	1,594,549		$	1,433,598	$	6,132,881
Operating income		70,395			96,394			21,247			47,806		235,842
Net income (loss)		12,225			27,684			(18,483	)		1,988		23,414
Year Ended December 31, 2005
Revenues	$	208,253		$	244,739		$	282,204		$	1,093,831	$	1,829,027
Operating income		9,664			9,011			10,473			60,410		89,558
Net income (loss)		1,669			2,109			(39,616	)		21,623		(14,215	)
Preferred dividends		2,084			2,138			2,195			750		7,167
Net income (loss) to common stock		(415	)		(29	)		(41,811	)		20,873		(21,382	)

Note 18—Proposed Disposition of North Texas Assets

At the time we acquired DMS, we planned to market the North Texas assets in an auction style sales process in early 2006, with the expectation that the sales transaction would close by mid 2006. In September 2006, our Board of Directors (the “Board”) determined that the available sales options did not meet the Board’s criteria. As a result, the North Texas assets were reclassified from “held for sale” to “held for use” and we began activities necessary for an initial public offering (“IPO”) of common units representing limited partnership interests in Targa Resources Partners LP (“the Partnership”).

During 2006, we recorded $64.9 million of depreciation expense for the North Texas assets, including $9.1 million of previously deferred depreciation expense for the period from November 2005 to December 2005.

Note 19—Subsequent Events

On February 14, 2007, we completed the IPO and the Partnership borrowed $294.5 million under its newly established credit facility. In return for our contribution of the North Texas assets we received a 2% general partner interest, a 36.6% limited partner interest and cash proceeds of $665.7 million. After closing, we will continue to consolidate the Partnership’s net assets and results due to our continuing control of the Partnership through our general partner interest.

We used the proceeds received from contributing the North Texas assets and cash on hand to retire in full the outstanding balance (including accrued interest) of our $700 million senior secured asset sale bridge loan facility.

Note 20—Consolidating Financial Statements

We are the issuer of the notes discussed in Note 7. 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”);

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TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• The Guarantor Subsidiaries on a consolidated basis;

• The 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.

Condensed consolidating financial statements are not presented for the predecessor.

F-44

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2006

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	—		$	117,661		$	25,078		$	—		$	142,739
Accounts receivable and other current assets		1,694			692,935			22,289			—			716,918
		1,694			810,596			47,367			—			859,657
Property, plant, and equipment, at cost		—			2,088,468			562,907			—			2,651,375
Accumulated depreciation		—			40,081			(226,929	)		—			(186,848	)
Property, plant, and equipment, net		—			2,128,549			335,978			—			2,464,527
Unconsolidated investments		—			40,212						—			40,212
Investment in subsidiaries		2,622,245			—			—			(2,622,245	)		—
Advances to (from) subsidiaries		(14,088	)		(16,263	)		30,351			—			—
Other assets		146,184			(53,605	)		1,050			—			93,629
Total assets	$	2,756,035		$	2,909,489		$	414,746		$	(2,622,245	)	$	3,458,025
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and other liabilities	$	37,000		$	503,952		$	50,278		$	—		$	591,230
Current maturities of debt		712,500			—			—			—			712,500
		749,500			503,952			50,278			—			1,303,730
Long-term liabilities
Long-term debt, net of current maturities		1,471,875			—			—			—			1,471,875
Other long-term obligations		20,390			44,368			1,864			—			66,622
		1,492,265			44,368			1,864			—			1,538,497
Minority interest		—			—			101,528			—			101,528
Stockholders’ equity:
Stockholders’ equity		478,587			2,297,046			261,016			(2,558,062	)		478,587
Accumulated other comprehensive income		35,683			64,123			60			(64,183	)		35,683
		514,270			2,361,169			261,076			(2,622,245	)		514,270
Total liabilities and stockholders’ equity	$	2,756,035		$	2,909,489		$	414,746		$	(2,622,245	)	$	3,458,025

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TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2005

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents	$	—		$	9,624		$	31,803		$	—		$	41,427
Accounts receivable and other current assets		10,697			747,561			27,890			—			786,148
		10,697			757,185			59,693			—			827,575
Property, plant, and equipment, at cost		—			1,937,063			537,094			—			2,474,157
Accumulated depreciation		—			162,350			(199,904	)		—			(37,554	)
		—			2,099,413			337,190			—			2,436,603
Unconsolidated investments		—			62,337			—			—			62,337
Investment in subsidiaries		2,646,874			—			—			(2,646,874	)		—
Advances to (from) subsidiaries		(58,841	)		30,502			28,339			—			—
Other assets		63,830			5,405			836			—			70,071
Total assets	$	2,662,560		$	2,954,842		$	426,058		$	(2,646,874	)	$	3,396,586
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued liabilities	$	30,262		$	486,848		$	38,025		$	—		$	555,135
Current maturities of debt		12,500			—			—			—			12,500
Other current liabilities		133			6,552			1,665			—			8,350
		42,895			493,400			39,690			—			575,985
Long-term liabilities
Long-term debt, net of current maturities		2,184,375			—			—			—			2,184,375
Other long-term liabilities		913			85,367			2,855			—			89,135
		2,185,288			85,367			2,855			—			2,273,510
Minority interest		—			—			112,714			—			112,714
Stockholders’ Equity:
Stockholders equity		453,358			2,406,277			270,798			(2,677,075	)		453,358
Accumulated other comprehensive income		(18,981	)		(30,202	)		1			30,201			(18,981	)
		434,377			2,376,075			270,799			(2,646,874	)		434,377
Total liabilities and stockholders’ equity	$	2,662,560		$	2,954,842		$	426,058		$	(2,646,874	)	$	3,396,586

F-46

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2006

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Revenues	$	—		$	5,594,397		$	538,484		$	—		$	6,132,881
					—
Operating costs and expenses:					—
Product purchases		—			5,095,299			345,533			—			5,440,832
Operating expenses		—			124,120			100,049			—			224,169
Depreciation and amortization		—			122,142			27,545			—			149,687
General and administrative		161			81,883			307			—			82,351
		161			5,423,444			473,434			—			5,897,039
Operating income (loss)		(161	)		170,953			65,050			—			235,842
Other income (expense):
Interest expense, net		—			(181,417	)		1,228			—			(180,189	)
Equity income of unconsolidated investments		—			9,968			—			—			9,968
Equity in earnings of subsidiaries		39,784			—			—			(39,784	)		—
Minority interest		—			—			(25,998	)		—			(25,998	)
Income (loss) before income taxes		39,623			(496	)		40,280			(39,784	)		39,623
Income tax expense		(16,209	)		—			—			—			(16,209	)
Net income (loss)	$	23,414		$	(496	)	$	40,280		$	(39,784	)	$	23,414

F-47

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2005

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations		Consolidated
	(in thousands)
Revenues	$	—		$	1,725,587		$	103,440		$	—	$	1,829,027
Operating costs and expenses:
Product purchases		—			1,566,612			65,351			—		1,631,963
Operating expenses		—			39,151			12,939			—		52,090
Depreciation and amortization		—			22,662			4,479			—		27,141
General and administrative		—			28,233			42			—		28,275
		—			1,656,658			82,811			—		1,739,469
Operating income		—			68,929			20,629			—		89,558
Other income (expense):
Interest expense, net		—			(39,856	)		—			—		(39,856	)
Other income (expense)		—			(59,375	)		58			—		(59,317	)
Equity in earnings of unconsolidated investments		—			(3,776	)		—			—		(3,776	)
Equity in earnings of subsidiaries		(20,752	)		—			—			20,752		—
Minority interest		—			—			(7,361	)		—		(7,361	)
Income (loss) before income taxes		(20,752	)		(34,078	)		13,326			20,752		(20,752	)
Income tax benefit		6,537			—			—			—		6,537
Net income (loss)		(14,215	)		(34,078	)		13,326			20,752		(14,215	)
Dividends on redeemable preferred stock		(7,167	)		—			—			—		(7,167	)
Net income (loss) to common stock	$	(21,382	)	$	(34,078	)	$	13,326		$	20,752	$	(21,382	)

F-48

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Year Ended December 31, 2004

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries	Intercompany Eliminations			Consolidated
	(in thousands)
Revenues	$	—		$	602,376		$  —	$	—		$	602,376
Operating costs and expenses:
Product purchases		—			544,918		—		—			544,918
Operating expenses		—			15,253		—		—			15,253
Depreciation and amortization		—			10,631		—		—			10,631
General and administrative		485			10,664		—		—			11,149
		485			581,466		—		—			581,951
Operating income (loss)		(485	)		20,910		—		—			20,425
Other income (expense):
Interest expense, net		—			(6,406	)	—		—			(6,406	)
Equity in earnings of unconsolidated investment		—			2,370		—		—			2,370
Equity in earnings of subsidiaries		16,874			—		—		(16,874	)		—
Income before income taxes		16,389			16,874		—		(16,874	)		16,389
Income tax expense		(5,227	)		—		—		—			(5,227	)
Net income		11,162			16,874		—		(16,874	)		11,162
Dividends on redeemable preferred stock		(5,829	)		—		—		—			(5,829	)
Net income to common stock	$	5,333		$	16,874		$  —	$	(16,874	)	$	5,333

F-49

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Year Ended December 31, 2006

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities
Net income (loss)	$	23,414		$	(496	)	$	40,280		$	(39,784	)	$	23,414
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion		—			155,919			7,657			—			163,576
Deferred income tax expense		16,141			34			—			—			16,175
Noncash compensation		—			2,777			—			—			2,777
Inventory valuation adjustment		—			13,103			—			—			13,103
Provision for uncollectible accounts		—			(860	)		—			—			(860	)
Equity in earnings of unconsolidated investments		—			(9,968	)		—			—			(9,968	)
Distribution from unconsolidated investments		—			2,306			—			—			2,306
Equity in earnings of subsidiaries		(39,784	)		—			—			39,784			—
Minority interest		—			—			25,998			—			25,998
Minority interest distributions		—			(37,184	)		—			—			(37,184	)
Gain on sale of assets		—			169			—			—			169
Risk management activities		—			(24,618	)		—			—			(24,618	)
Other		—			—			—			—			—
Changes in operating assets and liabilities:
Accounts receivable and other assets		347			1,330			(3,729	)		—			(2,052	)
Inventory		—			22,598			809			—			23,407
Accounts payable and other liabilities		(18,243	)		77,032			(21,746	)		—			37,043
Net cash provided by (used in) operating activities		(18,125	)		202,142			49,269			—			233,286
Cash flows from investing activities
Purchases of property, plant, and equipment		—			(128,132	)		(8,533	)		—			(136,665	)
Proceeds from property insurance		—			27,221			—			—			27,221
Proceeds from sale of unconsolidated investment		—			—			—			—			—
Investment in unconsolidated affiliate		—			(9,102	)		—			—			(9,102	)
Other		—			734			—			—			734
Net cash used in investing activities		—			(109,279	)		(8,533	)		—			(117,812	)
Cash flows from financing activities
Senior secured credit facility:
Borrowings		—			—			—			—			—
Repayments		(12,500	)		—			—			—			(12,500	)
Proceeds from issuance of long-term debt		—			—			—			—			—
Repayment of long-term debt		—			—			—			—			—
Parent contributions (distributions)		—			—			(969	)		—			(969	)
Receipts from (payments to) subsidiaries		31,318			15,174			(46,492	)		—			—
Costs incurred in connection with financing arrangements		(693	)		—			—			—			(693	)
Net cash provided by (used in) financing activities		18,125			15,174			(47,461	)		—			(14,162	)
Net increase (decrease) in cash and cash equivalents		—			108,037			(6,725	)		—			101,312
Cash and cash equivalents, beginning of period		—			9,624			31,803			—			41,427
Cash and cash equivalents, end of period	$	—		$	117,661		$	25,078		$	—		$	142,739

F-50

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Year Ended December 31, 2005

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities
Net income (loss)	$	(14,215	)	$	(34,078	)	$	13,326		$	20,752		$	(14,215	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion		—			29,935			4,479			—			34,414
Deferred income taxes		(6,742	)		—			—			—			(6,742	)
Earnings (loss) from unconsolidated investments		—			4,163			—			—			4,163
Equity in earnings (losses) of subsidiaries		20,752			—			—			(20,752	)		—
Other		—			58,824			7,361			—			66,185
Changes in operating assets and liabilities:
Accounts receivable and other assets		—			(98,805	)		1,670			—			(97,135	)
Inventory		—			(17,412	)		656			—			(16,756	)
Accounts payable and other liabilities		205			141,872			(3,136	)		—			138,941
Net cash provided by (used in) operating activities		—			84,499			24,356			—			108,855
Cash flows from investing activities
Purchases of property and equipment		—			(18,918	)		(3,058	)		—			(21,976	)
Acquisition of DMS, net of cash acquired		(2,437,102	)		26,426			—			7,132			(2,403,544	)
Proceeds from sale of unconsolidated investment		—			117,000			—			—			117,000
Investment in unconsolidated affiliate		—			(6,032	)		—			—			(6,032	)
Other		—			(14,365	)		1			—			(14,364	)
Net cash used in investing activities		(2,437,102	)		104,111			(3,057	)		7,132			(2,328,916	)
Cash flows from financing activities
Senior secured credit facility:
Borrowings		1,950,000			48,000			—			—			1,998,000
Repayments		(3,125	)		(174,000	)		—			—			(177,125	)
Proceeds from issuance of long-term debt		250,000			—			—			—			250,000
Repayment of long-term debt		—			(77,000	)		—			—			(77,000	)
Parent contributions (distributions)		315,630			—			—			—			315,630
Receipts from (payments to) subsidiaries		(16,519	)		13,147			3,372			—			—
Costs incurred in connection with financing arrangements		(58,884	)		—			—			—			(58,884	)
Net cash provided by financing activities		2,437,102			(189,853	)		3,372			—			2,250,621
Net increase in cash and cash equivalents		—			(1,243	)		24,671			7,132			30,560
Cash and cash equivalents, beginning of year		—			10,867			7,132			(7,132	)		10,867
Cash and cash equivalents, end of year	$	—		$	9,624		$	31,803		$	—		$	41,427

F-51

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Year Ended December 31, 2004

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries	Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	11,162		$	16,874		$  —	$	(16,874	)	$	11,162
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, amortization and accretion		—			11,740		—		—			11,740
Deferred income tax expense		5,227			—		—		—			5,227
Noncash compensation		485										485
Equity in earnings (losses) of unconsolidated investments		—			(2,370	)	—		—			(2,370	)
Equity in (earnings) losses of subsidiaries		(16,874	)		—		—		16,874			—
Hedge ineffectiveness adjustment		—			(95	)	—		—			(95	)
Changes in operating assets and liabilities:
Accounts receivable and other assets		—			(77,843	)	—		—			(77,843	)
Inventory		—			(381	)	—		—			(381	)
Accounts payable and other liabilities		—			85,210		—		—			85,210
Net cash provided by operating activities		—			33,135		—		—			33,135
Cash flows from investing activities
Purchases of property and equipment		—			(250,187	)	—		—			(250,187	)
Investment in unconsolidated subsidiaries		—			(101,275	)	—		—			(101,275	)
Other		—			(1,772	)	—		—			(1,772	)
Net cash used in investing activities		—			(353,234	)	—		—			(353,234	)
Cash flows from financing activities
Senior secured credit facility:
Borrowings		—			168,000		—		—			168,000
Repayments		—			(42,000	)	—		—			(42,000	)
Proceeds from issuance of senior subordinated second lien notes		—			31,360		—		—			31,360
Proceeds from issuance of term loan		—			45,000		—		—			45,000
Parent contributions (distributions), net		2,550			—		—		—			2,550
Receipts from (payments to) subsidiaries		(133,866	)		133,866		—		—			—
Proceeds from the issuance of redeemable preferred stock		131,300			—		—		—			131,300
Proceeds from issuance of common stock		16			—		—		—			16
Costs incurred in connection with financing arrangements		—			(5,550	)	—		—			(5,550	)
Net cash provided by financing activities		—			330,676		—		—			330,676
Net increase in cash and cash equivalents		—			10,577		—		—			10,577
Cash and cash equivalents, beginning of year		—			290		—		—			290
Cash and cash equivalents, end of year	$	—		$	10,867		$  —	$	—		$	10,867

F-52

TARGA RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

	September 30, 2007			December 31, 2006
	(in thousands) (unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	152,408		$	142,739
Trade receivables, net of allowances of $720 and $781		633,728			528,864
Inventory		144,595			116,956
Deferred income taxes		8,593			—
Assets from risk management activities		14,277			34,255
Other current assets		43,567			36,843
Total current assets		997,168			859,657
Property, plant and equipment, at cost		2,744,357			2,651,375
Accumulated depreciation		(297,176	)		(186,848	)
Property, plant and equipment, net		2,447,181			2,464,527
Unconsolidated investments		46,637			40,212
Long-term assets from risk management activities		13,269			15,851
Other assets		50,256			77,778
Total assets	$	3,554,511		$	3,458,025
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	354,226		$	271,696
Accrued liabilities		345,740			301,540
Current maturities of debt		12,500			712,500
Liabilities from risk management activities		35,460			6,611
Deferred income taxes		—			11,383
Total current liabilities		747,926			1,303,730
Long-term debt, less current maturities		1,757,000			1,471,875
Long-term liabilities from risk management activities		35,286			17,731
Deferred income taxes		14,714			23,950
Other long-term obligations		33,907			24,941
Minority interest		103,335			101,528
Non-controlling interest in Targa Resources Partners LP		368,338			—
Commitments and contingencies (Note 8)
Stockholder’s equity:
Common stock ($0.001 par value, 1,000 shares authorized, issued and outstanding at September 30, 2007 and December 31, 2006, collateral for Targa Resources Investments Inc. debt, see Note 7)		—			—
Additional paid-in capital		474,407			472,423
Retained earnings		42,493			6,164
Accumulated other comprehensive income (loss)		(22,895	)		35,683
Total stockholder’s equity		494,005			514,270
Total liabilities and stockholder’s equity	$	3,554,511		$	3,458,025

See notes to unaudited consolidated financial statements

F-53

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Nine Months Ended September 30,
	2007			2006
	(in thousands) (unaudited)
Revenues	$	4,923,416		$	4,699,283
Costs and expenses:
Product purchases		4,373,289			4,174,895
Operating expenses		179,837			160,554
Depreciation and amortization		110,757			110,938
General and administrative		78,221			65,061
Gain on sale of assets		(95	)		(201	)
		4,742,009			4,511,247
Operating income		181,407			188,036
Other income (expense):
Interest expense, net		(112,752	)		(133,245	)
Equity in earnings of unconsolidated investments		7,964			5,403
Minority interest		(20,492	)		(22,403	)
Non-controlling interest in Targa Resources Partners LP		(6,628	)		—
Income before income taxes		49,499			37,791
Income tax expense:
Current		(1,289	)		—
Deferred		(11,881	)		(16,365	)
Net income	$	36,329		$	21,426

See notes to unaudited consolidated financial statements

F-54

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	Nine Months Ended September 30,
	2007			2006
	(in thousands) (unaudited)
Net income	$	36,329		$	21,426
Other comprehensive income (loss)
Commodity hedging contracts:
Non-controlling partners’ share of other comprehensive income of Targa Resources Partners LP		6,084			—
Change in fair value		(89,677	)		116,933
Reclassification adjustment for settled periods		(16,313	)		(17,597	)
Related income taxes		40,907			(37,798	)
Interest rate swaps:
Change in fair value		660			2,334
Reclassification adjustment for settled periods		(1,633	)		(455	)
Related income taxes		388			(705	)
Foreign currency items:
Foreign currency translation adjustment		1,714			222
Related income taxes		(708	)		(83	)
		(58,578	)		62,851
Comprehensive income (loss)	$	(22,249	)	$	84,277

See notes to unaudited consolidated financial statements

F-55

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER’S EQUITY

	Common Stock		Additional Paid-in Capital			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total
	Shares	Amount
	(in thousands) (unaudited)
Balance, December 31, 2006	1	$ —	$	472,423		$	6,164	$	35,683		$	514,270
Distribution to parent	—	—		(167	)		—		—			(167	)
Contribution of noncash compensation	—	—		1,614			—		—			1,614
Tax benefit on vesting of common stock	—	—		537			—		—			537
Other comprehensive loss	—	—		—			—		(58,578	)		(58,578	)
Net income	—	—		—			36,329		—			36,329
Balance, September 30, 2007	1	$ —	$	474,407		$	42,493	$	(22,895	)	$	494,005

See notes to unaudited consolidated financial statements

F-56

TARGA RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2007			2006
	(in thousands) (unaudited)
Cash flows from operating activities
Net income	$	36,329		$	21,426
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		110,664			110,845
Deferred income tax expense		11,881			16,365
Amortization of debt issue costs		10,846			9,737
Amortization of intangibles		93			93
Accretion of asset retirement obligations		740			632
Noncash compensation		1,742			2,204
Equity in earnings of unconsolidated investments		(7,964	)		(5,403	)
Distributions from unconsolidated investments		3,100			2,306
Minority interest		20,492			22,403
Minority interest distributions		(18,685	)		(29,414	)
Non-controlling interest in Targa Resources Partners LP		6,628			—
Distributions to non-controlling interest in Targa Resources Partners LP		(6,628	)		—
Risk management activities		(13,821	)		(19,249	)
Gain on sale of assets		(95	)		(201	)
Changes in operating assets and liabilities
Accounts receivable and other assets		(129,848	)		17,075
Inventory		(27,639	)		26,064
Accounts payable and other liabilities		138,989			6,714
Net cash provided by operating activities		136,824			181,597
Cash flows from investing activities
Purchases of property, plant and equipment		(97,766	)		(107,921	)
Proceeds from property insurance		17,900			20,529
Investment in unconsolidated affiliate		(4,648	)		(9,102	)
Other		2,255			439
Net cash used in investing activities		(82,259	)		(96,055	)
Cash flows from financing activities
Senior secured credit facilities
Borrowings		342,500			—
Repayments		(757,375	)		(9,375	)
Contributions from non-controlling interest in Targa Resources Partners LP		377,454			—
Distributions to non-controlling interest in Targa Resources Partners LP in excess of cumulative earnings		(3,161	)		—
Distribution to Targa Resources Investments Inc.		(167	)		—
Costs incurred in connection with financing arrangements		(4,147	)		(648	)
Net cash used in financing activities		(44,896	)		(10,023	)
Net increase in cash and cash equivalents		9,669			75,519
Cash and cash equivalents, beginning of period		142,739			41,427
Cash and cash equivalents, end of period	$	152,408		$	116,946

See notes to unaudited consolidated financial statements

F-57

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Basis of Presentation

Targa Resources, Inc. (the “Company”, “we”, “our”, “us”) is a Delaware corporation formed on February 26, 2004. Our business operations consist of gathering and processing natural gas, and fractionating, storing, terminalling, transporting, distributing and marketing NGLs.

The accompanying 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. 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 month periods ended September 30, 2007 and 2006 include all adjustments, both normal and recurring, which are, in the opinion of management, necessary for a fair presentation of the results for the interim periods. All significant intercompany balances and transactions have been eliminated in consolidation. The financial results for the three and nine months ended September 30, 2007 are not necessarily the results that may be expected for the full year ended December 31, 2007 due to seasonality of portions of our business, timing of maintenance activities and the impact of the resumption of operations at certain of our facilities that sustained damage during 2005. These unaudited consolidated financial statements and other information included in the quarterly report should be read in conjunction with our consolidated financial statements and notes thereto included in our Annual Report for the year ended December 31, 2006.

The reclassification of prior years’ cash flows related to property damage insurance claims was made to conform to the current year presentation. Such amounts were previously reflected as a component of changes in operating assets and liabilities.

We currently own approximately 38.6% of Targa Resources Partners LP (“TRP LP”), including the interests of the general partner, which is wholly owned by us. TRP LP 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 TRP LP on our September 30, 2007 consolidated balance sheet represents the initial investment by the partners other than Targa Resources, Inc., plus those partners’ share of the net income, less those partners’ share of distributions of TRP LP since its initial public offering on February 14, 2007. Non-controlling interest in net income of TRP LP on our consolidated statements of operations represents those partners’ share of the net income of TRP LP.

Note 2—Accounting Policies and Related Matters

Consolidation.We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities after the elimination of all material intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest.

We follow the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the operating and financial policies of the investee. Our proportionate share of

F-58

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on our equity method investees’ balance sheet in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

Accounting for Income Taxes. We follow the guidance in Statement of Financial Accounting Standards (“SFAS”) 109,“Accounting for Income Taxes”, which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.

As part of the process of preparing our consolidated financial statements, we estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.

We assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.

We believe future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize assets for which no reserve has been established. Any change in a valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.

We adopted the provisions of FASB Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes” on January 1, 2007. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. Based on our evaluation, we have determined that there are no significant uncertain tax positions requiring recognition in our financial statements at September 30, 2007. There are no unrecognized tax benefits that, if recognized, would affect the effective rate, and there are no unrecognized tax benefits that are reasonably expected to increase or decrease in the next twelve months.

We file numerous consolidated and separate income tax returns in the U.S. federal jurisdiction and many state jurisdictions, and are open to federal and state income tax examinations for years 2003 and later. Presently, no federal or state income tax examinations are underway, and none have been announced. No potential interest or penalties were recognized at September 30, 2007.

Recent Accounting Pronouncements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157 “Fair Value Measurements”. SFAS 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS 157 does not require any new fair value measurements. However, for some entities, the

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application of SFAS 157 will change current practice. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We have not yet determined the impact this statement will have on our results of operations or financial position.

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,” which is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. 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. We are currently reviewing this new accounting standard and the impact, if any, it will have on our financial statements.

Note 3—Initial Public Offering of TRP LP Units and Related Matters

On February 14, 2007 the initial public offering (“IPO”) of 19,320,000 common units representing limited partner interests in TRP LP was completed. Concurrently with the IPO, TRP LP entered into a five year, $500 million revolving credit facility and borrowed $294.5 million under this newly established facility (see Note 7). TRP LP used the proceeds from this borrowing, together with $377.5 million of net proceeds from the IPO to pay offering expenses and debt issue costs and to retire $665.7 million of affiliate debt owed to us. We applied this amount along with cash on hand to retire in full the outstanding balance (including accrued interest) of our $700 million senior secured asset sale bridge loan facility.

In return for our contribution of our North Texas assets to TRP LP in connection with the IPO, we received a 2% general partner interest, incentive distribution rights and a 36.6% limited partner interest in TRP LP. Our limited partner interest is represented by 11,528,231 subordinated units. These units are subordinated for a period of time to the common units with respect to distribution rights.

We continue to consolidate TRP LP’s assets, liabilities and results of operations due to our control of TRP LP through our general partner interest.

Cash Distributions. In accordance with TRP LP’s partnership agreement, TRP LP must distribute all of its available cash, as defined in the partnership agreement, within 45 days following the end of each calendar quarter. Distributions will generally be made 98% to the common and subordinated unitholders and 2% to the general partner, subject to the payment of incentive distributions to the extent that certain target levels of cash distributions are achieved.

Under the quarterly incentive distribution provisions, generally TRP LP’s general partner is entitled to 13% of amounts distributed in excess of $0.3881 per unit, 23% of the amounts distributed in excess of $0.4219 per unit and 48% of amounts distributed in excess of $0.50625 per unit. No incentive distributions were earned by us through our general partner interest for the period from February 14, 2007 through September 30, 2007. To the extent there is sufficient available cash, the holders of common units are entitled to receive the minimum quarterly distribution of $0.3375 per unit, plus arrearages, prior to any distribution of available cash to the holders of subordinated units. Subordinated units will not accrue any arrearages with respect to distributions for any quarter.

Due to the timing of TRP LP’s IPO, a pro-rated distribution for the first quarter of 2007 of $0.16875 per unit (approximately $5.3 million) was approved by the Board of Directors of TRP LP’s general partner on April 23, 2007 and paid on May 15, 2007 to unitholders of record as of the close of business on May 3, 2007. A distribution for the second quarter of 2007 of $0.3375 per unit (approximately $10.6 million) was approved by the Board of Directors of TRP LP’s general partner on July 23, 2007 and paid on August 14, 2007 to unitholders of record as of the close of business on August 2, 2007.

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Note 4—Share-Based Compensation

We account for share-based compensation in accordance with SFAS 123R, “Share-Based Payment,” which was adopted January 1, 2006, utilizing the modified prospective transition method.

Stock Option Plans

Under our 2004 Stock Incentive Plan, we issued options to acquire 949,002 shares of common stock for $8.50 per share to officers, directors and certain other employees. On October 31, 2005, each outstanding option was converted into options to buy 0.117549 shares of Series B preferred stock (representing options on a total of 111,550 shares) for $72.31 per share. On May 1, 2007, each option was exchanged for 10 shares of non-vested common stock (representing a total of 1,115,500 shares) and the right to receive a cash payment of $27.69 on January 2, 2008. This exchange resulted in no additional compensation costs.

Under its 2005 Incentive Compensation Plan (“the Plan”), our parent, Targa Resources Investments Inc. (“Targa Investments”) granted stock options to certain of our employees and directors. The options were granted at or above the fair market value of Targa Investments’ common stock on the date of grant, and generally have vesting terms of four years.

The fair value of each option grant was estimated on the date of grant using a Black-Scholes option pricing model. During the nine months ended September 30, 2007 and 2006, there were 82,791 and 51,672 stock options granted, respectively. 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. The fair value of options granted during the nine months ended September 30, 2006 ranged from $0.01 to $0.38 per share, with a weighted-average fair value of $0.21 per share.

Our unaudited consolidated statements of operations reflect share-based compensation cost related to stock options of $20,000 and $50,000 for the three and nine months ended September 30, 2007, and $25,000 and $73,000 for the three and nine months ended September 30, 2006, respectively.

As of September 30, 2007, there was $61,000 of total unamortized compensation cost related to stock options, which is expected to be recognized over a weighted-average period of 1.03 years. The total recognition period for the remaining unrecognized compensation cost is approximately 2.4 years. During the nine months ended September 30, 2007, options were exercised on 135,740 shares of common stock.

Non-Vested Common Stock

Targa Investments also issued non-vested (i.e., restricted) common stock to certain of our employees and directors. Restricted stock awards entitle recipients to exchange restricted common shares for unrestricted shares once the defined vesting period expires, subject to certain forfeiture provisions. The restrictions on the non-vested shares generally lapse four years from the date of grant. Compensation cost equal to the estimated grant date fair value of non-vested stock is recognized on a straight-line basis over the vesting period.

Awards of non-vested common stock during the nine months ended September 30, 2007 and 2006 were 73,049 and 72,564 shares, respectively. The estimated fair values of non-vested awards during the nine months ended September 30, 2007 and 2006 were $1.10 and $1.16 per share, respectively.

Our unaudited consolidated statements of operations reflect share-based compensation costs related to non-vested common stock of $0.5 million and $1.6 million for the three and nine months ended September 30, 2007, and $0.7 million and $2.1 million for the three and nine months ended September 30, 2006, respectively.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of September 30, 2007, there was $1.8 million of total unamortized compensation cost related to non-vested stock, which is expected to be recognized over a weighted-average period of 1.01 years. The total recognition period for the remaining unrecognized compensation cost is approximately 2.4 years.

Non-Employee Director Grants and Incentive Plan related to TRP LP Common Units

In connection with TRP LP’s IPO in February 2007, Targa Investments adopted a long-term incentive plan (“LTIP”) for employees, consultants and directors who perform services for Targa Investments or its affiliates. The LTIP provides for the grant of cash-settled performance units which are linked to the performance of TRP LP’s common units and may include distribution equivalent rights (“DERs”). The LTIP is administered by the compensation committee of the board of directors of Targa Investments. Subject to applicable vesting criteria, a DER entitles the grantee to a cash payment equal to cash distributions paid on an outstanding common unit.

On February 21, 2007, Targa Investments granted 304,600 performance units under the LTIP. Each vested performance unit will entitle the grantee to a cash payment equal to the then value of a TRP LP common unit, including DERs. Vesting of performance units is based on the total return per common unit of TRP LP through the end of the performance period, August 1, 2010, relative to the total return of a defined peer group.

Because the performance units require cash settlement, they have been accounted for as liability awards under SFAS 123R. Accordingly, the measurement date for the performance units is the date of settlement, subject to remeasurement at each reporting date until settlement. The percentage of the fair value that is accrued as compensation cost at the end of each reporting period is equal to the percentage of the requisite service that has been rendered at that date. Changes in fair value that occur after the end of the requisite service period are compensation cost of the period in which the changes occur.

The fair value of a performance unit is the sum of: (i) the closing price of a TRP LP common unit on the reporting date; (ii) the fair value of an at-the-money call option on a performance unit with a grant date equal to the reporting date and an expiration date equal to the last day of the performance period; and (iii) estimated DERs. The fair value of the call option was estimated with a Black-Scholes option pricing model using a risk-free rate of 4.02%, volatility of 21% and a dividend yield of zero.

At September 30, 2007, the aggregate fair value of performance units expected to vest was $10.8 million. For the three and nine months ended September 30, 2007, we recognized compensation expense of $0.6 million and $1.9 million, respectively, related to the performance units. The total recognition period for the remaining unrecognized compensation cost is approximately three years.

Targa Resources GP LLC, the general partner of TRP LP, also made equity-based awards of 16,000 restricted common units of TRP LP (2,000 restricted common units in TRP LP to each of TRP LP’s and Targa Investments’ non-management directors) under the Targa Resources Partners Long-Term Incentive Plan. 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. During the three and nine months ended September 30, 2007, we recognized compensation expense of $52,000 and $129,000, respectively, related to these awards. We estimate that the remaining fair value of $207,000 will be recognized in expense over the next 29 months.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 5—Inventory

Our inventory values consisted of the following at the dates indicated:

(in thousands)	September 30, 2007		December 31, 2006
Natural gas and natural gas liquids	$	144,044	$	116,568
Materials and supplies		551		388
	$	144,595	$	116,956

Due to fluctuating commodity prices for natural gas liquids, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceed their net realizable value. These non-cash adjustments are charged to product purchases within operating costs and expenses in the period they are recognized, with the related cash impact in the subsequent period. For the three and nine month periods ended September 30, 2007, we recognized $4,000 and $139,000 respectively, for lower of cost or market adjustments. For the three and nine month periods ended September 30, 2006, we recognized $7.8 million and $8.4 million, respectively, for lower of cost or market adjustments.

Note 6—Unconsolidated Investments

At September 30, 2007, our investments 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 in the Gulf Coast region, and a 38.75% ownership interest in Gulf Coast Fractionators (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast. The following table shows our unconsolidated investments at the dates indicated:

(in thousands)	September 30, 2007		December 31, 2006
Natural Gas Gathering and Processing
VESCO	$	27,238	$	20,610
Logistics Assets
GCF		19,399		19,602
	$	46,637	$	40,212

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,
(in thousands)	2007		2006		2007		2006
Equity in earnings of:
VESCO	$	1,567	$	1,048	$	5,067	$	3,302
GCF		750		387		2,897		2,101
	$	2,317	$	1,435	$	7,964	$	5,403
Cash contributions
VESCO	$	—	$	3,078	$	4,648	$	9,102
Cash distributions
GCF	$	775	$	271	$	3,100	$	2,306

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our equity in earnings of VESCO includes partially settled business interruption insurance claims of $3.1 million and $1.8 million for the nine months ended September 30, 2007 and 2006, respectively.

The following table shows summarized financial information of our unconsolidated investments for the periods indicated:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2007				2006				2007				2006
(in thousands)	GCF		VESCO (1)		GCF		VESCO (1)		GCF		VESCO (1)		GCF		VESCO (1)
Revenues	$	11,635	$	29,820	$	11,415	$	45,594	$	36,426	$	102,770	$	34,673	$	94,248
Cost of sales and operations		10,443		22,246		10,730		44,908		30,507		91,945		30,623		89,592
Income from operations		1,192		7,574		685		686		5,919		10,825		4,050		4,656
Net income		1,308		7,574		774		913		6,287		10,825		4,359		5,407

(1) Our equity earnings in VESCO reflects a disproportionate allocation of depreciation expense, which is based on the cost basis of assets contributed by each of the members.

	As of September 30, 2007				As of December 31, 2006
(in thousands)	GCF		VESCO		GCF		VESCO
Current assets	$	11,298	$	52,603	$	12,181	$	47,749
Property, plant and equipment, net		50,926		124,643		52,258		102,028
Other assets		—		328		—		328
Total assets		62,224		177,574		64,439		150,105
Current liabilities		704		16,083		1,206		20,444
Long-term liabilities		—		8,559		—		7,851
Owners’ equity		61,520		152,932		63,233		121,810
Total liabilities and owners’ equity		62,224		177,574		64,439		150,105

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 7—Debt Obligations

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

(in thousands)	September 30, 2007			December 31, 2006
Long-term debt:
Senior secured term loan facility, variable rate, due October 2012	$	1,225,000		$	1,234,375
Senior secured asset sale bridge loan facility, variable rate (1)		—			700,000
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 (2)		—			—
Senior secured revolving credit facility of TRP LP, variable rate, due February 2012		294,500			—
Subtotal debt		1,769,500			2,184,375
Current maturities of debt		(12,500	)		(712,500	)
Long-term debt	$	1,757,000		$	1,471,875
Irrevocable standby letters of credit:
Letters of credit outstanding under synthetic letter of credit facility (3)	$	274,630		$	227,571
Letters of credit outstanding under senior secured revolving credit facility of TRP LP		300			—
	$	274,930		$	227,571

(1) The entire amount was repaid in February 2007 concurrent with the closing of TRP LP’s IPO.

(2) The entire $250 million available under the senior secured revolving credit facility may also be utilized for letters of credit.

(3) The $300 million senior secured synthetic letter of credit facility terminates in October 2012. At September 30, 2007 we had $25.4 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 rate paid on our consolidated variable-rate debt obligations during the nine months ended September 30, 2007.

	Range of interest rates paid	Weighted average interest rate paid
Senior secured term loan facility	7.2% to 7.6%	7.5	%
Senior secured asset sale bridge loan facility	7.6% to 7.6%	7.6	%
Senior secured revolving credit facility of the Partnership	6.6% to 6.9%	6.9	%

Senior Secured Revolving Credit Facility of TRP LP.On February 14, 2007 TRP LP entered into a credit agreement which provides for a $500 million five year revolving credit facility with a syndicate of financial institutions. The revolving credit facility bears interest, at TRP LP’s option, at the higher of the lender’s prime rate or the federal funds rate plus 0.5%, plus an applicable margin ranging from 0% to 1.25% dependent on TRP LP’s total leverage ratio, or LIBOR plus an applicable margin ranging from 1.0% to 2.25% dependent on TRP LP’s total leverage ratio. The credit agreement restricts the ability of TRP LP to make distributions of available

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cash to unitholders if it is in default or an event of default exists (as defined in the credit agreement). The credit agreement requires TRP LP to maintain a leverage ratio (the ratio of consolidated indebtedness to consolidated EBITDA, as defined in the credit agreement) of no more than 5.00 to 1.00 on the last day of any fiscal quarter ending on or after September 30, 2007. The credit agreement also requires TRP LP to maintain an interest coverage ratio (the ratio of its consolidated EBITDA to consolidated interest expense, as defined in its credit agreement) of no less than 2.25 to 1.00 determined as of the last day of each quarter for the four-fiscal quarter period ending on the date of determination.

In addition, TRP LP’s credit agreement contains various covenants that may limit, among other things, its ability to:

• incur indebtedness;

• grant liens; and

• engage in transactions with affiliates.

As of September 30, 2007, TRP LP had approximately $205.5 million available under its credit agreement, after giving effect to outstanding borrowings of $294.5 million and the issuance of a $0.3 million letter of credit.

The assets owned by TRP LP no longer serve as security for the indebtedness of Targa Resources, Inc. In connection with the IPO, the collateral interest in the North Texas assets that we contributed to TRP LP was released from our senior secured term loan facility. TRP LP’s senior secured revolving credit facility is secured by substantially all of the assets held by the partnership. See also Note 13.

Holdco Loan Facility of Targa Investments. On August 9, 2007, Targa Investments borrowed $450 million under a newly arranged credit agreement. The net proceeds of $445.1 million (after payment of debt issuance costs) were used to pay a dividend on Targa Investments’ preferred stock.

Principal amounts outstanding under the credit agreement are due and payable in full on February 9, 2015. In connection with the agreement, Targa Investments pledged its indirect 100% ownership of our capital stock as collateral for amounts due under the agreement. Neither we nor any of our subsidiaries guaranty Targa Investments’ obligations under the loan, our assets are not pledged as collateral for the loan and we have no obligation to repay the loan.

Note 8—Derivative Instruments and Hedging Activities

At September 30, 2007, accumulated other comprehensive income (“OCI”) included unrealized net losses of $41.1 million ($24.2 million, net of tax) on our open commodity hedges; and unrealized net gains of $0.5 million ($0.3 million, net of tax) on our open interest rate swaps.

At December 31, 2006, OCI included $58.8 million ($34.8 million, net of tax) of unrealized net gains on our open commodity hedges; and unrealized net gains of $1.4 million ($0.9 million, net of tax) on our open interest rate swaps.

During the three and nine months ended September 30, 2007, deferred gains on commodity hedges of $2.3 million and $16.3 million, respectively, were reclassified from OCI to revenues; and deferred gains on interest rate swaps of $0.6 million and $1.6 million, respectively, were reclassified from OCI to interest income.

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

During the three and nine months ended September 30, 2006, deferred gains on commodity hedges of $2.4 million and $17.6 million, respectively, were reclassified from OCI to revenues; and deferred gains on interest rate swaps of $0.5 million and $0.5 million, respectively, were reclassified from OCI to interest expense.

During the next twelve months ending September 30, 2008, based on quoted forward commodity prices and interest rates as of September 30, 2007 we expect to reclassify $11.1 million ($6.6 million, net of tax) of net deferred losses associated with open commodity derivative contracts designated as hedges and $0.5 million ($0.3 million, net of tax) of deferred net gains on interest rate swaps from OCI to revenues and interest expense, respectively. The amounts ultimately reclassified will vary due to the actual realized value upon settlement.

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

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

At September 30, 2007 our open derivatives designated as hedges of forecasted sales of commodities expected to be owned by us consisted of the following:

Natural Gas

Instrument Type	Index	Avg. Price $/MMBtu	MMBtu per day						(in thousands) Fair Value
			2007	2008	2009	2010	2011	2012
Swap	IF-HSC	9.08	2,740	—	—	—	—	—	$	593
Swap	IF-HSC	8.09	—	2,328	—	—	—	—		381
Swap	IF-HSC	7.39	—	—	1,966	—	—	—		(381	)
						��
			2,740	2,328	1,966	—	—	—		593
Swap	IF-NGPL MC	8.56	8,152	—	—	—	—	—		1,836
Swap	IF-NGPL MC	8.43	—	6,964	—	—	—	—		3,958
Swap	IF-NGPL MC	8.02	—	—	6,256	—	—	—		1,415
Swap	IF-NGPL MC	7.43	—	—	—	5,685	—	—		202
Swap	IF-NGPL MC	7.34	—	—	—	—	2,750	—		72
Swap	IF-NGPL MC	7.18	—	—	—	—	—	2,750		140
			8,152	6,964	6,256	5,685	2,750	2,750		7,623
Swap	IF-Waha	7.71	30,118	—	—	—	—	—		4,123
Swap	IF-Waha	7.27	—	29,307	—	—	—	—		(101	)
Swap	IF-Waha	6.86	—	—	28,854	—	—	—		(8,412	)
Swap	IF-Waha	7.39	—	—	—	15,009	—	—		(956	)
Swap	IF-Waha	7.36	—	—	—	—	8,750	—		(135	)
Swap	IF-Waha	7.18	—	—	—	—	—	8,750		44
			30,118	29,307	28,854	15,009	8,750	8,750		(5,437	)
Swap	NY-HH	6.79	3,840	—	—	—	—	—		(178	)
Total Swaps			44,850	38,599	37,076	20,694	11,500	11,500		2,601
Floor	IF-NGPL MC	6.45	520	—	—	—	—	—		32
Floor	IF-NGPL MC	6.55	—	1,000	—	—	—	—		267
Floor	IF-NGPL MC	6.55	—	—	850	—	—	—		205
			520	1,000	850	—	—	—		504
Floor	IF-Waha	6.70	350	—	—	—	—	—		25
Floor	IF-Waha	6.85	—	670	—	—	—	—		173
Floor	IF-Waha	6.55	—	—	565	—	—	—		115
			350	670	565	—	—	—		313
Total Floors			870	1,670	1,415	—	—	—		817
									$	3,418

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NGL

Instrument Type	Index	Avg. Price $/gal	Barrels per day						(in thousands) Fair Value
			2007	2008	2009	2010	2011	2012
Swap	OPIS-MB	0.96	10,216	—	—	—	—	—	$	(10,672	)
Swap	OPIS-MB	0.92	—	9,257	—	—	—	—		(25,737	)
Swap	OPIS-MB	0.88	—	—	8,595	—	—	—		(12,259	)
Swap	OPIS-MB	0.87	—	—	—	6,559	—	—		1,102
Swap	OPIS-MB	0.88	—	—	—	—	3,950	—		1,235
Swap	OPIS-MB	0.88	—	—	—	—	—	2,950		1,121
			10,216	9,257	8,595	6,559	3,950	2,950	$	(45,210	)

Condensate

Instrument Type	Index	Avg. Price $/Bbl	Barrels per day						(in thousands) Fair Value
			2007	2008	2009	2010	2011	2012
Swap	NY-WTI	72.82	439	—	—	—	—	—	$	(268	)
Swap	NY-WTI	70.68	—	384	—	—	—	—		(777	)
Swap	NY-WTI	69.00	—	—	322	—	—	—		(491	)
Swap	NY-WTI	68.10	—	—	—	301	—	—		(388	)
Total Swaps			439	384	322	301	—	—		(1,924	)
Floor	NY-WTI	58.60	25	—	—	—	—	—		0
Floor	NY-WTI	60.50	—	55	—	—	—	—		17
Floor	NY-WTI	60.00	—	—	50	—	—	—		37
Total Floors			25	55	50	—	—	—		54
									$	(1,870	)

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 at which we have hedged, we will receive less revenue on the hedged volumes than we would receive in the absence of hedges.

The following table shows commodity derivative contracts directly related to short-term fixed price arrangements elected by certain customers in various natural gas purchase and sale agreements. They have been marked to market.

Period	Commodity	Instrument Type	MMBtu per day	Avg. Price $/MMBtu	Index	(in thousands) Fair Value
Purchases
Oct 2007 – Dec 2007	Natural gas	Swap	16,587	7.07	NY-HH	$	(717	)
Jan 2008 – June 2008	Natural gas	Swap	989	7.63	NY-HH		38
Sales
Oct 2007 – Dec 2007	Natural gas	Fixed price sale	16,587	7.07	—		717
Jan 2008 – June 2008	Natural gas	Fixed price sale	989	7.63	—		(38	)
						$	—

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TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We also have interest rate swaps with a notional amount of $350 million. The interest rate swaps effectively fix our interest rate on $350 million in borrowings under our senior secured term loan facility to a rate of 4.8% plus the applicable LIBOR margin (2.0% at September 30, 2007) through November 2007. At September 30, 2007, the fair value of our interest rate swaps was $0.5 million.

Note 9—Commitments and Contingencies

Environmental

For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated in accordance with the American Institute of Certified Public Accountants (“AICPA”) Statement of Position No. 96-1, “Environmental Remediation Liabilities” (“SOP 96-1”). Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success.

In August 2005, prior to Targa’s acquisition of Versado Gas Processors, LLC (“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 (“TMS”) is the operator of Versado. In May 2007, the NMED sent Versado a draft compliance order relating to the 2005 inspection. In that draft order, the NMED alleged that Versado violated certain emissions standards and permit, monitoring and recordkeeping requirements. TMS responded to the NMED’s allegations in June 2007. The NMED disposed of certain alleged violations but requested additional information on certain other alleged violations. TMS is in the process of preparing further supplemental responses to the NMED’s inquiries. At this time, we can not estimate the effect, if any, that this matter will have on our results of operations.

Our environmental liability at September 30, 2007 was $2.7 million, consisting of $0.9 million for gathering system leaks and $1.8 million for ground water assessment and remediation.

Litigation

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 that 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 filed suit in Texas state court against Versado as purchaser and processor of Apache’s gas and Dynegy Midstream Services, Limited Partnership (now known as TMS), 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 plaintiff’s claim with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the trial court and abated for a future trial, but was subsequently settled in May 2007. At trial, the jury found in favor of the plaintiff on the lost gas claim, awarding approximately $1.6 million in damages. In May 2004, the Versado Defendants’ motion to set aside this jury verdict was granted by the court and the jury award to the plaintiff was vacated. The plaintiff filed its notice of appeal with the 14th Court of Appeals in October 2004 and its appellate brief in December 2004.

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TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In September 2006, the 14th Court of Appeals of Houston 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 Versado Defendants to approximately $2.7 million. In October 2006, the Versado Defendants filed a motion for rehearing with the 14th Court of Appeals. After rehearing, the 14th 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 $2.8 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. At the request of the Supreme Court of Texas, the Versado Defendants and Apache filed responses to the opposing party’s petition in June 2007. Pursuant to an additional request from the Supreme Court of Texas, the Versado Defendants and Apache filed briefs on the merits on October 29, 2007. The appeal is currently pending before the Supreme Court of Texas.

As a result of damage caused by Hurricane Rita, TMS’ West Cameron 229A platform sank in late September 2005. On November 12, 2005, the submerged wreckage was struck by an integrated tug-barge, the M/T Rebel, owned by K-Sea Transportation (“K-Sea”). As much as 25,000 barrels of No. 6 fuel oil may have entered Gulf of Mexico waters as the barge dragged part of the platform debris approximately three (3) miles from the sunken platform location. After receiving a letter from K-Sea threatening to hold us liable for all damages, TMS filed suit in federal district court in Galveston, Texas on November 21, 2005, seeking to hold K-Sea responsible for damage to the platform. In June 2007, the case was transferred to the federal district court in Houston, Texas.

In January 2006, Rios Energy (“Rios”), owner of the oil being transported in the barge, intervened in the existing suit and filed a new suit in the same federal court against both TMS and K-Sea alleging their negligence caused the loss of and damage to Rios’ oil. On March 8, 2006, K-Sea filed a counterclaim against TMS seeking to recover its alleged damages in excess of $90 million. In order to resolve K-Sea’s concerns over security for its claims, we agreed to provide a guarantee to K-Sea pursuant to which we would satisfy any final, non-appealable judgment or settlement against TMS if TMS is unable to pay any judgment against it. Discovery is proceeding in the underlying claim, counterclaim and Rios lawsuit. Trial has been set for December 3, 2007. TMS intends to contest liability but we can give no assurances regarding the outcome of the initial proceeding, the counterclaim or the Rios lawsuit.

On December 8, 2005, WTG Gas Processing (“WTG”) filed suit in the 333rd District Court of Harris County, Texas against several defendants, including Targa Resources, Inc., and Targa Texas, and two other Targa entities and private equity funds affiliated with Warburg Pincus LLC, seeking damages from the defendants. The suit alleges that Targa and private equity funds affiliated with Warburg Pincus LLC, along with ConocoPhillips Company (“ConocoPhillips”) and Morgan Stanley, tortiously interfered with (i) a contract WTG claims to have had to purchase certain ConocoPhillips assets, and (ii) prospective business relations of WTG. WTG claims the alleged interference resulted from Targa’s competition to purchase the ConocoPhillips’ assets and its successful acquisition of those assets in 2004. A hearing on our motion for summary judgment was held on April 10, 2007 (see Note 13).

F-71

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Contractual Obligations

The debt incurred by TRP LP in connection with its IPO is the only significant change to our consolidated schedule of maturities of long-term debt since those reported in our Annual Report for the year ended December 31, 2006. See Note 7 and Note 13 for additional information regarding the debt obligations of TRP LP.

Casualty or Other Risks

We maintain coverage in various insurance programs providing us with property damage, business interruption and other coverage which are customary for the nature and scope of our operations.

We believe that we have adequate insurance coverage, although insurance will not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially, and in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts the revenues generated by us, or which caused us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations.

Note 10—Income Taxes

Texas House Bill 3928, effective June 15, 2007, required us to recognize changes in deferred tax assets related to a computational change of the temporary credit related to the Texas Margin Tax. For the nine months ended September 30, 2007 we recognized a deferred tax asset of $8.3 million, with a corresponding decrease to deferred income tax expense.

F-72

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 11—Related Party Transactions

Hedging Arrangements

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. Under the terms of these various commodity derivative transactions, MLCI has agreed to pay us specified fixed prices in relation to specified notional quantities of natural gas, NGL, and condensate over periods ending in 2010, and we have agreed to pay MLCI floating prices based on published index prices of such commodities for delivery at specified locations. The following table shows our open commodity derivatives with MLCI as of September 30, 2007:

Period	Commodity	Instrument Type	MMBtu per day	Avg. Price			Index
Oct 2007 – Dec 2007	Natural gas	Swap	26,118	$	7.65	per MMBtu	IF-Waha
Jan 2008 – Dec 2008	Natural gas	Swap	25,765	$	7.23	per MMBtu	IF-Waha
Jan 2009 – Dec 2009	Natural gas	Swap	25,474	$	6.82	per MMBtu	IF-Waha
Jan 2010 – Dec 2010	Natural gas	Swap	3,289	$	7.39	per MMBtu	IF-Waha
Oct 2007 – Dec 2007	NGLs	Swap	6,498	$	39.57	per barrel	OPIS-MB
Jan 2008 – Dec 2008	NGLs	Swap	6,222	$	38.38	per barrel	OPIS-MB
Jan 2009 – Dec 2009	NGLs	Swap	5,847	$	36.28	per barrel	OPIS-MB
Oct 2007 – Dec 2007	Condensate	Swap	319	$	75.27	per barrel	NY-WTI
Jan 2008 – Dec 2008	Condensate	Swap	264	$	72.66	per barrel	NY-WTI
Jan 2009 – Dec 2009	Condensate	Swap	202	$	70.60	per barrel	NY-WTI
Jan 2010 – Dec 2010	Condensate	Swap	181	$	69.28	per barrel	NY-WTI

During the nine months ended September 30, 2007, we paid MLCI $5.8 million to settle payments due under hedge transactions.

Commodity Transactions

During the nine months ended September 30, 2007, we completed natural gas and NGL purchases and sales transactions with related parties as follows (in thousands):

	Purchases		Sales
VESCO	$	104,828	$	1,455
GCF		170		10,139
MLCI		12,083		52,171
	$	117,081	$	63,765

These transactions were at market prices consistent with similar transactions with nonaffiliated entities.

Note 12—Segment Information

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 is a single segment consisting of our natural gas gathering and processing facilities, as well as certain fractionation capability integrated within those facilities; and

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TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• our NGL Logistics and Marketing division, which consists of three segments: (1) Logistics Assets, (ii) NGL Distribution and Marketing, and (iii) Wholesale Marketing.

Our Natural Gas Gathering and Processing segment, which includes TRP LP, consists of 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 NGL production and purchased NGL 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 NGL products from refinery customers and sell NGL 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. Our Wholesale Marketing segment operates principally in the United States, and has a small marketing presence in Canada.

Eliminations and Other 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 corporate office. Eliminations and Other also includes the elimination of intersegment revenues and expenses.

We review performance based on the non-generally accepted accounting principle (“non-GAAP”) financial measure of operating margin. We view our operating margin as an important performance measure of the core profitability of our operations. We review our operating margin monthly for consistency and trend analysis. We believe that investors benefit from having access to the same financial measures that our management uses. The GAAP measure most directly comparable to total segment operating margin is net income. Our non-GAAP financial measure of total segment operating margin should not be considered an alternative to GAAP operating income in evaluating our operating results.

With respect to our Natural Gas Gathering and Processing division, we define operating margin as total operating revenues, which consist of natural gas and NGL sales plus service fee revenues, less product purchases, which consist primarily of producer payments and other natural gas purchases less operating expense. Natural gas and NGL sales revenue includes settlement gains and losses on commodity hedges.

With respect to our NGL Logistics and Marketing division, we define operating margin as total revenue, which consists primarily of service fee revenues and NGL sales, less cost of sales, which consists primarily of NGL purchases and changes in inventory valuation. Within this division, our management analyzes segment operating margin for each of the three segments per unit of NGL handled or sold as an indicator of operational and commercial performance.

F-74

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We consolidate the financial statements of TRP LP with those of our own. As a result, our consolidated operating margin amounts include the operating margin amounts of TRP LP on a 100% basis. Our reportable segment information is shown in the following tables:

Nine months ended September 30, 2007

(in thousands)	Gas Gathering and Processing		Logistics Assets		NGL Distribution and Marketing			Wholesale Marketing		Eliminations and Other			Total
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
General and administrative	$	39,725	$	14,902	$	8,163		$	15,194	$	237		$	78,221
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

Nine months ended September 30, 2006

(in thousands)	Gas Gathering and Processing		Logistics Assets			NGL Distribution and Marketing		Wholesale Marketing		Eliminations and Other			Total
Revenues	$	1,144,951	$	46,667		$	2,552,866	$	954,799	$	—		$	4,699,283
Intersegment revenues		838,296		88,169			309,483		53,560		(1,289,508	)		—
Revenues		1,983,247		134,836			2,862,349		1,008,359		(1,289,508	)		4,699,283
Product purchases		1,579,167		2			1,908,332		687,394		—			4,174,895
Intersegment product purchases		2,654		(2	)		945,769		315,808		(1,264,229	)		—
Product purchases		1,581,821		—			2,854,101		1,003,202		(1,264,229	)		4,174,895
Operating expenses		83,886		75,423			1,236		9		—			160,554
Intersegment operating expenses		521		24,758			—		—		(25,279	)		—
Operating expenses		84,407		100,181			1,236		9		(25,279	)		160,554
Operating margin	$	317,019	$	34,655		$	7,012	$	5,148	$	—		$	363,834
General and administrative	$	27,655	$	10,450		$	10,235	$	13,032	$	3,689		$	65,061
Equity in earnings of unconsolidated investments	$	3,302	$	2,101		$	—	$	—	$	—		$	5,403
Unconsolidated investments	$	16,789	$	13,200		$	—	$	—	$	—		$	29,989
Capital expenditures	$	94,803	$	12,565		$	—	$	—	$	2,362		$	109,730

F-75

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

A reconciliation of our measurement of operating margin to net income follows:

(in thousands)	Nine Months Ended September 30,
	2007			2006
Operating margin	$	370,290		$	363,834
Adjustments to reconcile operating margin to net income (loss):
Depreciation and amortization		(110,757	)		(110,938	)
Gain (loss) on sale of assets		95			201
General and administrative		(78,221	)		(65,061	)
Interest expense, net		(112,752	)		(133,245	)
Equity in earnings of unconsolidated investments		7,964			5,403
Minority interest		(20,492	)		(22,403	)
Non-controlling interest of net income of TRP LP		(6,628	)		—
Income tax (expense) / benefit		(13,170	)		(16,365	)
Net income (loss)	$	36,329		$	21,426

Note 13—Subsequent Events

TRP LP

On October 23, 2007, the general partner of TRP LP approved a quarterly distribution of available cash of $0.3375 per unit (approximately $15.3 million), for the quarter ended September 30, 2007, payable on November 14, 2007 to unitholders of record as of the close of business on November 4, 2007.

On October 24, 2007, TRP LP completed an offering of 13,500,000 common units representing limited partnership interests at $26.87 per common unit (before expenses). The net proceeds from the offering were approximately $346.2 million (net of the underwriting discount and estimated offering expenses). Concurrently with the offering, TRP LP entered into a commitment increase supplement to its existing five-year $500 million revolving credit facility that increased the aggregate commitments under the facility to $750 million and borrowed an additional $378.8 million under the facility.

TRP LP used the proceeds from the unit offering and borrowings to acquire our ownership interests in the San Angelo Operating Unit system located in the Permian Basin of west Texas and the Louisiana Operating Unit system located in southwest Louisiana. Total consideration paid by TRP LP consisted of $721.7 million in cash and 275,511 TRP LP general partner units issued to us to maintain our 2% general partner interest in TRP LP.

We continue to consolidate TRP LP’s assets, liabilities and results of operations due to our control of TRP LP through our general partner interest.

On October 24, 2007, TRP LP also amended its credit agreement. The amendment increased by $250 million the maximum amount of increases to the aggregate commitments that may be requested by TRP LP. The amendment allows TRP LP to request commitments under the credit agreement, as supplemented and amended, up to $1 billion.

F-76

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Litigation

On October 2, 2007, the Court granted defendants’ motions for summary judgment on all of WTG’s claims. WTG’s motion to reconsider and for new trial is pending before the Court. Targa intends to contest the motion and any appeal filed by WTG, but can give no assurances regarding the outcome of the proceeding.

Registration Statement

On October 31, 2007, we filed with the Securities and Exchange Commission an exchange offer registration statement on Form S-4. The exchange offer registration statement pertains to our existing 8 ¹/2% Senior Notes due 2013 and was filed pursuant to the terms of a registration rights agreement dated October 31, 2005.

Note 14—Condensed Consolidating Financial Statements

We are the issuer of the $250,000,000 in aggregate principal amount of 8 ¹/2% Senior Notes due 2013 referred to in Note 6 of our Annual Report for the year ended December 31, 2006. 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:

• Targa Resources, Inc. 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.

F-77

TARGA RESOURCES, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Prior period amounts have been restated to reflect as Guarantor Subsidiaries only those subsidiaries that guarantee our notes as of September 30, 2007. In connection with TRP LP’s IPO, the guarantee of indebtedness of the assets contributed to TRP LP from us was terminated, the collateral interest was released, and TRP LP and its consolidated subsidiaries are no longer Guarantor Subsidiaries.

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

September 30, 2007

(in thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—		$	83,102		$	69,306		$	—		$	152,408
Accounts receivable and other current assets		9,064			802,014			33,682			—			844,760
		9,064			885,116			102,988			—			997,168
Property, plant and equipment, at cost		—			1,016,676			1,727,681			—			2,744,357
Accumulated depreciation		—			58,083			(355,259	)		—			(297,176	)
Property, plant and equipment, net		—			1,074,759			1,372,422			—			2,447,181
Unconsolidated investments		—			46,637			—			—			46,637
Investment in subsidiaries		1,669,061			—			—			(1,669,061	)		—
Advances to (from) subsidiaries		183,923			(240,107	)		56,184			—			—
Other assets		135,846			(84,646	)		12,325			—			63,525
Total assets	$	1,997,894		$	1,681,759		$	1,543,919		$	(1,669,061	)	$	3,554,511
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable and other liabilities	$	17,092		$	612,636		$	105,698		$	—		$	735,426
Current maturities of debt		12,500			—			—			—			12,500
		29,592			612,636			105,698			—			747,926
Long-term liabilities
Long-term debt, net of current maturities		1,462,500			—			294,500			—			1,757,000
Other long-term obligations		11,797			54,216			18,506			(612	)		83,907
		1,474,297			54,216			313,006			(612	)		1,840,907
Minority interest		—			—			—			103,335			103,335
Non controlling interest in TRP LP		—			—			—			368,338			368,338
Stockholder’s equity:
Stockholder's equity		516,900			1,052,149			1,133,350			(2,185,499	)		516,900
Accumulated other comprehensive income		(22,895	)		(37,242	)		(8,135	)		45,377			(22,895	)
		494,005			1,014,907			1,125,215			(2,140,122	)		494,005
Total liabilities and stockholder’s equity	$	1,997,894		$	1,681,759		$	1,543,919		$	(1,669,061	)	$	3,554,511

F-78

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2006

(in thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	—		$	117,661		$	25,078		$	—		$	142,739
Accounts receivable and other current assets		1,694			674,950			40,274			—			716,918
		1,694			792,611			65,352			—			859,657
Property, plant, and equipment, at cost		—			959,258			1,692,117			—			2,651,375
Accumulated depreciation		—			105,183			(292,031	)		—			(186,848	)
Property, plant, and equipment, net		—			1,064,441			1,400,086			—			2,464,527
Unconsolidated investments		—			40,212			—			—			40,212
Investment in subsidiaries		2,622,245			—			—			(2,622,245	)		—
Advances to (from) subsidiaries		(14,088	)		(16,263	)		30,351			—			—
Other assets		146,184			(69,146	)		16,591			—			93,629
Total assets	$	2,756,035		$	1,811,855		$	1,512,380		$	(2,622,245	)	$	3,458,025
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable and other liabilities	$	37,000		$	472,735		$	81,495		$	—		$	591,230
Current maturities of debt		712,500			—			—			—			712,500
		749,500			472,735			81,495			—			1,303,730
Long-term liabilities
Long-term debt, net of current maturities		1,471,875			—			—			—			1,471,875
Other long-term obligations		20,390			39,744			6,488			—			66,622
		1,492,265			39,744			6,488			—			1,538,497
Minority interest		—			—			101,528			—			101,528
Stockholder’s equity:
Stockholder’s equity		478,587			1,265,521			1,292,541			(2,558,062	)		478,587
Accumulated other comprehensive income		35,683			33,855			30,328			(64,183	)		35,683
		514,270			1,299,376			1,322,869			(2,622,245	)		514,270
Total liabilities and stockholder’s equity	$	2,756,035		$	1,811,855		$	1,512,380		$	(2,622,245	)	$	3,458,025

F-79

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Nine Months Ended September 30, 2007

(in thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:	$	—		$	4,780,909		$	731,482		$	(588,975	)	$	4,923,416
Operating costs and expenses:
Product purchases		—			4,443,046			487,349			(557,106	)		4,373,289
Operating expenses		—			119,028			92,678			(31,869	)		179,837
Depreciation and amortization		—			47,501			63,256			—			110,757
General and administrative and other		61			69,951			8,114			—			78,126
		61			4,679,526			651,397			(588,975	)		4,742,009
Operating income		(61	)		101,383			80,085			—			181,407
Other income (expense):
Interest expense, net		(6,709	)		(84,035	)		(22,008	)		—			(112,752	)
Equity in earnings of unconsolidated investments		—			7,964			—			—			7,964
Equity in earnings of subsidiaries		55,884			—			—			(55,884	)		—
Minority interest		—			—			—			(27,120	)		(27,120	)
Income before income taxes		49,114			25,312			58,077			(83,004	)		49,499
Income tax expense		(12,785	)		—			(997	)		612			(13,170	)
Net income (loss)	$	36,329		$	25,312		$	57,080		$	(82,392	)	$	36,329

F-80

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

Nine Months Ended September 30, 2006 (unaudited)

(in thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Revenues	$	—		$	4,581,364		$	705,745		$	(587,826	)	$	4,699,283
Operating costs and expenses:
Product purchases		—			4,261,774			469,820			(556,699	)		4,174,895
Operating expenses		—			101,061			90,620			(31,127	)		160,554
Depreciation and amortization		—			49,337			61,601			—			110,938
General and administrative and other		132			59,399			5,329			—			64,860
		132			4,471,571			627,370			(587,826	)		4,511,247
Income from operations		(132	)		109,793			78,375			—			188,036
Other income (expense):
Interest income (expense), net		—			(134,155	)		910			—			(133,245	)
Equity income of unconsolidated investments		—			5,403			—			—			5,403
Equity in earnings of subsidiaries		37,923			—			—			(37,923	)		—
Minority interest		—			—			—			(22,403	)		(22,403	)
Income (loss) before income taxes		37,791			(18,959	)		79,285			(60,326	)		37,791
Income tax expense		(16,365	)		1,988			(1,988	)		—			(16,365	)
Net income (loss)	$	21,426		$	(16,971	)	$	77,297		$	(60,326	)	$	21,426

F-81

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Nine Months Ended September 30, 2007

(in thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income	$	36,329		$	25,312		$	57,080		$	(82,392	)	$	36,329
Adjustments to reconcile net income to net cash provided by (used in) operating activities
Depreciation, amortization and accretion		10,338			48,013			63,992			—			122,343
Deferred income taxes		11,496			—			997			(612	)		11,881
Equity in earnings of unconsolidated investments		—			(7,964	)		—			—			(7,964	)
Equity in earnings of subsidiaries		(55,884	)		—			—			55,884			—
Other		(12,405	)		3,012			(24,994	)		27,120			(7,267	)
Changes in operating assets and liabilities:														—
Accounts receivable and other assets		(250,692	)		124,501			(3,657	)		—			(129,848	)
Inventory		—			(27,639	)		—			—			(27,639	)
Accounts payable and other liabilities		(32,162	)		156,662			14,489			—			138,989
Net cash provided by (used in) operating activities		(292,980	)		321,897			107,907			—			136,824
Cash flows from investing activities
Purchases of property and equipment		—			(62,202	)		(35,564	)		—			(97,766	)
Other		—			15,528			(21	)		—			15,507
Net cash used in investing activities		—			(46,674	)		(35,585	)		—			(82,259	)
Cash flows from financing activities
Senior secured credit facilities:
Borrowings		—			—			342,500			—			342,500
Repayments		(709,375	)		—			(48,000	)		—			(757,375	)
Non-controlling investment in Targa Resources Partners LP		—			—			377,454			—			377,454
Other		(167	)		—			(7,308	)		—			(7,475	)
Receipts from (payments to) subsidiaries		1,002,522			(309,782	)		(692,740	)		—			—
Net cash provided by (used in) financing activities		292,980			(309,782	)		(28,094	)		—			(44,896	)
Net increase in cash and cash equivalents		—			(34,559	)		44,228			—			9,669
Cash and cash equivalents, beginning of year		—			117,661			25,078			—			142,739
Cash and cash equivalents, end of year	$	—		$	83,102		$	69,306		$	—		$	152,408

F-82

TARGA RESOURCES, INC.

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

Nine Months Ended September 30, 2006

(in thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Intercompany Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	21,426		$	(16,971	)	$	54,894		$	(37,923	)	$	21,426
Adjustments to reconcile net income to net cash provided		—			—			—			—
by operating activities		—			—			—			—
Depreciation, amortization and accretion		—			55,734			65,573			—			121,307
Deferred income taxes		16,562			(2,185	)		1,988			—			16,365
Equity in earnings of unconsolidated investments		—			(5,403	)		—			—			(5,403	)
Equity in earnings of subsidiaries		(37,923	)		—			—			37,923			—
Other		—			(44,354	)		22,403			—			(21,951	)
Changes in operating assets and liabilities:		—			—			—			—
Accounts receivable and other assets		(20,529	)		36,044			1,560			—			17,075
Inventory		—			26,261			(197	)		—			26,064
Accounts payable and other liabilities		2,367			(6,119	)		10,466			—			6,714
Net cash provided by operating activities		(18,097	)		43,007			156,687			—			181,597
Cash flows from investing activities
Purchases of property and equipment		—			(72,872	)		(35,049	)		—			(107,921	)
Acquisition of DMS, net of cash acquired		20,529			(8,695	)		32			—			11,866
Net cash used in investing activities		20,529			(81,567	)		(35,017	)		—			(96,055	)
Cash flows from financing activities
Senior secured credit facility:
Borrowings		—			—			—			—			—
Repayments		(9,375	)		—			—			—			(9,375	)
Receipts from (payments to) subsidiaries		7,591			69,652			(77,243	)		—			—
Costs incurred in connection with financing arrangements		(648	)		47,779			(47,779	)		—			(648	)
Net cash provided by (used in) financing activities		(2,432	)		117,431			(125,022	)		—			(10,023	)
Net increase in cash and cash equivalents		—			78,871			(3,352	)		—			75,519
Cash and cash equivalents, beginning of year		—			9,624			31,803			—			41,427
Cash and cash equivalents, end of year	$	—		$	88,495		$	28,451		$	—		$	116,946

F-83

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of ConocoPhillips

We have audited the accompanying combined balance sheets of the Midstream Operations sold to Targa Resources, Inc. (the “Midstream Operations”) as of April 15, 2004, December 31, 2003 and 2002, and the related combined statements of operations, parent company investment, and cash flows for the 106-day period ended April 15, 2004, and years ended December 31, 2003 and 2002. These financial statements are the responsibility of ConocoPhillips’ management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Midstream Operations’ internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Midstream Operations’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of the Midstream Operations sold to Targa Resources, Inc. at April 15, 2004, December 31, 2003 and 2002, and the combined results of its operations and its cash flows for the 106-day period ended April 15, 2004, and the years ended December 31, 2003 and 2002, in conformity with U.S. generally accepted accounting principles.

/s/    ERNST & YOUNG LLP

Houston, Texas

July 29, 2005

F-84

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

COMBINED STATEMENTS OF OPERATIONS

	Thousands of Dollars
	106-Day Period Ended April 15, 2004		Years Ended December 31,
			2003		2002
Revenues
Sales and other operating revenues	$	232,769	$	724,667	$	541,195
Total revenues		232,769		724,667		541,195
Costs and Expenses
Purchased products		212,306		665,357		479,682
Operating expenses		7,850		23,223		24,319
Selling, general and administrative expenses		757		3,289		3,281
Depreciation and amortization		3,833		12,866		9,791
Taxes other than income taxes		1,407		4,325		4,775
Other		—		4		52
Total Costs and Expenses		226,153		709,064		521,900
Income before income taxes		6,616		15,603		19,295
Provision for income taxes		2,567		6,062		7,475
Net Income	$	4,049	$	9,541	$	11,820

See Notes to Combined Financial Statements.

F-85

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

COMBINED BALANCE SHEETS

	Thousands of Dollars
	At April 15, 2004		At December 31,
			2003		2002
Assets
Cash and cash equivalents	$	—	$	—	$	—
Accounts receivable		20,985		44,718		14,398
Materials and supplies inventories		1,332		1,332		1,339
Prepaid expenses and other current assets		493		1,924		969
Total Current Assets		22,810		47,974		16,706
Net properties, plants and equipment		266,011		268,816		296,583
Total Assets	$	288,821	$	316,790	$	313,289
Liabilities
Accounts payable	$	27,477	$	48,756	$	47,260
Accrued income and other taxes		711		942		50
Other accruals and current liabilities		991		881		1,618
Total Current Liabilities		29,179		50,579		48,928
Accrued environmental costs		827		345		364
Deferred income taxes		87,954		88,602		94,443
Total Liabilities		117,960		139,526		143,735
Parent Company Investment
Parent company investment		170,861		177,264		169,554
Total	$	288,821	$	316,790	$	313,289

See Notes to Combined Financial Statements.

F-86

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

COMBINED STATEMENTS OF CASH FLOWS

	Thousands of Dollars
	106-Day Period Ended April 15, 2004			Years Ended December 31,
				2003			2002
Cash Flows From Operating Activities
Net income	$	4,049		$	9,541		$	11,820
Adjustments to reconcile net income to net cash provided by operating activities
Non-working capital adjustments
Depreciation and amortization		3,833			12,866			9,791
Deferred taxes		(648	)		880			1,366
Other		482			(19	)		364
Working capital adjustments
Decrease (increase) in accounts receivable		23,733			(30,320	)		4,238
Decrease in inventories		—			7			128
Decrease (increase) in prepaid expenses and other current assets		1,431			(955	)		917
Increase (decrease) in accounts payable		(21,279	)		1,496			13,834
Increase (decrease) in taxes and other accruals		(121	)		155			996
Net Cash Provided by Operating Activities		11,480			(6,349	)		43,454
Cash Flows From Investing Activities
Capital expenditures		(1,176	)		(2,413	)		(11,407	)
Net Cash Used in Investing Activities		(1,176	)		(2,413	)		(11,407	)
Cash Flows From Financing Activities
Net cash changes in parent company investment		(10,304	)		8,762			(32,047	)
Net Cash Used in Financing Activities		(10,304	)		8,762			(32,047	)
Net Change in Cash and Cash Equivalents		—			—			—
Cash and cash equivalents at beginning of year/period		—			—			—
Cash and Cash Equivalents at End of Year/Period	$	—		$	—		$	—

See Notes to Combined Financial Statements.

F-87

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

COMBINED STATEMENT OF PARENT COMPANY INVESTMENT

	Thousands of Dollars
Parent company investment at December 31, 2001	$	122,420
Net income		11,820
Net change in parent company advances		35,314
Parent company investment at December 31, 2002		169,554
Net income		9,541
Net change in distributions to parent company		(1,831	)
Parent company investment at December 31, 2003		177,264
Net income		4,049
Net change in distributions to parent company		(10,452	)
Parent company investment at April 15, 2004	$	170,861

See Notes to Combined Financial Statements.

F-88

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO COMBINED FINANCIAL STATEMENTS

Note 1—Accounting Policies

• Basis of Financial Statements—These combined financial statements represent certain natural gas liquids operations of ConocoPhillips Company (the parent company) located in South Louisiana and the Permian Basin in West Texas (hereinafter collectively referred to as the Midstream Operations), which ConocoPhillips Company sold to Targa Resources, Inc., effective April 1, 2004. These operations are integrated gathering and processing systems that purchase raw natural gas from producers, which is gathered through pipeline gathering systems. The gathered natural gas is then processed to extract natural gas liquids from the raw gas stream and the remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel, or blendstock. These are sold to third parties, as well as to ConocoPhillips Company.

These financial statements are presented on a going-concern basis, as if these assets had existed as an entity separate from ConocoPhillips Company during the periods presented. These assets were not a separate legal entity during the periods presented. References to the Midstream Operations are to “ConocoPhillips Company, with respect to the midstream operations that it sold to Targa.” During the periods presented, ConocoPhillips Company charged the Midstream Operations a portion of its corporate support costs, including engineering, legal, treasury, planning, environmental, tax, auditing, information technology, and other corporate services, based on usage, actual costs or other allocation methods considered reasonable by ConocoPhillips Company management. Accordingly, expenses included in these financial statements may not be indicative of the level of expenses which might have been incurred had the Midstream Operations been operating as a separate stand-alone company.

ConocoPhillips Company is a wholly owned subsidiary of ConocoPhillips, a company incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. (Conoco) and Phillips Petroleum Company (Phillips). The merger between Conoco and Phillips (the merger) was consummated on August 30, 2002, and Conoco and Phillips each became wholly owned subsidiaries of ConocoPhillips. For accounting purposes, Phillips was designated as the acquirer of Conoco and ConocoPhillips was treated as the successor of Phillips. Subsequent to the merger, Phillips was renamed ConocoPhillips Company. Before the merger, the Midstream Operations were owned by Conoco. As a result of the merger and the subsequent allocation of the purchase price to specific assets and liabilities, the recorded book value of the Midstream Operations was re-measured to fair value as of August 30, 2002.

• Revenue Recognition—Revenues associated with sales of natural gas, natural gas liquids, and other items are recorded when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, which is generally at the tailgate of the processing plant. Midstream Operations uses commodity derivative instruments, such as swaps and futures, in various markets to effectively convert fixed-price contracts to a floating price. See Note 1—Accounting Policies—Derivative Instruments, for additional information on the accounting for, and reporting of, commodity derivatives contracts.

• Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from the estimates and assumptions used.

• Parent Company Investment—The parent company investment included in the balance sheet represents the net balances resulting from various transactions between the Midstream Operations and

F-89

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

ConocoPhillips Company. There were no terms of settlement or interest charges associated with the account balance. The balance included the Midstream Operations’ participation in ConocoPhillips Company’s central cash management program. The Midstream Operations’ cash receipts were remitted to, and its cash disbursements were funded by, ConocoPhillips Company. Other transactions included product purchases from, and sales to, the parent company; the Midstream Operations’ share of the current portion of ConocoPhillips Company’s consolidated income tax liability; and other administrative and support expenses incurred by ConocoPhillips Company and allocated or charged to the Midstream Operations.

• Inventories—Materials and supplies are valued at average cost.

• Derivative Instruments—All derivative instruments are recorded on the balance sheet at fair value in either prepaid expenses and other current assets or other accruals and current liabilities. Recognition of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives that are not accounted for as hedges under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” are recognized immediately in earnings. In the combined statement of operations, gains and losses from derivatives are recorded in sales and other operating revenues.

• Properties, Plants and Equipment—Properties, plants and equipment are recorded at cost except when re-measured to fair-value in a merger.

• Depreciation and Amortization—Depreciation and amortization is determined by the group-straight-line method over a 20-year to 22-year useful life. Prior to August 30, 2002, properties, plants and equipment were depreciated over a 25-year useful life.

• Impairment of Properties, Plants and Equipment—Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as Property Impairments in the periods in which the determination of impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell. In assessing impairment and applying the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” management considered the Midstream Operations as a going concern and separate reporting entity. Therefore, considerations related to ConocoPhillips Company’s intentions to dispose of these operations are not reflected in these statements. However, as described in Note 3, ConocoPhillips Company incurred an impairment charge on its investment in the Midstream Operations.

The expected future cash flows used for impairment reviews and related net realizable value calculations are based on production volumes, prices and costs, considering all available evidence at the date of the review.

F-90

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

• Maintenance and Repairs—The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

• Environmental Costs—Environmental expenditures are expensed or capitalized as appropriate, depending upon their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities for these expenditures are recorded on an undiscounted basis (unless acquired in a purchase business acquisition such as the merger) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Since the Midstream Operations were acquired by ConocoPhillips Company in the merger of Conoco and Phillips, the majority of its environmental liabilities are recorded on a discounted basis. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable.

• Income Taxes—The Midstream Operations’ results of operations are included in the consolidated U.S. federal and state income tax returns of ConocoPhillips. Deferred taxes are provided on all temporary differences between the financial-reporting basis and the tax basis of the Midstream Operations’ assets and liabilities. Income tax expense or benefit represents Midstream Operations, on a separate-return basis, using the same principles and elections used in ConocoPhillips’ consolidated return. Any resulting current tax liability or refund is settled with the parent company on a current basis.

Note 2—Related-Party Transactions

Significant transactions with related parties were:

	Thousands of Dollars
	106-Day Period Ended April 15, 2004		Years Ended December 31,
			2003		2002
Sales and other operating revenues(a)	$	112,706	$	557,977	$	322,264
Purchased products(b)		23,667		100,409		20,252
Selling, general and administrative expenses(c)		752		3,196		3,242

(a) The Midstream Operations sold natural gas and natural gas liquids to ConocoPhillips Company for re-marketing to third parties, at prices that approximate market.

(b) The Midstream Operations purchased natural gas feedstocks for its processing plants from ConocoPhillips Company, at prices that approximate market.

(c) ConocoPhillips Company charged the Midstream Operations a portion of its corporate support costs, including engineering, legal, treasury, planning, environmental, tax, auditing, information technology, research and development, and other corporate services, based on usage, actual costs, or other allocation methods considered reasonable by ConocoPhillips Company’s management.

Inventory profit-or-loss-elimination amounts at April 15, 2004, and December 31, 2003 and 2002, on purchases from, and sales to, related parties were not material.

F-91

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 3—Properties, Plants and Equipment

The Midstream Operations’ investment in properties, plants and equipment, with accumulated depreciation and amortization, at balance-sheet date was:

	Thousands of Dollars
	At April 15, 2004			At December 31,
				2003			2002
Processing plants	$	107,308		$	106,869		$	106,203
Pipelines		178,208			178,347			194,430
Gross properties, plants and equipment		285,516			285,216			300,633
Accumulated depreciation and amortization		(19,505	)		(16,400	)		(4,050	)
Net properties, plants and equipment	$	266,011		$	268,816		$	296,583

Properties, plants and equipment consist primarily of processing plant and pipeline assets, which are depreciated on estimated useful lives of 20 to 22 years. At the end of August 2002, in conjunction with the merger, the Midstream Operations’ properties, plants and equipment were re-measured to fair value. As part of this, the useful lives of the plants changed from 25 years to 20 years for Louisiana and to 22 years for the plants in West Texas. At December 31, 2002, properties, plants and equipment included $17,300,000 for certain pipeline assets in West Texas that the U.S. Federal Trade Commission required ConocoPhillips Company to sell as a condition of the merger. These pipelines were transferred to the parent company in 2003 as part of a sales transaction. Because these assets were an integrated part of the operating units sold to Targa, that transaction has been reflected in these financial statements.

In 2004, ConocoPhillips Company incurred a $24,141,000 impairment to write down to net realizable value the properties, plants and equipment planned to be sold to Targa Resources, Inc.

Note 4—Accrued Environmental Costs and Asset Retirement Obligations

Midstream Operations had environmental costs of $1,055,207, $428,694, and $415,521 accrued at April 15, 2004; December 31, 2003; and December 31, 2002, respectively. Of the total accrued at April 15, 2004, and December 31, 2003 and 2002, $227,988, $83,851 and $51,829, respectively, were classified as short-term on the combined balance sheet. Based on analyses of available information and previous experience with respect to remediation sites, it is reasonably possible that the costs associated with these sites could exceed current accruals by amounts that may not be material but that could range up to $3,000,000, in aggregate.

Because the Midstream Operations were acquired by ConocoPhillips Company in the merger of Conoco and Phillips, the majority of its environmental liabilities are recorded on a discounted basis. Expected expenditures for acquired environmental obligations are discounted using a 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $380,205 at April 15, 2004. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $69,000 in 2004, $50,000 in 2005, $30,000 in 2006, $10,000 in 2007, $10,000 in 2008, $10,000 in 2009, and $294,000 for all future years after 2009.

Effective January 1, 2003, Midstream Operations adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which applies to legal obligations associated with the retirement and removal of long-lived assets. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the

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MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

period when it is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, an entity capitalizes the cost by increasing the carrying amount of the related properties, plants and equipment. Over time, the liability is increased for the change in its present value, and the initial capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset.

Midstream Operations facilities, such as plants and office buildings, are not presently subject to any legal requirements to remove these facilities and so are not within the scope of SFAS No. 143. Consequently, application of this new accounting standard did not result in an increase in net properties, plants and equipment or impact net income.

Note 5—Contingencies

In the case of all known contingencies, the Midstream Operations accrue an undiscounted liability when the loss is probable and the amount is reasonably estimable. These liabilities are not reduced for potential insurance recoveries. If applicable, undiscounted receivables are accrued for probable insurance or other third-party recoveries. Based on information available at the time of the preparation of these financial statements, the management of ConocoPhillips Company believed that it was remote that future costs related to known contingent liability exposures would exceed accruals by an amount that would have a material adverse impact on the financial statements of the Midstream Operations.

As facts concerning contingencies become known, the Midstream Operations reassesses its position, both with respect to accrued liabilities and other potential exposures. Estimates that are particularly sensitive to future change include contingent liabilities recorded for environmental remediation and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the unknown magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of liability in proportion to other responsible parties. Estimated future costs related to legal matters are subject to change as events evolve, and as additional information becomes available during the administrative and litigation process.

Environmental—The Midstream Operations are subject to federal, state and local environmental laws and regulations. These may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various sites.

Other Legal Proceedings—The Midstream Operations are a party to a number of other legal proceedings pending in various courts or agencies for which, in some instances, no provision has been made.

Note 6—Financial Instruments and Derivative Contracts

Derivative Instruments

Commodity Derivative Contracts—Midstream Operations operates in the U.S. natural gas and natural gas liquids markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect revenues, as well as the cost of operating, investing, and financing activities. Generally, the Midstream Operations’ policy is to remain exposed to market prices of commodity purchases and sales. Consistent with this policy, Midstream Operations uses commodity derivative instruments, with the assistance of ConocoPhillips Company’s Commercial organization, to convert fixed-price sales contracts, which are often requested by natural gas consumers, to a floating market price.

SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (Statement No. 133 or SFAS No. 133), requires companies to recognize all derivative instruments as either assets or

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CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

liabilities on the balance sheet at fair value. Assets and liabilities resulting from derivative contracts open at each balance sheet date appear as prepaid expenses and other current assets or other accruals and current liabilities on the combined balance sheet.

The accounting for changes in fair value (i.e., gains or losses) of a derivative instrument depends on whether it meets the qualifications for, and has been designated as, a SFAS No. 133 hedge, and the type of hedge. At April 15, 2004, ConocoPhillips Company was not using SFAS No. 133 hedge accounting for commodity derivative contracts. All gains and losses, realized or unrealized, from the Midstream Operations’ swaps and futures have been recognized in the combined statement of operations.

SFAS No. 133 also requires purchase and sales contracts for commodities that are readily convertible to cash (e.g., natural gas) to be recorded on the combined balance sheet as derivatives unless the contracts are for quantities expected to be used or sold over a reasonable period in the normal course of business (the normal purchases and normal sales exception), among other requirements, and ConocoPhillips Company has documented its intent to apply this exception. If the exception had not been applied, both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the combined balance sheet at fair value in accordance with the preceding paragraphs.

Fair Values of Financial Instruments

The Midstream Operations used the following methods and assumptions to estimate the fair value of its financial instruments:

• Accounts receivable. The carrying amount reported on the combined balance sheet approximates fair value.

• Futures. Fair values are based on quoted market prices obtained form the New York Mercantile Exchange, the International Petroleum Exchange of London Limited, or other traded exchanges.

• Swaps. Fair value is estimated based on forward market prices and approximates the net gains and losses that would have been realized if the contracts had been closed out at balance-sheet date. When forward market prices are not available, they are estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.

The Midstream Operations’ financial instruments at balance sheet date were:

	Thousands of Dollars
	Carrying Amount						Fair Value
	At April 15, 2004		At December 31,				At April 15, 2004		At December 31,
			2003		2002				2003		2002
Financial assets
Commodity derivatives	$	452	$	1,193	$	811	$	452	$	1,193	$	811
Financial liabilities
Commodity derivatives		763		797		1,566		763		797		1,566

Note 7—Financial Instruments and Credit Risk

The Midstream Operations’ financial instruments that were exposed to concentrations of credit risk consisted primarily of third-party trade receivables, which reflected a broad customer base, and over-the-counter derivative contracts, such as swaps, in which the credit risk derived from the counterparty to the transaction.

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CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

ConocoPhillips Company’s management closely monitored these exposures against predetermined credit limits, including the continual exposure adjustments that resulted from market movements. Individual counterparty exposure was managed within these limits, and included the use of cash-call margins when appropriate, thereby reducing the risk of significant non-performance. The Midstream Operations also used futures contracts, but futures have a negligible credit risk because they are traded on the New York Mercantile Exchange.

Note 8—Employee Benefit Plans

The employees of the Midstream Operations were included in the various employee benefit plans of ConocoPhillips Company. These plans included retirement and savings plans, and employee and retiree medical, dental and life insurance plans, and other such benefits. For the purpose of these separate financial statements, the Midstream Operations were considered as if participating in multi-employer benefit plans. Its share of allocated parent company employee benefit plan expenses was $1,047,000, $3,047,000, and $2,386,000 for the periods ended April 15, 2004; December 31, 2003; and December 31, 2002, respectively.

Note 9—Taxes

Taxes charged (credited) to income were:

	Thousands of Dollars
	106-Day Period Ended April 15, 2004			Years Ended December 31,
				2003		2002
Taxes Other Than Income Taxes
Property	$	691		$	3,014	$	3,805
Payroll		182			611		589
Franchise		479			480		303
Other		55			220		78
	$	1,407		$	4,325	$	4,775
Income Taxes
Federal
Current	$	2,733		$	4,392	$	5,202
Deferred		(553	)		746		1,164
State and local
Current		482			790		907
Deferred		(95	)		134		202
	$	2,567		$	6,062	$	7,475

F-95

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets were:

	Thousands of Dollars
	At April 15, 2004		At December 31,
			2003		2002
Deferred Tax Liabilities
Properties, plants and equipment	$	93,022	$	93,236	$	99,787
Derivatives		—		139		—
Total deferred tax liabilities		93,022		93,375		99,787
Deferred Tax Assets
Deferred state income tax		4,590		4,623		4,935
Derivatives		109		—		264
Accrued environmental costs		369		150		145
Total deferred tax assets		5,068		4,773		5,344
Net deferred tax liabilities	$	87,954	$	88,602	$	94,443

The purchase price allocation for the merger resulted in deferred tax liabilities of $42,444,000 related to the step up in value of properties, plants and equipment and the establishment of environmental liabilities at August 30, 2002.

The amounts of U.S. income before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:

	Thousands of Dollars						Percent of Pretax Income
	106-Day Period Ended April 15, 2004		Years Ended December 31,				106-Day Period Ended April 15, 2004	Years Ended December 31,
			2003		2002			2003	2002
United States income before income taxes	$	6,616	$	15,603	$	19,295	100.0	100.0	100.0
Federal statutory income tax	$	2,316		5,461		6,754	35.0	35.0	35.0
State income tax		251		601		721	3.8	3.9	3.7
	$	2,567	$	6,062	$	7,475	38.8	38.9	38.7

F-96

CONOCOPHILLIPS COMPANY’S

MIDSTREAM OPERATIONS SOLD TO TARGA RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 10—Cash Flow Information

	Thousands of Dollars
	106-Day Period Ended April 15, 2004		Years Ended December 31,
			2003			2002
Non-Cash Investing and Financing Activities
Distribution of non-cash assets to parent company	$	148	$	10,593	*	$	—
Contribution of non-cash assets by parent company		—		—			304
Revaluation of assets in conjunction with the merger of Conoco and Phillips		—		—			67,057	**
Cash Payments
Income taxes***		3,215		5,182			6,109

* Net of deferred taxes of $6,721,000.

** Net of deferred taxes of $42,444,000.

*** Amount paid to parent company for income taxes.

F-97

Report of Independent Registered Public Accounting Firm

Tothe Partners of

Dynegy Midstream Services, Limited Partnership:

In our opinion, the accompanying consolidated statements of operations, of changes in partners’ capital, and of cash flows present fairly, in all material respects, the results of operations and cash flows of Dynegy Midstream Services, Limited Partnership and its subsidiariesfor the ten months ended October 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 8 to the Consolidated Financial Statements, the Partnership has engaged in significant transactions with Dynegy Inc. and its subsidiaries and ChevronTexaco Corporation and its affiliates, related parties.

/s/    PricewaterhouseCoopers LLP

Houston, Texas

October 30, 2007

F-98

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENT OF OPERATIONS

(in millions)

	Ten Months Ended October 31, 2005
Revenues from third parties	$	2,080
Revenues from affiliates		1,508
Total revenues		3,588
Cost of sales, exclusive of depreciation shown separately below		3,317
Depreciation expense		64
Gain on sale of assets, net		(10	)
General and administrative expenses		50
Operating income		167
Losses from unconsolidated investments		(20	)
Other income, net		16
Minority interest expense		(24	)
Net income	$	139
Comprehensive income	$	139

See notes to consolidated financial statements.

F-99

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENT OF CASH FLOWS

(in millions)

	Ten Months Ended October 31, 2005
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	139
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		62
Accretion expense		1
Impairment charge		65
Losses from unconsolidated investments, net of cash distributions		26
Risk-management activities		(1	)
Gain on sale of assets, net		(10	)
Income attributable to minority interest holders		24
Changes in working capital:
Accounts receivable, net		(132	)
Inventory		(77	)
Prepayments and other assets		35
Accounts payable and accrued liabilities		124
Changes in non-current liabilities		(8	)
Non-cash settlement of transactions with Dynegy (See Notes 1 and 8)		(150	)
Net cash provided by operating activities		98
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(45	)
Proceeds from asset sales, net		11
Net cash used in investing activities		(34	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners, net		(45	)
Distributions to minority interest holders		(25	)
Net cash used in financing activities		(70	)
Net decrease in cash and cash equivalents		(6	)
Cash and cash equivalents, beginning of period		17
Cash and cash equivalents, end of period	$	11

See notes to consolidated financial statements.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(in millions)

	Limited Partner			General Partner			Total
Partners’ Capital, December 31, 2004	$	1,252		$	44		$	1,296
Net income		134			5			139
Cash distributions to Dynegy		(44	)		(2	)		(46	)
Settlement of transactions with Dynegy (See Notes 1 and 8)		(145	)		(5	)		(150	)
Partners’ Capital, October 31, 2005	$	1,197		$	42		$	1,239

See notes to consolidated financial statements.

F-101

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Nature of Business and Basis of Presentation

Nature of Business. Dynegy Midstream Services, Limited Partnership (“DMS”, “we”, “us”, “our”) is owned by Dynegy Midstream G.P., Inc. and Dynegy Midstream Holdings, Inc., which are each indirect, wholly owned subsidiaries of Dynegy, Inc. (“Dynegy”). Our business operations consist of natural gas gathering and processing, fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids.

Basis of Presentation. Effective November 1, 2005, DMS was acquired by Targa Resources, Inc. (“Targa”). The accompanying financial statements were prepared for the purpose of complying with Rule 3-05 of Regulation S-X of the Securities and Exchange Commission and have been included in the Registration Statement on Form S-4 of Targa.

Throughout the period covered by these financial statements, Dynegy has provided cash management services to us through a centralized treasury system whereby excess cash from most of its subsidiaries, held in separate subsidiary bank accounts, is swept to a centralized account managed by Dynegy treasury services. Our cash distributions to Dynegy are deemed to have occurred through the general and limited partner in accordance with our partnership agreement, and are reflected as an adjustment to partners’ capital.

We routinely conduct business with other subsidiaries of Dynegy that are not a part of this consolidated group. Such transactions primarily result from sales and purchases of natural gas and natural gas liquids. These transactions with Dynegy are not settled in cash. Instead, they are settled through adjustments to our partners’ capital and are not included in our operating cash flows.

Also, our consolidated financial statements include costs allocated to us by Dynegy for centralized general and administrative services performed by Dynegy on our behalf, as well as depreciation of assets utilized by such centralized Dynegy general and administrative functions. These transactions with Dynegy are not settled in cash. Instead, they are settled through adjustments to our partners’ capital and are not included in our operating cash flows.

As a result, operating cash flows, as reported, are not necessarily indicative of the operating cash flows that would have resulted if we had been operated as a separate entity. Were such transactions conducted with third parties and/or settled in cash, the effect on our consolidated financial statements, particularly on our operating cash flows, could be significant. Please see Note 8—Related Party Transactions for further information.

Note 2—Accounting Policies

Our accounting policies conform to accounting principles generally accepted in the United States of America (“GAAP”). Our most significant accounting policies are described below. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) developing fair value assumptions, including estimates of future cash flows and discount rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets and (4) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities. Intercompany accounts and transactions have been eliminated.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

Allowance for Doubtful Accounts. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable. We review our doubtful accounts regularly. Past due balances over 60 days, and over a specified amount, are reviewed individually for collectibility. Account balances are charged off against the allowance when we feel it is probable the receivable will not be collected. We review collectibility and establish or adjust our allowance as necessary, primarily utilizing methodologies involving historical levels of write-offs. The specific identification method is also used in certain circumstances. We do not have any off-balance sheet credit exposure related to our customers.

Investment in Unconsolidated Affiliates. Investments in affiliates over which we exercise significant influence, generally occurring in ownership interests of 20% to 50%, and also occurring in lesser ownership percentages due to voting rights or other factors, are accounted for using the equity method. Our share of net income (loss) from these affiliates is reflected in the consolidated statement of operations as earnings (losses) from unconsolidated investments. Any excess of our investment in affiliates, as compared to our share of the underlying equity that is not recognized as goodwill, is amortized over the estimated economic service lives of the underlying assets. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in earnings (losses) from unconsolidated investments in the consolidated statement of operations, if applicable.

Inventory. Our inventory consists primarily of natural gas and natural gas liquids valued at the lower of weighted average cost or at market

Property, Plant and Equipment. Property, plant and equipment, which consists principally of gas gathering, processing, fractionation, terminalling and storage facilities and natural gas transportation lines is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized. We consider major maintenance to be expenditures incurred on a cyclical basis to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 3 to 25 years. Composite depreciation rates (which we refer to as composite rates) are applied to functional groups of assets having similar economic characteristics. The estimated economic service lives of our functional asset groups are as follows:

Asset Group	Range of Years
Natural gas gathering systems and processing facilities	15 to 25
Fractionation, terminalling and natural gas liquids storage facilities	15 to 25
Transportation equipment and barges	5 to 10
Office and miscellaneous equipment	3 to 7

Gains and losses are not recognized for retirements of property, plant and equipment subject to composite rates until the asset group subject to the composite rate is retired. Gains and losses on sales of individual assets

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

are reflected in gain (loss) on sale of assets, net in the consolidated statement of operations. We assess the carrying value of our property, plant and equipment in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”). If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the related discounted cash flows of the assets and recording a loss if the resulting estimated fair value is less than the book value. For assets identified as held for sale, the book value is compared to comparable market prices, or the estimated fair value if comparable market prices are not readily available, to determine if an impairment loss is required.

Goodwill and Other Intangible Assets. Goodwill represents, at the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis and when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. We perform our annual impairment test in the fourth quarter after our annual budgetary process, and we may record impairment charges in future periods as a result of such test. We have $4 million of goodwill attributable to our Marketing Assets segment and $11 million of goodwill attributable to our Gas Gathering and Processing segment. During the ten months ended October 31, 2005, there was no change in our $15 million carrying amount of goodwill.

Income Taxes. As a partnership, we are not subject to federal income tax. We are subject to income taxes in the states of Texas and Tennessee through certain of our subsidiaries. However, historically, any state income tax on the partnership has been immaterial. The taxable income or loss resulting from our operations will ultimately be included in the federal and state income tax returns of the partners.

Revenue Recognition. Our segments consist largely of the ownership and operation of physical assets that we use in various natural gas processing operations and natural gas liquids fractionation, storage and terminalling and delivery operations. The business of these segments includes natural gas gathering and processing, separation of natural gas liquids into their component parts from a commingled stream of light liquid hydrocarbons and the transportation and delivery of natural gas liquids through gas liquids pipelines, transport tractors and tank trailers, our LPG barge fleet and railcars that we manage pursuant to a services agreement with ChevronTexaco Corporation and its affiliates (“ChevronTexaco”). End sales from these businesses result in physical delivery of natural gas residue and natural gas liquids to our wholesale and industrial customers. We recognize revenue from these transactions when the product or service is delivered to a customer. We also provide natural gas liquids storage and terminalling services for a fee.

Minority Interest. Minority interest includes third-party investments in entities that we consolidate, but do not wholly own. The net results attributed to minority interest holders in consolidated entities are included in minority interest expense in the consolidated statements of operations.

Accounting Principles Not Yet Adopted

SFAS No. 153. In December 2004, the FASB issued SFAS No. 153, “ Exchanges of Nonmonetary Assets—An Amendment of APB Opinion No. 29.” The guidance in APB Opinion No. 29, “ Accounting for Nonmonetary Transactions” , is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. The guidance in that Opinion, however, included certain exceptions to that principle. SFAS No. 153 amends Opinion No. 29 to eliminate the exception for nonmonetary exchanges of

F-104

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of SFAS No. 153 are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Early application is permitted and companies must apply the standard prospectively. The adoption of this standard did not have a material effect on our results of operations, financial position or cash flows.

SFAS No. 154. In May 2005, the Financial Accounting Standards Board issued SFAS No. 154, “ Accounting Changes and Error Corrections—A Replacement of APB Opinion No. 20 and SFAS No. 3”. SFAS 154 changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS No. 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of this standard did not have a material effect on our results of operations, financial position or cash flows.

EITF Issue 05-6. In June 2005, the EITF reached consensus on Issue No. 05-6, “Determining the Amortization Period for Leasehold Improvements”. EITF Issue 05-6 provides guidance on determining the amortization period for leasehold improvements acquired in a business combination or acquired subsequent to lease inception. The guidance in EITF Issue 05-6 will be applied prospectively and is effective for periods beginning after June 29, 2005. The adoption of this standard did not have a material effect on our results of operations, financial position or cash flows.

FIN 48. In June 2006 the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We adopted the provisions of FIN 48 on January 1, 2007. Based on our evaluation, we have determined that there are no significant uncertain tax positions requiring recognition in our financial statements at June 30, 2007. There are no unrecognized tax benefits that, if recognized, would affect the effective rate, and there are no unrecognized tax benefits that are reasonably expected to increase or decrease in the next twelve months.

SFAS No. 157. In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”. SFAS 157 defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS 157 does not require any new fair value measurements. However, for some entities, the application of SFAS 157 will change current practice. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We have not yet determined the impact this statement will have on our results of operations or financial position.

SFAS No. 159. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” which is effective for fiscal years beginning after November 15, 2007, with early adoption permitted. 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. We are currently reviewing this new accounting standard and the impact, if any, it will have on our financial statements.

F-105

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 3—Hurricanes Katrina and Rita

Certain of our Louisiana and Texas assets sustained damage during 2005 from two Gulf Coast Hurricanes—Katrina and Rita. The estimated cost of damages to our facilities is expected to approximate $101 million, which includes anticipated replacement, repair, and cleanup costs based upon current estimates. Of this estimated loss, $25 million is included in losses from unconsolidated investments in the Consolidated Statement of Operations for the ten months ended October 31, 2005. An additional $65 million loss is included in Other income, net. Insurance recoveries related to the hurricane damages estimated to be $81 million were also included in Other income, net .

The table below summarizes the following information for our operated facilities where we sustained property damage: our ownership percentage, the actual or estimated date when the facility resumed or will resume full operation and our share of the estimated repair costs (for which we have filed or will file property damage insurance claims).

Facility	% Owned	Actual or Estimated Date for Full Facility Resumption	(in millions) Est. Cost of Repairs
Venice	22.9	4th Qtr. 2006	$	36.1
Yscloskey	23.8	Early 2nd Qtr 2006		13.3
Hattiesburg	50.0	Sept 2005		0.2
Pelican Offshore Pipeline and Platform	100.0	Jan 2006		24.7
Stingray	100.0	Mar 2006		11.7
Barracuda	100.0	Feb 2006		10.8
Lake Charles Frac/Hackberry Storage	100.0	Oct 2005		1.4
Seahawk Offshore Pipeline	100.0	Oct 2005		0.9
Lowry	100.0	Oct 2005		0.3
Mt. Belvieu/Galena Park	100.0	Oct 2005		0.5

The following table contains similar information for non-operated facilities affected by the hurricanes, where the impact on us for business interruption claims for non-operated facilities is anticipated to be more significant than for property damage claims.

Facility	% Owned	Plant Operator	Actual or Estimated Date for Full Facility Resumption
Toca	9.4	Enterprise	Dec 2005
Calumet	37.2	Enterprise	Oct 2005
Terrebone	11.4	Enterprise	Oct 2005
Bluewater	21.8	ExxonMobil	Oct 2005
Iowa	9.9	Duke	Oct 2005
Sea Robin	0.8	Hess	Early 2nd Qtr 2006
Gulf Coast Fractionator	38.8	ConocoPhillips	Oct 2005

The total estimated cost of repairs associated with the non-operated facilities is $1.3 million, with Toca accounting for $1.0 million of the total. We are filing business interruption claims for the facilities included in the tables above and for other operated assets where there was no significant property damage (such as the Cedar Bayou Fractionator). We will also file contingent business interruption claims resulting from the hurricane damage to third-party facilities including the Pascagoula and Alliance Refineries, and the Grand Cheniere Plant (which BP p.l.c. has decided not to repair) and offshore production facilities. The most significant business interruption impact was from Hurricane Katrina, resulting in material losses in Louisiana at the Venice Complex, the Yscloskey Plant, the Toca Plant, and other plants. In addition to negatively impacted direct plant profits, the associated business interruption losses also affected liquids marketing profits, wholesale/transportation profits and caused us to incur additional expenses to meet commercial obligations under existing contracts.

F-106

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We believe we have adequate insurance coverage to cover the facility repair costs and to offset the majority of the associated lost profits as a result of the hurricanes. The property damage insurance coverage has a $1 million (100%) per onshore occurrence deductible and a $250,000 per offshore occurrence deductible associated with each respective hurricane claim. These deductibles will reduce our ultimate property damage insurance recoveries by approximately $1.5 million.

With the exception of the Venice Complex, where funds are paid from a joint account with a cash call mechanism where we contribute our ownership share, we are currently funding the cost of repair for the facilities we operate and expect to be reimbursed by our partners for their share of costs under the normal joint interest billing process. We expect to be reimbursed under our property insurance coverage for our portion of repair costs. For the non-operated facilities, we are funding our share through joint interest billings from the facility operator and expect to be reimbursed by our insurance coverage.

Note 4—Dispositions

Sale of Land. On September 9, 2005, we sold a tract of land at our Port Everglades, Florida terminal for approximately $11 million in cash. As a result, we recognized a gain of approximately $10 million in the third quarter of 2005 in our Marketing Assets segment. The gain is included in Gain on sale of assets, net in our consolidated statements of operations.

Note 5—Risk Management Activities

Our operations are impacted by several factors, some of which may not be mitigated by risk management methods. These risks include, but are not limited to, commodity price, weather patterns, counterparty credit risks, changes in competition, operational risks, environmental risks and changes in regulations.

Market Risk. We define market risk as changes to our earnings and cash flows resulting from changes in market conditions, including changes in commodity prices, as well as the impact of volatility and market liquidity on such prices. We manage market risk through diversification, controlling position sizes and executing hedging strategies. Our hedging activity for the ten months ended October 31, 2005 was immaterial.

Note 6—Asset Retirement Obligations

We follow SFAS No. 143, “Asset Retirement Obligations” (“SFAS No. 143”) to account for our legal obligations (including those obligations conditioned upon events that may not be within our control) to retire tangible, long-lived assets. Under the provisions of SFAS No. 143, we are required to record the obligations as liabilities on our balance sheet at a discount when incurred. The fair value of the remediation and pipeline abandonment costs estimated to be required upon retirement or abandonment of our assets was included in the asset retirement obligation (“ARO”) and was recorded upon adoption of SFAS No. 143. Changes are recognized when obligations are incurred or settled and when the fair value of the obligation changes due to revisions in estimates and passage of time. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates of the amount or timing of the cash flow change, the change may have a material impact on our results of operations.

In addition to these ARO’s, we also have potential retirement obligations for dismantlement of a fractionation facility and natural gas liquids storage facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate potential retirement obligations associated with these assets at this time. Liabilities will be recorded in accordance with SFAS No. 143 at the time we are able to estimate the obligations.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Our ARO’s relate to activities such as closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. A summary, in millions, of changes is as follows:

Balance at December 31, 2004	$	10
Obligations incurred		—
Obligations settled		—
Revision in estimates (included in cost of sales)		1
Accretion expense (included in cost of sales)		1
Balance at October 31, 2005	$	12

Note 7—Unconsolidated Investments

Our unconsolidated investments consist primarily of investments in affiliates that we do not control, but where we have significant influence over operations. Our principal equity method investments consist of entities that operate natural gas liquids assets. We entered into these ventures principally to share risk and leverage existing commercial relationships. These ventures maintain independent capital structures and have financed their operations either on a non-recourse basis to us or through their ongoing commercial activities.

At October 31, 2005, our investments included a 22.9% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), a venture that operates a natural gas liquids processing, extraction, fractionation and storage facility in the Gulf Coast region. We also hold a 38.75% ownership interest in Gulf Coast Fractionators LP (“GCF”), a venture that fractionates natural gas liquids on the Gulf Coast.

The following table shows our unconsolidated investments as of October 31, 2005 (in millions):

Natural Gas Gathering and Processing
VESCO	$	29
Logistics Assets
GCF		23
	$	52

The following table shows our equity earnings and cash distributions with respect to our unconsolidated investments for the ten months ended October 31, 2005 (in millions):

Equity earnings of:
VESCO	$	(22	)
GCF		2
	$	(20	)
Cash distributions:
VESCO	$	3
GCF		3

VESCO’s facilities were significantly damaged by Hurricane Katrina during August 2005. Our equity earnings from VESCO includes approximately $25 million in losses, not including insurance recoveries, related to our share of damages. We expect to make significant capital contributions to VESCO to fund our share of expenditures to repair and rebuild certain damaged facilities operated by VESCO.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table shows summarized financial results of our unconsolidated investments for the ten months ended October 31, 2005 (in millions):

	Ten Months Ended October 31, 2005
	GCF		VESCO
Revenues	$	39	$	147
Cost of sales and operations		33		158
Income from operations	$	6	$	(11	)
Net income (loss)	$	6	$	(147	)
	As of October 31, 2005
	GCF		VESCO
Current assets	$	8	$	22
Property, plant and equipment, net		56		48
Other assets		—		1
Total assets	$	64	$	71
Current liabilities	$	1	$	29
Long-term liabilities		—		7
Owners’ equity		63		35
Total liabilities and owners’ equity	$	64	$	71

Note 8—Related Party Transactions

Transactions with Affiliates

Sales to and Purchases from Dynegy. We routinely conduct business with other subsidiaries of Dynegy that are not a part of this consolidated group. Transactions with other subsidiaries of Dynegy result primarily from purchases and sales of natural gas and natural gas liquids. Unlike purchase and sales transactions with third parties that settle in cash, settlement of these sales and purchases occurs through adjustment to partners’ capital.

Allocation of Dynegy Costs. Our consolidated financial statements include costs allocated to us, by Dynegy, for centralized general and administrative services performed by Dynegy on our behalf, as well as depreciation of assets utilized by such centralized Dynegy general and administrative functions. The costs are allocated to us based on our proportionate share of Dynegy assets, revenues and employees. All of the allocations are based on assumptions that we believe are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operated as a separate entity. These allocations are not settled in cash. Settlement of these allocations occurs through adjustment to partners’ capital.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes the sales to Dynegy, purchases from Dynegy, and allocations of costs from Dynegy, settled through adjustment to partners’ capital and not included in our operating cash flows for the ten months ended October 31, 2005. We believe these transactions are executed on terms that are fair and reasonable.

	(in millions)
Aggregate sales to other subsidiaries of Dynegy	$	338
Aggregate purchases from other subsidiaries of Dynegy		(166	)
Allocations of general and administrative expenses from Dynegy		(22	)
Total transactions with Dynegy settled through adjustments to partners’ capital	$	150

Dynegy Centralized Cash Management. Dynegy operates a cash management system whereby excess cash from most of its various subsidiaries, held in separate bank accounts, is swept to a centralized account managed by Dynegy treasury services. Cash distributions are deemed to have occurred through the general and limited partner in accordance with our partnership agreement, and are reflected as an adjustment to partners’ capital. Net distributions of cash to Dynegy were $46 million during the ten months ended October 31, 2005.

Sales to and Purchases from ChevronTexaco. All of our reportable segments conduct business with ChevronTexaco, the largest shareholder of Dynegy. Sales to ChevronTexaco represented approximately 33% of consolidated total revenues during the ten months ended October 31, 2005. Transactions with ChevronTexaco, result primarily from purchases and sales of natural gas and natural gas liquids. Settlement of these sales and purchases normally occurs through payment of cash. At October 31, 2005, there were receivables from ChevronTexaco of $14 million and payables to ChevronTexaco of $101 million.

Sales to and Purchases from Equity Investees. We conduct business with entities in which we have equity investments. Transactions with entities in which we have equity investments, result primarily from purchases and sales of natural gas and natural gas liquids. Settlement of these sales and purchases occurs through payment of cash. At October 31, 2005, there were net receivables from entities in which we have equity investments of $2 million.

The following table summarizes the sales to and purchases from ChevronTexaco and entities in which we have equity investments for the ten months ended October 31, 2005. We believe these transactions are executed on terms that are fair and reasonable.

	(in millions)
Aggregate sales to ChevronTexaco	$	1,169
Aggregate purchases from ChevronTexaco		(1,031	)
Aggregate sales to equity investees		—
Aggregate purchases from equity investees		(135	)

Note 9—Commitments and Contingencies and Summary of Material Legal Proceedings

Environmental Litigation. We are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of operations or cash flows. We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable under SFAS No. 5. For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated in accordance with SOP 96-1 “Environmental Remediation Liabilities”. Environmental reserves do not reflect management’s assessment of the insurance

F-110

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. We have established environmental liabilities of $2 million at October 31, 2005, primarily related to remediation of ground water contamination. We cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

Apache Litigation. In May 2002, Apache Corporation 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 (“TMSLP”)), 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 plaintiff’s claim with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the trial court and abated for a future trial, and the jury found in favor of the plaintiff on the lost gas claim, awarding approximately $1.6 million in damages. In May 2004, the Versado Defendants’ motion to set aside this jury verdict was granted by the court and the jury award to the plaintiff was vacated. The plaintiff filed its notice of appeal with the 14^th Court of Appeals in October 2004 and its appellate brief in December 2004.

See Note 11—Subsequent Events.

Firm Capacity Payments. We have entered into firm capacity payments related to storage and transportation of natural gas liquids. Such arrangements are routinely used in the physical movement and storage of natural gas liquids consistent with our business strategy. The total of such obligations at October 31, 2005 are as follows: 2005-$1.4 million; 2006-$1.9 million; 2007-$0.7 million; 2008-$0.4 million; 2009-$0.3 million and beyond-$2.5 million.

Other Minimum Commitments. Minimum commitments in connection with site leases for plants at October 31, 2005, were as follows: 2005- $0.1 million; 2006-$0.4 million; 2007-$0.4 million; 2008-$0.4 million; 2009-$0.5 million and beyond-$5.6 million. Rental payments made under the terms of these arrangements totaled $0.8 million during the first ten months of 2005.

Guarantees. We routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third-party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, management is unable to estimate any range of loss and considers the probability of loss to be remote.

We have also entered into various indemnifications regarding environmental, tax, employee and other representations when completing our past asset sales. We carry reserves for existing environmental, tax and

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

employee liabilities, when they have been identified. We have incurred no other expense relating to these indemnities. Management considers the probability of loss to be remote. There is always the possibility of a loss related to such indemnifications, of which the maximum potential exposure to the Company cannot be reasonably estimated.

Note 10—Regulatory Issues

We are subject to regulation by various federal, state, local and foreign agencies, in the normal course of business. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment and permitting at various operating facilities and abandonment and remediation obligations. We cannot predict the outcome of regulatory developments or the effects that they might have on our business.

Note 11—Subsequent Events

Sale of DMS. Effective November 1, 2005, DMS was acquired by Targa for approximately $2,452 million. The acquisition was accounted for as a purchase by Targa and the results of DMS have been included in the consolidated results of Targa beginning November 1, 2005.

Stock-Based Compensation and Pension Plans. Upon completion of our sale to Targa, our employees’ eligibility to participate in the Dynegy stock-based compensation and pension and other incentive programs terminated.

Apache Litigation. In September 2006, the 14^th Court of Appeals of Houston 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. In October 2006, the Versado Defendants filed a motion for rehearing with the 14^th Court of Appeals. After rehearing, the 14^th 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 $2.8 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. At the request of the Supreme Court of Texas, the Versado Defendants and Apache filed responses to the opposing party’s petition in June 2007.

In May 2007, the parties settled the severed lawsuit referenced in Note 9 above.

Guarantee of Debt Held by Targa. Although we have not historically incurred debt obligations, a significant portion of our assets were pledged as collateral for debt issued by Dynegy, and we have guaranteed debt issued by Dynegy. Upon completion of our sale to Targa, our obligation as guarantors of debt issued by Dynegy were terminated and all liens and mortgages on our assets pledged as collateral for such debt were released.

Further, upon completion of our sale to Targa and Targa’s debt offering, we became guarantors of Targa’s obligations under its senior secured credit facilities and senior notes.

F-112

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Dynegy Midstream Services, Limited Partnership:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in partners’ capital, and cash flows present fairly, in all material respects, the financial position of Dynegy Midstream Services, Limited Partnership and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed on Note 8 to the Consolidated Financial Statements, the Company has entered into significant transactions with Dynegy Inc. and its subsidiaries and ChevronTexaco Corporation and its affiliates, related parties.

/s/    PricewaterhouseCoopers LLP

Houston, Texas

May 6, 2005, except for Note 14, as to which the date is September 20, 2005

F-113

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

CONSOLIDATED BALANCE SHEETS

(in millions)

	December 31, 2004			December 31, 2003
ASSETS (Collateral for Parent Company Debt—See Note 8)
Current Assets
Cash and cash equivalents	$	17		$	20
Accounts receivable, net of allowance for doubtful accounts of $2 and $4, respectively		284			247
Accounts receivable, affiliates		11			20
Inventory		58			42
Prepayments		42			49
Total Current Assets		412			378
Property, Plant and Equipment		1,771			1,763
Accumulated depreciation		(694	)		(618	)
Property, Plant and Equipment, Net		1,077			1,145
Other Assets
Unconsolidated investments		78			82
Goodwill		15			15
Other long-term assets		3			3
Total Assets (Collateral for Parent Company Debt—See Note 8)	$	1,585		$	1,623
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable	$	57		$	57
Accounts payable, affiliates		23			21
Accrued liabilities		76			87
Total Current Liabilities		156			165
Other long-term liabilities		27			29
Total Liabilities		183			194
Minority Interest		106			107
Commitments and Contingencies (See Note 9)
Partners’ Capital
Limited partner interest		1,252			1,277
General partner interest		44			45
Total Partners’ Capital		1,296			1,322
Total Liabilities and Partners’ Capital	$	1,585		$	1,623

See notes to consolidated financial statements.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)

	Year Ended December 31,
	2004			2003			2002
Revenues from third parties	$	2,245		$	2,033		$	1,788
Revenues from affiliates		1,506			1,215			938
Total revenues		3,751			3,248			2,726
Cost of sales, exclusive of depreciation shown separately below		(3,414	)		(2,986	)		(2,532	)
Depreciation expense		(91	)		(87	)		(86	)
Impairment charge		(5	)		—			—
Severance and restructuring reductions (charges)		(2	)		1			(17	)
Gain (loss) on sale of assets, net		69			23			(1	)
General and administrative expenses		(47	)		(56	)		(36	)
Operating income		261			143			54
Earnings (losses) from unconsolidated investments		10			(2	)		16
Other expense, net		—			—			(10	)
Minority interest expense		(22	)		(17	)		(8	)
Net income	$	249		$	124		$	52
Comprehensive income	$	249		$	124		$	52
Allocation of net income to:
Limited partner interest in net income	$	241		$	120		$	50
General partner interest in net income	$	8		$	4		$	2

See notes to consolidated financial statements.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2004			2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	249		$	124		$	52
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation expense		91			87			86
Impairment charge		5			—			—
Losses (earnings) from unconsolidated investments, net of cash distributions		1			16			2
Risk-management activities		—			1			—
Loss (gain) on sale of assets, net		(69	)		(23	)		1
Income attributable to minority interest holders		22			17			8
Changes in working capital:
Accounts receivable, net		(28	)		(3	)		(41	)
Inventory		(16	)		7			7
Prepayments and other assets		7			(35	)		(1	)
Accounts payable and accrued liabilities		(9	)		(59	)		(28	)
Changes in non-current assets		—			—			1
Changes in non-current liabilities		(2	)		(6	)		3
Non-cash settlement of transactions with Dynegy (See Notes 1 and 8)		(125	)		(81	)		139
Net cash provided by operating activities		126			45			229
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(59	)		(56	)		(109	)
Return of investment from unconsolidated investments		3			4			2
Proceeds from asset sales, net		100			35			—
Net cash provided by (used in) investing activities		44			(17	)		(107	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners, net		(150	)		(8	)		(105	)
Distribution to minority interest holders		(23	)		(19	)		(5	)
Net cash used in financing activities		(173	)		(27	)		(110	)
Net increase (decrease) in cash and cash equivalents		(3	)		1			12
Cash and cash equivalents, beginning of period		20			19			7
Cash and cash equivalents, end of period	$	17		$	20		$	19
NON-CASH TRANSACTIONS:
Contribution of Delta Gathering System to unconsolidated investment (See Note 7)	$	—		$	—		$	(17	)
Distribution of WTLPS, LLC (“WTLPS”) to Dynegy (See Note 8)	$	—		$	—		$	(45	)
Settlement of transactions with parent company (See Notes 1 and 8)	$	(125	)	$	(81	)	$	139

See notes to consolidated financial statements.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(in millions)

	Limited Partner Capital			General Partner Capital			Total
January 1, 2002	$	1,203		$	43		$	1,246
Net income		50			2			52
Cash distributions to Dynegy		(101	)		(4	)		(105	)
Settlement of transactions with Dynegy (See Notes 1 and 8)		134			5			139
Distribution of WTLPS to Dynegy		(43	)		(2	)		(45	)
December 31, 2002	$	1,243		$	44		$	1,287
Net income		120			4			124
Cash distributions to Dynegy		(8	)		—			(8	)
Settlement of transactions with Dynegy (See Notes 1 and 8)		(78	)		(3	)		(81	)
December 31, 2003	$	1,277		$	45		$	1,322
Net income		241			8			249
Cash distributions to Dynegy		(145	)		(5	)		(150	)
Settlement of transactions with Dynegy (See Notes 1 and 8)		(121	)		(4	)		(125	)
December 31, 2004	$	1,252		$	44		$	1,296

See notes to consolidated financial statements.

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DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations of the Company

Organization. Dynegy Midstream Services, Limited Partnership is owned by Dynegy Midstream G.P., Inc. and DMS LP, Inc., which are each indirect, wholly owned subsidiaries of Dynegy Holdings Inc. (“DHI”). DHI is an indirect, wholly owned subsidiary of Dynegy Inc. (Dynegy Inc. and its subsidiaries are hereafter collectively referred to as “Dynegy”). Dynegy Midstream Services, Limited Partnership was originally formed in 1996 under the name of WPC-NGC, Limited Partnership. In 1996, subsequent to formation, WPC-NGC, Limited Partnership changed its name to Warren Petroleum, Limited Partnership. In 1998, Warren Petroleum, Limited Partnership changed its name to Dynegy Midstream Services, Limited Partnership (WPC-NGC, Limited Partnership, Warren Petroleum, Limited Partnership and Dynegy Midstream Services, Limited Partnership are hereafter collectively referred to, together with its subsidiaries, as “us”, “our”, “we” or “DMS”).

Dynegy Midstream G.P., Inc., a Delaware corporation, became the general partner of DMS as WPC GP, Inc. In 1996, subsequent to the formation of DMS, WPC GP, Inc. changed its name to Warren Petroleum G.P., Inc. In 1998, Warren Petroleum G.P., Inc. changed its name to Dynegy Midstream G.P., Inc. (WPC GP, Inc., Warren Petroleum G.P., Inc. and Dynegy Midstream G. P., Inc. are hereafter collectively referred to as “DMS GP”). For all years presented hereto, DMS GP owns 3.3874% of DMS.

DMS LP, Inc., a Delaware corporation, became a limited partner of DMS as WPC LP, Inc. In 1998, WPC LP, Inc. changed its name to DMS LP, Inc. (WPC LP, Inc. and DMS LP, Inc. are hereafter collectively referred to as “DMS LP”). For all years presented hereto, DMS LP owns 96.6126% of DMS.

The dissolution of DMS will occur on July 8, 2026, or earlier, depending on certain events as defined in our partnership agreement. All distributions and gains and losses, resulting from liquidation or otherwise, shall be made to our partners based upon their respective capital accounts as defined in our partnership agreement, except where otherwise required by the Internal Revenue Code.

Operations. Our business operations consist of natural gas gathering and processing, fractionating, storing, terminalling, transporting, distributing and marketing of natural gas liquids. Please see Note 13—Segment Information for a description of our segments and segment operations.

Parent Company Debt. A significant portion of our assets are pledged as collateral for debt held by subsidiaries of Dynegy, principally DHI, that are not part of DMS. In addition, we and substantially all of our wholly-owned subsidiaries guarantee this debt. Please see Note 8—Related Party Transactions for further information.

Settlement of Transactions with Dynegy. Dynegy operates a cash management system whereby excess cash from most of its subsidiaries, held in separate subsidiary bank accounts, is swept up to a centralized account managed by Dynegy treasury services. Our cash distributions to Dynegy are deemed to have occurred through the general and limited partner in accordance with our partnership agreement, and are reflected as an adjustment to the partners’ capital.

We routinely conduct business with other subsidiaries of Dynegy that are not a part of this consolidated group. Such transactions primarily result from sales and purchases of natural gas and natural gas liquids. These transactions with Dynegy are not settled in cash. Instead, they are settled through adjustments to our partners’ capital and are not included in our operating cash flows.

Also, our consolidated financial statements include costs allocated to us by Dynegy for centralized general and administrative services performed by Dynegy on our behalf, as well as depreciation of assets utilized by such

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centralized Dynegy general and administrative functions. These transactions with Dynegy are not settled in cash. Instead, they are settled through adjustments to our partners’ capital and are not included in our operating cash flows.

As a result, operating cash flows as reported are not necessarily indicative of the operating cash flows that would have resulted if we had been operated as a separate entity. Were such transactions conducted with third parties and/or settled in cash, the effect on our consolidated financial statements, particularly on our operating cash flows, could be significant. Please see Note 8—Related Party Transactions for further information.

Note 2—Accounting Policies

Our accounting policies conform to accounting principles generally accepted in the United States of America (“GAAP”). Our most significant accounting policies are described below. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (1) developing fair value assumptions, including estimates of future cash flows and discount rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets and (4) determining amounts to accrue for contingencies, guarantees and indemnifications. Actual results could differ materially from our estimates.

Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities. Intercompany accounts and transactions have been eliminated.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

Allowance for Doubtful Accounts. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable. We review our doubtful accounts regularly. Past due balances over 60 days, and over a specified amount, are reviewed individually for collectibility. Account balances are charged off against the allowance when we feel it is probable the receivable will not be collected. We review collectibility and establish or adjust our allowance as necessary, primarily utilizing methodologies involving historical levels of write-offs. The specific identification method is also used in certain circumstances. We do not have any off-balance sheet credit exposure related to our customers.

Investment in Unconsolidated Affiliates. Investments in affiliates over which we exercise significant influence, generally occurring in ownership interests of 20% to 50%, and also occurring in lesser ownership percentages due to voting rights or other factors, are accounted for using the equity method. Our share of net income (loss) from these affiliates is reflected in the consolidated statements of operations as earnings (losses) from unconsolidated investments. Any excess of our investment in affiliates, as compared to our share of the underlying equity that is not recognized as goodwill, is amortized over the estimated economic service lives of

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the underlying assets. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in earnings (losses) from unconsolidated investments in the consolidated statements of operations if applicable.

Concentration of Credit Risk. We sell our energy products and services to customers in the gas distribution industry and to entities engaged in industrial and petrochemical businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because the customer base may be similarly affected by changes in economic, industry, weather or other conditions. Dynegy’s Credit Department, based on guidelines approved by its Board of Directors, establishes our counterparty credit limits. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. Our credit risk system provides current credit exposure to counterparties on a daily basis.

Inventory. Our inventory consists primarily of natural gas and natural gas liquids valued at the lower of weighted average cost or at market. Inventory adjustments of $7 million and $11 million were recorded during the years ended December 31, 2004 and 2003, respectively, due to the differential between the weighted average price of the natural gas liquids inventory and natural gas liquids market prices at December 31, 2004 and 2003.

Property, Plant and Equipment. Property, plant and equipment, which consists principally of gas gathering, processing, fractionation, terminalling and storage facilities and natural gas transportation lines is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized. We consider major maintenance to be expenditures incurred on a cyclical basis to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 3 to 25 years. Composite depreciation rates (which we refer to as composite rates) are applied to functional groups of assets having similar economic characteristics. The estimated economic service lives of our functional asset groups are as follows:

Asset Group	Range of Years
Natural gas gathering systems and processing facilities	15 to 25
Fractionation, terminalling and natural gas liquids storage facilities	15 to 25
Transportation equipment and barges	5 to 10
Office and miscellaneous equipment	3 to 7

Gains and losses are not recognized for retirements of property, plant and equipment subject to composite rates until the asset group subject to the composite rate is retired. Gains and losses on sales of individual assets are reflected in gain (loss) on sale of assets, net in the consolidated statements of operations. We assess the carrying value of our property, plant and equipment in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”). If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the related discounted cash flows of the assets and recording a loss if the resulting estimated fair value is less than the book value. For assets identified as held for sale, the book value is compared to comparable market prices, or the estimated fair value if comparable market prices are not readily available, to determine if an impairment loss is required. Please see Note 4—Restructuring and Impairment Charges.

Asset Retirement Obligations. We adopted SFAS No. 143, “Asset Retirement Obligations” (“SFAS No. 143”), effective January 1, 2003. Under the provisions of SFAS No. 143, we are required to record legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities, which are recorded at a discount when the liability is incurred. Significant judgment is involved in estimating future cash flows

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associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flow change, the change may have a material impact on our results of operations.

As part of adopting SFAS No. 143, existing environmental liabilities in the amount of $9 million were reversed in the first quarter 2003. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the asset retirement obligation (“ARO”) and was recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities equaled the fair value of the future retirement obligations, the adoption of SFAS No. 143 did not have an impact on our consolidated financial statements. In addition to these ARO’s, we also have potential retirement obligations for dismantlement of a fractionation facility and natural gas liquids storage facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. Liabilities will be recorded in accordance with SFAS No. 143 at the time we are able to estimate any new AROs.

Our AROs relate to activities such as closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. Annual amortization of the assets associated with the AROs was $0.2 million and $0.6 million in 2004 and 2003, respectively. A summary of changes in our AROs by reportable segment is as follows:

	Gas Gathering and Processing		Marketing Assets		Total
	(in millions)
Balance at January 1, 2003	$	8	$	1	$	9
Accretion expense		1		—		1
Balance at December 31, 2003		9		1		10
Accretion expense		1		—		1
Other (1)		—		—		—
Balance at December 31, 2004	$	10	$	1	$	11

(1) During 2004, AROs totaling less than $1 million were removed following our sales of Sherman and our interest in Indian Basin. There were no additional AROs recorded or settled, nor were there any revisions to estimated cash flows associated with existing AROs, during 2004 or 2003.

The following pro forma financial information has been prepared to give effect to the adoption of SFAS No. 143 for the year ended December 31, 2002 as if it had been adopted January 1, 2002 (in millions):

Net income, as reported	$	52
Pro forma adjustments to reflect retroactive adoption of SFAS No. 143		(1	)
Pro forma net income	$	51

Contingencies, Commitments, Guarantees and Indemnifications. We are involved in lawsuits, claims, proceedings, joint venture audits and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”) we record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on the consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Our estimates and judgment could change based on

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new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts. Actual results could vary materially from these estimates and judgments.

Liabilities for environmental contingencies are recorded when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro rata share of such liability. These assumptions involve the judgments and estimates of management and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.

We follow the guidance of Financial Accounting Standards Board (“FASB”) Interpretation (“FIN”) No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN No. 45”) for disclosures and accounting of various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject to FIN No. 45 is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances, however management also considers the probability of such circumstances occurring when estimating the fair value. Actual results may materially differ from the estimated fair value of such guarantees and indemnifications.

Goodwill and Other Intangible Assets. Goodwill represents, at the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis and when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. We currently perform our annual impairment test in the fourth quarter after our annual budgetary process, and we may record impairment charges in future periods as a result of such test. We have $4 million of goodwill attributable to our Marketing Assets segment and $11 million of goodwill attributable to our Gas Gathering and Processing segment. During 2004, 2003 and 2002, there were no changes in our $15 million carrying amount of goodwill.

Income Taxes. As a limited partnership we are not subject to federal income tax. We are subject to income taxes in the states of Texas and Tennessee through certain of our subsidiaries. However, historically, any state income tax on the partnership has been immaterial. The taxable income or loss resulting from our operations will ultimately be included in the federal and state income tax returns of the general and limited partners. Individual partners will have different investment bases depending upon the timing and price of their investment in the partnership. Further, each partner’s tax accounting, which is partially dependent upon their tax position, may differ from the accounting followed in the consolidated financial statements. Accordingly, there could be significant differences between each individual partner’s tax basis and their share of the net assets reported in the consolidated financial statements.

Revenue Recognition. Our segments consist largely of the ownership and operation of physical assets that we use in various natural gas processing operations and natural gas liquids fractionation, storage and terminalling and delivery operations. The business of these segments includes natural gas gathering and processing, separation of natural gas liquids into their component parts from a commingled stream of light liquid hydrocarbons and the

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transportation and delivery of natural gas liquids through gas liquids pipelines, transport tractors and tank trailers, our LPG barge fleet and railcars that we manage pursuant to a services agreement with ChevronTexaco Corporation and its affiliates (“ChevronTexaco”). End sales from these businesses result in physical delivery of natural gas residue and natural gas liquids to our wholesale and industrial customers. We recognize revenue from these transactions when the product or service is delivered to a customer. We also provide natural gas liquids storage and terminalling services for a fee.

Employee Stock Options. In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure” (“SFAS No. 148”). SFAS No. 148 amends SFAS No. 123, “Accounting for Stock- Based Compensation” (“SFAS No. 123”) and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. We transitioned to a fair value- based method of accounting for stock-based compensation in the first quarter 2003 and are using the prospective method of transition as described under SFAS No. 148.

Dynegy has granted stock options for Dynegy stock to certain of our employees. Under the prospective method of transition, all Dynegy stock options granted by Dynegy to our employees after January 1, 2003 are accounted for on a fair value basis. Dynegy options granted by Dynegy to our employees prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Accordingly, for such options granted prior to January 1, 2003, compensation expense is not reflected for employee stock options unless they were granted at an exercise price lower than market value on the grant date. Dynegy has granted in-the-money options in the past and we continue to recognize compensation expense over the applicable vesting periods. No in-the-money stock options have been granted since 1999.

Had compensation cost for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income would have approximated the following pro forma amounts for the years ended December 31, 2004, 2003 and 2002, respectively.

	Years Ended December 31,
	2004			2003			2002
	(in millions)
Net income as reported	$	249		$	124		$	52
Add: Stock-based employee compensation expense included in reported net income		1			—			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards		(2	)		(6	)		(3	)
Pro forma net income	$	248		$	118		$	49

Minority Interest. Minority interest on the consolidated balance sheets includes third-party investments in entities that we consolidate, but do not wholly own. The net results attributed to minority interest holders in consolidated entities are included in minority interest expense in the consolidated statements of operations.

Accounting Principles Newly Adopted

FIN No. 46R. In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (“FIN No. 46”) In December 2003, the FASB issued the updated and final

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interpretation FIN No. 46(R). FIN No. 46(R) requires that an equity investor in a variable interest entity have significant equity at risk (generally a minimum of 10%, which is an increase from the 3% required under previous guidance) and hold a controlling interest (evidenced by voting rights), and absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected returns, or both. If the equity investor is unable to evidence these characteristics, the entity that retains these ownership characteristics will be required to consolidate the variable interest entity as the primary beneficiary. FIN No. 46(R) was applicable immediately to variable interest entities created or obtained after January 31, 2003. We were also required to adopt the remaining provisions of FIN No. 46(R) on March 31, 2004. These provisions require that we review the structure of all legal entities in which we have an investment and other legal entities with whom we transact to determine whether such entities are variable interest entities (“VIE”), as defined by FIN No. 46(R). With respect to each of the VIEs we identify, we must assess whether we are the “primary beneficiary,” as defined by FIN No. 46(R). FIN 46(R) was effective on December 31, 2003 and did not identify any VIEs and, therefore, the adoption did not have an impact on our consolidated financial statements.

Accounting Principles Not Yet Adopted

SFAS No. 123(R). In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”), which revises SFAS No. 123. SFAS No. 123(R) is effective January 1, 2006 for all calendar year-end companies. SFAS No. 123(R) requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. This expense will be recognized over the period during which an employee is required to provide services in exchange for the award. We expect to adopt the provisions of SFAS No. 123(R) on January 1, 2006. SFAS 123(R) describes several transition methods, and we expect to apply the modified prospective method of adoption. Under this method, compensation expense is recognized for the remaining portion of outstanding, unvested awards. The fair value for these awards is calculated on the grant date in accordance with SFAS 123 for either recognition in our statement of operations or through our pro forma disclosures.

As noted in “Employee Stock Options” above, we transitioned to a fair value based method of accounting for stock-based compensation in the first quarter 2003. Our expense relating to share-based compensation consists of awards by Dynegy to certain of our employees, in the form Dynegy stock options and Dynegy restricted stock. For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model. For restricted stock awards, we consider the fair value to be the closing price of the stock on the grant date. We recognize the fair value of our share based payments over the vesting periods of the awards, which is typically a three-year service period.

Prior to the issuance of SFAS No. 123(R), we adopted the prospective method for expensing the fair value of stock options and restricted stock awards granted after January 1, 2003, and as such we do not expect the guidance under SFAS 123(R) to have a material impact on our consolidated statement of operations.

FIN No. 47. In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN No. 47”), which is an interpretation of SFAS No. 143. FIN No. 47 clarifies the term “conditional asset retirement obligation,” which refers to legal obligations for which companies must perform asset retirement activity for which the timing and/or method of settlement are conditional upon future events that may or may not be within the control of the entity. However, the obligation to perform the asset retirement is unconditional, despite the uncertainty that exists surrounding the timing and method of settlement. Uncertainty about the timing and method of settlement for a conditional ARO should be considered in estimating the ARO when sufficient information exists. FIN No. 47 clarifies when sufficient information exists to

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reasonably estimate the fair value of an ARO. FIN No. 47 is effective no later than the first fiscal year ending after December 15, 2005, and early adoption is encouraged.

As noted in “Asset Retirement Obligations” above, we currently record AROs for our Gas Gathering and Processing and Marketing Assets segments. These AROs involve significant judgment regarding future cash flows and the ultimate timing of these cash flows, some of which include the probability of future events occurring such as the timing and method of settlement. As such, we are in the process of evaluating the impact of FIN No. 47. We expect to adopt the provisions of FIN No. 47 on January 1, 2006.

Note 3—Dispositions

Sherman. In November 2004, we sold our Sherman natural gas processing facility located in Sherman, Texas, for approximately $35 million, and we recognized a gain on the sale of approximately $16 million. This gain is included in gain (loss) on sale of assets, net on our consolidated statements of operations.

Indian Basin. In April 2004, we sold our 16% interest in the Indian Basin Gas Processing Plant, located in Eddie County, New Mexico, for approximately $48 million, and we recognized a gain on the sale of approximately $36 million. This gain is included in gain (loss) on sale of assets, net on our consolidated statements of operations.

Hackberry LNG Project. In April 2003, we sold our proposed LNG terminal and gasification project in Hackberry, Louisiana. At closing, we received an initial payment of $20 million and recognized a gain of approximately $9 million. We retained the right to receive additional contingent payments based upon project development milestones. In October 2003, we received a $15 million payment associated with the completion of a project milestone and recognized a gain of $15 million. In March 2004, we sold our remaining financial interest in this project, including rights to receive future contingent payments under the 2003 agreement, for $17 million and recognized a gain of $17 million on the sale. These gains are included in gain (loss) on sale of assets, net on our consolidated statements of operations.

Note 4—Severance, Restructuring and Impairment Charges

In 2004, as a result of our testing of certain of our assets for impairment based on identification of triggering events as defined by SFAS No. 144, we recorded an impairment of $5 million for our Puckett gas treatment plant and gathering system due to rapidly depleting reserves associated with that facility. This impairment is included in impairment and other charges on our consolidated statements of operations. We concluded that no impairment was necessary for any other facilities as estimated undiscounted cash flows exceeded facility book values.

In 2003, we recorded a $12 million charge related to the impairment of our investment in Gulf Coast Fractionators (GCF). This impairment is included in earnings (losses) from unconsolidated investments on our consolidated statements of operations. Please see Note 7—Unconsolidated Investments.

In 2002, Dynegy recorded restructuring, severance and impairment charges relating to various aspects of its operations and we were allocated $17 million of such charges. In 2003, Dynegy reduced portions of the severance and restructuring charges and we were allocated $1 million of the benefit from the reduction. In 2004, Dynegy recorded additional severance and restructuring charges and we were allocated $2 million of such charges. The allocations of these charges and reductions, for all periods presented, are included in severance and restructuring reductions (charges) on the consolidated statements of operations.

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Note 5—Risk Management Activities and Financial Instruments

Our operations are impacted by several factors, some of which may not be mitigated by risk management methods. These risks include, but are not limited to, commodity price, weather patterns, counterparty credit risks, changes in competition, operational risks, environmental risks and changes in regulations.

We define market risk as changes to our earnings and cash flow resulting from changes in market conditions, including changes in commodity prices, as well as the impact of volatility and market liquidity on such prices. We manage market risk through diversification, controlling position sizes and executing hedging strategies.

Accounting for Derivative Instruments and Hedging Activities

We follow the accounting and disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133). Under SFAS No. 133, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value are recognized immediately in earnings, unless such instruments qualify, and are designated, as hedges of future cash flows, fair values or net investments in foreign operations or qualify, and are designated, as normal purchases and sales.

Cash Flow Hedges. Under these derivatives, the effective portion of changes in fair value is recorded as a component of accumulated other comprehensive income until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported immediately as a component of other income and expense, net in the consolidated statements of operations. We have previously entered into financial derivative instruments that qualify as cash flow hedges. Instruments are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin. There were no outstanding cash flow hedges at December 31, 2004 or 2003.

During the years ended December 31, 2004, 2003 and 2002, there was no material ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the years ended December 31, 2004, 2003 and 2002, we did not record any charges related to the reclassification of earnings in connection with forecasted transactions that were no longer considered probable of occurring.

Fair Value of Financial Instruments. The carrying values of current financial assets and liabilities approximate fair values due to the short-term maturities of these instruments.

Note 6—Property, Plant and Equipment

A summary of our property, plant and equipment is as follows:

	December 31,
	2004			2003
	(in millions)
Natural gas gathering systems	$	115		$	98
Processing facilities		1,058			1,067
Fractionation facilities		247			249
Terminalling and natural gas liquids storage facilities		301			308
Liquids marketing assets		21			12
Barges		29			29
		1,771			1,763
Accumulated depreciation		(694	)		(618	)
	$	1,077		$	1,145

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Note 7—Unconsolidated Investments

Our unconsolidated investments consist primarily of investments in affiliates that we do not control, but where we have significant influence over operations. Our principal equity method investments consist of entities that operate natural gas liquids assets. We entered into these ventures principally to share risk and leverage existing commercial relationships. These ventures maintain independent capital structures and have financed their operations either on a non-recourse basis to us or through their ongoing commercial activities. We hold investments in joint ventures in which ChevronTexaco or its affiliates are investors. Please see Note 8—Related Party Transactions.

At December 31, 2004, our investments included a 22.9% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), a venture that operates a natural gas liquids processing, extraction, fractionation and storage facility in the Gulf Coast region as well as a 38.75% ownership interest in GCF, a venture that fractionates natural gas liquids on the Gulf Coast.

As part of our initial capital contribution in VESCO, we agreed to construct and contribute to VESCO an expansion of the Delta Gathering System (“DGS”), a condensate, separation and dehydration facility located immediately upstream of the Venice Gas Processing Plant. The DGS expansion was completed in 1997, at a cost of $17 million, and was transferred to VESCO in 2002.

Investments in unconsolidated affiliates totaled $78 million and $82 million at December 31, 2004 and 2003, respectively. Cash received from our equity investments during 2004, 2003 and 2002 totaled $15 million, $16 million and $17 million, respectively, of which $3 million, $4 million and $2 million, respectively, represented a return of original investment in our unconsolidated affiliates. Our investment balances include unamortized purchase price differences of $7 million and $8 million at December 31, 2004 and 2003, respectively. The unamortized purchase price differences represent the excess of our purchase price over our share of the investee’s book value at the time of acquisition.

During 2003, we determined that the fair value of our equity interest in GCF, based on bid prices received for a possible sale of the investment, was lower than the book value. As such, we recorded an impairment charge in 2003 totaling $12 million. This charge is included in earnings (losses) from unconsolidated investments on our consolidated statements of operations.

Note 8—Related Party Transactions

Transactions with Affiliates

Sales to and Purchases from Dynegy. We routinely conduct business with other subsidiaries of Dynegy that are not a part of this consolidated group. Transactions with other subsidiaries of Dynegy result primarily from purchases and sales of natural gas and natural gas liquids. Unlike purchase and sales transactions with third parties that settle in cash, settlement of these sales and purchases occurs through adjustment to partners’ capital.

Allocation of Dynegy Costs. Our consolidated financial statements include costs allocated to us, by Dynegy, for centralized general and administrative services performed by Dynegy on our behalf, as well as depreciation of assets utilized by such centralized Dynegy general and administrative functions. The costs are allocated to us based on our proportionate share of Dynegy assets, revenues and employees. All of the allocations are based on assumptions that we believe are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operated as a separate entity. These allocations are not settled in cash. Settlement of these allocations occurs through adjustment to partners’ capital.

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The following table summarizes the sales to Dynegy, purchases from Dynegy, and allocations of costs from Dynegy, settled through adjustment to partners’ capital and not included in our operating cash flows. We believe these transactions are executed on terms that are fair and reasonable.

	Years Ended December 31,
	2004			2003			2002
	(in millions)
Aggregate sales to other subsidiaries of Dynegy	$	301		$	253		$	192
Aggregate purchases from other subsidiaries of Dynegy		(150	)		(146	)		(288	)
Allocations of general and administrative expenses from Dynegy		(24	)		(27	)		(26	)
Allocations of severance charges from Dynegy (See Note 4)		(2	)		1			(17	)
Total transactions with Dynegy settled through adjustments to partners’ capital	$	125		$	81		$	(139	)

Dynegy Centralized Cash Management. Dynegy operates a cash management system whereby excess cash from most of its various subsidiaries, held in separate bank accounts, is swept to a centralized account managed by Dynegy treasury services. Cash distributions are deemed to have occurred through the general and limited partner in accordance with our partnership agreement, and are reflected as an adjustment to the partners’ capital. Net distributions of cash to Dynegy were $150 million, $8 million and $105 million during the years ending December 31, 2004, 2003 and 2002, respectively.

Sales to and Purchases from ChevronTexaco. All of our reportable segments conduct business with ChevronTexaco, the largest shareholder of Dynegy. Sales to ChevronTexaco represented approximately 32%, 30% and 27% of consolidated total revenues during the years ending December 31, 2004, 2003 and 2002, respectively. Transactions with ChevronTexaco, result primarily from purchases and sales of natural gas and natural gas liquids. Settlement of these sales and purchases normally occurs through payment of cash. At December 31, 2004 and 2003, there were receivables from ChevronTexaco of $10 million and $19 million, respectively. At December 31, 2004 and 2003, there were payables to ChevronTexaco of $20 million and $21 million, respectively.

In 2002, in partial satisfaction of certain Dynegy obligations to ChevronTexaco, we transferred our 39.2% ownership interest in WTLPS, valued at $45 million, to Dynegy, who transferred it to ChevronTexaco, the largest interest owner of WTLPS and operator of the pipeline. This non-cash transaction was accounted for as a distribution to our partners.

Sales to and Purchases from Equity Investments. We conduct business with entities in which we have equity investments. Transactions with entities in which we have equity investments, result primarily from purchases and sales of natural gas and natural gas liquids. Settlement of these sales and purchases occurs through payment of cash. At December 31, 2004 and 2003, there were receivables from entities in which we have equity investments of $1 million and $1 million, respectively. At December 31, 2004 and 2003, there were payables to entities in which we have equity investments of $3 million and $0, respectively.

The following table summarizes the sales to and purchases from ChevronTexaco and entities in which we have equity investments. We believe these transactions are executed on terms that are fair and reasonable.

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	Years Ended December 31,
	2004			2003			2002
	(in millions)
Aggregate sales to ChevronTexaco	$	1,206		$	963		$	745
Aggregate purchases from ChevronTexaco		(1,134	)		(842	)		(566	)
Aggregate sales to equity investments		—			—			1
Aggregate purchases from equity investments		(175	)		(180	)		(155	)

Earnings from Equity Investments. We hold a 22.9% ownership interest in VESCO, in which ChevronTexaco or its affiliates are also investors. VESCO holds a pipeline gathering system, a processing plant, a fractionator and an underground natural gas liquids storage facility in Louisiana. During the years ended December 31, 2004, 2003 and 2002, our portion of the net income from VESCO was approximately $8 million, $6 million and $6 million, respectively.

Collateral for Dynegy Debt. A significant portion of our assets are pledged as collateral for debt held by subsidiaries of Dynegy, principally DHI, that are not part of DMS. In addition, we and substantially all of our wholly-owned subsidiaries guarantee this debt. The maximum amount of parent company debt which can be collateralized by our assets is limited to 15% of DHI’s net tangible assets at the time of any new Dynegy secured debt issuance. The last such issuance of Dynegy secured debt was May 28, 2004, and the maximum debt collateralized by our assets has since been limited to $1,212 million. At December 31, 2004 and 2003, such parent company debt consists of the following:

	December 31, 2004				December 31, 2003
	DMS Assets Pledged as Collateral		Carrying Value of Debt at Dynegy		DMS Assets Pledged as Collateral		Carrying Value of Debt at Dynegy
	(in millions)
Term Loan, floating rate due through 2010	$	498	$	597	$	—	$	—
Second Priority Senior Secured Notes, floating rate due 2008		32		225		32		225
Second Priority Senior Secured Notes, 9.875% due 2010		165		625		165		625
Second Priority Senior Secured Notes, 10.125% due 2013		280		900		280		900
ABG Gas Supply Credit Agreement		—		—		185		185
Generation Facility Debt, due 2007		152		182		184		184
Outstanding Letters of Credit		79		94		188		188
		1,206				1,034
Unamortized premium on debt, net		6				12
Total long-term debt collateralized by DMS assets	$	1,212			$	1,046

DHI Term Loan and Credit Facility. Effective May 28, 2004, DHI entered into a $1.3 billion credit facility consisting of:

• a $700 million secured revolving credit facility that matures on May 28, 2007; and

• a $600 million secured amortizing term loan that matures on May 28, 2010.

The revolving credit facility provides funding for general corporate purposes and is also available for the issuance of letters of credit. No borrowing are outstanding under the revolving credit facility during any of the periods presented. Borrowings under the revolving credit facility bear interest, at DHI’s option, at (i) a base rate

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plus 3.00% per annum or (ii) LIBOR plus 4.00% per annum. A letter of credit fee is payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.00% of such undrawn amount. We also incur additional fees for issuing letters of credit. An unused commitment fee of 0.50% is payable on the unused portion of the revolving credit facility.

Of the $600 million in proceeds from the term loan drawn at closing, a portion was used by Dynegy to post cash collateral in lieu of letters of credit, while approximately $19 million was used to pay fees and expenses incurred in connection with the new facility. These fees have been capitalized and are being amortized over the terms of the credit facility. In August 2004, $154 million of the proceeds from the $600 million term loan were used to pre-pay all outstanding indebtedness and other amounts owed in connection with other Dynegy debt. The remaining proceeds, subject to specified restrictions in the credit facility, are available for general Dynegy purposes. Borrowings under the term loan bear interest, at DHI’s option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus 4.00% per annum.

The credit facility provides for no amortization of principal prior to the maturity dates except (i) upon the occurrence of a mandatory prepayment event as defined in the credit facility and (ii) term loan amortization of 1% per annum.

The credit facility generally prohibits DHI and its subsidiaries, subject to specified exceptions, from incurring additional debt. Notwithstanding this restriction, DHI may issue, to the extent permitted by the more restrictive covenants in the indenture governing the DHI second priority senior secured notes, (i) up to $700 million of additional second lien or junior secured debt or unsecured debt, provided such additional debt matures at least six months after the term loan, and (ii) permitted refinancing indebtedness.

The credit facility generally prohibits DHI and its subsidiaries from pre-paying, redeeming or repurchasing its outstanding debt or preferred stock. Notwithstanding this restriction, DHI may pre-pay, repurchase or redeem its remaining 2005 and 2006 senior notes and the Generation facility debt. DHI also may pre-pay, repurchase or redeem its other senior unsecured notes and its second priority senior secured notes, subject to specified conditions.

DHI is prohibited from (i) permitting its Secured Debt/EBITDA Ratio (as defined in the credit facility) on and after September 30, 2004 to exceed specified ratios; (ii) permitting liquidity to be less than $200 million for a period of more than ten consecutive business days; or (iii) making capital expenditures during each four fiscal quarter period in excess of a designated amount, subject to specified exceptions.

The terms and conditions of the credit facility are described in more detail in the definitive agreements governing the credit facility, which are filed and/or incorporated by reference as exhibits to the Dynegy Inc. second quarter 2004 Form 10-Q.

DHI Second Priority Senior Secured Notes. In August 2003, DHI issued $1.45 billion in second priority senior secured notes, comprised of: (i) $225 million in floating rate notes due 2008 which accrue interest at a rate of LIBOR plus 650 basis points (reset on a quarterly basis); (ii) $525 million in 9.875% notes due 2010 with a yield to maturity of 10.0%; and (iii) $700 million in 10.125% notes due 2013 with a yield to maturity of 10.25%.

In October 2003, DHI consummated a follow-on offering of $300 million aggregate principal amount of additional second priority senior secured notes, comprised of: (i) $100 million of 9.875% second priority senior secured notes due 2010 issued at a premium to par of 104.25% with a yield to maturity of approximately 9.0%; and (ii) $200 million of 10.125% second priority senior secured notes due 2013 issued at a premium to par of

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105.25% with a yield to maturity of approximately 9.3%. Each of these series of additional notes are treated as a single class with the corresponding series of DHI second priority senior secured notes that were originally issued in August 2003.

Each of DHI’s existing and future wholly owned domestic subsidiaries that guarantee DHI’s obligations under its credit facility also guarantee the obligations under the notes on a senior secured basis. In addition, Dynegy and its other subsidiaries that guarantee DHI’s existing credit facility also guarantee the obligations under the notes on a senior secured basis. The notes and guarantees are senior obligations secured by a second-priority lien on, subject to certain exceptions and permitted liens, all of DHI’s and its guarantors’ existing and future property and assets that secure DHI’s obligations under its credit facility.

The indenture governing the notes contains restrictive covenants that limit the ability of DHI and its subsidiaries that guarantee the notes to, among other things: (1) redeem, repurchase or pay dividends or distributions on capital stock; (2) make investments or restricted payments; (3) incur or guarantee additional indebtedness; (4) create certain liens; (5) engage in sale and leaseback transactions; (6) consolidate, merge or transfer all or substantially all of its assets; or (7) engage in certain transactions with affiliates.

Generation Facility Debt. Dynegy previously entered into a lease arrangement in for the purpose of constructing a generation facility located in Kentucky. As originally constituted, this arrangement required variable-rate interest only payments that include an option to purchase the related assets at maturity of the facility for a balloon payment equal to the principal balance on the financing. Upfront fees with Dynegy’s generation facility lease arrangement are capitalized and amortized over the term of the arrangement. The generation lease arrangement expires in 2007 and bears interest at LIBOR plus 1.5% to 2.5%.

ABG Gas Supply Agreement. In April 2001, ABG Gas Supply entered into a credit agreement in order to provide specific project financing. Advances under the agreement allowed ABG Gas Supply to purchase natural gas contracts with the underlying physical gas supply to be sold to Dynegy under an existing natural gas purchase and sale agreement. The credit agreement requires ABG Gas Supply to repay the advances in monthly installments commencing February 2002 from funds received from Dynegy under the natural gas purchase and sale agreement. The advances bear interest at a LIBOR rate plus a margin as defined in the agreement (2.415% at December 31, 2003). All advances were repaid in full in August 2004.

Note 9—Commitments and Contingencies

Summary of Material Legal Proceedings

Environmental Litigation. We are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of operations or cash flows. We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable under SFAS No. 5. For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated in accordance with SOP 96-1 “Environmental Remediation Liabilities”. Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue. Management has assessed each of the matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. We have established environmental liabilities of $2 million and $3 million at December 31, 2004 and 2003, respectively, primarily related to remediation of ground water contamination. We cannot make any assurances that the amount of any reserves or

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potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

Apache Litigation. In 2002, Apache Corporation filed suit in state court against our subsidiary, Versado, as purchaser and processor of Apache’s gas, and DMS, as operator of the Versado assets in New Mexico, seeking more than $9 million in damages. The plaintiff’s petition, as amended, alleges (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that Versado engaged in “sham” transactions with affiliates, resulting in Versado not receiving fair market value when it sells gas and liquids, and (iii) that the formula for calculating the amount Versado receives from its buyers of gas and liquids is flawed since it is based on gas price indexes that these same affiliates are alleged to have manipulated by providing false price information to the index publisher. At trial, the plaintiff’s claim with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the court and abated for a future trial, and the jury found in favor of the plaintiff on the remaining lost gas claim, awarding approximately $1.6 million in damages. In 2004, our motion to set aside this judgment was granted by the court, the jury’s award to the plaintiff was vacated, and in response, the plaintiff filed notice of appeal and their appellate brief with the court. The parties attended mediation in February 2005, subsequent to year end, but did not reach a settlement. Settlement discussions continue outside of mediation. Barring settlement, we expect to file our response to the plaintiff’s appellate briefs in 2005. We do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.

Maxus Litigation. In 2002, we were found liable for failing to deliver processable gas to a processing plant in Oklahoma owned by Midland Energy, formerly known as Maxus Exploration Co. (“Maxus”). The judgment was appealed, but in 2003 was upheld in part, and after exhausting all further options, we paid a $6.9 million final settlement in 2004.

Other Commitments and Contingencies.

In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, equipment and plant sites.

Firm Capacity Payments. We have entered into firm capacity payments related to storage and transportation of natural gas liquids. Such arrangements are routinely used in the physical movement and storage of natural gas liquids consistent with our business strategy. The total of such obligations at December 31, 2004 are as follows: 2005-$1.2 million; 2006-$0.3 million; 2007-$0.3 million; 2008-$0.3 million; 2009-$.3 million and beyond-$2.7 million.

Other Minimum Commitments. Minimum commitments in connection with site leases for plants at December 31, 2004, were as follows: 2005- $0.4 million; 2006-$0.4 million; 2007-$0.4 million; 2008-$0.4 million; 2009-$0.4 million and beyond-$5.4 million. Rental payments made under the terms of these arrangements totaled $0.9 million in 2004, $0.3 million in 2003 and $0.3 million in 2002.

Guarantees. We routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third-party claims, in which event we will effectively be indemnifying the

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other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, management is unable to estimate any range of loss and considers the probability of loss to be remote.

We have also entered into various indemnifications regarding environmental, tax, employee and other representations when completing our Sherman, Hackberry and Indian Basin asset sales. We carry reserves for existing environmental, tax and employee liabilities, when such are identified, and have incurred no other expense relating to these indemnities. Management considers the probability of loss to be remote. There is always the possibility of a loss related to such indemnifications, of which the maximum potential exposure to the Company cannot be reasonably estimated.

Note 10—Regulatory Issues

We are subject to regulation by various federal, state, local and foreign agencies, in the normal course of business. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment and permitting at various operating facilities and remediation obligations. We cannot predict the outcome of regulatory developments or the effects that they might have on our business.

Note 11—Stock-Based Compensation

Restricted Stock. During the first quarter 2004, Dynegy awarded an aggregate 76,814 shares of restricted stock to our employees, of which 76,424 shares were outstanding, but not vested, at December 31, 2004. The closing stock price of Dynegy’s Class A common stock was $4.48 on the date of grants. These unvested restricted shares vest on the third anniversary from the date of grant. The share awards were awarded pursuant to the terms of the Dynegy 2000 and 2001 Non-Executive Plans, which are described in “Stock Options” below.

Stock Options. Dynegy has six stock option plans in which our employees participate, all of which contain authorized shares of Dynegy’s Class A common stock. Each option granted is exercisable at an option price, which ranges from $1.47 per share to $47.19 per share for options currently outstanding. A brief description of each plan is provided below:

• NGC Plan. Created early in Dynegy’s history and revised prior to Dynegy becoming a publicly traded company in 1996, this plan contains 13,651,802 authorized shares, has a 10-year term, and expires in May 2006. All option grants are vested.

• Employee Equity Plan. This plan expired in May 2002 and is the only plan in which Dynegy granted options below the fair market value of Class A common stock on the date of grant. This plan contains 20,358,802 authorized shares, and grants from this plan vest on the fifth anniversary from the date of the grant. All option grants are vested.

• Dynegy 1999 Long-Term Incentive Plan (“LTIP”). This annual compensation plan contains 6,900,000 authorized shares, has a 10-year term and expires in 2009. All option grants are vested.

• Dynegy 2000 LTIP. This annual compensation plan, created for all employees upon the merger of Illinova and Dynegy, contains 10,000,000 authorized shares, has a 10-year term and expires in February 2010. Grants from this plan vest in equal annual installments over a three-year period.

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• Dynegy 2001 Non-Executive LTIP. This plan is a broad-based plan and contains 10,000,000 authorized shares, has a ten-year term and expires in September 2011. Grants from this plan vest in equal annual installments over a three-year period.

• Dynegy 2002 LTIP. This annual compensation plan contains 10,000,000 authorized shares, has a 10-year term and expires in May 2012. Grants from this plan vest in equal annual installments over a three-year period.

All of Dynegy’s option plans cease vesting for employees who are terminated for cause. For voluntary and involuntary termination, disability, retirement or death, continued vesting and/or an extended period in which to exercise vested options may apply, dependent upon the terms of the grant agreement in which a specific grant was awarded. Options awarded to Dynegy’s executive officers and others who participate in Dynegy’s Executive Severance Pay Plan vest immediately upon the occurrence of a change in control in accordance with the terms of the Second Supplemental Amendment to the Executive Severance Pay Plan.

Compensation expense related to options granted and restricted stock awarded totaled $1 million or less for each of the years ended December 31, 2004, 2003 and 2002. We recognize compensation expense ratably over the vesting period of the respective awards. Total options outstanding and exercisable for 2004, 2003 and 2002 were as follows:

	Year Ended December 31,
	2004				2003				2002
	Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price		Options		Weighted Average Exercise Price
	(options in thousands)
Outstanding at beginning of period	2,578		$	18.12	648		$	23.17	728		$	22.91
Granted	165			4.48	378			1.77	—			—
Exercised	(25	)		3.69	—			—	(24	)		6.08
Transferred in	119			20.01	1,984			19.66	22			23.78
Cancelled, expired or transferred out	(895	)		17.76	(432	)		18.47	(78	)		26.19
Outstanding at end of period	1,942			17.43	2,578			18.12	648			23.17
Exercisable at end of period	1,597			20.53	1,930			18.92	361			21.09
Weighted average fair value of options granted during the period at market				4.48				1.77				—

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During the three-year period ended December 31, 2004, Dynegy granted no options at an exercise price less than the market price on the date of grant. Options outstanding as of December 31, 2004 are summarized below:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number of Options Outstanding at December 31, 2004	Weighted Average Remaining Contractual Life (Years)	Weighted Average Exercise Price		Number of Options Exercisable at December 31, 2004	Weighted Average Exercise Price
	(options in thousands)
$1.47-$1.77	293	7.8	$	1.75	113	$	1.71
$4.10-$4.48	266	6.2	$	4.40	102	$	4.26
$9.31-$10.51	236	3.8	$	10.06	236	$	10.06
$13.04-$16.62	449	4.2	$	15.74	448	$	15.74
$23.38-$23.85	428	6.5	$	23.73	428	$	23.73
$29.91-$36.56	12	5.5	$	35.60	12	$	35.60
$39.99-$47.19	258	6.1	$	47.12	258	$	47.12
	1,942				1,597

The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions used for grants in 2004, 2003 and 2002: dividends per year of zero for 2004 and 2003 and $0.15 for 2002; expected volatility of 87.5%, 89.6%, and 74.3%, respectively; a risk-free interest rate of 4.1%, 3.9%, and 4.2%, respectively; and an expected option life of 10 years for all periods.

Note 12—Employee Compensation, Savings and Pension Plans

Short-Term Incentive Plan. Our employees participate in a Dynegy maintained discretionary incentive compensation plan to provide employees with rewards for the achievement of corporate goals and individual, professional accomplishments. Specific awards are at the discretion of the Compensation and Human Resources Committee of the Board of Directors of Dynegy.

401(k) Savings Plan. Our employees participated in the Dynegy Inc. 401(k) Savings Plan, which meets the requirements of Section 401(k) of the Internal Revenue Code and is a defined contribution plans subject to the provisions of ERISA. This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the United States. All employees of designated Dynegy subsidiaries are eligible to participate in the plan. Employee pre-tax contributions to the plan are matched 100%, up to a maximum of 5% of base pay, subject to IRS limitations. Vesting in our contributions is based on years of service at 25% per full year of service. We may also make annual discretionary contributions to employee accounts, subject to our performance. Matching and discretionary contributions, if any, are allocated in the form of units in the Dynegy common stock fund. In connection with these annual discretionary contributions to employee accounts, we recognized $1 million of aggregate costs during each of the years ended December 31, 2004, 2003 and 2002.

Pension and Other Post-Retirement Benefits. All of our employees participate in Dynegy-sponsored defined benefit pension plans and post-retirement benefit plans. The costs of such plans are shared by Dynegy and its employees. Plan assets of funded plans and plan obligations have not been allocated to us. Our share of pension and other post-retirement benefits expense for the plans was $4 million, $3 million and $1 million in 2004, 2003 and 2002, respectively.

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In addition, some of our employees participated in a DMS defined benefit pension plan, which is a traditional career average or final average pay formula plan. We use a December 31 measurement date for this plan. The following tables contain information about the obligations and funded status of this plan:

	December 31,
	2004			2003
	(in millions)
Projected benefit obligation, beginning of the year	$	13.0		$	11.8
Service cost		0.3			0.3
Interest cost		0.8			0.7
Actuarial (gain) loss		0.9			0.5
Benefits paid		(0.3	)		(0.3	)
Projected benefit obligation, end of the year	$	14.7		$	13.0
Fair value of plan assets, beginning of the year	$	9.8		$	8.4
Actual return on plan assets		0.9			1.7
Benefits paid		(0.3	)		(0.3	)
Fair value of plan assets, end of the year	$	10.4		$	9.8
Funded status	$	(4.3	)	$	(3.2	)
Unrecognized actuarial (gain) loss		0.4			(0.5	)
Net amount recognized	$	(3.9	)	$	(3.7	)

Assets in this plan are managed in a master trust arrangement with other Dynegy plans. Amounts recognized in our consolidated balance sheets consist of an accrued benefit liability of $3.9 million and $3.7 million at December 31, 2004 and 2003, respectively.

The accumulated benefit obligation for the defined benefit pension plan was $12.5 million and $11.4 million at December 31, 2004 and 2003, respectively.

The components of net periodic benefit cost were:

	2004			2003			2002
	(in millions)
Service cost benefits earned during period	$	0.3		$	0.3		$	0.2
Interest cost on projected benefit obligation		0.8			0.7			0.7
Expected return on plan assets		(0.9	)		(1.0	)		(0.9	)
Recognized net actuarial loss		—			—			(0.3	)
Total net periodic benefit cost	$	0.2		$	—		$	(0.3	)

The following weighted average assumptions were used to determine benefit obligations:

	December 31,
	2004		2003
Discount rate	5.75	%	6.00	%
Rate of compensation increase	4.50	%	4.50	%

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The following weighted average assumptions were used to determine net periodic benefit cost:

	Year Ended December 31,
	2004		2003		2002
Discount rate	6.00	%	6.50	%	7.50	%
Expected return on plan assets	8.75	%	9.00	%	9.00	%
Rate of compensation increase	4.50	%	4.50	%	4.50	%

Our expected long-term rate of return on plan assets for the year ended December 31, 2005 will be 8.25%. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long-term. Current market factors such as inflation and interest rates are also incorporated in the assumptions. The figure also incorporates an upward adjustment reflecting the plan’s use of active management and favorable past experience.

We employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalization. Other assets such as real estate and private equity may be used judiciously to enhance long-term returns while improving portfolio diversification.

Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies, and annual liability measurement.

Our pension plan weighted-average asset allocations by asset category were as follows:

	December 31,
	2004		2003
Equity securities	72	%	64	%
Debt securities	28	%	28	%
Real estate	—		5	%
Other	—		3	%
Total	100	%	100	%

Equity securities did not include any of Dynegy’s common at December 31, 2004 or 2003.

F-137

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

In 2005, we do not expect to make any contributions to our pension plan. Our expected benefit payments for future services for our pension benefits are as follows (in millions):

	Pension Benefits
2005	$	0.4
2006		0.5
2007		0.5
2008		0.5
2009		0.5
2010-2014		4.0

Note 13—Segment Information

We comprise substantially all of the natural gas liquids segment of Dynegy. On a stand-alone basis, our business segments consist of Gas Gathering and Processing, Marketing Assets, Distribution and Marketing Services and Wholesale Marketing. We identify our reportable segments based upon their operating activity.

Our 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 Marketing Assets segment is involved with the fractionating, storing, and transporting of natural gas liquids. These assets are generally connected to and supplied, in part, by our Gas Gathering and Processing segment and are located in Mont Belvieu, Texas and West Louisiana.

Our Distribution and Marketing Services segment markets our own natural gas liquids production and also purchased natural gas liquids products. We also have the right to purchase or market substantially all of ChevronTexaco’s natural gas liquids pursuant to a Master Natural Gas Liquids Purchase Agreement that extends through August 31, 2006.

Our Wholesale Marketing segment includes our refinery services business and wholesale propane marketing operations. In our refinery services business, we provide LPG balancing services, purchasing natural gas liquids products from refinery customers and selling 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.

F-138

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Reportable segment information, including intercompany transactions within this consolidated group, for the years ended December 31, 2004, 2003 and 2002, is presented below.

Segment Data for the Year Ended December 31, 2004

(in millions)

	Gas Gathering and Processing			Marketing Assets			Distribution and Marketing Services			Wholesale Marketing			Other and Eliminations			Total
Revenues	$	485		$	64		$	2,142		$	1,060		$	—		$	3,751
Intersegment revenues		592			104			398			82			(1,176	)		—
Total revenues		1,077			168			2,540			1,142			(1,176	)		3,751
Depreciation expense		(59	)		(30	)		(1	)		(1	)		—			(91	)
Impairment and other charges		(7	)		—			—			—			—			(7	)
Operating income		192			31			26			12			—			261
Earnings from unconsolidated investments		7			3			—			—			—			10
Other items, net		(19	)		(2	)		(1	)		—			—			(22	)
Net income																$	249
Identifiable assets	$	750		$	469		$	228		$	138		$	—		$	1,585
Unconsolidated investments	$	55		$	23		$	—		$	—		$	—		$	78
Capital expenditures	$	(52	)	$	(6	)	$	(1	)	$	—		$	—		$	(59	)

Segment Data for the Year Ended December 31, 2003

(in millions)

	Gas Gathering and Processing			Marketing Assets			Distribution and Marketing Services			Wholesale Marketing			Other and Eliminations			Total
Revenues	$	399		$	62		$	1,827		$	960		$	—		$	3,248
Intersegment revenues		479			90			332			59			(960	)		—
Total revenues		878			152			2,159			1,019			(960	)		3,248
Depreciation expense		(55	)		(29	)		(2	)		(1	)		—			(87	)
Impairment and other charges		1			—			—			—			—			1
Operating income		93			25			13			12			—			143
Earnings (losses) from unconsolidated investments		2			(4	)		—			—			—			(2	)
Other items, net		(17	)		(1	)		1			—			—			(17	)
Net income																$	124
Identifiable assets	$	797		$	504		$	197		$	125		$	—		$	1,623
Unconsolidated investments	$	59		$	23		$	—		$	—		$	—		$	82
Capital expenditures	$	(46	)	$	(8	)	$	(2	)	$	—		$	—		$	(56	)

F-139

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Segment Data for the Year Ended December 31, 2002

(in millions)

	Gas Gathering and Processing			Marketing Assets			Distribution and Marketing Services			Wholesale Marketing			Other and Eliminations			Total
Revenues	$	262		$	50		$	1,642		$	772		$	—		$	2,726
Intersegment revenues		385			94			275			72			(826	)		—
Total revenues		647			144			1,917			844			(826	)		2,726
Depreciation expense		(56	)		(28	)		(1	)		(1	)		—			(86	)
Impairment and other charges		(9	)		(5	)		(2	)		(1	)		—			(17	)
Operating income		14			14			19			7			—			54
Earnings from unconsolidated investments		7			9			—			—			—			16
Other items, net		(13	)		(5	)		—			—			—			(18	)
Net income																$	52
Identifiable assets	$	843		$	526		$	174		$	112		$	—		$	1,655
Unconsolidated investments	$	67		$	35		$	—		$	—		$	—		$	102
Capital expenditures	$	(66	)	$	(40	)	$	(3	)	$	—		$	—		$	(109	)

Note 14—Subsequent Events

Sale of DMS LP. On July 1, 2005, our limited partner, DMS LP, sold its entire interest in DMS to DMT Holdings, Inc. (“DMTHI”), a Dynegy owned affiliate, for $2.415 billion, which approximated the fair market value of the limited partner interest. In a series of transactions, DMTHI contributed its entire limited partner interest in DMS to one of its wholly-owned subsidiaries, Dynegy Midstream Holdings, Inc.

Sale of DMS. On August 2, 2005, Dynegy and our partners entered into an agreement to sell the entire partnership interests in DMS to Targa Resources, Inc. and two of its subsidiaries (collectively referred to as “Targa”). Dynegy expects to receive approximately $2.475 billion in cash proceeds from the sale, which include the base purchase price and DMS’ cash collateral. The base purchase price of $2.35 billion in cash will be paid by Targa at closing, subject to certain purchase price adjustments. In addition, cash collateral of DMS outstanding on the closing date, as defined in the purchase agreement, will be paid by Targa within 60 days of closing. The parties have made representations, warranties and covenants in the purchase agreement and the completion of the transaction is conditioned upon the expiration or termination of the Hart-Scott-Rodino waiting period and fulfillment of other closing conditions as set forth in the purchase agreement, including the lack of a material adverse effect. Dynegy expects its sale to Targa to close in the fourth quarter of 2005.

Hurricane Katrina. On August 29, 2005, Hurricane Katrina struck the Gulf Coast region of the United States, causing widespread damage. The hurricane damaged certain of our facilities, including the Yscloskey gas processing plant in which we have a proportionally consolidated 26% interest, the Toca gas processing plant in which we have a proportionally consolidated 9% interest, and the VESCO complex, in which we have a 23% equity interest and accounted for using the equity method. Dynegy carries, for the benefit of DMS, property damage insurance which we believe contains customary deductibles, limits and sub-limits for companies in our industry.

Additionally, our financial condition, results of operations and cash flows may be adversely affected by hurricane damage to our facilities, suppliers and customers. In addition to the loss of revenues at the facilities

F-140

DYNEGY MIDSTREAM SERVICES, LIMITED PARTNERSHIP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

which were damaged, the loss of NGL supplies to our Marketing and Distribution segment and our Wholesale Marketing segment may impact the profitability of those segments, as incremental costs of supply and distribution may reduce margins. We are in the process of evaluating the impact to our financial condition, results of operations and cash flows. Our share of operating income from the Yscloskey and Toca gas processing plants was $8 million, or 3% of our consolidated operating income, for the year ended December 31, 2004. Equity earnings from VESCO were $7 million for the year ended December 31, 2004. Dynegy carries business interruption insurance for the benefit of DMS covering lost profits and other costs and losses triggered by specified circumstances or events, including hurricanes, with limits which we believe are customary for companies in our industry. These policies provide that we may make claims for covered interruption of business following the expiration of the deductible periods of 30 days for onshore interruptions and 45 days for offshore interruptions. We are currently evaluating the damage to our facilities and business interruption losses. The amount of insured and uninsured losses and the timing of the reimbursement of losses has not yet been determined.

Sale of Land. On September 9, 2005, we sold a tract of land at our Port Everglades, Florida terminal for approximately $11 million in cash. As a result, we expect to recognize a gain of approximately $10 million in the third quarter of 2005 in our Marketing Assets segment. The gain will be included in gain on sale of assets, net in our consolidated statements of operations.

Guarantee of Debt Held by Targa. Although we have not historically incurred debt obligations, a significant portion of our assets are pledged as collateral for debt issued by Dynegy, and we have guaranteed debt issued by Dynegy. Upon completion of the sale of DMS to Targa, our obligation as guarantors of debt issued by Dynegy will be terminated and all liens and mortgages on our assets pledged as collateral for such debt will be released. Please see Note 8—Related Party Transactions for further information.

Further, upon completion of our sale to Targa and Targa’s debt offering, Dynegy Midstream Services, Limited Partnership (the “Parent”) and substantially all of the Parent’s wholly-owned subsidiaries will become guarantors of Targa’s obligations under its senior secured credit facilities and senior notes (as presented in Section—Description of the Notes of the offering circular for Targa senior notes due 2013; the “Offering Circular”). These guarantees will be on a full and unconditional, joint and several bases. The following condensed consolidating financial statements are presented on the equity method, reflecting Targa’s anticipated guarantor structure, and shown including investments in subsidiaries, recorded at cost and adjusted for the Parent’s ownership share of the subsidiaries’ cumulative results of operations, capital contributions and distributions and other equity changes. The guarantor structure presented within the Offering Circular is preliminary and subject to change based upon closing of related financing transactions and consummation of the DMS acquisition. Were the guarantor structure to subsequently change, the following condensed consolidating financial statements would also change accordingly.

F-141

The following historical condensed consolidating financial statements reflect the anticipated guarantor structure under Targa as of September 20, 2005:

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2004

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations			Total
ASSETS
Current Assets
Cash and cash equivalents	$	—		$	—		$	17		$	—		$	17
Accounts receivable		23			255			17			—			295
Inventory		—			58			—			—			58
Prepayments		4			38			—			—			42
Total Current Assets		27			351			34			—			412
Property, Plant and Equipment		1,138			115			518			—			1,771
Accumulated depreciation		(480	)		(40	)		(174	)		—			(694	)
Property, Plant and Equipment, Net		658			75			344			—			1,077
Other Assets
Unconsolidated equity investments		78			—			—			—			78
Net investment in consolidated subsidiaries		603			9			—			(612	)		—
Goodwill		15			—			—			—			15
Other long-term assets		3			—			1			(1	)		3
Total Assets	$	1,384		$	435		$	379		$	(613	)	$	1,585
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	17		$	58		$	5		$	—		$	80
Accrued liabilities		46			3			27			—			76
Total Current Liabilities		63			61			32			—			156
Other long-term liabilities		25			1			2			(1	)		27
Total Liabilities		88			62			34			(1	)		183
Minority Interest		—			—			106			—			106
Equity		1,296			373			239			(612	)		1,296
Total Liabilities and Equity	$	1,384		$	435		$	379		$	(613	)	$	1,585

F-142

CONDENSED CONSOLIDATING BALANCE SHEET

December 31, 2003

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations			Total
ASSETS
Current Assets
Cash and cash equivalents	$	—		$	—		$	20		$	—		$	20
Accounts receivable		22			231			14			—			267
Inventory		—			42			—			—			42
Prepayments		8			41			—			—			49
Total Current Assets		30			314			34			—			378
Property, Plant and Equipment		1,157			107			499			—			1,763
Accumulated depreciation		(433	)		(35	)		(150	)		—			(618	)
Property, Plant and Equipment, Net		724			72			349			—			1,145
Other Assets
Unconsolidated equity investments		82			—			—			—			82
Net investment in consolidated subsidiaries		564			9			—			(573	)		—
Goodwill		15			—			—			—			15
Other long-term assets		3			1			—			(1	)		3
Total Assets	$	1,418		$	396		$	383		$	(574	)	$	1,623
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	8		$	64		$	6		$	—		$	78
Accrued liabilities		61			5			21			—			87
Total Current Liabilities		69			69			27			—			165
Other long-term liabilities		27			1			2			(1	)		29
Total Liabilities		96			70			29			(1	)		194
Minority Interest		—			—			107			—			107
Equity		1,322			326			247			(573	)		1,322
Total Liabilities and Equity	$	1,418		$	396		$	383		$	(574	)	$	1,623

F-143

CONDENSED CONSOLIDATING INCOME STATEMENT

For the Year Ended December 31, 2004

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations			Total
Revenues from third parties	$	80		$	2,124		$	41		$	—		$	2,245
Revenues from affiliates		872			1,573			360			(1,299	)		1,506
Total revenues		952			3,697			401			(1,299	)		3,751
Cost of sales, exclusive of depreciation shown separately below		(770	)		(3,634	)		(309	)		1,299			(3,414	)
Depreciation expense		(57	)		(5	)		(29	)		—			(91	)
Impairment charge		(5	)		—			—			—			(5	)
Severance and restructuring reductions (charges)		(1	)		—			(1	)		—			(2	)
Gain (loss) on sale of assets, net		70			(1	)		—			—			69
General and administrative expenses		(26	)		(21	)		—			—			(47	)
Operating income		163			36			62			—			261
Earnings (losses) from unconsolidated investments		10			—			—			—			10
Other expense, net		—			—			—			—			—
Minority interest expense		—			—			(22	)		—			(22	)
Net income before equity in earnings of consolidated subsidiaries		173			36			40			—			249
Equity in earnings of consolidated subsidiaries		76			—			—			(76	)		—
Net income	$	249		$	36		$	40		$	(76	)	$	249

CONDENSED CONSOLIDATING INCOME STATEMENT

For the Year Ended December 31, 2003

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations			Total
Revenues from third parties	$	65		$	1,930		$	38		$	—		$	2,033
Revenues from affiliates		720			1,257			312			(1,074	)		1,215
Total revenues		785			3,187			350			(1,074	)		3,248
Cost of sales, exclusive of depreciation shown separately below		(647	)		(3,136	)		(277	)		1,074			(2,986	)
Depreciation expense		(56	)		(8	)		(23	)		—			(87	)
Impairment charge		—			—			—			—			—
Severance and restructuring reductions (charges)		1			—			—			—			1
Gain (loss) on sale of assets, net		23			—			—			—			23
General and administrative expenses		(34	)		(22	)		—			—			(56	)
Operating income		72			21			50			—			143
Earnings (losses) from unconsolidated investments		(2	)		—			—			—			(2	)
Other expense, net		1			1			(2	)		—			—
Minority interest expense		—			—			(17	)		—			(17	)
Net income before equity in earnings of consolidated subsidiaries		71			22			31			—			124
Equity in earnings of consolidated subsidiaries		53			—			—			(53	)		—
Net income	$	124		$	22		$	31		$	(53	)	$	124

F-144

CONDENSED CONSOLIDATING INCOME STATEMENT

For the Year Ended December 31, 2002

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations			Total
Revenues from third parties	$	27		$	1,725		$	36		$	—		$	1,788
Revenues from affiliates		572			1,047			225			(906	)		938
Total revenues		599			2,772			261			(906	)		2,726
Cost of sales, exclusive of depreciation shown separately below		(507	)		(2,721	)		(210	)		906			(2,532	)
Depreciation expense		(57	)		(7	)		(22	)		—			(86	)
Impairment charge		—			—			—			—			—
Severance and restructuring reductions (charges)		(13	)		(4	)		—			—			(17	)
Gain (loss) on sale of assets, net		(1	)		—			—			—			(1	)
General and administrative expenses		(21	)		(15	)		—			—			(36	)
Operating income		—			25			29			—			54
Earnings (losses) from unconsolidated investments		16			—			—			—			16
Other expense, net		(10	)		—			—			—			(10	)
Minority interest expense		—			—			(8	)		—			(8	)
Net income before equity in earnings of consolidated subsidiaries		6			25			21			—			52
Equity in earnings of consolidated subsidiaries		46			—			—			(46	)		—
Net income	$	52		$	25		$	21		$	(46	)	$	52

F-145

CONDENSED CONSOLIDATING CASH FLOWS

For the Year Ended December 31, 2004

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations		Total
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	173		$	36		$	40		$	—	$	249
Adjustments to reconcile net income to net cash flows from operating activities		(141	)		(27	)		45			—		(123	)
Net cash provided by operating activities		32			9			85			—		126
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(26	)		(9	)		(24	)		—		(59	)
Return of investment from unconsolidated investments		3			—			—			—		3
Proceeds from asset sales, net		100			—			—			—		100
Net cash provided by (used in) investing activities		77			(9	)		(24	)		—		44
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners, net		(150	)		—			—			—		(150	)
Distributions (contributions) between affiliates		41			—			(41	)		—		—
Distribution to minority interest holders		—			—			(23	)		—		(23	)
Net cash used in financing activities		(109	)		—			(64	)		—		(173	)
Net decrease in cash and cash equivalents		—			—			(3	)		—		(3	)
Cash and cash equivalents, beginning of period		—			—			20			—		20
Cash and cash equivalents, end of period	$	—		$	—		$	17		$	—	$	17

CONDENSED CONSOLIDATING CASH FLOWS

For the Year Ended December 31, 2003

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations		Total
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	71		$	22		$	31		$	—	$	124
Adjustments to reconcile net income to net cash flows from operating activities		(111	)		(18	)		50			—		(79	)
Net cash provided by (used in) operating activities		(40	)		4			81			—		45
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(26	)		(4	)		(26	)		—		(56	)
Return of investment from unconsolidated investments		4			—			—			—		4
Proceeds from asset sales, net		35			—			—			—		35
Net cash provided by (used in) investing activities		13			(4	)		(26	)		—		(17	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners, net		(8	)		—			—			—		(8	)
Distributions (contributions) between affiliates		34			—			(34	)		—		—
Distribution to minority interest holders		1			—			(20	)		—		(19	)
Net cash provided by (used in) financing activities		27			—			(54	)		—		(27	)
Net increase (decrease) in cash and cash equivalents		—			—			1			—		1
Cash and cash equivalents, beginning of period		—			—			19			—		19
Cash and cash equivalents, end of period	$	—		$	—		$	20		$	—	$	20

F-146

CONDENSED CONSOLIDATING CASH FLOWS

For the Year Ended December 31, 2002

(in millions)

	Parent Guarantor			Subsidiary Guarantors			Subsidiary Non-Guarantors			Eliminations		Total
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	6		$	25		$	21		$	—	$	52
Adjustments to reconcile net income to net cash flows from operating activities		167			(19	)		29			—		177
Net cash provided by operating activities		173			6			50			—		229
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(84	)		(6	)		(19	)		—		(109	)
Return of investment from unconsolidated investments		2			—			—			—		2
Proceeds from asset sales, net		—			—			—			—		—
Net cash used in investing activities		(82	)		(6	)		(19	)		—		(107	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to partners, net		(105	)		—			—			—		(105	)
Distributions (contributions) between affiliates		14			—			(14	)		—		—
Distribution to minority interest holders		—			—			(5	)		—		(5	)
Net cash used in financing activities		(91	)		—			(19	)		—		(110	)
Net increase (decrease) in cash and cash equivalents		—			—			12			—		12
Cash and cash equivalents, beginning of period		—			—			7			—		7
Cash and cash equivalents, end of period	$	—		$	—		$	19		$	—	$	19

F-147

ANNEX A

LETTER OF TRANSMITTAL

TO TENDER

OUTSTANDING 8 ¹/2% SENIOR NOTES DUE 2013

OF

TARGA RESOURCES, INC.

AND

TARGA RESOURCES FINANCE CORPORATION

PURSUANT TO THE EXCHANGE OFFER AND PROSPECTUS

DATED DECEMBER 20, 2007

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M.,

NEW YORK CITY TIME, ON JANUARY 24 , 2008 (THE “EXPIRATION DATE”),

UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE ISSUERS.

The Exchange Agent for the Exchange Offer is:

WELLS FARGO BANK, NATIONAL ASSOCIATION

By Registered and Certified Mail   Wells Fargo Bank, N.A. Corporate Trust Operations MAC N9303-121 P.O. Box 1517 Minneapolis, MN 55480 By Overnight Courier or Regular Mail:   Wells Fargo Bank, N.A.
Corporate Trust Operations
MAC N9303-121
6^th & Marquette Avenue
Minneapolis, MN 55479 By Hand Delivery   Wells Fargo Bank, N.A. Corporate Trust Services 608 2^ndAvenue South Northstar East Building -12^th Floor Minneapolis, MN 55402

Or

By Facsimile Transmission:

(612) 667-6282

Telephone:

(800) 344-5128

If you wish to exchange currently outstanding 8 ¹/2% Senior Notes due 2013 (the “outstanding notes”) for an equal aggregate principal amount at maturity of new 8 ¹/2% Senior Notes due 2013 pursuant to the exchange offer, you must validly tender (and not withdraw) outstanding notes to the exchange agent prior to the expiration date.

The undersigned hereby acknowledges receipt of the Prospectus, dated December 20, 2007 (the “Prospectus”), of Targa Resources, Inc. and Targa Resources Finance Corporation (the “Issuers”), and this Letter of Transmittal (the “Letter of Transmittal”), which together describe the Issuers’ offer (the “Exchange Offer”) to exchange their 8 ¹/2% Senior Notes due 2013 (the “New Notes”) that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), for a like principal amount of their issued and outstanding 8 ¹/2% Senior Notes due 2013 (the “Outstanding Notes”). Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

The Issuers reserve the right, at any time or from time to time, to extend the Exchange Offer at their discretion, in which event the term “Expiration Date” shall mean the latest date to which the Exchange Offer is extended. The Issuers shall notify the Exchange Agent and each registered holder of the Outstanding Notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

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This Letter of Transmittal is to be used by holders of the Outstanding Notes. Tender of Outstanding Notes is to be made according to the Automated Tender Offer Program (“ATOP”) of The Depository Trust Company (“DTC”) pursuant to the procedures set forth in the Prospectus under the caption “The Exchange Offer—Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer-generated message known as an “agent’s message” to the Exchange Agent for its acceptance. For you to validly tender your Outstanding Notes in the Exchange Offer, the Exchange Agent must receive, prior to the Expiration Date, an agent’s message under the ATOP procedures confirming that:

• DTC has received your instructions to tender your Outstanding Notes; and

• You agree to be bound by the terms of this Letter of Transmittal.

BY USING THE ATOP PROCEDURES TO TENDER OUTSTANDING NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

SIGNATURES MUST BE PROVIDED

PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

1. By tendering Outstanding Notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

2. By tendering Outstanding Notes in the Exchange Offer, you represent and warrant that you have full authority to tender the Outstanding Notes described above and will, upon request, execute and deliver any additional documents deemed by the Issuers to be necessary or desirable to complete the tender of Outstanding Notes.

3. You understand that the tender of the Outstanding Notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between the undersigned and the Issuers as to the terms and conditions set forth in the Prospectus.

4. By tendering Outstanding Notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the “SEC”), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1989), Morgan Stanley & Co. Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the New Notes issued in exchange for the Outstanding Notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof without compliance with the registration and prospectus delivery provisions of the Securities Act (other than a broker-dealer who purchased Outstanding Notes exchanged for such New Notes directly from the Issuers to resell pursuant to Rule 144A or any other available exemption under the Securities Act of 1933, as amended (the “Securities Act”) and any such holder that is an “affiliate” of the Issuers within the meaning of Rule 405 under the Securities Act), provided that such New Notes are acquired in the ordinary course of such holders’ business and such holders are not participating in, and have no arrangement with any other person to participate in, the distribution of such New Notes.

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5. By tendering Outstanding Notes in the Exchange Offer, you hereby represent and warrant that:

(a) any New Notes will be acquired in the ordinary course of your business;

(b) you have no arrangement or understanding with any person to participate in the distribution of the New Notes;

(c) you are not our “affiliate,” as defined in Rule 405 of the Securities Act, or if you are our “affiliate,” as defined in Rule 405 of the Securities Act, you will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;

(d) if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the New Notes; and

(e) if you are a broker-dealer, you will receive New Notes for your own account in exchange for Outstanding Notes that you acquired as a result of market-making activities or other trading activities and you will comply with the applicable provisions of the Securities Act including, but not limited to, delivery of a prospectus in connection with any resale of such New Notes; see “Plan of Distribution” in the prospectus.

6. You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your Outstanding Notes registered in the shelf registration statement described in the Registration Rights Agreement, dated as of October 31, 2005 (the “Registration Rights Agreement”), by and among the Issuers, the Subsidiary Guarantors (as defined therein) and the Initial Purchasers (as defined therein). Such election may be made by notifying the Issuers in writing at 1000 Louisiana, Suite 4300, Houston, Texas 77002, Attention: Investor Relations. By making such election, you agree, as a holder of Outstanding Notes participating in a shelf registration, to indemnify and hold harmless the Issuers, each of the directors of the Issuers, each of the officers of the Issuers who signs such shelf registration statement, each person who controls the Issuers within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and each other holder of Outstanding Notes, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to you furnished in writing by you or on your behalf expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

7. If you are a broker-dealer that will receive New Notes for your own account in exchange for Outstanding Notes that were acquired as a result of market-making activities or other trading activities, you acknowledge by tendering Outstanding Notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such New Notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act. If you are a broker-dealer and Outstanding Notes held for your own account were not acquired as a result of market-making or other trading activities, such Outstanding Notes cannot be exchanged pursuant to the Exchange Offer.

8. Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives.

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INSTRUCTIONS

FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER

1. Book-Entry Confirmations.

Any confirmation of a book-entry transfer of Outstanding Notes to the Exchange Agent’s account at DTC (a “Book-Entry Confirmation”), as well as any Agent’s Message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at its address set forth herein prior to 5:00 P.M., New York City time, on the Expiration Date.

2. Partial Tenders.

Tenders of Outstanding Notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000. The entire principal amount of Outstanding Notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all Outstanding Notes is not tendered, then Outstanding Notes for the principal amount of Outstanding Notes not tendered and New Notes issued in exchange for any Outstanding Notes accepted will be delivered to the holder via the facilities of DTC promptly after the Outstanding Notes are accepted for exchange.

3. Validity of Tenders.

All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered Outstanding Notes will be determined by the Issuers, in their sole discretion, which determination will be final and binding. The Issuers reserve the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuers, be unlawful. The Issuers also reserve the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any Outstanding Notes. The Issuers’ interpretation of the terms and conditions of the Exchange Offer (including the instructions on the Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Outstanding Notes must be cured within such time as the Issuers shall determine. Although the Issuers intend to notify holders of defects or irregularities with respect to tenders of Outstanding Notes, neither the Issuers, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of Outstanding Notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any Outstanding Notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in the Letter of Transmittal, as soon as practicable following the Expiration Date.

4. Waiver of Conditions.

The Issuers reserve the absolute right to waive, in whole or part, up to the expiration of the Exchange Offer, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.

5. No Conditional Tender.

No alternative, conditional, irregular or contingent tender of Outstanding Notes will be accepted.

6. Request for Assistance or Additional Copies.

Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent at the address or telephone number set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

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7. Withdrawal.

Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption “Exchange Offer—Withdrawal of Tenders.”

8. No Guarantee of Late Delivery.

There is no procedure for guarantee of late delivery in the Exchange Offer.

IMPORTANT: BY USING THE ATOP PROCEDURES TO TENDER OUTSTANDING NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. YOU WILL, HOWEVER, BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

¨ CHECK HERE IF YOU ARE A BROKER-DEALER AND WISH TO RECEIVE 10 ADDITIONAL COPIES OF THE PROSPECTUS AND 10 COPIES OF ANY AMENDMENTS OR SUPPLEMENTS THERETO.

Name:

Address:

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