S-1/A 1 h40954a4sv1za.htm AMENDMENT NO. 4 TO FORM S-1 - REGISTRATION NO. 333-138747 sv1za
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As filed with the Securities and Exchange Commission on February 1, 2007
Registration No. 333-138747
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Amendment No. 4
to
 
Form S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
 
 
 
 
TARGA RESOURCES PARTNERS LP
(Exact name of registrant as specified in its charter)
 
 
 
         
Delaware   4922   65-1295427
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)
 
1000 Louisiana, Suite 4300
Houston, Texas 77002
(713) 584-1000
(Address, including zip code and telephone number, including area code, of registrant’s principal executive offices)
 
Rene R. Joyce
Chief Executive Officer
1000 Louisiana, Suite 4300
Houston, Texas 77002
(713) 584-1000
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
 
 
 
Copies to:
     
David P. Oelman
Christopher S. Collins
Vinson & Elkins LLP
1001 Fannin Street, Suite 2500
Houston, Texas 77002
(713) 758-2222
  Joshua Davidson
Douglass M. Rayburn
Baker Botts L.L.P.
910 Louisiana Street
Houston, Texas 77002
(713) 229-1234
 
 
 
Approximate date of commencement of proposed sale to the public:  As soon as practicable after this Registration Statement becomes effective.
 
 
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  o
 
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  o
 
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
 


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
 
Subject to Completion, dated February 1, 2007
PROSPECTUS
(TARGA LOGO)
 
TARGA RESOURCES PARTNERS LP
 
16,800,000 Common Units
Representing Limited Partner Interests
 
Targa Resources Partners LP is a limited partnership recently formed by Targa Resources, Inc. This is the initial public offering of our common units. All of the common units are being sold by us. Prior to this offering, there has been no public market for our common units. We expect the initial public offering price to be between $19.00 and $21.00 per unit. Our common units have been approved for listing on The NASDAQ Global Market under the symbol “NGLS.”
 
Investing in our common units involves risks. Please see “Risk Factors” beginning on page 17.
 
These risks include the following:
 
  •  We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.
 
  •  Our cash flow is affected by natural gas and natural gas liquid prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.
 
  •  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 natural gas liquids, which depends on certain factors beyond our control. Any decrease in supplies of natural gas or natural gas liquids could adversely affect our business and operating results.
 
  •  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. In addition, the significant contribution to our results of operations that we are currently receiving from our hedge positions will decrease substantially through 2010.
 
  •  We depend on one natural gas producer for a significant portion of our supply of natural gas. The loss of this customer or replacement of its contracts on less favorable terms could result in a decline in our volumes, revenues and cash available for distribution.
 
  •  Targa Resources, Inc. controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa Resources, Inc. has conflicts of interest with us and may favor its own interests to your detriment.
 
  •  Targa Resources, Inc. is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.
 
  •  Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
 
  •  You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
                 
    Per Common Unit     Total  
Public Offering Price
  $             $          
Underwriting Discount(1)
  $       $    
Proceeds to Targa Resources Partners LP (before expenses)(2)
  $       $  
 
(1)
Excludes an aggregate structuring fee equal to 0.4% of the gross proceeds of this offering, or approximately $1.3 million, payable to Citigroup Global Markets Inc., Goldman, Sachs & Co., UBS Securities LLC and Merrill Lynch & Co.
 
(2)
We will pay approximately $307.1 million of the proceeds we receive from this offering to Targa Resources, Inc. to retire a portion of our affiliate indebtedness.
 
 
We have granted the underwriters a 30-day option to purchase up to an additional 2,520,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 16,800,000 common units in this offering.
 
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 underwriters expect to deliver the common units through the facilities of The Depository Trust Company on or about          , 2007.
 
Citigroup        Goldman, Sachs & Co.        UBS Investment Bank        Merrill Lynch & Co.
 
A.G. Edwards  
  Credit Suisse  
  Lehman Brothers  
  Wachovia Securities
Raymond James  
  RBC Capital Markets  
  Sanders Morris Harris
 
          , 2007


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  166
  167
  170
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  F-1
  A-1
  B-1
 Specimen Unit Certificate
 Form of Indemnification Agreement
 Targa Resources Partners Long-Term Incentive Plan
 Form of Credit Agreement
 Form of Contribution Agreement
 Targa Resources Investments Inc. Long-Term Incentive Plan
 Subsidiaries
 Consent of PricewaterhouseCoopers LLP
 Consent of Robert B. Evans
 Consent of Chansoo Joung
 Consent of Barry R. Pearl
 Consent of William D. Sullivan
          
 
You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.
 
Until          , 2007 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


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SUMMARY
 
This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary may not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $20.00 per unit and (2) that the underwriters do not exercise their option to purchase additional units. You should read “Risk Factors” beginning on page 17 for more information about important risks that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix B. As used in this prospectus, unless we indicate otherwise: (1) “our,” “we,” “us” and similar terms refer to Targa Resources Partners LP, together with our subsidiaries, after giving effect to the Formation Transactions described on page 5 of this prospectus, (2) “Targa” refers to Targa Resources, Inc. and its subsidiaries and affiliates (other than us) and (3) references to our pro forma financial information refer to the historical financial information of the Predecessor Business described on page 13 of this prospectus as adjusted to give effect to the Formation Transactions.
 
Targa Resources Partners LP
 
We are a growth-oriented Delaware limited partnership recently formed by 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 currently operate in the Fort Worth Basin in north Texas and are engaged in the business of gathering, compressing, treating, processing and selling natural gas and fractionating and selling natural gas liquids, or NGLs, and NGL products. Fractionating means separating a mixed stream of NGLs into its constituent products. 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. At September 30, 2006, Targa had total assets of $3.4 billion, with the North Texas System to be contributed to us in connection with this offering representing $1.1 billion of this amount. Targa intends, but is not obligated, to offer us the opportunity to purchase substantially all of its remaining businesses.
 
Our operations consist of an extensive network of approximately 3,950 miles of integrated gathering pipelines that gather and compress natural gas received from approximately 2,650 receipt points in the Fort Worth Basin, two natural gas processing plants that compress, treat and process the natural gas and a fractionator that fractionates a portion of our raw NGLs produced in our processing operations into NGL products. These assets, together with the business conducted thereby, are collectively referred to as the “North Texas System.” We serve a fourteen-county natural gas producing region in the Fort Worth Basin that includes production from the Barnett Shale formation and other shallower formations, which are subsurface rock formations containing hydrocarbons, including the Bend Conglomerate, Caddo, Atoka, Marble Falls, and other Pennsylvanian and upper Mississippian formations, which we refer to as the “other Fort Worth Basin formations.” For more information on the North Texas System, please see “Business — Our Partnership”.
 
For the year ended December 31, 2005 and the nine months ended September 30, 2006, we generated pro forma net income (loss) of approximately $(6.8) million and $0.4 million, respectively, pro forma operating margin of $81.2 million and $67.8 million, respectively, and had 162.5 million cubic feet of natural gas per day, or MMcf/d, and 168.2 MMcf/d of gathering throughput, respectively. For the year ended December 31, 2005 and the nine months ended September 30, 2006, we generated approximately $72.8 million and $62.7 million of pro forma income before interest, income taxes, depreciation and amortization, or EBITDA, respectively.


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Non-GAAP Financial Measures
 
EBITDA.  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.
 
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.
 
Management compensates 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 management’s decision-making processes.
 
Operating Margin.  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, and 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 performance 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.
 
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 incorporating these learnings into 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;


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  •  our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure;
 
  •  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
 
                                                                   
    Predecessor Business     Targa Resources Partners LP  
    Dynegy       Targa     Pro Forma  
                Nine Months
    Ten Months
      Two Months
    Nine Months
          Nine Months
 
    Years Ended
    Ended
    Ended
      Ended
    Ended
    Year Ended
    Ended
 
    December 31,     September 30,
    October 31,
      December 31,
    September 30,
    December 31,
    September 30,
 
    2003     2004     2005     2005       2005     2006     2005     2006  
    (Audited)     (Audited)     (Unaudited)     (Audited)       (Audited)     (Unaudited)     (Unaudited)     (Unaudited)  
    (in millions of dollars)  
Reconciliation of “EBITDA” to net cash provided by (used in) operating activities:
                                                                 
Net cash provided by (used in) operating activities
  $ 31.3     $ 58.0     $ 59.2     $ 72.7       $ (1.5 )   $ 11.1                  
Allocated interest expense from parent(1)
                              10.7       50.5                  
Changes in operating working capital which provided (used) cash:
                                                                 
Accounts receivable
    0.7       (0.7 )     0.5       0.3         0.1       (0.4 )                
Accounts payable
    (1.0 )     (2.7 )     1.1       1.3         0.8                        
Other, including changes in noncurrent assets and liabilities
    (4.9 )     (3.8 )     (12.6 )     (17.1 )       5.5       1.5                  
                                                                   
EBITDA
  $ 26.1     $ 50.8     $ 48.2     $ 57.2       $ 15.6     $ 62.7                  
                                                                   
Reconciliation of “EBITDA” to net income:
                                                                 
Net income (loss)
  $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
Add:
                                                                 
Interest expense, net
                              11.5       54.4       24.8       18.6  
Deferred tax expense
                                    2.0             2.0  
Depreciation and amortization expense
    12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
                                                                   
EBITDA
  $ 26.1     $ 50.8     $ 48.2     $ 57.2       $ 15.6     $ 62.7     $ 72.8     $ 62.7  
                                                                   
Reconciliation of “operating margin” to net income:
                                                                 
Net income (loss)
  $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
Add:
                                                                 
Depreciation and amortization expense
    12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
Deferred income tax
                                    2.0             2.0  
Other, net
    0.6       0.3                                        
Interest expense, net
                              11.5       54.4       24.8       18.6  
General and administrative expense
    7.7       7.2       6.7       7.3         1.1       5.1       8.4       5.1  
                                                                   
Operating margin
  $ 34.4     $ 58.3     $ 54.9     $ 64.5       $ 16.7     $ 67.8     $ 81.2     $ 67.8  
                                                                   
 
(1)  Excludes non-cash amortization of debt issue costs of $0.8 million for the two months ended December 31, 2005 and $3.9 million for the nine months ended September 30, 2006.
 
Please see “Business — Strategies” and “Business — Competitive Strengths” for a discussion of our strategies and competitive strengths.


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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 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. We expect to have the opportunity to make acquisitions directly from Targa in the future. 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. Targa has retained such flexibility because it believes it is in the best interests of its shareholders to do so. 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 will 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.
 
Following this offering, Targa will continue to own interests in or operate approximately 6,680 miles of natural gas pipelines and approximately 720 miles of NGL pipelines, with natural gas gathering systems covering approximately 11,900 square miles and 20 natural gas processing plants with access to natural gas supplies in the Permian basin, onshore Louisiana and the Gulf of Mexico. Additionally, Targa has a significant, integrated NGL logistics and marketing business, with 13 storage, marine and transport terminals with an NGL storage capacity of 730 MBbls, net NGL fractionation capacity of approximately 287 thousand barrels per day, or MBbls/d, and 43 operated storage wells with a capacity of 103 MMBbls. These asset locations provide Targa access to relatively stable natural gas supplies and proximity to end-use markets and market hubs while positioning Targa to capitalize on growth opportunities from the continued development of onshore as well as deepwater and deep shelf Gulf of Mexico natural gas reserves and the increasing importation of liquified natural gas, or LNG, to the Gulf Coast.
 
Our Relationship with Warburg Pincus LLC
 
Warburg Pincus LLC, or Warburg Pincus, controls us through its ownership of securities in Targa Resources Investments Inc., the indirect parent of Targa, and a stockholders agreement among Targa Resources Investments Inc. and its owners. Warburg Pincus is a private equity firm and over four decades has invested more than $20 billion in 525 companies in 30 countries, representing a variety of industries including energy, information and communication technology, financial services, healthcare, media and business services and real estate.
 
Summary of Risk Factors
 
An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. Please see these and other risks described under “Risk Factors.”
 
Risks Related to Our Business
 
  •  We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.
 
  •  On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2005 or for the twelve months ended September 30, 2006.


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  •  Our cash flow is affected by natural gas and NGL prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.
 
  •  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 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. In addition, the significant contribution to our results of operations that we are currently receiving from our hedge positions will decrease substantially through 2010.
 
Risks Inherent in an Investment in Us
 
  •  Targa controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa has conflicts of interest with us and may favor its own interests to your detriment.
 
  •  The credit and business risk profile of our general partner and its owners could adversely affect our credit ratings and profile.
 
  •  Our partnership agreement limits our general partner’s fiduciary duties to holders of our units and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
  •  Targa is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.
 
Tax Risks to Common Unitholders
 
  •  Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
 
  •  If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the cost of any contest will reduce our cash available for distribution to you.
 
  •  You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
Formation Transactions and Partnership Structure
 
General
 
At the closing of this offering, we anticipate that the following transactions, which we refer to as the Formation Transactions, will occur:
 
  •  Targa will contribute the North Texas System to us;
 
  •  we will issue to Targa 11,528,231 subordinated units, representing a 39.9% limited partner interest in us;
 
  •  we will issue to our general partner, Targa Resources GP LLC, 578,127 general partner units representing its initial 2% general partner interest in us, and all of our incentive distribution rights,


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  which incentive distribution rights will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3881 per unit per quarter;
 
  •  we will issue 16,800,000 common units to the public in this offering, representing a 58.1% limited partner interest in us, and will use the proceeds to pay expenses associated with this offering, the Formation Transactions and our new credit facility and to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness;
 
  •  we will borrow approximately $342.5 million under our new $500 million credit facility, the proceeds of which will be paid to Targa to retire an additional portion of our affiliate indebtedness;
 
  •  the remaining affiliate indebtedness will be retired and treated as a capital contribution to us;
 
  •  we will enter into an omnibus agreement with Targa and our general partner, which will address, among other things, the provision of and the reimbursement for general and administrative and operating services;
 
  •  we will enter into a natural gas purchase agreement, pursuant to which we will sell all of our residue natural gas to Targa at market-based prices for a term of 15 years; and
 
  •  we will enter into NGL and condensate purchase agreements, pursuant to which we will sell all of our NGLs and high-pressure condensate to Targa at market-based prices for a term of 15 years.
 
Our affiliate indebtedness consists of borrowings incurred by Targa and allocated to us for financial reporting purposes as well as intercompany indebtedness to be contributed to us together with the North Texas System.
 
We will use any net proceeds from the exercise of the underwriters’ option to reduce outstanding borrowings under our new credit facility. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 19,320,000 common units, representing an aggregate 61.4% limited partner interest in us, the ownership interest of our general partner will increase to 629,555 general partner units, representing a 2% general partner interest in us, and the ownership interest of Targa will remain at 11,528,231 subordinated units, representing a 36.6% limited partner interest in us.
 
Management of Targa Resources Partners LP
 
Targa Resources GP LLC, our general partner, will manage our business and operations, and its board of directors and officers will make decisions on our behalf. All of the executive officers and some of the directors of Targa also serve as executive officers or directors of our general partner.
 
Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or its directors. Targa will elect all five members to the board of directors of our general partner and we will have three directors that are independent as defined under the independence standards established by The NASDAQ Global Market. For more information about these individuals, please see “Management — Directors and Executive Officers.”
 
The diagram on the following page depicts our organization and ownership after giving effect to the offering and the related Formation Transactions.


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Simplified Organizational Structure and Ownership of Targa Resources Partners LP
after the Formation Transactions
 
         
Public Common Units
    58.1 %
Targa Subordinated Units
    39.9 %
General Partner Units
    2.0 %
         
Total
    100.0 %
 
 
 
(1) Ownership percentages are presented on a fully-diluted basis.
 
(2) Targa Resources, Inc. is an indirect wholly-owned subsidiary of Targa Resources Investments Inc. Warburg Pincus LLC controls us through its ownership of securities in Targa Resources Investments Inc. and a stockholders agreement among Targa Resources Investments Inc. and its owners.
 


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Principal Executive Offices and Internet Address
 
Our principal executive offices are located at 1000 Louisiana, Suite 4300, Houston, Texas 77002 and our telephone number is (713) 584-1000. Our website is located at www.targaresources.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.
 
Summary of Conflicts of Interest and Fiduciary Duties
 
Targa Resources GP LLC, our general partner, has a legal duty to manage us in a manner beneficial to holders of our common units and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is owned by Targa, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to Targa. As a result of this relationship, conflicts of interest may arise in the future between us and holders of our common units and subordinated units, on the one hand, and our general partner and its affiliates on the other hand. Our partnership agreement also provides that Targa is not restricted from competing with us.
 
For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please see “Conflicts of Interest and Fiduciary Duties.”

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The Offering
 
Common units offered to the public 16,800,000 common units or 19,320,000 common units if the underwriters exercise in full their option to purchase additional common units.
 
Units outstanding after this offering 16,800,000 common units and 11,528,231 subordinated units, representing 58.1% and 39.9% limited partner interests in us (19,320,000 common units and 11,528,231 subordinated units, representing 61.4% and 36.6% limited partner interests in us if the underwriters exercise in full their option to purchase additional common units). The general partner will own 578,127 general partner units, or 629,555 general partner units if the underwriters exercise in full their option to purchase additional common units, in each case representing a 2% general partner interest in us.
 
Use of proceeds We intend to use the net proceeds of approximately $315.3 million from this offering (at an assumed offering price of $20.00 per common unit), after deducting underwriting discounts and deducting a structuring fee of approximately $1.3 million but before paying offering expenses, to:
 
• pay approximately $4.0 million in expenses associated with this offering and the Formation Transactions;
 
• pay approximately $4.2 million in fees and expenses related to our new credit facility; and
 
• use the remaining proceeds to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness.
 
We also expect to borrow approximately $342.5 million under our new credit facility upon the closing of this offering and to pay that amount to Targa to retire an additional portion of our affiliate indebtedness. The remaining balance of our affiliate indebtedness will be retired and treated as a capital contribution to us. Please see “Certain Relationships and Related Party Transactions — Distributions and Payments to our General Partner and its Affiliates.”
 
We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to reduce outstanding borrowings under our new credit facility.
 
Cash distributions We will make an initial quarterly distribution of $0.3375 per common unit ($1.35 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”
 
Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. Our


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partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter during the subordination period in the following manner:
 
• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.3375 plus any arrearages from prior quarters;
 
• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.3375; and
 
• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received an aggregate distribution of $0.3881.
 
If cash distributions to our unitholders exceed $0.3881 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please see “Provisions of Our Partnership Agreement Relating to Cash Distributions.”
 
We will adjust the quarterly distribution for the period from the closing of this offering through March 31, 2007 based on the actual length of the period. We expect to pay this cash distribution on or about May 15, 2007.
 
The amount of our pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended September 30, 2006 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units but only approximately 29% and 98%, respectively, of the minimum quarterly distribution on our subordinated units during these periods (28% and 97%, respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please see “Our Cash Distribution Policy and Restrictions on Distributions.”
 
We believe that, based on the minimum estimated EBITDA for the twelve months ending December 31, 2007 included under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash available for distribution to make cash distributions for the four quarters ending December 31, 2007 at the initial quarterly distribution rate of $0.3375 per unit on all common units, subordinated units and general partner units.
 
Subordinated units Targa will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.3375 per unit only after the common units have received the minimum quarterly distribution plus any


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arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. The subordination period generally will end if we have earned and paid at least $0.3375 on each outstanding unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2009. The subordination period will also end if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal.
 
When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
 
Early conversion of subordinated units If we have earned and paid at least $2.025 (150% of the annualized minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any four-quarter period, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please see “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”
 
General Partner’s right to reset the target distribution levels Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.
 
In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. For a more detailed description of our general partner’s right to reset the target distribution levels upon which the incentive distribution payments are based and the concurrent right of our general partner to receive Class B units in connection with this reset, please see “Provisions of Our


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Partnership Agreement Related to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”
 
Issuance of additional units We can issue an unlimited number of units without the consent of our unitholders. Please see “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
 
Limited voting rights Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 40.7% of our common and subordinated units. This will give our general partner the ability to prevent its involuntary removal. Please see “The Partnership Agreement — Voting Rights.”
 
Limited call right If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.
 
Estimated ratio of taxable income to distributions We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.35 per unit, we estimate that your average allocable federal taxable income per year will be no more than $0.27 per unit. Please see “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”
 
Material tax consequences For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please see “Material Tax Consequences.”
 
Exchange listing Our common units have been approved for listing on The NASDAQ Global Market under the symbol “NGLS.”


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Summary Historical and Pro Forma Financial and Operating Data
 
The following table shows summary historical financial and operating data of the North Texas System and pro forma financial data of Targa Resources Partners LP for the periods and as of the dates indicated. The historical financial statements included in this prospectus reflect the results of operations of the North Texas System to be contributed to us by Targa upon the closing of this offering. We refer to the results of operations of the North Texas System as the results of operations of the Predecessor Business. The summary historical financial data for the years ended December 31, 2003 and 2004, the ten-month period ended October 31, 2005 and for the two-month period ended December 31, 2005 are derived from the audited financial statements of the Predecessor Business. The summary historical financial data for the nine months ended September 30, 2005 and 2006 are derived from the unaudited financial statements of the Predecessor Business. The Predecessor Business was acquired by Targa as part of Targa’s acquisition of substantially all of Dynegy Inc.’s midstream business on October 31, 2005 (the “DMS Acquisition”). The summary pro forma financial data for the year ended December 31, 2005 and the nine months ended September 30, 2006 are derived from the unaudited pro forma financial statements of Targa Resources Partners LP included in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2006, in the case of the pro forma balance sheet, or as of January 1, 2005, in the case of the pro forma statement of operations for the nine months ended September 30, 2006 and for the year ended December 31, 2005. The transactions reflected in the pro forma adjustments assume the following actions will occur:
 
• Targa will contribute the North Texas System to us;
 
  •  we will issue to Targa 11,528,231 subordinated units, representing a 39.9% limited partner interest in us;
 
  •  we will issue to our general partner, Targa Resources GP LLC, 578,127 general partner units representing its initial 2% general partner interest in us, and all of our incentive distribution rights, which incentive distribution rights will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3881 per unit per quarter;
 
  •  we will issue 16,800,000 common units to the public in this offering, representing a 58.1% limited partner interest in us, and will use the proceeds to pay expenses associated with this offering, the Formation Transactions and our new credit facility and to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness;
 
  •  we will borrow approximately $342.5 million under our new $500 million credit facility the proceeds of which will be paid to Targa to retire an additional portion of our affiliate indebtedness; and
 
  •  the remaining affiliate indebtedness will be retired and treated as a capital contribution to us.
 
We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical combined and pro forma condensed financial statements and the accompanying notes included elsewhere in this prospectus.
 


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    Predecessor Business     Targa Resources Partners LP  
    Dynegy       Targa     Pro Forma  
                Nine Months
    Ten Months
      Two Months
    Nine Months
          Nine Months
 
    Years Ended
    Ended
    Ended
      Ended
    Ended
    Year Ended
    Ended
 
    December 31,     September 30,
    October 31,
      December 31,
    September 30,
    December 31,
    September 30,
 
    2003     2004     2005     2005       2005     2006     2005     2006  
    (Audited)     (Audited)     (Unaudited)     (Audited)       (Audited)     (Unaudited)     (Unaudited)     (Unaudited)  
    (in millions of dollars, except per unit and operating data)  
Statement of Operations Data:
                                                                 
Total operating revenues
  $ 196.8     $ 258.6     $ 249.7     $ 293.3       $ 75.1     $ 290.9     $ 368.4     $ 290.9  
Product purchases
    147.3       182.6       179.0       210.8         54.9       205.2       265.7       205.2  
Operating expense
    15.1       17.7       15.8       18.0         3.5       17.9       21.5       17.9  
Depreciation and amortization expense
    12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
General and administrative expense
    7.7       7.2       6.7       7.3         1.1       5.1       8.4       5.1  
Interest expense, net
                              11.5       54.4       24.8       18.6  
Deferred income tax(1)
                                    2.0             2.0  
Other, net
    0.6       0.3                                        
                                                                   
Net income (loss)
  $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
                                                                   
Pro forma net income (loss) per limited partner unit
                                                    $ (0.24 )   $ 0.01  
Financial and Operating Data:
                                                                 
Financial data:
                                                                 
Operating margin(2)
  $ 34.4     $ 58.3     $ 54.9     $ 64.5       $ 16.7     $ 67.8     $ 81.2     $ 67.8  
EBITDA(3)
    26.1       50.8       48.2       57.2         15.6       62.7       72.8       62.7  
Operating data:
                                                                 
Gathering throughput, MMcf/d(4)
    134.3       152.0       160.4       161.2         168.8       168.2                  
Plant natural gas inlet, MMcf/d(5)
    128.6       145.4       155.4       156.2         161.9       161.6                  
Gross NGL production, MBbl/d
    15.9       17.2       18.4       18.5         19.8       18.8                  
Natural gas sales, BBtu/d
    42.0       59.2       68.4       68.9         72.3       75.2                  
NGL sales, MBbl/d
    15.3       13.2       14.2       14.3         15.4       15.1                  
Condensate sales, MBbl/d
    0.6       0.7       0.5       0.5         0.5       0.5                  
Balance Sheet Data (at period end):
                                                                 
Property, plant, and equipment, net
  $ 180.4     $ 191.2       195.4     $ 196.4       $ 1,097.0     $ 1,073.0             $ 1,073.0  
Total assets
    182.9       193.5       197.6       198.5         1,122.8       1,126.3               1,110.9  
Long-term debt (including current portion)
                              868.9       865.2               342.5  
Partners’ capital / Net parent equity
    164.8       168.8       161.9       158.5         219.5       227.2               734.5  
Cash Flow Data:
                                                                 
Net cash provided by (used in):
                                                                 
Operating activities
  $ 31.3     $ 58.0     $ 59.2     $ 72.7       $ (1.5 )   $ 11.1                  
Investing activities
    (14.6 )     (23.4 )     (14.2 )     (16.4 )       (2.1 )     (17.7 )                
Financing activities
    (16.7 )     (34.6 )     (45.0 )     (56.3 )       3.6       6.6                  
 
 
(1)  In May 2006, Texas adopted a margin tax consisting of a 1% tax on the amount by which total revenue exceeds cost of goods sold. The amount presented represents our estimated liability for this tax.
 
(2)  Operating margin is total operating revenues less product purchases and operating expense. Please see “— Non-GAAP Financial Measures.”
 
(3)  EBITDA is net income before interest, income taxes, depreciation and amortization. Please 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 point of a natural gas processing plant.

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Non-GAAP Financial Measures
 
EBITDA.  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.
 
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.
 
Management compensates 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 management’s decision-making processes.
 
Operating Margin.  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, and 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 performance 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.
 
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 incorporating these learnings into 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;


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  •  our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure;
 
  •  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
 
                                                                   
    Predecessor Business     Targa Resources Partners LP  
    Dynegy       Targa     Pro Forma  
                Nine Months
    Ten Months
      Two Months
    Nine Months
          Nine Months
 
    Years Ended
    Ended
    Ended
      Ended
    Ended
    Year Ended
    Ended
 
    December 31,     September 30,
    October 31,
      December 31,
    September 30,
    December 31,
    September 30,
 
    2003     2004     2005     2005       2005     2006     2005     2006  
    (Audited)     (Audited)     (Unaudited)     (Audited)       (Audited)     (Unaudited)     (Unaudited)     (Unaudited)  
    (in millions of dollars)  
Reconciliation of “EBITDA” to net cash provided by (used in) operating activities:
                                                                 
Net cash provided by (used in) operating activities
  $ 31.3     $ 58.0     $ 59.2     $ 72.7       $ (1.5 )   $ 11.1                  
Allocated interest expense from parent(1)
                              10.7       50.5                  
Changes in operating working capital which provided (used) cash:
                                                                 
Accounts receivable
    0.7       (0.7 )     0.5       0.3         0.1       (0.4 )                
Accounts payable
    (1.0 )     (2.7 )     1.1       1.3         0.8                        
Other, including changes in noncurrent assets and liabilities
    (4.9 )     (3.8 )     (12.6 )     (17.1 )       5.5       1.5                  
                                                                   
EBITDA
  $ 26.1     $ 50.8     $ 48.2     $ 57.2       $ 15.6     $ 62.7                  
                                                                   
Reconciliation of “EBITDA” to net income:
                                                                 
Net income (loss)
  $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
Add:
                                                                 
Interest expense, net
                              11.5       54.4       24.8       18.6  
Deferred tax expense
                                    2.0             2.0  
Depreciation and amortization expense
    12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
                                                                   
EBITDA
  $ 26.1     $ 50.8     $ 48.2     $ 57.2       $ 15.6     $ 62.7     $ 72.8     $ 62.7  
                                                                   
Reconciliation of “operating margin” to net income:
                                                                 
Net income (loss)
  $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
Add:
                                                                 
Depreciation and amortization expense
    12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
Deferred income tax
                                    2.0             2.0  
Other, net
    0.6       0.3                                        
Interest expense, net
                              11.5       54.4       24.8       18.6  
General and administrative expense
    7.7       7.2       6.7       7.3         1.1       5.1       8.4       5.1  
                                                                   
Operating margin
  $ 34.4     $ 58.3     $ 54.9     $ 64.5       $ 16.7     $ 67.8     $ 81.2     $ 67.8  
                                                                   
 
(1)  Excludes non-cash amortization of debt issue costs of $0.8 million for the two months ended December 31, 2005 and $3.9 million for the nine months ended September 30, 2006.


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RISK FACTORS
 
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
 
If any of the following risks were actually to occur, then our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.
 
Risks Related to Our Business
 
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.
 
In order to make our cash distributions at our initial distribution rate of $0.3375 per common unit and subordinated unit per complete quarter, or $1.35 per unit per year, we will require available cash of approximately $9.8 million per quarter, or $39.0 million per year, based on the common units and subordinated units outstanding immediately after completion of this offering ($10.6 million or $42.5 million, respectively, if the underwriters exercise in full their option to purchase additional common units). We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
  •  the fees we charge and the margins we realize for our services;
 
  •  the prices of, levels of production of, and demand for, natural gas and natural gas liquids, or NGLs;
 
  •  the volume of natural gas we gather, treat, compress, process, transport and sell, and the volume of NGLs we process or fractionate and sell;
 
  •  the relationship between natural gas and NGL prices;
 
  •  cash settlements of hedging positions;
 
  •  the level of competition from other midstream energy companies;
 
  •  the level of our operating and maintenance and general and administrative costs; and
 
  •  prevailing economic conditions.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:
 
  •  the level of capital expenditures we make;
 
  •  our ability to make borrowings under our credit facility to pay distributions;
 
  •  the cost of acquisitions;
 
  •  our debt service requirements and other liabilities;
 
  •  fluctuations in our working capital needs;
 
  •  general and administrative expenses, including expenses we will incur as a result of being a public company;


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  •  restrictions on distributions contained in our debt agreements; and
 
  •  the amount of cash reserves established by our general partner for the proper conduct of our business.
 
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please see “Our Cash Distribution Policy and Restrictions on Distributions.”
 
On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2005 or for the twelve months ended September 30, 2006.
 
The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of our units to be outstanding immediately after this offering is approximately $39.0 million. The amount of our pro forma available cash generated during the year ended December 31, 2005 and the twelve months ended September 30, 2006 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units but only approximately 29% and 98%, respectively, of the minimum quarterly distribution on our subordinated units during these periods (28% and 97% respectively, assuming the underwriters exercise in full their option to purchase additional common units). For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please see “Our Cash Distribution Policy and Restrictions on Distributions.”
 
Our cash flow is affected by natural gas and NGL prices, and decreases in these prices could adversely affect our ability to make distributions to holders of our common units and subordinated units.
 
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 forward month contract in 2005 ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu. In the first nine months of 2006, NYMEX pricing ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu. Natural gas prices reached relatively high levels in 2005 and early 2006 but have declined substantially through the first three quarters of 2006, with the forward month gas futures contracts closing at a four-year low in September of 2006. NGL prices exhibit similar volatility. Based on monthly index prices, the average price for our NGL composition ranged from a high of $1.12 per gallon to a low $0.73 per gallon in 2005, and from a high of $1.14 per gallon to a low of $0.88 per gallon for the first nine months of 2006.
 
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.


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Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For the nine month period ended September 30, 2006, our percent-of-proceeds arrangements accounted for approximately 96% of our gathered natural gas volume. Under percent-of-proceeds arrangements, we generally process natural gas from producers for an agreed percentage of the proceeds from the sale of residue gas and NGLs resulting from our processing activities, selling the resulting residue gas and NGLs at market prices. 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 crude oil fluctuates. 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 — Commodity Price Risk.”
 
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 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. 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. We believe that rig availability in the Fort Worth Basin has been and will continue to be a limiting factor on the number of wells drilled in that area. 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. Natural gas prices reached relatively high levels in 2005 and early 2006 but have declined substantially through the first three quarters of 2006, with gas futures contracts closing at a four-year low in September of 2006. These recent declines in natural gas prices are beginning to have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. 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 and impair our ability to make distributions to our unitholders.
 
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. In addition, the significant contribution to our results of operations that we are currently receiving from our hedge positions will decrease substantially through 2010.
 
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


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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 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. 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.
 
Our results of operations are currently realizing a significant benefit from hedge positions entered into in April and May of 2006. We estimate that our hedges will generate approximately $15 million in operating income for the twelve months ending December 31, 2007. If future prices remain comparable to current prices, we expect that this benefit will decline materially over the life of the hedges, which cover decreasing volumes at declining prices through 2010. 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.”
 
The assumptions underlying the minimum estimated EBITDA we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
 
The minimum estimated EBITDA set forth in “Our Cash Distribution Policy and Restrictions on Distributions” presents our ability to make the minimum quarterly distribution for the twelve months ending December 31, 2007. Our minimum estimated EBITDA and related assumptions have been prepared by, and are the responsibility of, management and our independent auditor has neither compiled nor examined our minimum estimated EBITDA and provides no assurance nor any report on it. The assumptions underlying our minimum estimated EBITDA are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve our anticipated results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.
 
We depend on one natural gas producer for a significant portion of our supply of natural gas. The loss of this customer or replacement of its contracts on less favorable terms could result in a decline in our volumes, revenues and cash available for distribution.
 
Our largest natural gas supplier for the year ended December 31, 2005 and the nine months ended September 30, 2006 was ConocoPhillips, who accounted for approximately 36% and 34%, respectively, of our supply. The loss of all or even a portion of the natural gas volumes supplied by this customer or the extension or replacement of these contracts on less favorable terms, if at all, as a result of competition or otherwise, could reduce our revenue or increase our cost for product purchases, impairing our ability to make distributions to our unitholders.
 
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 and cash available for distribution could be adversely affected.
 
We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation 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, our revenues and cash available for distribution could be adversely affected.


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We depend on our Chico system for a substantial majority of our revenues and if those revenues were reduced, there would be a material adverse effect on our results of operations and ability to make distributions to unitholders.
 
Any significant curtailment of gathering, compressing, treating, processing or fractionation of natural gas on our Chico system could result in our realizing materially lower levels of revenues and cash flow for the duration of such curtailment. For the nine months ended September 30, 2006, our Chico plant inlet volume accounted for over 90% of our revenues. Operations at our Chico system could be partially curtailed or completely shut down, temporarily or permanently, as a result of:
 
  •  competition from other systems that may be able to meet producer needs or supply end-user markets on a more cost-effective basis;
 
  •  operational problems such as catastrophic events at the Chico processing plant or gathering lines, labor difficulties or environmental proceedings or other litigation that compel cessation of all or a portion of the operations on our Chico system;
 
  •  an inability to obtain sufficient quantities of natural gas for the Chico system at competitive terms; or
 
  •  reductions in exploration or production activity, or shut-ins by producers in the areas in which we operate.
 
The magnitude of the effect on us of any curtailment of operations will depend on the length of the curtailment and the extent of the operations affected by such curtailment. We have no control over many of the factors that may lead to a curtailment of operations.
 
In addition, our business interruption insurance is subject to limitations and deductions. If a significant accident or event occurs at our Chico system that is not fully insured, it could adversely affect our operations and financial condition.
 
We are exposed to the credit risk of Targa and any material nonperformance by Targa could reduce our ability to make distributions to our unitholders.
 
At the closing of this offering, we will enter into purchase agreements with Targa pursuant to which Targa will purchase all of our natural gas, NGLs and high-pressure condensate for a term of 15 years. We will also enter into an omnibus agreement with Targa which will address, among other things, the provision of general and administrative and operating services to us. As of January 31, 2007, Moody’s and Standard & Poor’s assigned Targa corporate credit ratings of B1 and B+, respectively, which are speculative ratings. These speculative ratings signify a higher risk that Targa will default on its obligations, including its obligations to us, than does an investment grade credit rating. Any material nonperformance under the omnibus and purchase agreements by Targa could materially and adversely impact our ability to operate and make distributions to our unitholders.
 
Our general partner is an obligor under, and subject to a pledge related to, Targa’s credit facility; in the event Targa is unable to meet its obligations under that facility, or is declared bankrupt, Targa’s lenders may gain control of our general partner or, in the case of bankruptcy, our partnership may be dissolved.
 
Our general partner is an obligor under, and all of its assets and Targa’s ownership interest in it are subject to a lien related to, Targa’s credit facility. In the event Targa is unable to satisfy its obligations under the credit facility and the lenders foreclose on their collateral, the lenders will own our general partner and all of its assets, which include the general partner interest in us and our incentive distribution rights. In such event, the lenders would control our management and operation. Moreover, in the event Targa becomes insolvent or is declared bankrupt, our general partner may be deemed insolvent or declared bankrupt as well. Under the terms of our partnership agreement, the bankruptcy or insolvency of our general partner will cause a dissolution of our partnership.


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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 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 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.
 
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, our operations and financial results could be adversely affected.
 
Our operations are subject to many hazards inherent in the gathering, compressing, treating, processing and transporting of natural gas and NGLs, including:
 
  •  damage to pipelines and plants, 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. Our insurance is provided under Targa’s insurance programs. 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, it could adversely affect our operations and financial condition. In addition, Targa may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Moreover, significant claims by Targa may limit or eliminate the amount of insurance proceeds available to us. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially, and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.
 
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
 
At the closing of this offering, we will borrow approximately $342.5 million under our new credit facility. Our level of debt could have important consequences for us, 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;


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  •  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, future business opportunities and distributions to unitholders;
 
  •  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 responding to changing business and economic conditions.
 
Our ability to service our debt 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 distributions, 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 Operations — Liquidity and Capital Resources — Capital Requirements.”
 
Increases in interest rates could adversely affect our business.
 
In addition to our exposure to commodity prices, we will have significant exposure to increases in interest rates. After this offering, we expect to have approximately $342.5 million of debt on a pro forma basis at variable interest rates. An increase of 1 percentage point in the interest rates will result in an increase in annual interest expense of $3.4 million. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.
 
Restrictions in our credit facility may interrupt distributions to us from our subsidiaries, which may limit our ability to make distributions to you, satisfy our obligations and capitalize on business opportunities.
 
We are a holding company with no business operations. As such, we depend upon the earnings and cash flow of our subsidiaries and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders. In connection with this offering, we expect to enter into a new credit facility which will contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, and engage in transactions with affiliates. Furthermore, our credit facility will contain covenants requiring us to maintain a ratio of consolidated indebtedness to consolidated EBITDA initially of not more than 5.75 to 1.00 and a ratio of consolidated EBITDA to consolidated interest expense of not less than 2.25 to 1.00. If we fail to meet these tests or otherwise breach the terms of our credit facility our operating subsidiary will be prohibited from making any distribution to us and, ultimately, to you. Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to make distributions to you.
 
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 operations are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations 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 discharge of waste from our facilities and (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 locations to which we have sent waste for disposal. 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 regulations,


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including CERCLA and analogous state laws and regulations, 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 the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions 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 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 these costs from insurance. Please see “Business — Environmental Matters.”
 
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 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, financial condition and our ability to make cash distributions to you.
 
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.
 
Our natural gas gathering operations 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 these 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, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. 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 natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of regular litigation; accordingly, the classification and regulation of some of our intrastate pipelines may be subject to change based on future determinations by FERC, the courts or Congress.
 
State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take 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 Railroad Commission of Texas, or TRRC, has adopted regulations that generally allow natural gas producers and shippers to file complaints with the TRRC in an effort to resolve grievances relating to intrastate pipeline access and rate discrimination. Our natural gas gathering operations could be


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adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to 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. Other state and local regulations also may affect our business. See “Business — Regulation of Operations.”
 
Our costs may increase because our credit obligations under hedging and other contractual arrangements will not be guaranteed by Targa.
 
Prior to the completion of this offering, Targa maintains credit support for our obligations related to derivative financial instruments, such as commodity price hedging contracts. Beginning with the closing of this offering, Targa will no longer provide credit support for our obligations under derivative financial instruments and other commercial contracts governing our business or operations. Consequently, we will need to provide our own credit support arrangements for commercial contracts, which may increase our costs. For example, it could be more costly for us to manage our commodity price risk through certain types of financial hedging arrangements unless we are able to achieve creditworthiness similar to the current creditworthiness of Targa.
 
All of our operations are based in the Fort Worth Basin and we are dependent on drilling activities and our ability to attract and maintain customers in such region.
 
All of our operations are located in the Fort Worth Basin in north Texas. Due to our lack of diversification in industry type and location, an adverse development in the oil and gas production from this area would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
 
Under the terms of our gas sales agreement, Targa will manage the sales of our natural gas and will pay us the amount it realizes for gas sales less certain costs; however, unexpected volume changes due to production variability or to gathering, plant, or pipeline system disruptions may increase our exposure to commodity price movements.
 
Targa will sell our processed natural gas to third parties and other Targa affiliates at our plant tailgate or at interstate pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted by disruptions to volumes anywhere along the system. Targa will attempt to balance sales with volumes supplied from our processing operations, but unexpected volume variations due to production variability or to gathering, plant, or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements in commodity prices, could materially impact our income from operations, and cash flow.
 
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 pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators 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;


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  •  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 $1 million between 2006 and 2010 to implement pipeline integrity management program testing along certain segments of our natural gas and NGL pipelines. This 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.
 
Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.
 
One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a new pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
 
If we do not make acquisitions on economically acceptable terms, or efficiently and effectively integrate the acquired assets with our asset base, our future growth will be limited.
 
Our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited.
 
Any acquisition involves potential risks, including, among other things:
 
  •  mistaken assumptions about volumes, revenues and costs, including synergies;
 
  •  an inability to integrate successfully the businesses we acquire;
 
  •  the assumption of unknown liabilities;
 
  •  limitations on rights to indemnity from the seller;
 
  •  mistaken assumptions about the overall costs of equity or debt;
 
  •  the diversion of management’s and employees’ attention from other business concerns;


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  •  unforeseen difficulties operating in new product areas or new geographic areas; and
 
  •  customer or key employee losses at the acquired businesses.
 
If these risks materialize, the acquired assets may inhibit our growth or fail to deliver expected benefits.
 
Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.
 
We do not own all 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, reduce our revenue and impair our ability to make distributions to our unitholders.
 
We do not have any officers or employees and rely solely on officers of our general partner and employees of Targa.
 
None of the officers of our general partner are employees of our general partner. We intend to enter into an omnibus agreement with Targa, pursuant to which Targa will operate our assets and perform other administrative services for us such as accounting, legal, regulatory, corporate development, finance, land and engineering. Affiliates of Targa conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to Targa. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and Targa. If the officers of our general partner and the employees of Targa do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
 
If our general partner fails to develop or maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.
 
Targa Resources GP LLC, our general partner, has sole responsibility for conducting our business and for managing our operations. Effective internal controls are necessary for our general partner, on our behalf, to provide reliable financial reports, prevent fraud and operate us successfully as a public company. If our general partner’s efforts to develop and maintain its internal controls are not successful, it is unable to maintain adequate controls over our financial processes and reporting in the future or it is unable to assist us in complying with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.
 
The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability. Consequently, even if we are profitable, we may not be able to make cash distributions to holders of our common units and subordinated units.
 
You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we


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may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
 
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.
 
Risks Inherent in an Investment in Us
 
Targa controls our general partner, which has sole responsibility for conducting our business and managing our operations. Targa has conflicts of interest with us and may favor its own interests to your detriment.
 
Following this offering, Targa will own and control our general partner. Some of our general partner’s directors, and some of its executive officers, are directors or officers of Targa. Therefore, conflicts of interest may arise between Targa, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
 
  •  neither our partnership agreement nor any other agreement requires Targa to pursue a business strategy that favors us. Targa’s directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Targa, which may be contrary to our interests;
 
  •  our general partner is allowed to take into account the interests of parties other than us, such as Targa, or its owners, including Warburg Pincus, in resolving conflicts of interest; and
 
  •  Targa is not limited in its ability to compete with us and is under no obligation to offer assets to us; please see “— Targa is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses” below.
 
Please see “Conflicts of Interest and Fiduciary Duties.”
 
The credit and business risk profile of our general partner and its owners could adversely affect our credit ratings and profile.
 
The credit and business risk profiles of the general partner and its owners may be factors in credit evaluations of a master limited partnership. This is because the general partner can exercise significant influence over the business activities of the partnership, including its cash distribution and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of the general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.
 
Targa, the owner of our general partner, has significant indebtedness outstanding and is partially dependent on the cash distributions from their indirect general partner and limited partner equity interests


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in us to service such indebtedness. Any distributions by us to such entities will be made only after satisfying our then current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.
 
Our partnership agreement limits our general partner’s fiduciary duties to holders of our units and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Targa. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
 
  •  permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;
 
  •  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
 
  •  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
 
  •  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
 
  •  provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 
If you purchase any common units, you will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please see “Conflicts of Interests and Fiduciary Duties — Fiduciary Duties.”
 
Targa is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.
 
Neither our partnership agreement nor the omnibus agreement between us and Targa will prohibit Targa from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Targa may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Targa is a large, established participant in the midstream energy business, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with Targa with respect to commercial activities as well as for acquisition candidates. As a result, competition from Targa


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could adversely impact our results of operations and cash available for distribution. Please see “Conflicts of Interest and Fiduciary Duties.”
 
Cost reimbursements due our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.
 
Pursuant to an omnibus agreement we will enter into with Targa Resources GP LLC, our general partner and others upon the closing of this offering, Targa will receive reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please see “Certain Relationships and Related Party Transactions — Omnibus Agreement.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify our general partner. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.
 
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or our general partner’s board of directors, and will have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner will be chosen by Targa. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
 
The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner and its affiliates will own 40.7% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.


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We may issue additional units without your approval, which would dilute your existing ownership interests.
 
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •  our unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available for distribution on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
  •  the ratio of taxable income to distributions may increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
 
Affiliates of our general partner may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
 
After the sale of the common units offered hereby, management of our general partner and Targa will hold no common units and 11,528,231 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.
 
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or holders of our common units. This ability may result in lower distributions to holders of our common units in certain situations.
 
Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.
 
In connection with resetting these target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount


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of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please see “Provisions of Our Partnership Agreement Related to Cash Distributions — General Partner Interest and Incentive Distribution Rights.”
 
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, for expansion capital expenditures or for other purposes.
 
As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, for expansion capital expenditures or for other purposes.
 
We will incur increased costs as a result of being a publicly-traded company.
 
We have no history operating as a publicly-traded company. As a publicly-traded company, we will incur significant legal, accounting and other expenses that we would not incur as a private company. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and The NASDAQ Global Market, have required changes in corporate governance practices of publicly-traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded company, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly-traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included $2.5 million of estimated incremental costs per year associated with being a publicly-traded company for purposes of our financial forecast included elsewhere in this prospectus; however, it is possible that our actual incremental costs of being a publicly-traded company will be higher than we currently estimate.
 
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
 
Control of our general partner may be transferred to a third party without unitholder consent.
 
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.


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Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
 
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 40.7% of our aggregate outstanding common units. For additional information about this right, please see “The Partnership Agreement — Limited Call Right.”
 
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in Texas. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if:
 
  •  a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
 
For a discussion of the implications of the limitations of liability on a unitholder, please see “The Partnership Agreement — Limited Liability.”
 
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
 
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
 
Tax Risks to Common Unitholders
 
In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.


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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
 
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, margin, franchise and other forms of taxation. For example, beginning in 2008, we will be subject to a new entity level tax (imposed at a maximum effective rate of 0.7%) on the portion of our income that is generated in Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to you. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
 
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the cost of any contest will reduce our cash available for distribution to you.
 
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
 
You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
 
Tax gain or loss on disposition of our common units could be more or less than expected.
 
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common


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unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
 
Tax-exempt entities and foreign persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a foreign person, you should consult your tax advisor before investing in our common units.
 
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please see “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election.”
 
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
 
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please see “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.
 
You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
 
In addition to federal income taxes, you might be subject to return filing requirements and other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, now or in the future, even if you do not live in any of those jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and conduct business in the State of Texas. Currently, Texas does not impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or do business in states that impose a personal income tax. It is your responsibility to file all United States federal, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in our common units.


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USE OF PROCEEDS
 
We expect to receive net proceeds from this offering of approximately $315.3 million, after deducting underwriting discounts and deducting a structuring fee of approximately $1.3 million but before paying offering expenses. We base this amount on an assumed initial public offering price of $20.00 per common unit. We anticipate using the aggregate net proceeds of this offering to:
 
  •  pay approximately $4.0 million in expenses associated with this offering and the Formation Transactions;
 
  •  pay approximately $4.2 million in fees and expenses related to our new credit facility; and
 
  •  use the remaining proceeds to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness.
 
The structuring fee will be paid to Citigroup Global Markets Inc., Goldman, Sachs & Co., UBS Securities LLC and Merrill Lynch & Co. for evaluation, analysis and structuring of our partnership. We also expect to borrow approximately $342.5 million under our new credit facility upon the closing of this offering and to pay that amount to Targa to retire an additional portion of our affiliate indebtedness. The remaining balance of our affiliate indebtedness will be retired and treated as a capital contribution to us. Please see “Certain Relationships and Related Party Transactions — Distributions and Payments to our General Partner and its Affiliates.” The affiliate indebtedness to be repaid with proceeds of this offering and borrowings under our new credit facility will be contributed to us in connection with the Formation Transactions, is due December 31, 2007 and bears interest at a rate of 10% per annum.
 
We will use any net proceeds from the exercise of the underwriters’ option to purchase additional common units to reduce outstanding borrowings under our new credit facility. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 19,320,000 common units representing an aggregate 61.4% limited partner interest in us and the ownership interest of our general partner will increase to 629,555 general partner units representing a 2% general partner interest in us.
 
An increase or decrease in the assumed public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and commissions and offering expenses payable by us, to increase or decrease by approximately $15.8 million.


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CAPITALIZATION
 
The following table shows:
 
  •  the cash and capitalization of the Predecessor Business as of September 30, 2006; and
 
  •  our pro forma cash and capitalization as of September 30, 2006, as adjusted to reflect this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure — General” and the application of the net proceeds from this offering as described under “Use of Proceeds.”
 
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of the pro forma adjustments, please see our Unaudited Pro Forma Condensed Balance Sheet.
 
                 
    As of September 30,
 
    2006  
    Historical     Pro Forma  
    (in millions of dollars)  
 
Cash
  $     $  
                 
Long-term debt:
               
Credit facility
          342.5  
Affiliate debt (including current portion)(1)
    865.2        
                 
Total long-term debt
    865.2       342.5  
                 
Partners’ capital(2)(3):
               
Predecessor Business
    194.8        
Common units — public
          311.3  
Subordinated units — sponsor
          372.8  
General partner interest
          18.7  
                 
Total partners’ capital
    194.8       702.8  
                 
Total capitalization
  $ 1,060.0     $ 1,045.3  
                 
 
 
(1) Affiliate debt presented above represents indebtedness incurred by Targa in connection with the DMS Acquisition that has been allocated to the North Texas System. In connection with this offering, a portion of the affiliate indebtedness will be repaid and the remainder will be retired and treated as a capital contribution to us. Please see “Use of Proceeds.”
 
(2) Assumes a public offering price of our common units of $20.00 per unit and reflects partner capital of common unitholders from the net proceeds of this offering of approximately $311.3 million, including approximately $24.7 million of underwriters’ discounts, fees and other offering expenses payable by us and the application of the proceeds as described in “Use of Proceeds.” A $1.00 increase (decrease) in the assumed public offering price per common unit would increase (decrease) the net proceeds by $15.8 million, and would result in a corresponding increase (decrease) in net proceeds to be used to retire indebtedness, and therefore would not change our total partners’ capital, assuming the number of common units offered by us, as set forth on the cover page of this prospectus, remains the same. The pro forma information discussed above is illustrative only and following completion of this offering will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.
 
(3) Partners’ capital as presented above excludes accumulated other comprehensive income.
 
This table does not reflect the issuance of up to 2,520,000 common units that may be sold to the underwriters upon exercise of their option to purchase additional units.


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DILUTION
 
Dilution or accretion is the difference between the offering price paid by the purchasers of common units sold in this offering and the pro forma net tangible book value per unit after the offering. Assuming an initial public offering price of $20.00, which is the midpoint of the estimated initial public offering price range per common unit in this offering, on a pro forma basis as of September 30, 2006, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value would be $730.3 million, or $25.26 per common unit. Net tangible book value excludes $4.2 million of net intangible assets. Purchasers of common units in this offering will experience an immediate accretion in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:
 
                 
Assumed initial public offering price per common unit
          $ 20.00  
Net tangible book value per unit before the offering(1)
  $ 17.21          
Increase in net tangible book value per common unit attributable to purchasers in the offering
    8.05          
                 
Pro forma net tangible book value per common unit after the offering(2)
            25.26  
                 
Immediate dilution (accretion) in tangible net book value per common unit to new investors(3)
          $ (5.26 )
                 
 
 
(1)  Determined by dividing the number of units (11,528,231 subordinated units and 578,127 general partner units) to be issued to Targa for its contribution of the North Texas System into the net tangible book value of the North Texas System before the offering.
 
(2)  Determined by dividing the total number of limited partner units and general partner units to be outstanding after the offering (16,800,000 common units, 11,528,231 subordinated units and 578,127 general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.
 
(3)  If the initial public offering price were to increase or decrease by $1.00 per common unit, immediate dilution (accretion) in tangible net book value per common unit would not change after giving effect to the corresponding change in our pro forma use of proceeds.
 
The following table sets forth the number of units that we will issue and the total consideration contributed to us by Targa and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:
 
                                 
    Units Acquired     Total Consideration  
    Number     Percent     Amount     Percent  
 
Equity contribution by Targa(1)(2)
    12,106,358       41.9 %   $ 391,500,000       53.8 %
New investors cash contribution
    16,800,000       58.1 %     336,000,000       46.2 %
                                 
Total
    28,906,358       100.0 %   $ 727,500,000       100.0 %
                                 
 
 
(1)  The units acquired by Targa and its affiliates consist of 11,528,231 subordinated units and 578,127 general partner units.
 
(2)  The North Texas System contributed by Targa is reflected at Targa’s historical net carrying value subsequent to recording the step up in property, plant and equipment at fair value in connection with the DMS Acquisition. Related acquisition indebtedness of Targa was also recognized and is reflected in partners’ capital. See the historical financial statements and related notes of the Predecessor Business for a discussion of the DMS Acquisition.


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The table below shows the net investment of Targa in us after giving effect to this offering and the Formation Transactions. Please see our Unaudited Pro Forma Balance Sheet on page F-3 for a more complete presentation of the adjustments associated with this offering and the Formation Transactions.
 
                 
    (in millions
 
    of dollars)  
 
Total partners’ capital excluding accumulated other comprehensive income as of September 30, 2006
          $ 194.8  
Affiliate debt including current portion, net of deferred issuance costs
  $ 846.3          
                 
Application of net offering proceeds, after expenses associated with this offering and the Formation Transactions, to reduce affiliate debt
    307.1          
Application of borrowings under our new credit facility to reduce affiliate debt
    342.5          
                 
Total reduction in affiliate debt
    649.6          
                 
Elimination of remaining affiliate debt (net of unamortized debt issue cost), treated as a capital contribution to us
            196.7  
                 
Equity contribution by Targa
          $ 391.5  
                 


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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
 
You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please see “Assumptions and Considerations.” In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.
 
For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma financial statements included elsewhere in this prospectus.
 
General
 
Rationale for Our Cash Distribution Policy.  Our partnership agreement requires us to distribute all of our available cash quarterly. Our available cash is our cash on hand, including cash from borrowings, at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs. We intend to fund a portion of our capital expenditures with additional borrowings, or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing rather than retaining our available cash.
 
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.  There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:
 
  •  Our cash distribution policy is subject to restrictions on distributions under our new credit facility. Specifically, the agreement related to our credit facility will contain material financial tests and covenants that we must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Reserves — Description of Credit Agreement.” Should we be unable to satisfy these restrictions under our credit facility or if we are otherwise in default under our credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.
 
  •  Our board of directors will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.
 
  •  While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a class (including common units held by Targa) after the subordination period has ended. At the closing of this offering, Targa will own our general partner and approximately 40.7% of our outstanding common units and subordinated units.
 
  •  Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.


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  •  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.
 
  •  We may lack sufficient cash to pay distributions to our unitholders due to increases in our operating or general and administrative expense, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.
 
Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital.  We will distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement or our credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
 
Our Initial Distribution Rate
 
Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare an initial quarterly distribution of $0.3375 per unit per complete quarter, or $1.35 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter through the quarter ending December 31, 2007. This equates to an aggregate cash distribution of $9.8 million per quarter or $39.0 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 19,320,000 common units representing an aggregate 61.4% limited partner interest in us and our aggregate cash distribution per quarter would be $10.6 million or $42.5 million per year. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “— Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”
 
As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. In the future, the general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. However, if the underwriters’ option is exercised in the transaction, and additional common units are issued, our general partner will maintain its initial 2% interest and will not be required to make a capital contribution to us. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest.


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The table below sets forth the assumed number of outstanding common units (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units), subordinated units and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis).
 
                                                 
    No Exercise of the Underwriters’
    Full Exercise of the Underwriters’
 
    Option to Purchase Additional Units     Option to Purchase Additional Units  
    Number of
    Distributions     Number of
    Distributions  
    Units     One Quarter     Annualized     Units     One Quarter     Annualized  
 
Publicly held common units
    16,800,000     $ 5,670,000     $ 22,680,000       19,320,000     $ 6,520,500     $ 26,082,000  
Subordinated units held by Targa
    11,528,231       3,890,778       15,563,112       11,528,231       3,890,778       15,563,112  
General partner units held by Targa
    578,127       195,118       780,471       629,555       212,475       849,899  
                                                 
Total
    28,906,358     $ 9,755,896     $ 39,023,583       31,477,786     $ 10,623,753     $ 42,495,011  
                                                 
 
The subordination period generally will end if we have earned and paid at least $1.35 on each outstanding unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2009. If we have earned and paid at least $2.025 (150% of the annualized minimum quarterly distribution) on each outstanding common unit, subordinated unit and general partner unit for any four-quarter period, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please see the “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our partnership agreement requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of expenses and the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, comply with applicable law, to comply with any of our debt instruments or other agreements or provide for future distributions to our unitholders for any one or more of the upcoming four quarters. Please see “Provisions of Our Partnership Agreement Relating to Cash Distributions.”
 
If distributions on our common units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future except that, during the subordination period to the extent we have available cash in any future quarter in excess of the amount necessary to make cash distributions to holders of our common units at the initial distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. Please see “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”
 
Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirements to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests.
 
Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above.


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We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through March 31, 2007 based on the actual length of the period.
 
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.3375 per unit each quarter through the quarter ending December 31, 2007. In those sections, we present two tables, consisting of:
 
  •  “Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2005 and the twelve months ended September 30, 2006, derived from our unaudited pro forma financial statements that are included in this prospectus, which unaudited pro forma financial statements are based on the combined results of operations of the Predecessor Business reflected in the Pre-Acquisition Financial Statements and the Post-Acquisition Financial Statements and on the results of operations reflected in the unaudited historical financial statements of the Predecessor Business for the nine months ended September 30, 2006, each as adjusted to give pro forma effect to the offering and the Formation Transactions; and
 
  •  “Statement of Minimum Estimated EBITDA for the Twelve Months Ending December 31, 2007,” in which we demonstrate our ability to generate the minimum estimated EBITDA necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending December 31, 2007.
 
Unaudited Pro Forma Available Cash for Year Ended December 31, 2005 and the Twelve Months Ended September 30, 2006
 
If we had completed the transactions contemplated in this prospectus on January 1, 2005, pro forma available cash generated during the year ended December 31, 2005 would have been approximately $31.0 million. Assuming the underwriters exercise in full their option to purchase additional common units, this amount would have been sufficient to make a cash distribution for 2005 at the initial rate of $0.3375 per unit per quarter ($1.35 per unit on an annualized basis) on all of the common units and a cash distribution of $0.0932 per unit per quarter ($0.3728 on an annualized basis) or 28% of the minimum quarterly distribution on all of the subordinated units. Assuming the underwriters do not exercise their option to purchase additional common units, this amount would have been sufficient to make the full minimum quarterly distribution on all of the common units and a cash distribution of $0.0968 per unit per quarter ($0.3874 on an annualized basis) or 29% of the minimum quarterly distribution on all of the subordinated units.
 
If we had completed the transactions contemplated in this prospectus on October 1, 2005, our pro forma available cash generated for the twelve months ended September 30, 2006 would have been approximately $42.0 million. Assuming the underwriters exercise in full their option to purchase additional common units, this amount would have been sufficient to make a cash distribution for the twelve months ended September 30, 2006 at the initial distribution rate of $0.3375 per unit per quarter ($1.35 per unit on an annualized basis) on all of the common units and a cash distribution of $0.3270 per unit per quarter ($1.3079 on an annualized basis) or 97% of the minimum quarterly distribution on all of the subordinated units. Assuming the underwriters do not exercise their option to purchase additional common units, this amount would have been sufficient to make the full minimum quarterly distribution on all of the common units and a cash distribution of $0.3306 per unit per quarter ($1.3225 on an annualized basis) or 98% of the minimum quarterly distribution on all of the subordinated units. We had no hedges in place during the year ended December 31, 2005. Pro forma available cash for the twelve months ended September 30, 2006 includes $0.3 million in net benefit for hedge settlements during the second and third quarters of 2006.
 
Unaudited pro forma available cash from operating surplus includes direct, incremental general and administrative expenses that will result from operating as a separate publicly held limited partnership. These


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direct, incremental general and administrative expenses are expected to be approximately $2.5 million annually, are not subject to the cap contained in the omnibus agreement and 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 direct, incremental general and administrative expenditure are not reflected in the historical financial statements of the Predecessor Business or our pro forma financial statements.
 
We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.
 
The following table illustrates, on a pro forma basis, for the year ended December 31, 2005 and for the twelve months ended September 30, 2006, the amount of available cash that would have been available for distributions to our unitholders, assuming in each case that this offering had been consummated at the beginning of such period and that the underwriters exercised in full their option to purchase additional common units. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.
 
Targa Resources Partners LP
 
Unaudited Pro Forma Available Cash
 
                 
          Twelve Months
 
    Year Ended
    Ended
 
    December 31,
    September 30,
 
    2005     2006  
    (in millions of dollars,
 
    except per unit data)  
 
Net income (loss)(1)
  $ 40.8     $ (32.7 )
Interest expense (including debt issuance amortization)(2)
    11.5       65.9  
Depreciation and amortization(2)
    20.5       52.1  
Income taxes(2)
    0.0       2.0  
                 
EBITDA(3)
    72.8       87.3  
Incremental general and administrative expense of being a public company(4)
    2.5       2.5  
Pro forma net cash interest expense(5)
    20.7       20.7  
Maintenance capital expenditures(6)
    12.9       12.3  
Expansion capital expenditures(6)
    5.7       9.8  
                 
Pro forma available cash
  $ 31.0     $ 42.0  
                 
Distributions per unit(7)
  $ 1.35     $ 1.35  
Pro forma cash distributions:
               
Distributions to public common unitholders(7)
    26.1       26.1  
Distributions to Targa(7)
    16.4       16.4  
                 
Total distributions(7)
  $ 42.5     $ 42.5  
                 
Excess (shortfall)
  $ (11.5 )   $ (0.5 )
                 
Ratio of consolidated indebtedness to consolidated EBITDA(8)
    4.1 x     3.4 x
Ratio of consolidated EBITDA to consolidated interest expense(8)
    3.5 x     4.2 x


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(1) Reflects actual net income of the Predecessor Business derived from its financial statements for the periods indicated without giving pro forma effect to the offering and the related transactions.
 
(2) Reflects adjustments to reconcile net income to EBITDA.
 
(3) EBITDA.  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.
 
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.
 
Management compensates 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 management’s decision-making processes.
 
(4) Reflects an adjustment to our EBITDA for an estimated incremental cash expense associated with being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.
 
(5) Reflects the interest expense related to $295.2 million in borrowings under our new credit facility at an assumed annual interest rate of 7.0%. This balance reflects the reduction to our expected initial borrowings of approximately $342.5 million through the application of the net proceeds from the assumed exercise in full of the underwriters’ option to purchase additional common units. If the interest rate used to calculate this interest were 1% higher or lower, our annual cash interest cost would increase or decrease, respectively, by $3.0 million.
 
(6) Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures are made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities.
 
(7) The table below assumes full exercise of the underwriters’ option to purchase additional common units and sets forth the assumed number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the estimated per unit and aggregate distribution amounts payable on our common units, subordinated units and general partner units for four quarters at our initial distribution rate of $0.3375 per common unit per quarter ($1.35 per common unit on an annualized basis).
 


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    Full Exercise of the Underwriters’ Option to Purchase Additional Units                    
    Number of
                               
    Units     One Quarter     Annualized                    
 
Publicly held common units
    19,320,000     $ 6,520,500     $ 26,082,000                          
Subordinated units held by Targa
    11,528,231       3,890,778       15,563,112                          
General partner units held by Targa
    629,555       212,475       849,899                          
                                                 
Total
    31,477,786     $ 10,623,753     $ 42,495,011                          
                                                 
 
(8) In connection with this offering, we expect to enter into a new credit facility which will contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, and engage in transactions with affiliates. Furthermore, our credit facility will contain covenants requiring us to maintain a ratio of consolidated indebtedness to consolidated EBITDA initially of not more than 5.75 to 1.00 and a ratio of consolidated EBITDA to consolidated interest expense of not less than 2.25 to 1.00. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions.
 
Minimum Estimated EBITDA for the Twelve Months Ending December 31, 2007
 
Set forth below is a Statement of Minimum Estimated EBITDA that reflects our ability to generate sufficient cash flows to make the minimum quarterly distribution on all of our outstanding units for the twelve months ending December 31, 2007, based on assumptions we believe to be reasonable. EBITDA is defined as net income before interest, income taxes, depreciation and amortization. Our minimum estimated EBITDA is prepared on a basis consistent with the accounting principles used in the historical financial statements of the Predecessor Business.
 
Our minimum estimated EBITDA assumes the underwriters exercise in full their option to purchase additional common units. The underwriters may or may not elect to exercise this option. We have presented our ability to make distributions assuming the issuance of an additional 2,520,000 common units and 51,428 general partner units as a result of this option. Because we will use the proceeds from the exercise of this option to reduce outstanding indebtedness, our cash available for distribution will increase by $3.3 million as a result of reduced interest expense. This increase is offset by $3.5 million of cash required to make distributions on the additional common and general partner units. If the option to purchase additional units is not exercised, our interest expense will increase and cash available for distribution will decrease by $3.3 million. Our pro forma financial statements and other information presented in this prospectus does not assume any exercise of the underwriters’ option to purchase additional common units.
 
Our minimum estimated EBITDA reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take in order to make the minimum quarterly distribution on all our outstanding units for the twelve months ending December 31, 2007. The assumptions disclosed below under “— Assumptions and Considerations” are those that we believe are significant to our ability to generate our minimum estimated EBITDA. We believe our actual results of operations and cash flows will be sufficient to generate the minimum estimated EBITDA; however, we can give you no assurance that our minimum estimated EBITDA will be achieved. There will likely be differences between our minimum estimated EBITDA and our actual results and those differences could be material. If we fail to generate the minimum estimated EBITDA, we may not be able to pay cash distributions on our common units at the initial distribution rate stated in our cash distribution policy. Assuming the underwriters exercise in full their option to purchase additional common units, in order to fund distributions to all of our common and subordinated unitholders at our initial rate of $1.35 per unit for the twelve months ending December 31, 2007, our minimum estimated EBITDA for the twelve months ending December 31, 2007 must be at least $78.3 million. Assuming the underwriters do not exercise their option to purchase additional common units, in order to fund distributions to all of our common and subordinated unitholders at our initial rate of $1.35 per unit for the twelve months ending December 31, 2007, our minimum estimated EBITDA for the twelve months ending December 31, 2007 must be at least $78.1 million. The amount of our minimum estimated EBITDA is lower if the underwriters do not exercise their option to purchase additional units because we

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would have fewer units outstanding and lower aggregate distributions, offset by higher interest expense associated with the higher level of indebtedness. As set forth in the table below, our minimum estimated EBITDA for this period will be approximately $78.3 million.
 
We do not as a matter of course make public projections as to future operations, earnings, or other results. However, management has prepared the minimum estimated EBITDA and related assumptions set forth below to substantiate our belief that we will have sufficient cash to make the minimum quarterly distribution to all our unitholders for the twelve months ending December 31, 2007. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information but, in the view of our management, the prospective financial information has been prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum estimated EBITDA necessary for us to have sufficient cash available for distributions to pay the minimum quarterly distribution to all our unitholders. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.
 
The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. PricewaterhouseCoopers LLP has neither examined nor compiled the accompanying prospective financial information and accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report included in this prospectus relates to our historical information. It does not extend to the prospective financial information and should not be read to do so.
 
When considering our minimum estimated EBITDA, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus could cause our actual results of operations to vary significantly from those supporting our minimum estimated EBITDA.
 
We are providing our minimum estimated EBITDA and related assumptions to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient available cash to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the four-quarter period ending December 31, 2007 at our stated initial distribution rate. Please see below under “— Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast.
 
We do not undertake any obligation to release publicly the results of any future revisions we may make to the assumptions used in generating minimum estimated EBITDA or to update those assumptions to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.


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Targa Resources Partners LP
 
Statement of Minimum Estimated EBITDA
 
         
    Twelve Months Ending
 
    December 31, 2007  
    (in millions of dollars,
 
    except for per unit data)  
 
Operating revenues
  $ 358.5  
Hedging gain (loss)
    15.0  
         
Total operating revenues
    373.5  
Product purchases
    256.4  
Operating expense
    23.7  
General and administrative expense
    7.5  
Depreciation and amortization expense
    55.2  
Interest expense, net
    21.6  
         
Net income
  $ 9.1  
Adjustments to reconcile net income to minimum estimated EBITDA:
       
Add:
       
Depreciation and amortization expense
    55.2  
Interest expense, net
    21.6  
Less:
       
Cash reserves(1)
    7.6  
         
Minimum estimated EBITDA(2)
    78.3  
Adjustments to reconcile minimum estimated EBITDA to estimated cash available for distribution:
       
Less:
       
Cash interest expense
    20.8  
Expansion capital expenditures
    1.8  
Maintenance capital expenditures
    15.0  
Add:
       
Borrowing to fund expansion capital expenditures
    1.8  
         
Estimated cash available for distribution
  $ 42.5  
         
Per unit minimum annual distribution
  $ 1.35  
Annual distributions to:
       
Public common unitholders
  $ 26.1  
Targa
    16.4  
         
Total minimum annual cash distributions
    42.5  
         
Ratio of consolidated indebtedness to consolidated EBITDA(3)
    3.5 x
Ratio of consolidated EBITDA to consolidated interest expense(3)
    4.1 x
 
 
(1) Represents a discretionary reserve to be used for reinvestment and other general partnership purposes.
 
(2) EBITDA.  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.


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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.
 
Management compensates 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 management’s decision-making processes.
 
(3) In connection with this offering, we expect to enter into a new credit facility which will contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, and engage in transactions with affiliates. Furthermore, our credit facility will contain covenants requiring us to maintain a ratio of consolidated indebtedness to consolidated EBITDA of not more than 5.75 to 1.00 and a ratio of consolidated EBITDA to consolidated interest expense of not less than 2.25 to 1.00. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions.
 
Please see accompanying summary of the assumptions used to support our minimum estimated EBITDA.
 
Assumptions and Considerations
 
We believe the assumptions and estimates we have made to support our ability to generate minimum estimated EBITDA, which are set forth below, are reasonable.
 
General/Commodity Price and Risk Considerations
 
  •  Our minimum estimated EBITDA includes the effect of our commodity price hedging program under which we have hedged a portion of the commodity price risk related to our expected natural gas, NGL and condensate sales. Our hedging program for the twelve months ending December 31, 2007 covers approximately 90% of our expected natural gas, 62% of our expected NGL and 93% of our expected condensate equity volumes. We have the following hedging arrangements in place for 2007:
 
             
   
Natural Gas
 
NGL
 
Condensate
 
Hedged volume — swaps
  13,612 MMBtu/d   2,416 Bbls/d   439 Bbls/d
Weighted average price — swaps
  $8.63 per MMBtu   $0.99 per gallon   $72.82 per Bbl
Hedged volume — floors
  870 MMBtu/d     25 Bbls/d
Weighted average price — floors
  $6.55 per MMBtu     $58.60 per Bbl
 
  •  As of January 30, 2007, the NYMEX 2007 forward prices for natural gas and crude oil were $7.82/MMbtu and $58.35/Bbl, respectively. These prices are 6% above and 13% below the forecasted prices of $7.40/MMbtu and $67.00/Bbl for natural gas and crude oil (based on forward prices as of September 29, 2006) used to calculate 2007 minimum estimated EBITDA.
 
Total Operating Revenues
 
  •  Inlet Volumes.  We estimate that we will have average inlet volumes of 162.1 MMcf/d of natural gas for the twelve months ending December 31, 2007, as compared to 161.8 MMcf/d for the twelve months ended September 30, 2006, 157.2 MMcf/d for the year ended December 31, 2005, and 145.4 MMcf/d for the year ended December 31, 2004.
 
  •  Residue Gas Sales (Volumes and Prices).  We estimate that we will sell an average of 73.5 BBtu/d of residue gas for the twelve months ending December 31, 2007 at an average realized price of $6.96/MMBtu, as compared to 74.6 BBtu/d at an average price of $6.83/MMBtu for the twelve months


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  ended September 30, 2006, 69.5 BBtu/d at an average price of $7.11/MMBtu for the year ended December 31, 2005, and 59.2 BBtu/d at an average price of $5.43/MMBtu for the year ended December 31, 2004. These assumptions take into account the effect of our natural gas hedges under which we have hedged through a combination of swaps and purchased puts (or floors) natural gas commodity price exposure related to approximately 90% of our expected natural gas equity volumes. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” for additional detail related to the terms of these natural gas hedges. For our unhedged natural gas volumes, our forecasted realized price is $6.58/MMBtu compared to average realized prices of $6.09/MMBtu for the nine months ended September 30, 2006.
 
Based on these assumptions, residue gas sales for the:
 
  —  twelve months ending December 31, 2007 compared to twelve months ending September 30, 2006 increase approximately $0.6 million consisting of higher revenues of $3.3 million attributable to higher natural gas prices offset by $2.7 million due to decreased volumes;
 
  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2005 increase approximately $6.5 million consisting of higher revenues of $10.6 million attributable to increased volumes offset by $4.1 million due to lower natural gas prices; and
 
  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2004 increase approximately $69.0 million consisting of higher revenues of $41.0 million attributable to higher natural gas prices and $28.0 million due to increased volumes.
 
  •  NGL Sales (Volumes and Prices).  We estimate that we will sell an average of 14.2 MBbls/d of NGLs for the twelve months ending December 31, 2007 at an average price of $33.34/Bbl, as compared to 15.2 MBbls/d at an average price of $38.20/Bbl for the twelve months ended September 30, 2006, 14.5 MBbls/d at an average price of $33.56/Bbl for the calendar year ended December 31, 2005, and 13.2 MBbls/d at an average price of $26.71/Bbl for the calendar year ended December 31, 2004. These assumptions take into account the effect of our NGL hedges under which we have hedged the NGL commodity price exposure related to approximately 62% of our expected NGL equity volumes. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” for additional detail related to the terms of these NGL hedges. For our unhedged NGL volumes, our estimated realized price is $32.59/Bbl compared to average realized prices of $37.80/Bbl for the nine months ended September 30, 2006.
 
Based on these assumptions, NGL sales for the:
 
  —   twelve months ending December 31, 2007 compared to twelve months ending September 30, 2006 decrease approximately $37.4 million consisting of lower revenues of $23.8 million attributable to lower NGL prices and $13.6 million due to decreased volumes;
 
  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2005 decrease approximately $4.1 million consisting of lower revenues of $2.9 million attributable to decreased volumes and $1.2 million due to lower NGL prices; and
 
  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2004 increase approximately $43.9 million consisting of higher revenues of $34.4 million attributable to higher NGL prices and $9.5 million due to increased volumes.
 
  •  Condensate Sales (Volumes and Prices).  We estimate that we will sell an average of 0.5 MBbls/d of condensate for the twelve months ending December 31, 2007 at an average price of $71.12/Bbl, as compared to 0.5 MBbls/d at an average price of $61.55/Bbl for the twelve months ended September 30, 2006, 0.5 MBbls/d at an average price of $54.03/Bbl for the calendar year ended December 31, 2005, and 0.7 MBbls/d at an average price of $40.56/Bbl for the calendar year ended December 31, 2004. These assumptions take into account the effect of the crude oil hedges under


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  which we have hedged through a combination of swaps and purchased puts (or floors) commodity price exposure related to approximately 93% of our expected condensate equity volumes. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Commodity Price Risk” for additional detail related to the terms of these crude oil hedges. For our unhedged condensate volumes, our estimated realized price is $66.00/Bbl compared to average realized prices of $62.66/Bbl for the nine months ended September 30, 2006.
 
Based on these assumptions, condensate sales for the:
 
  —  twelve months ending December 31, 2007 compared to twelve months ending September 30, 2006 increase approximately $1.8 million due to higher condensate prices;
 
  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2005 increase approximately $2.6 million consisting of higher revenues of $3.1 million attributable to higher condensate prices offset by $0.5 million due to decreased volumes; and
 
  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2004 increase approximately $2.7 million consisting of higher revenues of $5.5 million attributable to higher condensate prices offset by $2.8 million due to decreased volumes.
 
  •  Impact of Volume Declines.  If all other assumptions are held constant, a 5% decline in inlet volumes below forecasted levels would result in a $5.1 million decline in cash available for distribution. A decline in estimated cash flows greater than $7.6 million would result in our generating less than the minimum cash necessary to pay distributions. For the twelve months ended December 31, 2004, the twelve months ended December 31, 2005 and the twelve months ended September 30, 2006, a 5% decline in inlet volumes would have resulted in a $3.8 million, $5.1 million and $5.4 million, respectively, decline in cash available for distribution.
 
  •  Impact of Price Declines.  A difference in realized versus estimated commodity prices would affect our cash flows. For the twelve months ending December 31, 2007, approximately 10%, 38% and 7% of our forecasted natural gas, NGL and condensate equity volumes are unhedged. If all other assumptions are held constant, a 10% decrease in realized natural gas, NGL and crude oil prices versus our estimated prices for the unhedged portions of our estimated volumes of natural gas, NGLs and condensate would result in a $2.8 million decline in cash available for distribution. A 20% decline in these prices would result in an $5.6 million decline in cash available for distribution.
 
  •  Hedging Gain / (Loss). We estimate hedge gains will be $15.0 million for the twelve months ending December 31, 2007. In 2006, we entered into certain hedges for 2007 at prices that are materially higher than the prices underlying our Estimated EBITDA for the year ending December 31, 2007. For a description of our hedges, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures about Market Risk — Summary of Our Hedges.”
 
Costs and Expenses
 
  •  Product Purchases.  We estimate that our product purchases for the twelve months ending December 31, 2007 will be $256.4 million, as compared to $291.9 million for the twelve months ended September 30, 2006, $265.7 million for the twelve months ended December 31, 2005, and $182.6 million for the twelve months ended December 31, 2004.
 
Based on this estimate, the product purchases for the:
 
  —  twelve months ending December 31, 2007 compared to twelve months ending September 30, 2006 decrease approximately $35.5 million consisting of lower costs of $82.9 million attributable to lower commodity prices offset by $47.4 million due to increased volumes;


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  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2005 decrease approximately $9.5 million consisting of lower costs of $65.6 million attributable to lower commodity prices offset by $56.1 million due to increased volumes; and
 
  —  twelve months ending December 31, 2007 compared to twelve months ending December 31, 2004 increase approximately $73.9 million consisting of higher costs of $10.9 million attributable to higher commodity prices and $63.0 million due to increased volumes.
 
  •  Operating Expense.  We estimate that we will incur operating expense of $23.7 million for the twelve months ending December 31, 2007, as compared to $23.6 million for the twelve months ended September 30, 2006, $21.5 million for the twelve months ended December 31, 2005, and $17.7 million for the twelve months ended December 31, 2004. The expected increase in operating expense is driven by higher costs for labor, supplies and equipment and the expansion of our gathering system.
 
  •  General and Administrative Expense.  Our estimated general and administrative expense will be $7.5 million for the twelve months ending December 31, 2007 and will consist of up to a maximum of $5.0 million, subject to adjustment, of general and administrative expense allocated from Targa pursuant to the omnibus agreement, and $2.5 million of estimated general and administrative expense that relates to operating as a publicly held limited partnership. General and administrative expense was $6.8 million, $8.4 million and $7.2 million for the twelve months ended September 30, 2006, the twelve months ended December 31, 2005 and the twelve months ended December 31, 2004, respectively. Please see “Certain Relationships and Related Party Transactions — Omnibus Agreement” for additional details related to our omnibus agreement.
 
  •  Depreciation and Amortization Expense.  Estimated depreciation and amortization expense for the twelve months ending December 31, 2007 is $55.2 million as compared to $52.1 million for the twelve months ending September 30, 2006, $20.5 million for the twelve months ended December 31, 2005 and $12.2 million for the twelve months ended December 31, 2004. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The majority of the increase in depreciation and amortization is attributable to the step-up in basis associated with the DMS Acquisition.
 
  •  Capital Expenditures.  Estimated capital expenditures for the twelve months ending December 31, 2007 are based on the following assumptions:
 
  —  Maintenance Capital Expenditures.  Our estimated maintenance capital expenditures are $15.0 million for the twelve months ending December 31, 2007 as compared to $12.3 million for the twelve months ending September 30, 2006, $12.9 million for the twelve months ended December 31, 2005 and $10.2 million for the twelve months ended December 31, 2004. The expected increase in maintenance capital expenditures is attributable to capital spending for additional well connections in 2007 and the increased size of our gathering systems compared to prior periods.
 
  —  Expansion Capital Expenditures.  Our estimated expansion capital expenditures are $1.8 million for the twelve months ending December 31, 2007 as compared to $9.8 million for the twelve months ending September 30, 2006, $5.7 million for the twelve months ended December 31, 2005 and $13.5 million for the twelve months ended December 31, 2004. We expect to finance our $1.8 million in expansion capital expenditures from borrowings under our credit facility. The expected decrease in expansion capital expenditures is primarily due to the completion of the refurbishment of the Chico processing plant in 2006 offset by remaining expenditures for projects expected to be completed in the year ending December 31, 2007.


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Financing.  Our estimate for the twelve months ending December 31, 2007 is based on the following significant financing assumptions:
 
  •  Indebtedness.  Our expected initial borrowings of approximately $342.5 million under our new credit facility will be reduced by $47.3 million through the application of the net proceeds from the exercise in full of the underwriters’ option to purchase additional units, and increased by $1.8 million in order to fund our expansion capital requirement.
 
  •  Interest Expense.  The borrowings under our credit facility will bear an average variable interest rate of 7.0% through December 31, 2007. An increase or decrease of 1% in the interest rate will result in increased or decreased, respectively, annual interest expense of $3.0 million.
 
  •  Covenant Compliance.  We will remain in compliance with the financial and other covenants in our new credit facility.
 
Regulatory, Industry and Economic Factors.  Our estimate for the twelve months ending December 31, 2007 is based on the following significant assumptions related to regulatory, industry and economic factors:
 
  •  There will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business.
 
  •  There will not be any major adverse change in the portions of the energy industry or in general economic conditions.
 
  •  Market, insurance and overall economic conditions will not change substantially.


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PROVISIONS OF OUR PARTNERSHIP AGREEMENT
RELATING TO CASH DISTRIBUTIONS
 
Targa Resources, Inc. and certain of its affiliates hold all of the membership interests in our general partner, and consequently are indirectly entitled to all of the distributions that we make to Targa Resources GP LLC, subject to the terms of the limited liability company agreement of Targa Resources GP LLC and relevant legal restrictions.
 
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.
 
Distributions of Available Cash
 
General.  Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2007, we distribute all of our available cash to unitholders of record on the applicable record date.
 
Definition of Available Cash.  The term “available cash,” for any quarter, means all cash and cash equivalents on hand on the date of determination of available cash for that quarter:
 
  •  less the amount of cash reserves established by our general partner to:
 
  —  provide for the proper conduct of our business;
 
  —  comply with applicable law, any of our debt instruments or other agreements; or
 
  —  provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
 
Minimum Quarterly Distribution.  We will distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3375 per unit, or $1.35 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreement. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements — Description of Credit Agreement” for a discussion of the restrictions to be included in our credit agreement that may restrict our ability to make distributions.
 
General Partner Interest and Incentive Distribution Rights.  Initially, our general partner will be entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest will be represented by 578,127 general partner units (or 629,555 general partner units if the underwriters exercise their option to purchase additional common units in full). Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.
 
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus (as defined below) in excess of $0.3881 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on subordinated units that it owns. Please see “— General Partner Interest and Incentive Distribution Rights” for additional information.


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Operating Surplus and Capital Surplus
 
General.  All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.
 
Operating Surplus.  Operating surplus consists of:
 
  •  an amount equal to four times the amount needed for any one quarter for us to pay a distribution on all of our units (including the general partner units) and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter; plus
 
  •  all of our cash receipts after the closing of this offering, excluding cash from borrowings, sales of equity and debt securities, sales or other dispositions of assets outside the ordinary course of business, capital contributions or corporate reorganizations or restructurings (provided that cash receipts from the termination of a commodity hedge or interest rate swap prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the scheduled life of such commodity hedge or interest rate swap); less
 
  •  all of our operating expenditures after the closing of this offering, but excluding the repayment of borrowings, and including maintenance capital expenditures; less
 
  •  the amount of cash reserves established by our general partner to provide funds for future operating expenditures.
 
Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. Expansion capital expenditures represent capital expenditures made to expand or to increase the efficiency of the existing operating capacity of our assets or to expand the operating capacity or revenues of existing or new assets, whether through construction or acquisition. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as operating expenses as we incur them. Our partnership agreement provides that our general partner determines how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.
 
Capital Surplus.  Capital surplus generally consists of:
 
  •  borrowings;
 
  •  sales of our equity and debt securities;
 
  •  sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets;
 
  •  capital contributions received; and
 
  •  corporate restructurings.
 
Characterization of Cash Distributions.  Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes an amount equal to four times the amount needed for any one quarter for us to pay a distribution on all of our units (including the general partner units) and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter. This amount, which initially equals approximately $39.0 million, does not reflect actual cash on hand that is available for distribution to our unitholders.


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Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and borrowings, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.
 
Subordination Period
 
General.  Our partnership agreement provides that, during the subordination period (which we define below and in Appendix B), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3375 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.
 
Subordination Period.  The subordination period will extend until the first day of any quarter beginning after December 31, 2009 that each of the following tests are met:
 
  •  distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and general partner units during those periods on a fully diluted basis during those periods; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
 
Expiration of the Subordination Period.  When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:
 
  •  the subordination period will end and each subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  the general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests.
 
Early Conversion of Subordinated Units.  The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs:
 
  •  distributions of available cash from operating surplus on each outstanding common unit and subordinated unit equaled or exceeded $2.025 (150% of the annualized minimum quarterly distribution) for any four-quarter period immediately preceding that date;


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  •  the “adjusted operating surplus” (as defined below) generated during any four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.025 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and general partner units on a fully diluted basis; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
 
Adjusted Operating Surplus.  Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:
 
  •  operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “— Operating Surplus and Capital Surplus — Operating Surplus” above); plus
 
  •  any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the following bullet point; less
 
  •  any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
 
Distributions of Available Cash from Operating Surplus during the Subordination Period
 
Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
 
  •  first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
  •  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
 
  •  third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
 
Distributions of Available Cash from Operating Surplus after the Subordination Period
 
Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
 
  •  first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— General Partner Interest and Incentive Distribution Rights” below.
 
The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.


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General Partner Interest and Incentive Distribution Rights
 
Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units that it may hold based on the current market value of the contributed common units.
 
Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.
 
The following discussion assumes that the general partner maintains its 2% general partner interest and continues to own the incentive distribution rights.
 
If for any quarter:
 
  •  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
 
  •  we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
 
then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:
 
  •  first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.3881 per unit for that quarter (the “first target distribution”);
 
  •  second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.4219 per unit for that quarter (the “second target distribution”);
 
  •  third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.50625 per unit for that quarter (the “third target distribution”); and
 
  •  thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.
 
Percentage Allocations of Available Cash from Operating Surplus
 
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and


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assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.
 
                         
    Total Quarterly
    Marginal Percentage
 
    Distribution
    Interest in
 
    per Unit     Distributions  
                General
 
    Target Amount     Unitholders     Partner  
 
Minimum Quarterly Distribution
    $0.3375       98 %     2 %
First Target Distribution
    up to $0.3881       98 %     2 %
Second Target Distribution
    above $0.3881 up to $0.4219       85 %     15 %
Third Target Distribution
    above $0.4219 up to $0.50625       75 %     25 %
Thereafter
    above $0.50625       50 %     50 %
 
General Partner’s Right to Reset Incentive Distribution Levels
 
Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.
 
In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period.
 
The number of Class B units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by (y) the average of the amount of cash distributed per common unit during each of these two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units.
 
Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum


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quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:
 
  •  first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter;
 
  •  second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter;
 
  •  third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for that quarter; and
 
  •  thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.
 
The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various levels of cash distribution levels pursuant to the cash distribution provision of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.
 
                 
        Marginal Percentage
   
        Interest in Distributions    
    Quarterly Distribution
      General
  Quarterly Distribution per Unit
    per Unit Prior to Reset   Unitholders   Partner   Following Hypothetical Reset
 
Minimum Quarterly Distribution
  $0.3375   98%   2%   $0.6000
First Target Distribution
  up to $0.3881   98%   2%   up to $0.6900(1)
Second Target Distribution
  above $0.3881 up to $0.4219   85%   15%   above $0.6900(1) up to $0.7500(2)
Third Target Distribution
  above $0.4219 up to $0.50625   75%   25%   above $0.7500(2) up to $0.9000(3)
Thereafter
  above $0.50625   50%   50%   above $0.9000(3)
 
 
(1) This amount is 115% of the hypothetical reset minimum quarterly distribution.
 
(2) This amount is 125% of the hypothetical reset minimum quarterly distribution.
 
(3) This amount is 150% of the hypothetical reset minimum quarterly distribution.
 
The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, based on an average of the amounts distributed per quarter for the two quarters immediately prior to the reset. The table assumes that there are 30,848,231 common units and 629,555 general partner units outstanding and that the average distribution to each common unit is $0.60 for the two quarters prior to the reset. The assumed number of outstanding units assumes the underwriters exercise in full their option to purchase additional common units, the conversion of all subordinated units into common units and no additional unit issuances.
 
                                                     
    Quarterly
  Common
    General Partner Cash Distributions Prior to Reset        
    Distribution
  Unitholders Cash
          2% General
    Incentive
             
    per Unit
  Distributions
    Class B
    Partner
    Distribution
          Total
 
    Prior to Reset   Prior to Reset     Units     Interest     Rights     Total     Distributions  
 
Minimum Quarterly Distribution
  $0.3375   $ 10,411,278     $     $ 212,475     $     $ 212,475     $ 10,623,753  
First Target Distribution
  up to $0.3881     1,560,920             31,856             31,856       1,592,776  
Second Target Distribution
  above $0.3881 up to $0.4219     1,042,670             24,533       159,467       184,001       1,226,671  
Third Target Distribution
  above $0.4219 up to $0.50625     2,603,591             69,429       798,434       867,864       3,471,454  
Thereafter
  above $0.50625     2,890,479             115,619       2,774,860       2,890,479       5,780,958  
                                                     
        $ 18,508,939     $     $ 453,912     $ 3,732,762     $ 4,186,674     $ 22,695,613  
                                                     


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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 30,848,231 common units, 6,221,270 Class B units and 756,520 general partner units outstanding, and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (x) the $3,732,762 received by the general partner in respect of its incentive distribution rights per quarter for the two quarters prior to the reset as shown in the table above by (y) the $0.60 of available cash from operating surplus distributed to each common unit per quarter for the two quarters prior to the reset.
 
                                                     
    Quarterly
  Common
    General Partner Cash Distributions After Reset        
    Distribution
  Unitholders Cash
          2% General
    Incentive
             
    per Unit
  Distributions
    Class B
    Partner
    Distribution
          Total
 
    After Reset   After Reset     Units     Interest     Rights     Total     Distributions  
 
Minimum Quarterly Distribution
  $0.6000   $ 18,508,939     $ 3,732,762     $ 453,912     $     $ 4,186,674     $ 22,695,613  
First Target Distribution(1)
  up to 0.6900                                                
Second Target Distribution(2)
  above $0.6900 up to $0.7500                                                
Third Target Distribution(3)
  above $0.7500 up to $0.9000                                                
Thereafter
  above $0.9000                                                
                                                     
        $ 18,508,939     $ 3,732,762     $ 453,912     $     $ 4,186,674     $ 22,695,613  
                                                     
 
(1) This amount is 115% of the hypothetical reset minimum quarterly distribution.
 
(2) This amount is 125% of the hypothetical reset minimum quarterly distribution.
 
(3) This amount is 150% of the hypothetical reset minimum quarterly distribution.
 
Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.
 
Distributions from Capital Surplus
 
How Distributions from Capital Surplus Will Be Made.  Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:
 
  •  first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;
 
  •  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
 
  •  thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.
 
Effect of a Distribution from Capital Surplus.  Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding


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reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
 
Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.
 
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
 
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:
 
  •  the minimum quarterly distribution;
 
  •  target distribution levels;
 
  •  the unrecovered initial unit price; and
 
  •  the number of common units into which a subordinated unit is convertible.
 
For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level, and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.
 
In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that general partner may reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.
 
Distributions of Cash Upon Liquidation
 
General.  If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
 
The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to


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fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.
 
Manner of Adjustments for Gain.  The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:
 
  •  first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
 
  •  second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;
 
  •  third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
 
  •  fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;
 
  •  fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;
 
  •  sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence; and
 
  •  thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.
 
The percentage interests set forth above for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.
 
Manner of Adjustments for Losses.  If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner:
 
  •  first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;


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  •  second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and
 
  •  thereafter, 100% to the general partner.
 
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
 
Adjustments to Capital Accounts.  Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.


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SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
 
The following table shows selected historical financial and operating data of the North Texas System and pro forma financial data of Targa Resources Partners LP for the periods and as of the dates indicated. The historical financial statements included in this prospectus reflect the results of operations of the North Texas System to be contributed to us by Targa upon the closing of this offering. We refer to the results of operations of the North Texas System as the results of operations of the Predecessor Business. The selected historical financial data for the years ended December 31, 2001 and 2002 are derived from the books and records of the Predecessor Business. The selected historical financial data for the years ended December 31, 2003 and 2004, the ten-month period ended October 31, 2005 and the two-month period ended December 31, 2005 are derived from the audited financial statements of the Predecessor Business. The selected historical financial data for the nine months ended September 30, 2005 and 2006 are derived from the unaudited financial statements of the Predecessor Business. The Predecessor Business was acquired by Targa as part of the DMS Acquisition. The selected pro forma financial data for the year ended December 31, 2005 and the nine months ended September 30, 2006 are derived from the unaudited pro forma financial statements of Targa Resources Partners LP included in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2006, in the case of the pro forma balance sheet, or as of January 1, 2005, in the case of the pro forma statement of operations for the nine months ended September 30, 2006 and for the year ended December 31, 2005. The transactions reflected in the pro forma adjustments assume the following actions will occur:
 
  •  Targa will contribute the North Texas System to us;
 
  •  we will issue to Targa 11,528,231 subordinated units, representing a 39.9% limited partner interest in us;
 
  •  we will issue to our general partner, Targa Resources GP LLC, 578,127 general partner units representing its initial 2% general partner interest in us, and all of our incentive distribution rights, which incentive distribution rights will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3881 per unit per quarter;
 
  •  we will issue 16,800,000 common units to the public in this offering, representing a 58.1% limited partner interest in us, and will use the proceeds to pay expenses associated with this offering, the Formation Transactions and our new credit facility and to pay approximately $307.1 million to Targa to retire a portion of our affiliate indebtedness;
 
  •  we will borrow approximately $342.5 million under our new $500 million credit facility the proceeds of which will be paid to Targa to retire an additional portion of our affiliate indebtedness; and
 
  •  the remaining affiliate indebtedness will be retired and treated as a capital contribution to us.
 
We derived the information in the following table from, and that information should be read together with and is qualified in its entirety by reference to, the historical combined and pro forma condensed financial statements and the accompanying notes included elsewhere in this prospectus.
 


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    Predecessor Business     Targa Resources Partners LP  
    Dynegy       Targa     Pro Forma  
                            Nine
    Ten
      Two
    Nine
          Nine
 
                            Months
    Months
      Months
    Months
    Year
    Months
 
                            Ended
    Ended
      Ended
    Ended
    Ended
    Ended
 
    Years Ended December 31,     September 30,
    October 31,
      December 31,
    September 30,
    December 31,
    September 30,
 
    2001     2002     2003     2004     2005     2005       2005     2006     2005     2006  
    (Unaudited)     (Unaudited)     (Audited)     (Audited)     (Unaudited)     (Audited)       (Audited)     (Unaudited)     (Unaudited)     (Unaudited)  
    (in millions of dollars, except per unit, operating and price data)  
Statement of Operations Data:
                                                                                 
Total operating revenues
  $ 122.9     $ 112.5     $ 196.8     $ 258.6     $ 249.7     $ 293.3       $ 75.1     $ 290.9     $ 368.4     $ 290.9  
Product purchases
    94.0       82.7       147.3       182.6       179.0       210.8         54.9       205.2       265.7       205.2  
Operating expense
    15.8       14.9       15.1       17.7       15.8       18.0         3.5       17.9       21.5       17.9  
Depreciation and amortization expense
    9.7       11.8       12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
General and administrative expense
    7.2       7.7       7.7       7.2       6.7       7.3         1.1       5.1       8.4       5.1  
Interest expense, net
                                          11.5       54.4       24.8       18.6  
Deferred income taxes(1)
                                                2.0             2.0  
Other, net
          (0.3 )     0.6       0.3                                        
                                                                                   
Net income (loss)
  $ (3.8 )   $ (4.3 )   $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
                                                                                   
Pro forma net income (loss) per limited partner unit
                                                                    $ (0.24 )   $ 0.01  
Financial and Operating Data:
                                                                                 
Financial data:
                                                                                 
Operating margin(2)
  $ 13.1     $ 14.9     $ 34.4     $ 58.3     $ 54.9     $ 64.5       $ 16.7     $ 67.8     $ 81.2     $ 67.8  
EBITDA(2)
    5.9       7.5       26.1       50.8       48.2       57.2         15.6       62.7       72.8       62.7  
Operating data:
                                                                                 
Gathering throughput, MMcf/d(3)
    95.9       106.6       134.3       152.0       160.4       161.2         168.8       168.2                  
Plant natural gas inlet, MMcf/d(4)
    85.6       104.0       128.6       145.4       155.4       156.2         161.9       161.6                  
Gross NGL production, MBbl/d
    11.3       12.5       15.9       17.2       18.4       18.5         19.8       18.8                  
Natural gas sales, BBtu/d
    31.5       38.2       42.0       59.2       68.4       68.9         72.3       75.2                  
NGL sales, MBbl/d
    11.3       12.3       15.3       13.2       14.2       14.3         15.4       15.1                  
Condensate sales, MBbl/d
    0.6       0.6       0.6       0.7       0.5       0.5         0.5       0.5                  
Average Realized Prices:
                                                                                 
Natural gas, $/MMBtu
    4.00       2.84       4.97       5.43       6.39       6.79         8.61       6.09                  
NGL, $/gal
    0.41       0.35       0.47       0.64       0.75       0.78         0.90       0.90                  
Condensate, $/Bbl
    21.34       23.24       29.86       40.56       52.61       53.42         57.54       62.66                  
Balance Sheet Data (at period end):
                                                                                 
Property, plant and equipment, net
  $ 159.0     $ 178.2     $ 180.4     $ 191.2       195.4     $ 196.4       $ 1,097.0     $ 1,073.0             $ 1,073.0  
Total assets
    160.1       179.7       182.9       193.5       197.6       198.5         1,122.8       1,126.3               1,110.9  
Long-term debt (including current portion)
                                          868.9       865.2               342.5  
Partners’ capital / Net parent equity
    151.2       167.3       164.8       168.8       161.9       158.5         219.5       227.2               734.5  
Cash Flow Data:
                                                                                 
Net cash provided by (used in):
                                                                                 
Operating activities
  $ 2.6     $ 10.2     $ 31.3     $ 58.0     $ 59.2     $ 72.7       $ (1.5 )   $ 11.1                  
Investing activities
    (41.2 )     (30.6 )     (14.6 )     (23.4 )     (14.2 )     (16.4 )       (2.1 )     (17.7 )                
Financing activities
    38.6       20.4       (16.7 )     (34.6 )     (45.0 )     (56.3 )       3.6       6.6                  
_ _
 
(1)  In May 2006, Texas adopted a margin tax consisting of a 1% tax on the amount by which total revenue exceeds cost of goods. The amount presented represents our estimated liability for this tax.


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(2)  EBITDA.  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.
 
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.
 
Management compensates 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 management’s decision-making processes.
 
Operating Margin.  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, and 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 performance 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.
 
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 incorporating these learnings into 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;
 
  •  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
 


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    Predecessor Business     Targa Resources Partners LP  
    Dynegy       Targa     Pro Forma  
                Nine Months
    Ten Months
      Two Months
    Nine Months
          Nine Months
 
    Years Ended
    Ended
    Ended
      Ended
    Ended
    Year Ended
    Ended
 
    December 31,     September 30,
    October 31,
      December 31,
    September 30,
    December 31,
    September 30,
 
    2003     2004     2005     2005       2005     2006     2005     2006  
    (Audited)     (Audited)     (Unaudited)     (Audited)       (Audited)     (Unaudited)     (Unaudited)     (Unaudited)  
    (in millions of dollars)  
Reconciliation of “EBITDA” to net cash provided by (used in) operating activities:
                                                                 
Net cash provided by (used in) operating activities
  $ 31.3     $ 58.0     $ 59.2     $ 72.7       $ (1.5 )   $ 11.1                  
Allocated interest expense from parent(a)
                              10.7       50.5                  
Changes in operating working capital which provided (used) cash:
                                                                 
Accounts receivable
    0.7       (0.7 )     0.5       0.3         0.1       (0.4 )                
Accounts payable
    (1.0 )     (2.7 )     1.1       1.3         0.8                        
Other, including changes in noncurrent assets and liabilities
    (4.9 )     (3.8 )     (12.6 )     (17.1 )       5.5       1.5                  
                                                                   
EBITDA
  $ 26.1     $ 50.8     $ 48.2     $ 57.2       $ 15.6     $ 62.7                  
                                                                   
Reconciliation of “EBITDA” to net income:
                                                                 
Net income (loss)
  $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
Add:
                                                                 
Interest expense, net
                              11.5       54.4       24.8       18.6  
Deferred tax expense
                                    2.0             2.0  
Depreciation and amortization expense
    12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
                                                                   
EBITDA
  $ 26.1     $ 50.8     $ 48.2     $ 57.2       $ 15.6     $ 62.7     $ 72.8     $ 62.7  
                                                                   
Reconciliation of “operating margin” to net income:
                                                                 
Net income (loss)
  $ 14.1     $ 38.6     $ 38.1     $ 45.9       $ (5.1 )   $ (35.4 )   $ (6.8 )   $ 0.4  
Add:
                                                                 
Depreciation and amortization expense
    12.0       12.2       10.1       11.3         9.2       41.7       54.8       41.7  
Deferred income tax
                                    2.0             2.0  
Other, net
    0.6       0.3                                        
Interest expense, net
                              11.5       54.4       24.8       18.6  
General and administrative expense
    7.7       7.2       6.7       7.3         1.1       5.1       8.4       5.1