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Article by DailyStocks_admin    (11-25-08 06:52 AM)

Targa Resources Partners LP. CEO RENE R JOYCE bought 31000 shares on 11-18-2008 at $9.96

BUSINESS OVERVIEW

General

We are a growth-oriented Delaware limited partnership formed on October 26, 2006 by Targa Resources, Inc. (“Targa”), a leading provider of midstream natural gas and NGL services in the United States, to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products. We currently operate in the Fort Worth Basin/Bend Arch (the “Fort Worth Basin”) in north Texas, the Permian Basin of west Texas and in southwest Louisiana.

In connection with our Initial Public Offering (“IPO”) in February 2007, Targa contributed the assets of the North Texas System located in the Fort Worth Basin (the “North Texas System”) to us. We acquired the assets of the SAOU System located in the Permian Basin (the “SAOU System”) and the assets of the LOU System located in southwest Louisiana (the “LOU System”) from Targa in October 2007.

We intend to leverage our relationship with Targa to acquire and construct additional midstream energy assets and to utilize the significant experience of Targa’s management team to execute our growth strategy.

Business Strategies

Our primary objective is to provide increasing cash distributions to our unitholders over time. Our business strategies focus on creating and increasing value for our unitholders through efficient operations, prudent risk management and growth through acquisitions and organic projects. We intend to accomplish this objective by executing the following strategies:


• Increasing the profitability of our existing assets. With our North Texas System, we have an extensive network of gathering systems and two natural gas processing facilities, which positions us to capitalize on the active development and growing production from the Barnett Shale and the other Fort Worth Basin formations. The SAOU System is located in the Permian Basin of west Texas, which is characterized by long-lived, multi-horizon oil and gas reserves that have low natural production declines. The LOU System has access to onshore basins in south Louisiana and serves the Lake Charles industrial market. Our assets provide us opportunities to:


• Utilize excess pipeline and plant capacity to connect and process new supplies of natural gas at minimal incremental cost;

• Undertake additional initiatives to improve operating efficiencies and increase processing yields;

• Eliminate bottlenecks to allow for increased throughput;

• Pursue pressure reduction projects to increase volumes of gas to be gathered and processed; and

• Expand our footprint in a cost effective manner.


• Managing our contract mix to optimize profitability. The majority of our operating margin is generated pursuant to percent-of-proceeds contracts or similar arrangements which, if unhedged, benefit us in increasing commodity price environments and expose us to a reduction in profitability in decreasing commodity price environments. We believe that if appropriately managed, our current contract mix allows us to optimize our profitability over time. Although we expect to maintain primarily percent-of-proceeds arrangements, we continually evaluate the market for attractive fee-based and other arrangements which will further reduce the variability of our cash flows as well as enhance our profitability and competitiveness.

• Mitigating commodity price exposure through prudent hedging arrangements. The primary purpose of our commodity price 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. We have hedged the commodity price associated with a significant portion of our expected natural gas, NGLs and condensate equity volumes for the years 2008 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 decrease over time. We have structured our hedges to approximate our actual NGL product composition and to approximate our actual NGL and natural gas delivery points. We do not use crude oil prices to approximate NGL prices for purposes of hedging. 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 warrant.

• Capitalizing on organic expansion opportunities. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that will allow us to expand our business.

• Focusing on producing regions with attractive characteristics. We seek to focus on those regions and supplies with attractive characteristics, including regions:


• where treating or processing is required to access end-markets;

where permitting, drilling and workover activity is high;

• with the potential for long-term acreage dedications;

• with a strong base of current production and the potential for significant future development; and

• that can serve as a platform to expand into adjacent areas with existing or new production.


• Pursuing strategic and accretive acquisitions. We plan to pursue strategic and accretive acquisition opportunities within the midstream energy industry, both from Targa and from third parties. We will seek acquisitions in our existing areas of operation that provide the opportunity for operational efficiencies, the potential for higher capacity utilization and expansion of existing assets, as well as acquisitions in other related midstream businesses and/or expansion into new geographic areas of operation. Among the factors we will consider in deciding whether to acquire assets include, but are not limited to, the economic characteristics of the acquisition (such as return on capital and cash flow stability), the region in which the assets are located (both regions contiguous to our areas of operation and other regions with attractive characteristics) and the availability and sources of capital to finance the acquisition. We intend to finance our expansion through a combination of debt and equity, including commercial debt facilities and public and private offerings of debt and equity securities.

• Leveraging our relationship with Targa. Our relationship with Targa provides us access to its extensive pool of operational, commercial and risk management expertise which enables all of our strategies. In addition, we intend to pursue acquisition opportunities as well as organic growth opportunities with Targa and with Targa’s assistance. We may also acquire assets or businesses directly from Targa, which will provide us access to an array of growth opportunities broader than that available to many of our competitors.

Competitive Strengths

We believe that we are well positioned to execute our primary business objective and business strategies successfully because of the following competitive strengths:


• Affiliation with Targa. We expect that our relationship with Targa will provide us with significant business opportunities. Targa is a large gatherer and processor of natural gas in the United States. Targa owns and operates a large integrated platform of midstream assets in oil and natural gas producing regions, including the Permian Basin in west Texas and southeast New Mexico and the onshore and offshore regions of the Texas and Louisiana Gulf Coast. These operations are integrated with Targa’s NGL logistics and marketing business that extends services to customers throughout the United States. Targa has an experienced and knowledgeable executive management team and experienced and knowledgeable commercial and operations teams. We believe Targa’s relationships throughout the energy industry, including with producers of natural gas in the United States, will help facilitate implementation of our acquisition strategy and other strategies. Targa has indicated that it intends to use us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL and other complementary energy businesses and assets and we expect to have the opportunity, but not the obligation, to acquire such businesses and assets directly from Targa in the future.

• Strategically located assets. Our North Texas System is one of the largest integrated natural gas gathering, compression, treating and processing systems in the Fort Worth Basin. Current high levels of natural gas exploration, development and production activities within the Fort Worth Basin present significant organic growth opportunities to generate additional throughput on our system.

The SAOU System provides us access to the Permian Basin, which is characterized by long-lived, multi-horizon oil and gas reserves that have low natural production declines. The SAOU System has access to liquid market hubs for both natural gas and NGLs.

The LOU System gathers gas primarily from onshore oil and gas production in southwest Louisiana in the area around and between Lafayette and Lake Charles, Louisiana. 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. It also has access to both interstate natural gas supplies and markets as well as access to the NGL markets of the Louisiana and Texas gulf coast.


• High quality and efficient assets. Our gathering and processing systems consist of high quality assets that have been well maintained, resulting in low cost, efficient operations. We have implemented state of the art processing, measurement and operations and maintenance technologies. These technologies have allowed us to proactively manage our operations with fewer field personnel resulting in lower costs and minimal downtime. As a result, we believe we have established a reputation in the midstream business as a reliable and cost-effective supplier of services to our customers and have a track record of safe and efficient operation of our facilities.

• Low maintenance capital expenditures. We believe that a low level of maintenance capital expenditures is sufficient for us to continue operations in a safe, prudent and cost-effective manner.

• Prudent hedging arrangements. While our percent-of-proceeds gathering and processing contracts subject us to commodity price risk, we have entered into long-term hedges covering the commodity price exposure associated with a significant portion of our near to mid-term expected equity gas, condensate and NGL volumes. This strategy reduces volumetric risk while managing commodity price risk related to these arrangements. We manage our business by hedging the commodity price exposure associated with a significant portion of our expected equity volumes of natural gas and NGLs in the near to mid-term.

• Strong producer customer base. We have a strong producer customer base consisting of both major oil and gas companies and independent producers. We believe we have established a reputation as a reliable operator by providing high quality services and focusing on the needs of our customers. Targa also has relationships throughout the energy industry, including with producers of natural gas in the United States, and has established a positive reputation in the energy business which we believe will assist us in our primary business objectives.

• Comprehensive package of midstream services. We provide a comprehensive package of services to natural gas producers, including natural gas gathering, compression, treating, processing and NGL fractionating. We believe our ability to provide all of these services provides us with an advantage in competing for new supplies of natural gas because we can provide substantially all of the services producers, marketers and others require to move natural gas and NGLs from wellhead to market on a cost-effective basis.

• Experienced management team. Targa has an experienced and knowledgeable executive management team with an average of 28 years in the energy industry that owns a 3.4% direct and indirect ownership interest in us. Targa’s executive management team has a proven track record of enhancing value through the acquisition, optimization and integration of midstream assets. In addition, Targa’s operations and commercial management team consists of individuals with an average of of approximately 25 years of midstream operating experience. Our relationship with Targa provides us with access to significant operational, commercial, technical, risk management and other expertise.

While we have set forth our strategies and competitive strengths above, our business involves numerous risks and uncertainties which may prevent us from executing our strategies. These risks include the adverse impact of changes in natural gas and NGL prices on the amount we are able to distribute to you, our inability to access sufficient additional production to replace natural declines in production and our dependence on a single natural gas producer for a significant portion of our natural gas supply. For a more complete description of the risks associated with an investment in us, please see “Item 1A. Risk Factors”.

Our Relationship with Targa Resources, Inc.

One of our principal strengths is our relationship with Targa, a leading provider of midstream natural gas and NGL services in the United States. Targa 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 (“Warburg Pincus”), a private equity firm. In April 2004, Targa purchased the SAOU and LOU Systems from ConocoPhillips Company (“ConocoPhillips”), for $247 million and, in October 2005, Targa purchased substantially all of the midstream assets of Dynegy, Inc. and its affiliates (“Dynegy”), for approximately $2.5 billion. These transactions formed 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 December 31, 2007, Targa had total assets of $3.8 billion (including the assets of the Partnership, which represent $1.5 billion of this amount).

Targa’s businesses include:

Natural Gas Gathering and Processing Division — Targa gathers and processes natural gas from the Permian Basin in west Texas and southeast New Mexico and the offshore regions of the Texas and Louisiana Gulf Coast. Most of the NGLs Targa processes are supplied through its gathering systems which, in aggregate, consist of approximately 11,000 miles of natural gas pipelines. The remainder is supplied through third party owned pipelines. Targa’s processing plants include nine facilities that it operates (either wholly or jointly) as well as six facilities in which it has an ownership interest but are operated by others. For the year ended December 31, 2007, these assets processed an average inlet plant volume of approximately 2 Bcf/d of natural gas and produced an average of approximately 107 MBbls/d of NGLs, in each case, net to Targa’s ownership interests.

NGL Logistics and Marketing Division — Targa has a significant, 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 approximately 62 MMBbl. This division uses its extensive platform of integrated assets to fractionate, store, terminal, transport, distribute and market NGLs, typically under fee-based and margin-based arrangements. Its assets are generally connected to and supplied, in part, by its Natural Gas Gathering and Processing assets and are primarily located in southwest Louisiana and near Mont Belvieu, Texas, the primary NGL hub in the United States. Targa owns, operates or leases assets in a number of other states, including Alabama, Nevada, California, Florida, Mississippi, Tennessee, New Jersey and Kentucky. The geographic diversity of Targa’s assets provides it direct access to many NGL end-users in both its geographic markets as well as markets outside its operating regions via open-access regulated NGL pipelines owned by third parties. Targa also owns 21 pressurized NGL barges, leases approximately 80 transport tractors and owns 100 tank trailers, and leases and manages approximately 800 railcars.

Targa has indicated that it intends to use us as a growth vehicle to pursue the acquisition and expansion of midstream natural gas, NGL and other complementary energy businesses and assets. Over time, Targa intends to offer us the opportunity to purchase substantially all of its remaining businesses, although it is not obligated to do so. While Targa believes it will be in its best interest to contribute additional assets to us given its significant ownership of limited and general partner interests in us, Targa constantly evaluates acquisitions and dispositions and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to purchase or construct those assets. We cannot say with any certainty which, if any, opportunities to acquire assets from Targa may be made available to us or if we will choose to pursue any such opportunity. Moreover, Targa is not prohibited from competing with us and constantly evaluates acquisitions and dispositions that do not involve us. In addition, through our relationship with Targa, we have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to Targa’s broad operational, commercial, technical, risk management and administrative infrastructure.

Targa has a significant indirect interest in our partnership through its ownership of a 24.5% limited partner interest and a 2% general partner interest in us. In addition, Targa owns incentive distribution rights

that entitle Targa to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. We are party to an Omnibus Agreement with Targa that governs our relationship with them regarding certain reimbursement and indemnification matters. Please see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement”. In addition, to carry out operations, our general partner and its affiliates, which are indirectly owned by Targa, employ approximately 920 people, some of whom provide direct support to our operations. We do not have any employees. Please see “Item 1. Business — Employees”.

While our relationship with Targa is a significant advantage, it is also a source of potential conflicts. For example, Targa is not restricted from competing with us. Targa owns substantial midstream assets and may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please see “Item 13. — Certain Relationships and Related Transactions, and Director Independence — Conflicts of Interest”.

Midstream Sector Overview

General. Natural gas gathering and processing is a critical part of the natural gas value chain. Natural gas gathering and processing systems create value by collecting raw natural gas from the wellhead and separating dry gas (primarily methane) from NGL such as ethane, propane, normal butane, isobutane and natural gasoline. Most natural gas produced at the wellhead contains NGL. Natural gas produced in association with crude oil typically contains higher concentrations of NGL than natural gas produced from gas wells. This “rich,” unprocessed natural gas is generally not acceptable for transportation in the nation’s interstate transmission pipeline system or for commercial use. Processing plants extract the NGL, leaving residual dry gas that meets interstate transmission pipeline and commercial quality specifications.

MANAGEMENT DISCUSSION FROM LATEST 10K

On February 14, 2007, we had Targa’s ownership interests in the North Texas System contributed to us. On October 24, 2007, we acquired Targa’s ownership interests in the SAOU System and the LOU System. As required by Statement of Financial Accounting Standards (“SFAS)” 141, we accounted for these transactions as transfers of net assets between entities under common control. For combinations of entities under common control, the purchase cost provisions (as they relate to purchase business combinations involving unrelated entities) of SFAS 141 explicitly do not apply; instead the method of accounting prescribed by SFAS 141 for such transfers is similar to the pooling-of-interests method of accounting. Under this method, the carrying amount of net assets recognized in the balance sheets of each combining entity are carried forward to the balance sheet of the combined entity, and no other assets or liabilities are recognized as a result of the combination (that is, no recognition is made for a purchase premium or discount representing any difference between the cash consideration paid and the book value of the net assets acquired).

Although in connection with our IPO, the North Texas System was presented as our predecessor entity, as a result of our October 2007 acquisition of the SAOU and LOU Systems, the predecessor entity for us is now considered to be the net assets of the SAOU and LOU Systems as these were the first assets acquired by Targa on April 16, 2004. Therefore, subsequent to the contribution of the North Texas System from Targa on February 14, 2007, we recognized the assets and liabilities of the North Texas System contributed to us at their carrying amounts (historical cost) in the accounts of the SAOU and LOU Systems (the predecessor entity) at the date of transfer. The accounting treatment for combinations of entities under common control is consistent with the concept of poolings as combinations of common shareholder (or unitholder) interests, as all of the North Texas System’s equity accounts were also carried forward intact initially, and subsequently adjusted due to the cash consideration we paid for the acquired net assets.

In addition to requiring that assets and liabilities be carried forward at historical costs, SFAS 141 also prescribes that for transfers of net assets between entities under common control, all income statements presented be combined as of the date of common control. Accordingly, our consolidated financial statements and all other financial information included in this report have been restated to assume that the transfer of the North Texas System net assets from Targa to us had occurred at the date when both the North Texas System and the SAOU and LOU Systems met the accounting requirements for entities under common control (October 31, 2005). As a result, financial statements and financial information presented for prior periods in this report have been restated.

Accordingly, our historical results include the historical results of the SAOU and LOU Systems (acquired by Targa effective April 16, 2004) for the years ended December 31, 2007, 2006 and 2005; and the historical results of the North Texas System (acquired by Targa effective November 1, 2005) subsequent to October 31, 2005.

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical financial statements and notes included elsewhere in this annual report.

Overview

We are a Delaware limited partnership formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products. We currently operate in the Fort Worth Basin in north Texas, the Permian Basin in west Texas and in southwest Louisiana.

We are owned 98% by our limited partners and 2% by our general partner, Targa Resources GP LLC, an indirect, wholly-owned subsidiary of Targa. Our limited partner common units are publicly traded on the NASDAQ Stock Market LLC under the symbol “NGLS”.

Factors That Significantly Affect Our Results

Our results of operations are substantially impacted by changes in commodity prices as well as increases and decreases in the volume of natural gas that we gather and transport through our pipeline systems, which we refer to as throughput volume. Throughput volumes and capacity utilization rates generally are driven by wellhead production, our competitive position on a regional basis and more broadly by prices and demand for natural gas and NGLs.

Our processing contract arrangements can have a significant impact on our profitability. We process natural gas under a combination of percent-of-proceeds contracts (approximately 79% of our gathered natural gas volumes), wellhead purchases/keep-whole contracts (approximately 19% of our gathered natural gas volumes), fee-based contracts (approximately 1% of our gathered natural gas volumes) and hybrid contracts (approximately 1% of our gathered natural gas volumes). The percent-of-proceeds and keep-whole contracts expose us to commodity price risk. We attempt to mitigate this risk through hedging activities which can materially impact our results of operations. Please see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk”.

Actual contract terms are based upon a variety of factors, including natural gas quality, geographic location, and the competitive commodity and pricing environment at the time the contract is executed and customer requirements. Our gathering and processing contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of producer preferences, competition, and changes in production as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common as well as other market factors. For a more complete discussion of the types of contracts under which we process natural gas, please see “Item 1. Business — Market Overview”.

The historical financial statements of the SAOU and LOU Systems and the North Texas System include certain items that will not materially impact our future results of operations and liquidity and do not fully reflect a number of other items that will materially impact future results of operations and liquidity, including the items described below:

Affiliate Indebtedness and Borrowings. Affiliate indebtedness prior to our acquisition of the SAOU and LOU Systems and the contribution of the North Texas System, consisted of borrowings incurred by Targa and allocated to us for financial reporting purposes.

Prior to Targa’s acquisition of the Dynegy Inc.’s interest in Dynegy Midstream Services, Limited Partnership (the “DMS Acquisition”), which included the North Texas System, the Predecessor Business was financed through borrowings by Targa and reflected allocated indebtedness on its balance sheet and allocated interest expense on its income statement. A substantial portion of the DMS Acquisition was also financed through borrowings by Targa. Following the October 31, 2005 DMS Acquisition, a significant portion of Targa’s acquisition borrowings were allocated to the North Texas System, resulting in approximately $868.9 million of allocated indebtedness and corresponding levels of interest expense. This indebtedness was incurred by Targa in connection with the DMS Acquisition and the entity holding the North Texas System provided a guarantee of this indebtedness. “This indebtedness was also secured by a collateral interest in both the equity of the entity holding the North Texas System as well as its assets.” In connection with our IPO, this guarantee was terminated, the collateral interest was released and the allocated indebtedness was retired.

On February 14, 2007, we borrowed approximately $294.5 million under our credit facility. The proceeds from this borrowing, together with approximately $371.2 million of net proceeds from our IPO (including 2,520,000 common units sold pursuant to the full exercise by the underwriters of their option to purchase additional common units), were used to repay approximately $665.7 million of affiliate indebtedness and the remaining balance of this indebtedness was retired and treated as a capital contribution to us.

On October 24, 2007, we completed our acquisition of the SAOU and LOU Systems concurrently with the sale of 13,500,000 common units representing limited partnership interests in us for gross proceeds of $362.7 million (approximately $349.2 million after underwriting discount and structuring fees). The net proceeds from the sale of the 13,500,000 units were used to pay approximately $2.5 million in expenses associated with the sale of the common units, and $24.2 million to Targa for certain hedge transactions associated with the SAOU and LOU Systems. We used the net proceeds after offering expenses and the hedge transactions of $322.5 million along with net borrowings of $375.5 million to pay approximately $698.0 million of the acquisition costs of the SAOU and LOU Systems. The allocated indebtedness from Targa related to the SAOU and LOU Systems was $124.0 million. Targa debt was guaranteed by the entities that own the SAOU and LOU Systems and was secured by a collateral interest in both the equity interests of those entities as well as their underlying assets. In conjunction with our acquisition of the SAOU and LOU Systems, this guarantee was terminated, the collateral interest was released and the allocated indebtedness was retired.

On November 20, 2007, the Underwriters exercised their option to purchase an additional 1,800,000 common units. The gross proceeds from the Underwriters exercise of their option to purchase additional common units were $48.4 million (approximately $46.5 million after underwriting discounts). The proceeds from the exercise of the underwriters’ option were used to reduce outstanding borrowings under our credit facility.

Concurrent with the acquisition of the SAOU and LOU Systems, we entered into a Commitment Increase Supplement (the “Supplement”) to our existing five-year $500 million senior secured revolving credit facility. The Supplement increased the aggregate commitment under our credit agreement by $250 million to an aggregate of $750 million. On October 24, 2007, we entered into the First Amendment to Credit Agreement (the “Amendment”). The Amendment increased by $250 million the maximum amount of increases to the aggregate commitments that may be requested by us. The Amendment allows us to request commitments under our credit agreement, as supplemented and amended, of up to $1 billion.

Impact of Our Hedging Activities. In an effort to reduce the variability of our cash flows, we have hedged the commodity price associated with a portion of our expected natural gas, NGLs and condensate equity volumes for the years 2008 through 2012 by entering into derivative financial instruments including swaps and purchased puts (or floors). With these arrangements, we have attempted to mitigate our exposure to commodity price movements with respect to our forecasted volumes for this period. For additional information regarding our hedging activities, please see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk.”

General and Administrative Expenses. Prior to the contribution of the assets of the North Texas System to us and the acquisition of the assets from the SAOU and LOU Systems by us from Targa, general and administrative expenses were allocated from Targa to the North Texas, SAOU and LOU Systems in accordance with the general and administrative expenses allocation policies of Targa. On February 14, 2007, we entered into an Omnibus Agreement with Targa, pursuant to which our allocated general and administrative expenses related to the North Texas System are capped at $5.0 million per year for three years, subject to adjustment. For a more complete description of this agreement, see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement”. In addition to these allocated general and administrative expenses, we incur incremental general and administrative expenses as a result of operating as a separate publicly held limited partnership. These direct, incremental general and administrative expenses of approximately $3.1 million for the year ended December 31, 2007, including one-time expenses associated with our equity offerings, financing arrangements and acquisitions, are not subject to the cap contained in the Omnibus Agreement. These costs include costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, incremental independent auditor fees, registrar and transfer agent fees and independent director compensation. These incremental general and administrative expenditures are not reflected in the historical financial statements of the North Texas, SAOU and LOU Systems.

On October 24, 2007, we amended and restated our Omnibus Agreement with Targa (the “Amended and Restated Omnibus Agreement”). The Amended and Restated Omnibus Agreement governs certain relationships between Targa and us, including:

i. Targa’s obligation to provide certain general and administrative services to us;

ii. our obligation to reimburse Targa and its affiliates for the provision of general and administrative services (a) subject to a cap of $5 million (relating solely to the North Texas System) in the first year, with increases in the subsequent two years based on a formula specified in the Amended and Restated Omnibus Agreement and (b) fully allocated as to the SAOU and LOU Systems according to Targa’s previously established allocation practices;

iii. our obligation to reimburse Targa and its affiliates for direct expenses incurred on our behalf; and

iv. Targa’s obligation to indemnify us for certain liabilities and our obligation to indemnify Targa for certain liabilities.

Allocated general and administrative expenses were $13.9 million, $16.1 million and $16.7 million for the years ended December 31, 2007, 2006 and 2005, respectively.

Working Capital Adjustments. Prior to our IPO and the contribution of the North Texas System in February 2007 and the acquisition of the SAOU and LOU Systems in October 2007, all intercompany transactions, including commodity sales and expense reimbursements, were not cash settled with the Predecessor Business’ respective parent, but were recorded as an adjustment to parent equity on the balance sheet. The primary intercompany transactions between the respective parent and the Predecessor Business are natural gas and NGL sales, the provision of operations and maintenance activities and the provision of general and administrative services. Accordingly, the working capital of the Predecessor Business does not reflect any affiliate accounts receivable for intercompany commodity sales or affiliate accounts payable for the personnel and services provided or paid for by the applicable parent on behalf of the Predecessor Business.




MANAGEMENT DISCUSSION FOR LATEST QUARTER

Overview

We are a Delaware limited partnership formed by Targa to own, operate, acquire and develop a diversified portfolio of complementary midstream energy assets. We are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs and NGL products. We currently operate in the Fort Worth Basin/Bend Arch in North Texas, the Permian Basin in West Texas and in Southwest Louisiana.

We are owned 98% by our limited partners and 2% by our general partner, Targa Resources GP LLC, an indirect, wholly-owned subsidiary of Targa. Our limited partner common units are publicly traded on The NASDAQ Stock Market LLC under the symbol “NGLS.”

Our Operations

We sell the majority of our processed natural gas, NGLs and high-pressure condensate to Targa at market-based rates pursuant to natural gas, NGL and condensate purchase agreements. Low-pressure condensate is sold to third parties. For a more complete description of these arrangements, please see “Item 13. Certain Relationships and Related Transactions, and Director Independence” and “Item 1. Business — Market Access” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Critical Accounting Policies and Estimates

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

Recent Accounting Pronouncements

On January 1, 2008, we adopted the provisions of SFAS 157. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report for information regarding fair value disclosures pertaining to our financial assets and liabilities.

The accounting standard-setting bodies have recently issued the following accounting guidelines that will or may affect our future financial statements:


• EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.”

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

For additional information regarding these recent accounting developments and others that may affect our future financial statements, see Note 3 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Results of Operations

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

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

(3) Distributable Cash Flow is net income plus depreciation and amortization and deferred taxes, adjusted for losses on mark-to-market derivative contracts, less maintenance capital expenditures. See “Non-GAAP Financial Measures.”

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

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

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

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

Our operating margin decreased by $3.6 million, or 7%, to $50.9 million for the three months ended September 30, 2008 compared to $54.5 million for the three months ended September 30, 2007. Our operating margin for the three months ended September 30, 2008 was reduced by $2.2 million for estimated lost business as a result of Hurricanes Gustav and Ike.

Our revenues increased by $173.7 million, or 43%, to $578.7 million for the three months ended September 30, 2008 compared to $405.0 million for the three months ended September 30, 2007. The increase is primarily due to:


• An increase attributable to commodity prices of $182.8 million, comprising increases in natural gas, NGL and condensate revenues of $129.0 million, $45.0 million and $8.8 million;

• A decrease attributable to commodity sales volume of $8.8 million comprising decreases in natural gas, NGL and condensate revenues of $5.7 million, $0.3 million and $2.8 million;

• A decrease in other revenues of $0.3 million, primarily from miscellaneous processing activities.

Our average realized prices for natural gas increased by $3.46 per MMBtu (net of a $0.14 decrease related to hedge settlements), or 58%, to $9.42 per MMBtu for the three months ended September 30, 2008 compared to $5.96 per MMBtu for the three months ended September 30, 2007. Our average realized price for NGLs increased by $0.32 per gallon (net of a $0.09 decrease related to hedge settlements), or 31%, to $1.36 per gallon for the three months ended September 30, 2008 compared to $1.04 per gallon for the three months ended September 30, 2007. Our average realized price for condensate increased by $29.05 per barrel (net of a $5.28 decrease related to hedge settlements), or 42%, to $97.79 per barrel for the three months ended September 30, 2008 compared to $68.74 per barrel for the three months ended September 30, 2007.

Our natural gas sales volumes decreased by 10.4 BBtu/d, or 3%, to 404.4 BBtu/d for the three months ended September 30, 2008 compared to 414.8 BBtu/d for the three months ended September 30, 2007. Our natural gas sales for the three months ended September 30, 2008 decreased by 7.1 BBtu/d as a result of reductions in demand in the Lake Charles industrial market caused by Hurricanes Gustav and Ike. In addition, our inability to transport NGLs to market due to hurricane-related curtailments on third-party owned pipelines forced us to temporarily shutdown some of our West Texas natural gas processing plants, resulting in a 1.8 BBtu/d reduction in natural gas sales volumes for the three months ended September 30, 2008.

Our NGL sales volumes decreased by 0.1 MBbl/d, or less than 1.0%, to 37.4 MBbl/d for the three months ended September 30, 2008 compared to 37.5 MBbl/d for the three months ended September 30, 2007. In October 2007 our Gillis fractionation facility in Louisiana began fractionating and selling purchased third-party raw NGLs, which increased NGL sales by 2.2 MBbl/d for the three months ended September 30, 2008. Offsetting this increase was a 1.7 MBbl/d decrease due to the aforementioned hurricane-related curtailments on third-party owned pipelines.

Our product purchases increased by $174.6 million, or 52%, to $512.4 million for the three months ended September 30, 2008 compared to $337.8 million for the three months ended September 30, 2007. The increase in product purchase cost was due primarily to higher commodity prices in the three months ended

September 30, 2008 versus the three months ended September 30, 2007, partially offset by a volume decrease in gas purchases.

Our operating expenses increased by $2.7 million, or 21%, to $15.4 million for the three months ended September 30, 2008 compared to $12.7 million for the three months ended September 30, 2007. The increase in operating expenses was primarily the result of increases of $0.7 million in compensation related expenses, $0.8 million in gathering system maintenance, $0.5 million in lube oils and chemical expenses, $0.2 million in utilities and $0.5 million in other operating expenses.

Our general and administrative expenses decreased by $1.2 million, or 18%, to $5.3 million for the three months ended September 30, 2008 compared to $6.5 million for the three months ended September 30, 2007. The decrease consisted of a $0.5 million decrease in professional service fees and a $0.7 million decrease in the allocation of corporate level expenses. For additional information regarding our allocation of general and administrative costs, see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our Annual Report on Form 10-K for the year ended December 31, 2007.

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

Our operating margin increased by $22.1 million, or 15%, to $168.8 million for the nine months ended September 30, 2008 compared to $146.7 million for the nine months ended September 30, 2007. Our operating margin for the nine months ended September 30, 2008 was reduced by approximately $2.2 million for estimated lost business as a result of Hurricanes Gustav and Ike.

Our revenues increased $533.9 million, or 45%, to $1,721.3 million for the nine months ended September 30, 2008 compared to $1,187.4 million for the nine months ended September 30, 2007. The increase is primarily due to:


• An increase attributable to commodity prices of $485.4 million, comprising increases in natural gas, NGL and condensate revenues of $293.0 million, $159.2 million and $33.2 million:

• An increase attributable to commodity sales volume of $44.3 million comprising increases in natural gas and NGL revenues of $16.6 million and $28.5 million, partially offset by a decrease in condensate revenues of $0.8 million.

• An increase in other revenue of $4.2 million, primarily from miscellaneous processing activities.

Our average realized prices for natural gas increased by $2.60 per MMBtu (net of a $0.10 decrease related to hedge settlements), or 39%, to $9.29 per MMBtu for the nine months ended September 30, 2008 compared to $6.69 per MMBtu for the nine months ended September 30, 2007. The average realized price for NGLs increased by $0.37 per gallon (net of a $0.09 decrease related to hedge settlements), or 39%, to $1.31 per gallon for the nine months ended September 30, 2008 compared to $0.94 per gallon for the nine months ended September 30, 2007. The average realized price for condensate increased by $33.87 per barrel (net of a $4.90 decrease related to hedge settlements), or 56%, to $94.74 per barrel for the nine months ended September 30, 2008 compared to $60.87 per barrel for the nine months ended September 30, 2007.

Our natural gas sales volumes increased by 7.6 BBtu/d, or 2%, to 410.9 BBtu/d for the nine months ended September 30, 2008 compared to 403.3 BBtu/d for the nine months ended September 30, 2007.

Our NGL sales volumes increased by 2.5 MBbl/d, or 7%, to 38.2 MBbl/d for the nine months ended September 30, 2008 compared to 35.7 MBbl/d for the nine months ended September 30, 2007. The increase was primarily due to processing and sales of third party raw NGL volumes.

Our product purchases increased by $505.8 million, or 50%, to $1,509.8 million for the nine months ended September 30, 2008 compared to $1,004.0 million for the nine months ended September 30, 2007. The increase in product purchases was due primarily to higher commodity prices, increased spot price purchases for industrial sales customers and changing contract mix in North Texas.

Our operating expenses increased by $6.0 million, or 16%, to $42.7 million for the nine months ended September 30, 2008 compared to $36.7 million for the nine months ended September 30, 2007. The increase in operating expenses was primarily the result of increases of $2.0 million in compensation related expenses, $1.5 million in general maintenance and supplies, $0.9 million in lube oil, environmental, and automotive expenses, $0.7 million in utilities, $0.5 million in ad valorem taxes and $0.4 million in other operating expenses.

Our general and administrative and other expenses increased by $1.7 million, or 12%, to $16.2 million for the nine months ended September 30, 2008 compared to $14.5 million for the nine months ended September 30, 2007. The increase comprised $0.2 million in professional service fees, $0.3 million in insurance expenses, $1.0 million in allocated corporate level expenses and $0.2 million in other general and administrative expenses. For additional information regarding our allocation of general and administrative costs, see “Item 13. Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Liquidity and Capital Resources

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

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a senior secured credit facility with both uncommitted and committed availability and access to both the debt and equity capital markets. The credit markets are undergoing significant volatility. Many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our exposure to the current credit crisis includes our revolving credit facility, cash investments and counterparty performance risks. Continued volatility in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and affect our ability to access those markets. In order to increase our cash position in the face of the credit and capital market disruptions, on October 16, 2008, we requested a $100 million funding under our senior secured credit facility. Lehman Bank, a lender under our senior secured credit facility, defaulted on its portion of this borrowing request resulting in actual funding of $97.8 million. The proceeds from this borrowing request are currently available to us as cash deposits. As a result of the default, we believe the availability under our senior secured credit facility has been effectively reduced by $9.5 million.

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

Crude oil and natural gas prices are also volatile and have declined significantly during the quarter, continuing downward since the end of the quarter. In a continuing effort to reduce the volatility of our cash flows, we have periodically entered into commodity contracts for a portion of our estimated equity volumes through 2012 (see Note 7 — Derivative Instruments and Hedging Activities). The current market conditions may also impact our availability to enter into future commodity derivative contracts. In the event of a global recession commodity prices may stay depressed or reduce further thereby causing a prolonged downturn, which could reduce our operating margins and cash flow from operations.

At this point, we do not believe our liquidity has been materially affected by the current credit crisis and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the capital markets. Additionally, we will continue to monitor events and circumstances surrounding each of the other twenty three lenders under our senior secured credit facility. To date, other than the Lehman Bank default, we have experienced no disruptions in our ability to access funds committed under our senior secured credit facility. However, we cannot predict with any certainty the impact to us of any further disruptions in the credit environment. See “Item 1A. Risk Factors” in this Quarterly Report and “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Historically, our cash generated from operations has been sufficient to finance our operating expenditures and fund most of our maintenance and expansion capital expenditures, with remaining amounts being distributed to Targa during its period of ownership and to our unitholders since Targa’s contribution of assets to us and our acquisition of assets from Targa.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, much of our long-term capital expenditure requirements and our minimum quarterly cash distributions for at least the next year.

We intend to make cash distributions to our unitholders and our general partner at least at the minimum quarterly distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis). Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including other debt and common unit issuances, to fund our acquisition and expansion capital expenditures. See Note 4 of the Notes to Consolidated Financial Statements included in Item 1 of this Quarterly Report.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements are primarily driven by changes in accounts receivable and accounts payable. These changes are impacted by changes in the prices of commodities that we buy and sell. In general, our working capital requirements increase in periods of rising commodity prices and decrease in periods of declining commodity prices. However, our working capital needs do not necessarily change at the same rate as commodity prices because both accounts receivable and accounts payable are impacted by the same commodity prices. In addition, the timing of payments received from our customers or paid to our suppliers can also cause fluctuations in working capital because we settle with most of our larger suppliers and customers on a monthly basis and often near the end of the month. We expect that our future working capital requirements will be impacted by these same factors.

As of September 30, 2008, we had working capital of $30.6 million, including a net short-term asset for commodity and interest rate derivatives of $22.9 million. In accordance with SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” we record the fair value of all derivative instruments on the balance sheet. Our hedge agreements provide for monthly settlement (quarterly for interest rate swaps) based on the differential between the agreement price and published commodity price and interest rate indexes. Cash received from physical sales of commodities and cash paid for interest will be based on actual market prices and interest rates and will generally offset any gains or losses realized on the derivative instruments. Our derivative contracts do not have margin requirements or collateral provisions that could require funding prior to the scheduled cash settlement date. Excluding derivatives our working capital surplus was $7.7 million as of September 30, 2008. See “Item 3. Quantitative and Qualitative Disclosures about Market Risk” in this Quarterly Report and in our Annual Report on Form 10-K for the year ended December 31, 2007.

Contractual Obligations. In June 2008, we issued $250 million aggregate principal amount of 8 1 / 4 % Senior Notes due 2016 (the “Notes”). The proceeds from the offering were used to reduce outstanding indebtedness under our senior secured credit facility. The interest rate on the Notes is fixed at 8.25% with interest to be paid on January 1 and July 1 of each year and the Notes mature on July 1, 2016.

Available Credit. As of September 30, 2008, we had approximately $415.8 million in capacity available under our senior secured credit facility, after giving effect to outstanding borrowings of $390 million, the issuance of $34.7 million of letters of credit, and the default by Lehman Bank. Our senior secured credit facility allows us to request increases in the commitments under the facility by up to $150 million.

Capital Requirements. The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. A portion of the cost of constructing new gathering lines to connect to our gathering system is paid for by the natural gas producer. However, we expect to continue to incur significant expenditures through the remainder of 2008 related to the expansion of our natural gas gathering and processing infrastructure.


CONF CALL

Anthony Riley

Good morning. Thank you, operator. I’m Anthony Riley, and I would like to welcome you to Targa’s third quarter 2008 conference call. And thank you for joining us.

Before we get started, I would like to mention that Targa did publish an earnings release this morning, and it is available on our Web site at www.targaresources.com. Speaking today will be Rene Joyce, Chief Executive Officer; and Jeff McParland, Chief Financial Officer. Rene and Jeff are going to be comparing the third quarter 2008 to the third quarter 2007.

Before we begin, I would like to remind you that this call contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 as amended and Section 21E of the Exchange Act of 1934 as amended. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties, and assumptions. The future results of Targa may differ materially from those expressed from the forward-looking statements contained on this call.

Many of the factors that will determine these results and values are beyond Targa’s ability to control or predict. These statements are necessarily based upon various assumptions involving judgment with respect to the future, including among other things, weather, political, economic, and market conditions; timing and success of business development efforts; and, other uncertainties. You are cautioned not to put undue reliance on any forward-looking statements.

With that, I will turn it over to Rene Joyce, our Chief Executive Officer.

Rene Joyce

Thanks, Anthony, and good morning. And thank you for participating in our call. There are several members of the management team here today, and they will be available to assist with the Q&A session. By way of agenda, we’ll start off by reviewing our third quarter and year-to-date ‘08 performance, including operational and financial accomplishments. I will then turn it over to Jeff to review our consolidated and business segment results. Following Jeff’s comments, I will update the progress on a few strategic initiatives. And finally, we will take your questions.

Third quarter ’08 gathering throughput of 1.9 billion cubic feet a day and plant inlet volumes of 1.8 billion cubic feet per day were both 7% lower than for the third quarter of ‘07. Natural gas sales of a little over 515 billion Btu per day for the three months ended September 30, ‘08 was 4% lower than the comparable period in ‘07.

Gross NGL production of approximately 100,800 barrels a day in the three month period ended September 30 were 6% lower compared to the same ‘07 period. Third quarter ’08 NGL sales were approximately 290,100 barrels per day, 12% lower than the third quarter of ‘07. Condensate sales of 3,900 barrels per day were 11% lower compared to the ‘07 period.

With regard to the performance highlights for ’08 year-to-date, gathering throughput of 2 billion cubic feet a day and plant natural gas inlet of 2 Bcf per day were 3% and 2% higher, respectively, versus the same period in ‘07. Natural gas sales of 524,900 barrels – excuse me on that. Natural gas sales of almost 525 billion Btu per day for the nine months ended September 30, ‘08 were less than 1% lower than the comparable period in ‘07.

Gross NGL production of approximately 103,000 barrels per day for the nine-month period ended September 30, ‘08 were 2% lower compared to the same ‘07 period. Year-to-date, ’08 NGL sales were approximately 298,000 barrels or 4% lower than the same period ‘07. Condensate sales of 3,800 barrels per day for the nine-month period ended September 30, ‘08 were down 3% compared to the ‘07 period.

For details on the financial results, I’ll turn it over to Jeff.

Jeff McParland

Thanks, Rene. I’d like to add my welcome, and thank you for joining our call this morning.

We reported a net loss of $20.9 million for the third quarter of 2008, compared to net income of $13.3 million for the third quarter of 2007. The $34.2 million decrease in net income is primarily due to three items, the $31.6 million pretax charge to reduce the carrying value of our NGL inventory, the $17.9 million pretax loss reserve for damage to a certain of our Gulf Coast facilities caused by Hurricanes Gustav and Ike, and an $11.8 million non-cash derivative loss.

Third quarter revenues increased by $489 million to approximately $2.4 billion, 26% higher than the $1.9 billion for the same period in 2007. Income from operations was $16.9 million for the quarter, compared to $66 million in 2007, a decrease of 74%. Third quarter adjusted EBITDA was $46.4 million, compared to $92.1 million for the same period in 2007. On a consolidated basis, capital expenditures for the third quarter totaled approximately $35 million.

Looking at our year-to-date results, we reported net income of approximately $44 million for the nine months ended September 30, 2008, compared to $36 million for the comparable period of 2007. Year-to-date revenues increased by $1.9 billion to approximately $6.8 billion, 38% higher than the $4.9 billion for the same period last year. Income from operations was $198.7 million for the nine months ended September 30, 2008, compared to $181.4 million in 2007, an increase of 10%. Year-to-date adjusted EBITDA increased 6% to $275.7 million. On a consolidated basis, year-to-date CapEx totaled approximately $94 million.

During the second quarter of 2008, we recognized a gain of $18.6 million in connection with insurance receipts in excess of the property damage receivables that was included in our purchase price allocation for the DMS acquisition in 2005. Year-to-date, we have received $48.3 million and $21.6 million related to property damage and business interruption insurance claims, respectively, most of which was in connection with the final resolution of our claims related to Katrina under our onshore property insurance program.

Let me now turn to the impact of Hurricanes Gustav and Ike, which resulted in damage to certain facilities in Louisiana and Texas, and disrupted industry operations across the Gulf Coast. As I will summarize the impacts at a high level on these remarks, please refer to our quarterly report and our earnings press release for further details. As you will see in those disclosures, all facilities have resumed operations with three exceptions. Mechanical repairs are completed at the Yscloskey straddle plant and start-up is expected late in November pending repairs to a third party’s offshore system. Repairs to our Stingray and Barracuda plants will continue onto the next year, with operations expected to resume in the second quarter.

While it is still very early in the claims process and we are, in some cases, still finalizing repair assessments and cost estimates, we currently estimate the repair costs associated with our interests in the impacted facilities to be approximately $65 million. In addition, we are still in the process of analyzing the factors affecting the amount of our business interruption claims. However, based on the information currently available to us, we believe that we could receive business interruption claims in excess of $10 million. We will recognize income from business interruption claims in the period that a proof of loss is executed with our insurers.

With that overview, I’d like to turn to a discussion of our segment results. We report our operations in four segments, first, natural gas gathering and processing; second, logistics assets; third, NGL distribution and marketing; and fourth, wholesale marketing.

Let’s start with the gathering and processing segment, which includes our gathering and processing businesses in New Mexico, Texas, and Louisiana, including those owned by the MLP, Targa Resources Partners LP. All throughput, inlet, and production volumes were down in the third quarter of 2008 relative to the same quarter last year. The lower volumes were primarily as a result of Gulf Coast natural gas processing plant shutdowns and disruptions leading up to and following Hurricanes Gustav and Ike in September.

Operating margin for the third quarters of 2008 and 2007 was $117.3 million and $108.5 million, respectively. Year-to-date gathering throughput and plant inlet volumes were up relative to the same period in 2007. Natural gas sales volumes decreased less than 1% to 543 Btu per day for the first nine months of this year. NGL sales volumes of 88,600 barrels per day were down 2% compared to 2007 levels, while condensate sales volumes decreased 4% to 5,000 barrels per day for the first nine months of 2008 compared to the same period in 2007.

Segment revenues were approximately $2.9 billion for the nine months ended September 30, 2008, up $824 million from the same period of 2007. Operating margin increased 17% to $346.7 million for the first nine months of 2008, compared to $296.7 million last year.

We refer to our assets that are involved in the fractionation, storage, treating, and transportation of natural gas liquids as the logistics assets.

Fractionation volume decreased 11% from 232,000 barrels per day for the third quarter of 2007 to 207,100 barrels a day for the third quarter this year. Third quarter 2008 revenues in this segment were $65.4 million, 25% higher than the same period in 2007. The revenue increase was primarily from higher fractionation fees due to higher natural gas prices, an increase in commercial transportation revenues due to increased barge activity, and an increase in terminal revenue due to a new connection into a common carrier pipeline.

Operating margin was $15.6 million, an increase of 26% compared to the same period last year. Operating expenses increased $9.8 million to $49.8million for the quarter. This increase was primarily from increased fuel and electricity expense due to higher natural gas prices, increased barge and trucking activity, and increased usage of third party fractionation services.

Moving to the first nine months, fractionation volumes increased 6% from 207,300 barrels per day in 2007 to 219,300 barrels per day this year. Nine months revenues in 2008 were $182.3 million, 26% higher than the same period in 2007. The revenue increase was primarily from higher fractionation fees due to higher natural gas prices, higher revenues from our low sulfur natural gasoline plant, an increase in commercial transportation revenues partially offset by lower barge activity at Galena Park.

Operating margin was $34.1 million, an increase of 19% compared to the same period in 2007. Operating expenses increased $32 million to $148 million for the nine months ended September 30, 2008. The increase is primarily due to increased fuel and electricity expense; operating expenses at our LSNG plant, which commenced commercial operations in June of last year; higher barge and truck activity as part of our maintenance cost due to the turnaround of the Cedar Bayou Fractionator; oil eventuals at the fractionator; maintenance at the Mont Belvieu Terminal; and, increased usage of third party fractionation facilities.

Our NGL distribution and marketing services segment markets our own NGL production as well as NGLs purchased from third parties.

NGL sales for the three months ended September 30, 2008 were 258,000 barrels per day, a decrease of 11% compared to the same period in 2007, primarily due to disruptions from Hurricanes Gustav and Ike. Revenues increased $331 million or 25%, to $1.7 billion for the third quarter of 2008 compared to the same period in 2007.

Operating loss for the three months ended September 30 was $25 million, down $41 million compared to the 2007 period quarter. The decrease in operating margin was primarily due to lower volumes attributable to the impact of the hurricane and to a 2008 charge of $24.1 million to reduce the carrying value of our NGL inventory.

NGL sales for the nine months ended September 30, 2008 were 258,000 barrels per day, a decrease of 4% compared to the same period in 2007. Revenues increased $1.3 billion or 40%, to $4.6 billion for the first nine months of 2008 compared to the same period in 2007.

Operating margin for the nine months ended September 30, 2008 was $15 million, down $19 million compared to 2007. The decrease in operating margin was primarily due to lower volumes attributable to the impact of the hurricane and to charges taken in 2008 of $25.8 million to reduce the carrying value of our NGL inventory.

Our wholesale marketing segment includes our refinery services businesses as well as our wholesale propane operations. NGL sales decreased by 6% to approximately 47,000 barrels per day in the third quarter of 2008. Revenues for the segment were $321 million for the three months ended September 30, 2008, an increase of 30% compared to the 2007. Segment operating results for the third quarter of 2008 – excuse me, segment operating loss for the third quarter of 2008 was approximately $5.4 million, down $8 million compared to the third quarter of 2007. The decrease is primarily due to a 2008 charge of $7.5 million to reduce the carrying value of inventory.

For the first nine months, NGL sales increased by 2% to 60,100 barrels per day in. Revenues for this segment were $1.2 billion for the nine months ended September 30, 2008, an increase of 46% compared to the nine months in 2007. Segment operating margin for the first nine months of 2008 increased approximately $2 million or 18% to approximately $13 million, compared to approximately $11 million in 2007. The increase is primarily due to higher volumes, and the $5.9 million in business interruptions insurance receipts offset by a 2008 charge of $7.7 million to reduce the carrying value of inventory.

Let me wrap up the financial overview by touching on capital structure and liquidity. At September 30, 2008, our funded debt level on a consolidated basis was approximately $1.4 billion. This level includes $640 million of debt at the MLP. This debt is non-recourse to Targa, but is consolidated along with the MLP, given our control of its general partner. Excluding the MLP debt, Targa's total funded debt was approximately $775 million.

On October 16th, 2008, we requested a $100 million funding under our senior secured revolving credit facility to increase our cash on hand in the face of the significant and continuing deterioration in the credit markets. Lehman Brothers Commercial Bank, a lender under our senior secured credit facility, defaulted on its portion of the borrowing request, which resulted in actual funding to us of $95.9 million. Proceeds from this borrowing are currently available to us as cash on hand. As a result of the Lehman default, we believe that the availability of the revolving credit facility has been effectively reduced by $10.2 million.

On the same date and for the same reason, the partnership requested a $100 million funding under its senior secured credit facility, and Lehman also defaulted on its portion of that borrowing request, resulting in proceeds to the partnership of $97.8 million, also currently available to it as cash on hand. As a result of the Lehman default, we believe that the availability of the partnership’s revolving credit facility has been effectively reduced by $9.5 million.

At October 31st, 2008 and excluding the partnership, Targa had approximately $271 million of cash, approximately $144 million of availability under the senior secured revolving credit facility, and approximately $121 million – $120 million available for the issuance of letters of credit under the Synthetic LC facility, bringing Targa’s total liquidity to approximately $535 million.

As of October 31, 2008, the partnership had approximately $130 million of cash, $313 million of availability of this revolver, bringing its total liquidity to approximately $443 million. These capital and liquidity highlights, along with our year-to-date operating results, underscored Targa’s solid financial footing, including substantial liquidity; meaningful headroom with respect to our financial covenants; no capital expenditure commitments that require external financing; and, with our earliest debt maturity in the fourth quarter of 2011, no refinancing requirements for approximately three years.

The partnership is also on solid financial footing with respect to the same elements, liquidity, financial covenants’ headroom, absence of external financing requirements, no debt maturities for over three years. And the partnership also reported solid distribution coverage for the quarter.

That wraps up the financial overview. So I’ll now turn the call back to Rene.

Rene Joyce

Thanks, Jeff. We continue to expand and to produce the acreage dedications and our gathering footprint with pipeline additions, direct connections, connections behind central delivery points, and with small pipeline acquisitions. Additionally, we are adding compression to support the producer needs across our gathering and processing systems. For example, we recently approved the $11 million in pipeline additions in North Texas to support additional Barnett Shale production near our Bryan Compressor Station in Wise County. And we should see the benefits of this project in the first quarter of next year.

We always have a number of processing and treating projects and process to improve recoveries or efficiencies. For example, an enhanced ethane recovery project and two acid gas injection wells are underway for our Permian operations.

Regarding our NGL business, we are evaluating an opportunity to expand our Mont Belvieu fractionator and potential projects to add new terminals and above ground storage to support our refinery services and wholesale propane business. The cogeneration facility at Mont Belvieu should be completed in the second quarter of ’09, and the grassroots propane storage facility supporting our West Coast business should be completed in the first quarter of ’09 also.

We received final FERC approval late this summer for the Floridian Gas Storage project, and development of that project continues.

Thank you for your time this afternoon. That concludes the formal part of the call. We will now open it up for your questions.

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