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As filed with the Securities and Exchange Commission on December 26, 2007
Registration No. 333-146700
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Amendment No. 1
to
Form S-1
 
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
 
 
WESTERN GAS PARTNERS, LP
(Exact Name of Registrant as Specified in Its Charter)
 
 
         
Delaware   1311   26-1075808
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)
 
1201 Lake Robbins Drive
The Woodlands, Texas 77380-1046
(832) 636-1000
(Address, Including Zip Code, and Telephone Number, Including Area Code, of
Registrant’s Principal Executive Offices)
 
Robert G. Gwin
1201 Lake Robbins Drive
The Woodlands, Texas 77380-1046
(832) 636-1000
(Name, Address, Including Zip Code, and Telephone Number, Including Area
Code, of Agent for Service)
 
 
Copies to:
 
     
David P. Oelman
Vinson & Elkins L.L.P.
1001 Fannin Street, Suite 2500
Houston, Texas 77002
(713) 758-2222
  G. Michael O’Leary
Andrews Kurth LLP
600 Travis Street, Suite 4200
Houston, Texas 77002
(713) 220-4200
 
 
     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, 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
     If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.  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 preliminary 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 preliminary prospectus is not an offer to sell these securities and we are not soliciting offers to buy these securities in any jurisdiction where the offer or sale is not permitted.
 
PRELIMINARY PROSPECTUS Subject to Completion December 26, 2007
­ ­
 
18,750,000 Common Units
 
Western Gas Partners Logo
 
Representing Limited Partner Interests
 
 
This is the initial public offering of our common units. We currently estimate that the initial public offering price will be between $      and $      per common unit. Prior to this offering, there has been no public market for the common units. We have applied to list our common units on the New York Stock Exchange under the symbol “WES.”
 
Investing in our common units involves risks.  Please read “Risk factors” beginning on page 18.
 
These risks include the following:
 
Ø  We are dependent on a single natural gas producer, Anadarko Petroleum Corporation, for almost all of the natural gas that we gather and transport. A material reduction in Anadarko’s production gathered or transported by our assets would result in a material decline in our revenues and cash available for distribution.
 
Ø  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 pay the minimum quarterly distribution to holders of our common and subordinated units.
 
Ø  Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of natural gas, which is dependent on certain factors beyond our control. Any decrease in the volumes of natural gas that we gather and transport could adversely affect our business and operating results.
 
Ø  Anadarko owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Anadarko and our general partner have conflicts of interest and may favor Anadarko’s interests to your detriment.
 
Ø  Cost reimbursements due to Anadarko and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to you. The amount and timing of such reimbursements will be determined by our general partner.
 
Ø  You will have limited voting rights and are not entitled to elect our general partner or its directors.
 
Ø  Even if you are dissatisfied, you cannot initially remove our general partner without its consent.
 
Ø  Our general partner interest or the control of our general partner may be transferred to a third party without your consent.
 
Ø  You will experience immediate and substantial dilution in pro forma net tangible book value of $5.09 per common unit.
 
Ø  You will 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 discounts and commissions(1)
  $       $    
 
 
Proceeds, before expenses, to Western Gas Partners, LP
  $       $    
 
 
 
(1) Excludes a structuring fee payable to UBS Securities LLC that is equal to     % of the gross proceeds of this offering, or approximately $          .
 
We have granted the underwriters a 30-day option to purchase up to an additional 2,812,500 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 18,750,000 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 on or about          , 2008.
 
UBS Investment Bank
 


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You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on our behalf. 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.
 
 
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  F-1
     
  A-1
     
  B-1
 Dew Gas Gathering Agreement
 Haley Gas Gathering Agreement
 Hugoton Gas Gathering Agreement
 Pinnacle Gas Gathering Agreement
 Revolving Credit Agreement
 First Amendment to Revolving Credit Agreement
 Second Amendment to Revolving Credit Agreement
 Consent of KPMG LLP
 Consent of KPMG LLP
 Consent of KPMG LLP
 
 
Through and including          , 2008 (the 25th day after the date of this prospectus), federal securities law may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement 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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Prospectus summary
 
This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully, including the historical and pro forma combined financial statements and the notes to those financial statements. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit and (2) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk factors” beginning on page 18 for more information about important risks that you should consider carefully before investing in our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.
 
Unless the context otherwise requires, references in this prospectus to (i) “Western Gas Partners, LP,” “we,” “our,” “us” or like terms, when used in a historical context, refer to our Predecessor, as defined in “—Summary historical and pro forma financial data,” and when used in the present tense or prospectively, refer to Western Gas Partners, LP and its subsidiaries; (ii) “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries and affiliates, other than Western Gas Partners, LP and Western Gas Holdings, LLC, our general partner, as of the closing date of this offering; (iii) “Anadarko Petroleum Corporation” refers to Anadarko Petroleum Corporation excluding its subsidiaries and affiliates; and (iv) “MIGC” refers to MIGC, Inc.
 
OVERVIEW
 
We are a growth-oriented Delaware limited partnership recently formed by Anadarko (NYSE: APC) to own, operate, acquire and develop midstream energy assets. We currently operate in East Texas, the Rocky Mountains, the Mid-Continent and West Texas and are engaged in the business of gathering, compressing, treating and transporting natural gas for our ultimate parent, Anadarko, and third-party producers and customers. We principally provide our midstream services under long-term contracts with fee-based rates extending for primary terms of up to 20 years. We generally do not take title to the natural gas that we gather and, therefore, are able to avoid significant direct commodity price exposure.
 
We believe that one of our principal strengths is our relationship with Anadarko. During each of the year ended December 31, 2006 and the nine months ended September 30, 2007, over 90% of our total natural gas gathering and transportation volumes were comprised of natural gas production owned or controlled by Anadarko. Anadarko Petroleum Corporation has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Volumes associated with this dedication averaged approximately 736 MMBtu/d for the year ended December 31, 2006 and 738 MMBtu/d for the nine months ended September 30, 2007.
 
We expect to utilize the significant experience of Anadarko’s management team to execute our growth strategy, which includes acquiring and constructing additional midstream assets. For the nine months ended September 30, 2007, as adjusted for divestitures prior to this offering and including the assets being contributed to us, Anadarko’s total domestic midstream asset portfolio generated approximately $250 million of cash flow from operations and consisted of 25 gathering systems and one transportation system with an aggregate throughput of approximately 3.0 Bcf/d, approximately 11,200 miles of pipeline and 25 processing and/or treating facilities.


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OUR ASSETS AND AREAS OF OPERATION
 
Our assets consist of six gathering systems, five natural gas treating facilities and one interstate pipeline. Our assets are located in East Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma) and West Texas. The following table provides information regarding our assets by operating area as of or for the nine months ended September 30, 2007:
 
                             
            Approximate
      Treating
  Average
 
    Asset
  Length
  # of receipt
  Gas compression
  capacity
  throughput
 
Area   Type   (miles)   points   (horsepower)   (MMcf/d)   (MMcf/d)  
   
 
East Texas
 
Gathering and
Treating
  577   789   45,633   510     304 (1)
Rocky Mountains
 
Gathering and
Treating
  114   162   20,385   92     55  
   
Transportation
  264   19   29,696       137  
Mid-Continent
 
Gathering
  1,753   1,507   130,720       123  
West Texas
 
Gathering
  87   50         185  
                             
Total
  2,795   2,527   226,434   602     804  
                         
 
 
(1)  To avoid duplicating volumes, 213 MMcf/d that is gathered on our Dew gathering system and delivered into our Pinnacle gas treating system is included only once in the calculation of average throughput.
 
STRATEGY
 
Our primary business objective is to increase our cash distribution per unit over time. We intend to accomplish this objective by executing the following strategy:
 
Ø  Pursuing accretive acquisitions.  We expect to pursue accretive acquisition opportunities within the midstream energy industry from Anadarko and third parties.
 
Ø  Capitalizing on organic growth opportunities.  We expect to grow organically by meeting Anadarko’s gathering needs, which we expect to increase as a result of its anticipated drilling activity in our areas of operation.
 
Ø  Attracting additional third-party volumes to our systems.  We intend to actively market our midstream services to and pursue strategic relationships with third-party producers to attract additional volumes and/or expansion opportunities.
 
Ø  Minimizing commodity price exposure.  Our midstream services are provided under fee-based arrangements which minimize our direct commodity price exposure. We expect to utilize hedging to manage any significant future commodity price risk that could result from contracts we may acquire or enter into in the future.
 
COMPETITIVE STRENGTHS
 
We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective because of the following competitive strengths:
 
Ø  Affiliation with Anadarko.  We believe Anadarko, as the owner of our general partner interest, all of our incentive distribution rights and a 57.3% limited partner interest in us, is motivated to promote and support the successful execution of our business plan and to pursue projects that enhance the value of our business.
 
Ø  Relatively stable and predictable cash flow.  Our cash flow is largely protected from fluctuations caused by commodity price volatility due to the fee-based, long-term nature of our midstream service agreements.
 
Ø  Well-positioned, well-maintained and efficient assets. We believe that our established positions in our areas of operation provide us with opportunities to expand and attract additional volumes to our


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systems. Moreover, our systems consist of high-quality, well-maintained assets for which we have implemented modern treating, measuring and operating technologies.
 
Ø  Financial flexibility to pursue expansion and acquisition opportunities. We have up to $100 million of borrowing capacity available to us under Anadarko’s $750 million credit facility and, concurrently with the closing of this offering, we expect to obtain a $30 million working capital facility from Anadarko. In addition, we will have no indebtedness outstanding at the closing of this offering. We believe that our borrowing capacity and our ability to effectively access debt and equity capital markets provide us with the financial flexibility necessary to achieve our organic expansion and acquisition strategy.
 
Ø  Experienced management team.  Members of our general partner’s management team have extensive experience in building, acquiring, integrating, financing and managing midstream assets. In addition, our relationship with Anadarko provides us with the services of experienced personnel who successfully managed our assets and operations while they were owned by Anadarko.
 
We believe that we will effectively leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties which may prevent us from achieving our primary business objective. For a more complete description of the risks associated with an investment in us, please read “Risk factors.”
 
OUR RELATIONSHIP WITH ANADARKO PETROLEUM CORPORATION
 
One of our principal attributes is our relationship with Anadarko. It will own our general partner and a significant interest in us following this offering. Anadarko is one of the largest independent oil and gas exploration and production companies in the world. Anadarko’s upstream oil and gas business finds and produces natural gas, crude oil, condensate and natural gas liquids, or NGLs, and Anadarko annually pursues one of the most active drilling programs in the industry. At September 30, 2007, including the assets being contributed to us but adjusted for divestitures prior to this offering, Anadarko’s total domestic midstream asset portfolio consisted of 25 gathering systems and one transportation system with an aggregate throughput of approximately 3.0 Bcf/d, approximately 11,200 miles of pipeline and 25 processing and/or treating facilities. Following this offering, Anadarko’s remaining midstream business will consist of 19 gathering systems with an aggregate throughput of approximately 2.2 Bcf/d, 8,400 miles of pipeline and 20 processing and/or treating facilities. The assets to be retained by Anadarko generated approximately $191 million of cash flow from operating activities for the nine months ended September 30, 2007. Anadarko has invested significant capital into its domestic midstream business, including the assets being contributed to us, with investments of approximately $290 million in 2006 and planned investments of approximately $600 million in 2007, of which approximately $475 million had been invested as of September 30, 2007.
 
Upon completion of this offering, Anadarko will own a 2.0% general partner interest in us, all of our incentive distribution rights and a 57.3% limited partner interest in us. We will enter into an omnibus agreement with Anadarko and our general partner that will govern our relationship with them regarding certain reimbursement and indemnification matters. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.” Although our relationship with Anadarko provides us with a significant advantage in the midstream natural gas market, it is also a source of potential conflicts. For example, Anadarko is not restricted from competing with us. Please read “Conflicts of interest and fiduciary duties.” Given Anadarko’s significant ownership of limited and general partner interests in us following this offering, we believe it will be in Anadarko’s best interest for it to sell additional assets to us over time; however, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire or construct those assets. Anadarko is under no contractual obligation to offer any such opportunities to us, nor are we obligated to participate in any such opportunities. We cannot state with any certainty which, if any, opportunities to acquire assets from Anadarko may be made available to us or if we will elect to pursue any such opportunities.


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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. Please read “Risk factors” for a more thorough description of these and other risks.
 
FORMATION TRANSACTIONS AND PARTNERSHIP STRUCTURE
 
General
 
We are a growth-oriented Delaware limited partnership recently formed by Anadarko to own, operate, acquire and develop midstream energy assets. At the closing of this offering, assuming that the underwriters do not exercise their option to purchase additional common units, the following transactions, which we refer to as the formation transactions, will occur:
 
Ø  Anadarko will contribute certain midstream assets to us;
 
Ø  we will issue to Western Gas Holdings, LLC, our general partner and a subsidiary of Anadarko, 921,385 general partner units representing a 2.0% general partner interest in us as well as all of our incentive distribution rights;
 
Ø  we will issue to Anadarko 3,823,925 common units and 22,573,925 subordinated units, representing an aggregate 57.3% limited partner interest in us;(1)
 
Ø  we will issue 18,750,000 common units to the public, representing a 40.7% limited partner interest in us;(1)
 
Ø  we will receive gross proceeds of $375.0 million from the issuance and sale of 18,750,000 common units at an assumed initial offering price of $20.00 per unit;
 
Ø  we will use the proceeds from this offering to pay underwriting discounts and a structuring fee totaling approximately $24.4 million and other estimated offering expenses of $3.0 million;
 
Ø  we will use the remaining $347.6 million of aggregate net proceeds of this offering to (i) make a loan of $337.6 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.00% and (ii) provide $10.0 million for general partnership purposes;
 
Ø  we will have up to $100 million of long-term borrowing capacity available to us under Anadarko’s $750 million credit facility;
 
Ø  we will enter into a $30 million working capital facility with Anadarko as the lender;
 
Ø  we will enter into an omnibus agreement with Anadarko and our general partner pursuant to which, among other things, (i) we will reimburse Anadarko and our general partner for certain expenses incurred on our behalf, including expenses for various general and administrative services rendered by Anadarko and our general partner to us, and (ii) the parties will agree to certain indemnification obligations;
 
Ø  our general partner will enter into a services and secondment agreement with Anadarko, pursuant to which certain employees of Anadarko will be under our control and render services to us or on our behalf; and
 
Ø  our general partner will enter into a tax sharing agreement with Anadarko, pursuant to which we will pay Anadarko for our share of state and local income and other taxes that are included in combined or consolidated tax returns filed by Anadarko.
 
 
(1) If the underwriters exercise their option to purchase up to 2,812,500 additional common units within 30 days of this offering, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public instead of Anadarko.


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Ownership of Western Gas Partners, LP
 
The diagram below illustrates our organization and ownership after giving effect to the offering and the related formation transactions and assumes that the underwriters’ option to purchase additional common units is not exercised.
 
         
Public Common Units
    40.7 %
Anadarko Common and Subordinated Units
    57.3 %
General Partner Units
    2.0 %
         
Total
    100.0 %
 
(GRAPHIC)


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OUR MANAGEMENT
 
Our general partner has sole responsibility for conducting our business and for managing our operations and will be controlled by our ultimate parent, Anadarko. Pursuant to the omnibus agreement and the services and secondment agreement that we will enter into concurrently with the closing of this offering, Anadarko and our general partner will be entitled to reimbursement for all direct and indirect expenses that they incur on our behalf. Under the omnibus agreement, our reimbursement to Anadarko for certain general and administrative expenses it allocates to us will be capped at $6.0 million annually through December 31, 2009, subject to adjustments to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement” and “—Services and secondment agreement.”
 
Neither our general partner nor its board of directors will be elected by our unitholders. Anadarko is the sole member of our general partner and will have the right to appoint our general partner’s entire board of directors. Certain of our officers and directors are also officers of Anadarko.
 
As is common with publicly traded partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries. We will initially have one direct subsidiary, Western Gas Operating, LP, a limited partnership that will conduct business itself and through its subsidiaries.
 
PRINCIPAL EXECUTIVE OFFICES AND INTERNET ADDRESS
 
Our principal executive offices are located at 1201 Lake Robbins Drive, The Woodlands, Texas 77380, and our telephone number is (832) 636-1000. We expect our website to be located at www.westerngas.com. We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, 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 herein and does not constitute a part of this prospectus.
 
OUR GENERAL PARTNER’S RIGHT TO RECEIVE DISTRIBUTIONS
 
2.0% general partner interest
 
Our general partner initially will be entitled to receive 2.0% of our quarterly cash distributions. This 2.0% interest will initially be represented by 921,385 general partner units. General partner units are not deemed outstanding units for purposes of voting rights and such units represent a non-voting general partner interest. Our general partner’s initial 2.0% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest. If and to the extent our general partner elects to contribute sufficient capital to maintain its 2.0% general partner interest, it will be issued the number of general partner units necessary to maintain its 2.0% interest. All references in this prospectus to our general partner’s 2.0% general partner interest assume that our general partner will elect to make these additional capital contributions in order to maintain its right to receive 2.0% of our cash distributions.
 
Incentive distributions
 
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percentage of quarterly distributions of available cash as higher target distribution levels of cash are achieved. The following table shows how our available cash will be distributed among our unitholders and our general partner as higher target distribution levels are met:
                 
        Marginal percentage interest
    Total quarterly distribution
  in distributions(1)
    per unit   Unitholders   General partner
     
 
Minimum Quarterly Distribution
  $0.300     98.0%     2.0%
First Target Distribution
  up to $0.345     98.0%     2.0%
Second Target Distribution
  above $0.345 up to $0.375     85.0%     15.0%
Third Target Distribution
  above $0.375 up to $0.450     75.0%     25.0%
Thereafter
  above $0.450     50.0%     50.0%
 
 
(1) Assumes that there are no arrearages on common units and that our general partner maintains its 2.0% general partner interest and continues to own the incentive distribution rights.
 
For a more detailed description of the incentive distribution rights, please read “Provisions of our partnership agreement relating to cash distributions—General partner interest and incentive distribution rights.”
 
Our general partner’s right to reset the target distribution levels
 
Our general partner has the right, at any 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 target distribution levels to higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per common unit for the two fiscal quarters immediately preceding the reset election (we refer to such amount 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. As a result, following a reset, we would distribute all of our available cash for each quarter thereafter as follows (assuming our general partner maintains its 2.0% general partner interest and the ownership of the incentive distribution rights):
 
Ø  first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total amount equal to 115% of the reset minimum quarterly distribution for that quarter;
 
Ø  second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;
 
Ø  third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and
 
Ø  thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.
 
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of Class B units and general partner 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 to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.


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SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
 
General
 
Our general partner has a legal duty to manage us in a manner beneficial to holders of our common and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its owner, Anadarko. Certain of the officers and directors of our general partner are also officers of Anadarko. As a result, conflicts of interest will arise in the future between us and holders of our common and subordinated units, on the one hand, and Anadarko and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our general partner receives incentive cash distributions as discussed above.
 
Partnership agreement modifications to fiduciary duties
 
Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner to holders of our common and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement, each holder of common units consents to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.
 
Anadarko may engage in competition with us
 
Neither our partnership agreement nor the omnibus agreement between us and Anadarko will prohibit Anadarko from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Anadarko may acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to acquire or construct any of those assets.
 
For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, please read “Conflicts of interest and fiduciary duties.”


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The offering
 
Common units offered to the public 18,750,000 common units
 
21,562,500 common units, if the underwriters exercise in full their option to purchase additional common units
 
Units outstanding after this offering 22,573,925 common units(1) and 22,573,925 subordinated units, each representing a 49.0% limited partner interest in us. Our general partner will own 921,835 general partner units, representing a 2.0% general partner interest in us.
 
Use of proceeds We expect to receive gross proceeds of $375.0 million from this offering. We will use the proceeds to (i) make a loan of $337.6 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.00%, (ii) provide $10.0 million for general partnership purposes and (iii) pay underwriting discounts and a structuring fee totaling approximately $24.4 million and other estimated offering expenses of $3.0 million.
 
The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to reimburse Anadarko for capital expenditures it incurred with respect to the assets contributed to us during the two-year period prior to this offering.
 
Cash distributions Our general partner will adopt a cash distribution policy that will require us to pay a minimum quarterly distribution of $0.30 per unit ($1.20 per 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, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A and in the glossary included in this prospectus as Appendix B. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our cash distribution policy and restrictions on distributions.” We will adjust the minimum quarterly distribution payable for the period from the completion of this offering through March 31, 2008, based on the actual length of that period.
 
Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:
 
Ø first, 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $0.30 plus any arrearages from prior quarters;
 
Ø second, 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit
 
 
 (1)  Excludes common units subject to issuance under our Long-Term Incentive Plan. Please read “Management — Long-term incentive plan.”


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has received the minimum quarterly distribution of $0.30; and
 
Ø third, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $0.345.
 
If cash distributions to our unitholders exceed $0.345 per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of our partnership agreement relating to cash distributions.”
 
The amounts of pro forma available cash generated during each of the year ended December 31, 2006 and twelve months ended September 30, 2007 would have been sufficient to allow us to pay the full minimum quarterly distribution ($0.30 per unit per quarter, or $1.20 on an annualized basis) on all of our common and subordinated units for such periods. Please read “Our cash distribution policy and restrictions on distributions.”
 
We believe that, based on the Statement of Estimated Adjusted EBITDA included under the caption “Our cash distribution policy and restrictions on distributions,” we will have sufficient cash available for distribution to pay the minimum quarterly distribution of $0.30 per unit on all common and subordinated units and the corresponding distributions on our general partner’s 2.0% interest for the four quarters ending December 31, 2008.
 
Subordinated units Anadarko will initially indirectly own all of our subordinated units. The principal difference between our common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.
 
Conversion of subordinated units The subordination period will end on the first business day after we have earned and paid at least (i) $1.20 (the minimum quarterly distribution on an annualized basis) on each outstanding unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four quarter periods ending on or after December 31, 2010 or (ii) $0.45 per quarter (150% of the minimum quarterly distribution, which is $1.80 on an annualized basis) on each outstanding unit and the corresponding distributions on our general partner’s 2.0% interest for each of four consecutive quarters.
 
In addition, the subordination period will end upon the removal of our general partner other than for cause if the units


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held by our general partner and its affiliates are not voted in favor of such removal.
 
When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.
 
General partner’s right to reset the target distribution levels Our general partner has the right, at any 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 target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal 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.
 
If our general partner elects to reset the target distribution levels, it will be entitled to receive Class B units and general partner 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 to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election. Please read “Provisions of our partnership agreement relating 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 read “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 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 voting together as a single class, including any units owned by our general partner and its affiliates, including Anadarko. Upon consummation of this offering, Anadarko will own an aggregate of 58.5% of our common and subordinated units. This will give Anadarko the ability to


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prevent the involuntary removal of our general partner. Please read “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 that is 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, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.20 per unit, we estimate that your average allocable federal taxable income per year will be no more than $           per unit. Please read “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, or the U.S., please read “Material tax consequences.”
 
Exchange listing We have applied to list our common units on the New York Stock Exchange under the symbol “WES.”


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Summary historical and pro forma financial and operating data
 
The following table shows (i) the summary combined historical financial and operating data of our Predecessor, which is comprised of Anadarko Gathering Company and Pinnacle Gas Treating, Inc., with MIGC reported as an acquired business of our Predecessor, and (ii) the summary combined pro forma as adjusted financial and operating data of Western Gas Partners, LP (the “Partnership”), for the periods and as of the dates indicated. The information in the following table should be read together with “Management’s discussion and analysis of financial condition and results of operations.”
 
Our Predecessor’s summary combined historical balance sheet data as of December 31, 2006 and 2005 and summary combined historical statement of income and cash flow data for the years ended December 31, 2006, 2005 and 2004 are derived from the audited historical combined financial statements of our Predecessor included elsewhere in this prospectus. Our Predecessor’s summary combined historical balance sheet data as of December 31, 2004 are derived from the unaudited historical combined financial statements of our Predecessor not included in this prospectus. Our Predecessor’s summary combined historical balance sheet data as of September 30, 2007 and summary combined historical statement of income and cash flow data for the nine months ended September 30, 2007 and 2006 are derived from the unaudited historical combined financial statements of our Predecessor included elsewhere in this prospectus. Our Predecessor’s summary combined historical balance sheet data as of September 30, 2006 are derived from the unaudited historical combined financial statements of our Predecessor not included in this prospectus.
 
The Partnership’s summary combined pro forma as adjusted statement of income data for the year ended December 31, 2006 and the nine months ended September 30, 2007 and summary combined pro forma as adjusted balance sheet data as of September 30, 2007 are derived from the unaudited pro forma combined financial statements of the Partnership included elsewhere in this prospectus.
 
The pro forma adjustments have been prepared as if the acquisition of MIGC by our Predecessor occurred on January 1, 2006 and as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the pro forma balance sheet, and on January 1, 2006, in the case of the pro forma statements of operations for the year ended December 31, 2006 and the nine months ended September 30, 2007. These transactions include:
 
Ø  the receipt by the Partnership of gross proceeds of $375.0 million from the issuance and sale of 18,750,000 common units at an assumed initial offering price of $20.00 per unit;
 
Ø  the use of the proceeds from this offering to pay underwriting discounts and a structuring fee totaling approximately $24.4 million and other estimated offering expenses of $3.0 million; and
 
Ø  the use of the remaining $347.6 million of aggregate net proceeds of this offering to (i) make a loan of $337.6 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.00% and (ii) provide $10.0 million for general partnership purposes.
 
The following table includes our Predecessor’s historical and our pro forma Adjusted EBITDA, which have not been prepared in accordance with generally accepted accounting principles (“GAAP”). Adjusted EBITDA is presented because it is helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP financial measure” below.


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                                  Partnership pro forma
 
                                  as adjusted  
    Predecessor combined     Nine months
       
                      Nine months ended
    ended
    Year ended
 
    Year ended December 31,     September 30,     September 30,
    December 31,
 
    2006     2005     2004     2007     2006     2007     2006  
   
    (in thousands, except for operating and per unit data)  
 
Statement of Income Data:
                                                       
Total revenues
  $ 81,152     $ 71,650     $ 68,049     $ 85,513     $ 57,481     $ 85,513     $ 93,304  
Costs and expenses
    39,960       35,720       31,301       33,184       29,057       33,184       43,857  
Depreciation
    18,009       15,447       14,841       17,104       12,635       17,104       19,710  
                                                         
Total operating expenses
    57,969       51,167       46,142       50,288       41,692       50,288       63,567  
                                                         
Operating income
    23,183       20,483       21,907       35,225       15,789       35,225       29,737  
                                                         
Other (expense) income
    26       (66 )                 25             377  
Interest expense (income)
    9,631       8,650       7,146       6,643       7,943       (15,022 )     (20,030 )
Income tax expense
    3,814       4,789       5,504       10,469       1,740       160       978  
                                                         
Net income
  $ 9,712     $ 7,110     $ 9,257     $ 18,113     $ 6,081     $ 50,087     $ 48,412  
                                                         
General partner interest in pro forma net income
                                            1,315       968  
Common unitholders’ interest in pro forma net income
                                            24,386       23,722  
Subordinated unitholder’s interest in pro forma net income
                                            24,386       23,722  
Net income per common unit (basic and diluted)
                                          $ 1.08     $ 1.05  
Net income per subordinated unit (basic and diluted)
                                          $ 1.08     $ 1.05  
Balance Sheet Data (at period end):
                                                       
Net, property, plant and equipment
  $ 310,871     $ 200,451     $ 196,065     $ 353,894     $ 302,057     $ 353,894          
Total assets
    332,228       206,373       199,110       360,692       324,772       708,306          
Total parent net equity
    238,531       160,585       162,542       273,507       234,063       691,561          
Cash Flow Data:
                                                       
Net cash provided by (used in):
                                                       
Operating activities
    27,323       30,131       31,160       41,810       12,941                  
Investing activities
    (42,713 )     (21,076 )     (16,548 )     (37,247 )     (27,952 )                
Financing activities
    15,844       (9,067 )     (14,596 )     (5,021 )     15,007                  
Adjusted EBITDA(1)
    41,192       35,930       36,748       52,329       28,424       52,329       49,447  
Capital expenditures, net
    42,299       20,841       16,548       37,020       27,709                  


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                                  Partnership pro forma
 
                                  as adjusted  
    Predecessor combined     Nine months
       
                      Nine months ended
    ended
    Year ended
 
    Year ended December 31,     September 30,     September 30,
    December 31,
 
    2006     2005     2004     2007     2006     2007     2006  
   
    (in thousands, except for operating and per unit data)  
 
Operating Data:
                                                       
Affiliate
                                                       
Throughput, MMBtu/d
    820       757       715       904       778       904       878  
Average rate per MMBtu
  $ 0.22     $ 0.21     $ 0.21     $ 0.28     $ 0.22     $ 0.28     $ 0.23  
Third Party
                                                       
Throughput, MMBtu/d
    72       41       31       90       64       90       93  
Average rate per MMBtu
  $ 0.19     $ 0.16     $ 0.13     $ 0.25     $ 0.21     $ 0.25     $ 0.23  
Total
                                                       
Throughput, MMBtu/d
    892       798       746       994       842       994       971  
Average rate per MMBtu
  $ 0.21     $ 0.21     $ 0.21     $ 0.28     $ 0.22     $ 0.28     $ 0.23  
 
 
(1) Adjusted EBITDA is defined in “—Non-GAAP financial measure” below.

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NON-GAAP FINANCIAL MEASURE
 
We define Adjusted EBITDA as net income (loss), plus interest expense, income taxes and depreciation, less interest income and other income (expense). We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company’s ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
 
Ø  our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
 
Ø  the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and
 
Ø  the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
 
The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
 
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA and net income and net cash provided by operating activities, and incorporating this knowledge into its 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.
 
The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities on an historical and pro forma as adjusted basis:
 


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                                  Partnership pro forma
 
    Predecessor combined     as adjusted  
                                  Nine months
       
    Year ended
    Nine months
    ended
    Year ended
 
    December 31,     ended September 30,     September 30,
    December 31,
 
    2006     2005     2004     2007     2006     2007     2006  
   
    (in thousands)  
 
Reconciliation of Adjusted EBITDA to Net Income
                                                       
Net income
  $ 9,712     $ 7,110     $ 9,257     $ 18,113     $ 6,081     $ 50,087     $ 48,412  
Add:
                                                       
Interest expense (income)
    9,631       8,650       7,146       6,643       7,943       (15,022 )     (20,030 )
Income tax expense
    3,814       4,789       5,504       10,469       1,740       160       978  
Depreciation
    18,009       15,447       14,841       17,104       12,635       17,104       19,710  
Less:
                                                       
Other income (expense)
    (26 )     66                   (25 )           (377 )
                                                         
Adjusted EBITDA
  $ 41,192     $ 35,930     $ 36,748     $ 52,329     $ 28,424     $ 52,329     $ 49,447  
                                                         
Reconciliation of Adjusted EBITDA to Net Cash Provided by Operating Activities
                                                       
Net cash provided by operating activities
  $ 27,323     $ 30,131     $ 31,160     $ 41,810     $ 12,941     $ 66,880     $ 64,888  
Interest expense (income)
    9,631       8,650       7,146       6,643       7,943       (15,022 )     (20,030 )
Current income tax expense
                      3,406             1        
Other income (expense)
    (26 )     66                   (25 )           (377 )
Changes in operating working capital:
                                                       
Accounts receivable
    (374 )     662       (933 )     1,062       1,410       1,062       (374 )
Accounts payable and accrued expenses
    4,556       (3,373 )     551       (580 )     6,015       (580 )     4,556  
Other, including changes in non-current assets and liabilities
    30       (74 )     (1,176 )     (12 )     90       (12 )     30  
                                                         
Adjusted EBITDA
  $ 41,192     $ 35,930     $ 36,748     $ 52,329     $ 28,424     $ 52,329     $ 49,447  
                                                         
 
 
(1)  Includes impact of change in accounting principle.

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Risk factors
 
Limited partner units 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. We urge you to carefully consider 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 to occur, 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 in us.
 
RISKS RELATED TO OUR BUSINESS
 
We are dependent on a single natural gas producer, Anadarko, for almost all of the natural gas that we gather and transport. A material reduction in Anadarko’s production gathered or transported by our assets would result in a material decline in our revenues and cash available for distribution.
 
We rely on Anadarko for virtually all of the natural gas that we gather and transport. For the nine months ended September 30, 2007, Anadarko accounted for over 90% of our natural gas gathering and transportation volumes. We may be unable to negotiate on favorable terms, if at all, extensions or replacements of our contracts to gather, compress, treat and transport Anadarko’s production. Furthermore, Anadarko may suffer a decrease in production volumes in the areas serviced by us and is under no contractual obligation to maintain its production dedicated to us. The loss of a significant portion of the natural gas volumes supplied by Anadarko would result in a material decline in our revenues and our cash available for distribution. In addition, Anadarko may determine in the future that drilling activity in other areas of operation is strategically more attractive. A shift in Anadarko’s focus away from our areas of operation could result in reduced throughput on our system and a material decline in our revenues.
 
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 pay the minimum quarterly distribution to holders of our common and subordinated units.
 
In order to pay the minimum quarterly distribution of $0.30 per unit per quarter, or $1.20 per unit per year, we will require available cash of approximately $13.8 million per quarter, or $55.3 million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. 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:
 
Ø  the prices of, level of production of and demand for natural gas;
 
Ø  the volume of natural gas we gather, compress, treat and transport;
 
Ø  the volumes and prices of condensate that we retain and sell;
 
Ø  demand charges and volumetric fees associated with our transportation services;
 
Ø  the level of competition from other midstream energy companies;
 
Ø  the level of our operating and maintenance and general and administrative costs;


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Risk factors
 
 
Ø  regulatory action affecting the supply of or demand for natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
 
Ø  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:
 
Ø  the level of capital expenditures we make;
 
Ø  the cost of acquisitions;
 
Ø  our debt service requirements and other liabilities;
 
Ø  fluctuations in our working capital needs;
 
Ø  our ability to borrow funds and access capital markets;
 
Ø  restrictions contained in debt agreements to which we are a party; and
 
Ø  the amount of cash reserves established by our general partner.
 
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our cash distribution policy and restrictions on distributions.”
 
The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
 
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 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.
 
The amount of available cash we need to pay the minimum quarterly distribution on all of our units to be outstanding immediately after this offering and the corresponding distribution on our general partner’s 2.0% interest for four quarters is approximately $55.3 million. The amounts of pro forma available cash generated during each of the year ended December 31, 2006 and twelve months ended September 30, 2007 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common and subordinated units for such periods. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please read “Our cash distribution policy and restrictions on distributions.”
 
The assumptions underlying the forecast of cash available for distribution that 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 forecast of cash available for distribution set forth in “Our cash distribution policy and restrictions on distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending December 31, 2008. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast 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 the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.


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Risk factors
 
 
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of natural gas, which is dependent on certain factors beyond our control. Any decrease in the volumes of natural gas that we gather and transport could adversely affect our business and operating results.
 
The volumes that support our business are dependent on the level of production from natural gas wells connected to our gathering systems, the production of which will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells.
 
While Anadarko has dedicated production from certain of its properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. In addition, we have no control over Anadarko or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, governmental regulations, the availability of drilling rigs and other production and development costs. Fluctuations in energy prices can also greatly affect investments by Anadarko and third parties in the development of new natural gas reserves. Declines in natural gas prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering and treating assets.
 
Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Moreover, Anadarko may not develop the acreage it has dedicated to us. If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.
 
We typically do not obtain independent evaluations of natural gas reserves connected to our gathering and transportation systems; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.
 
We typically do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.
 
Lower natural gas and oil prices could adversely affect our business.
 
Lower natural gas and oil prices could impact natural gas and oil exploration and production activity levels and result in a decline in the production of natural gas and condensate, resulting in reduced throughput on our systems. Any such decline may cause our current or potential customers to delay drilling or shut in production. In addition, such a decline would reduce the amount of condensate we retain and sell. As a result, lower natural gas prices could have an adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.


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Risk factors
 
 
In general terms, the prices of natural gas, oil, condensate, NGLs and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
 
Ø  worldwide economic conditions;
 
Ø  weather conditions and seasonal trends;
 
Ø  the levels of domestic production and consumer demand;
 
Ø  the availability of imported liquified natural gas, or LNG;
 
Ø  the availability of transportation systems with adequate capacity;
 
Ø  the volatility and uncertainty of regional pricing differentials such as in the Mid-Continent;
 
Ø  the price and availability of alternative fuels;
 
Ø  the effect of energy conservation measures;
 
Ø  the nature and extent of governmental regulation and taxation; and
 
Ø  the anticipated future prices of natural gas, LNG and other commodities.
 
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
 
We compete with similar enterprises in our areas of operation. Our competitors may expand or construct gathering, compression, treating or transportation systems that would create additional competition for the services we provide to our customers. In addition, our customers, including Anadarko, may develop their own gathering, compression, treating or 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 flow 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 operating income could be affected by a change in oil prices relative to the price of natural gas.
 
Under our gathering agreements, we retain and sell condensate, which falls out of the natural gas stream during the gathering process, and compensate shippers with a thermally equivalent volume of natural gas. Condensate sales comprised approximately 9% of our gathering system revenues for the nine months ended September 30, 2007. The price we receive for our condensate is generally tied to the market price of oil. The relationship between natural gas prices and oil prices therefore affects the margin on our condensate sales. When natural gas prices are high relative to oil prices, the profit margin we realize on our condensate sales is low due to the higher value of natural gas. Correspondingly, when natural gas prices are low relative to oil prices, the profit margin is high.
 
If third-party pipelines or other facilities interconnected to our gathering or transportation systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
 
Our natural gas gathering and transportation systems connect to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.


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Risk factors
 
 
Our interstate natural gas transportation operations are subject to regulation by FERC, which could have an adverse impact on our ability to establish transportation rates that would allow us to earn a reasonable return on our investment, or even recover the full cost of operating our pipeline, thereby adversely impacting our ability to make distributions to you.
 
MIGC, our interstate natural gas transportation system, is subject to regulation by the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act of 1938, or the NGA, and the Energy Policy Act of 2005, or the EPAct 2005.
 
Under the NGA, FERC has the authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation extends to such matters as:
 
Ø  rates, services and terms and conditions of service;
 
Ø  the types of services MIGC may offer to its customers;
 
Ø  the certification and construction of new facilities;
 
Ø  the acquisition, extension, disposition or abandonment of facilities;
 
Ø  the maintenance of accounts and records;
 
Ø  relationships between affiliated companies involved in certain aspects of the natural gas business;
 
Ø  the initiation and discontinuation of services;
 
Ø  market manipulation in connection with interstate sales, purchases or transportation of natural gas; and
 
Ø  participation by interstate pipelines in cash management arrangements.
 
Natural gas companies are prohibited from charging rates that have been determined to be not just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
 
The rates and terms and conditions for our interstate pipeline services are set forth in a FERC-approved tariff. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation service.
 
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. FERC also has the power to order disgorgement of profits from transactions deemed to violate the NGA and EPAct 2005.
 
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 could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.
 
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas pipelines, other than MIGC, meet the traditional tests FERC has used to determine if a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial ongoing litigation and, over time, FERC policy concerning where to draw the line between activities it regulates and activities excluded from its regulation has changed. The classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements


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Risk factors
 
 
and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels.
 
FERC regulation of MIGC, including the outcome of certain FERC proceedings on the appropriate treatment of tax allowances included in regulated rates and the appropriate return on equity, may reduce our transportation revenues, affect our ability to include certain costs in regulated rates and increase our costs of operations, and thus adversely affect our cash available for distribution.
 
FERC has pending certain proceedings concerning the appropriate allowance for income taxes that may be included in cost-based rates for FERC regulated pipelines owned by publicly traded partnerships that do not directly pay federal income tax. FERC issued a policy permitting such tax allowances in 2005. FERC’s policy and its initial application in a specific case were upheld on appeal by the D.C. Circuit in May of 2007 and the D.C. Circuit’s decision is final. In December 2006, FERC issued another order addressing the income tax allowance in rates, in which it reaffirmed prior statements regarding its income tax allowance policy, but raised a new issue regarding the implication of the policy statement for publicly traded partnerships. FERC noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, creating an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC adjusted the equity rate of return of the pipeline at issue downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. Rehearing is currently pending before FERC.
 
FERC also has pending a proceeding on the appropriate composition of proxy groups for purposes of determining natural gas and oil pipeline equity returns to be included in cost-of-service based rates. In a policy statement issued July 19, 2007, FERC proposed to permit inclusion of publicly traded partnerships in the proxy group analysis relating to return on equity determinations in rate proceedings, provided that the analysis be limited to actual publicly traded partnership distributions capped at the level of the pipeline’s earnings and that evidence be provided in the form of a multiyear analysis of past earnings demonstrating a publicly traded partnership’s ability to provide stable earnings over time. In November 2007, the FERC requested additional comments and announced a technical conference regarding the method to be used for creating growth forecasts for publicly traded partnerships.
 
The ultimate outcome of these proceedings is not certain and may result in new policies being established at FERC that would limit the amount of income tax allowance permitted to be recovered in regulated rates or disallow the full use of distributions to unitholders by pipeline publicly traded partnerships in any proxy group comparisons used to determine return on equity in future rate proceedings. Any such policy developments may adversely affect the ability of MIGC to achieve a reasonable level of return or impose limits on its ability to include a full income tax allowance in cost of service, and therefore could adversely affect our cash available for distribution.
 
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
 
Our natural gas gathering, compression, treating and transportation operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. Examples of these laws include:
 
Ø  the federal Clean Air Act and analogous state laws that impose obligations related to air emissions;


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Ø  the federal Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the Superfund law, and analogous state laws that regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
 
Ø  the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
 
Ø  the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities; and
 
Ø  the Toxic Substances Control Act, also known as TSCA, and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.
 
These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations.
 
There is an inherent risk of incurring significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbon wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering or transportation systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance. Please read “Business—Environmental matters” for more information.
 
Our construction of new assets may not result in revenue increases and will be 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 involve numerous regulatory, environmental, political and legal uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For


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instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could 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 often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in that 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 as a result of the 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. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems 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 Anadarko were to limit divestitures of midstream assets to us or if we were to be unable to make acquisitions on economically acceptable terms from Anadarko or third parties, our future growth would be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.
 
Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including, most notably, Anadarko. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our distributions to our unitholders.
 
If we are unable to make accretive acquisitions from Anadarko or third parties, either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
 
Any acquisition involves potential risks, including, among other things:
 
Ø  mistaken assumptions about volumes, revenues and costs, including synergies;
 
Ø  an inability to successfully integrate the assets or businesses we acquire;
 
Ø  the assumption of unknown liabilities;
 
Ø  limitations on rights to indemnity from the seller;
 
Ø  mistaken assumptions about the overall costs of equity or debt;
 
Ø  the diversion of management’s and employees’ attention from other business concerns;
 
Ø  unforeseen difficulties operating in new geographic areas; and
 
Ø  customer or key employee losses at the acquired businesses.
 
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.


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Risk factors
 
 
 
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
 
We do not own all of the land on which our pipelines and facilities have been constructed, 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 if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on 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 or otherwise, 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 for which we are not fully insured, our operations and financial results could be adversely affected.
 
Our operations are subject to all of the risks and hazards inherent in the gathering, compressing, treating and transportation of natural gas, including:
 
Ø  damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
 
Ø  inadvertent damage from construction, farm and utility equipment;
 
Ø  leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
 
Ø  leaks of natural gas containing hazardous quantities of hydrogen sulfide from our Pinnacle gathering system or Bethel treating facility;
 
Ø  fires and explosions; and
 
Ø  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. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might incur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.


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Risk factors
 
 
We are exposed to the credit risk of Anadarko, and any material non-payment or non-performance by Anadarko, including with respect to our gathering and transportation agreements and our $337.6 million note receivable, could reduce our ability to make distributions to our unitholders.
 
We are dependent on Anadarko for the majority of our revenues. In addition, we anticipate using the proceeds of this offering to make a loan to Anadarko. Consequently, we are subject to the risk of non-payment or non-performance by Anadarko, including with respect to our gathering and transportation agreements and our $337.6 million note receivable. Any such non-payment or non-performance could reduce our ability to make distributions to our unitholders. Furthermore, Anadarko is subject to its own financial, operating and regulatory risks, which could increase the risk of default on its obligations to us. We cannot predict the extent to which Anadarko’s business would be impacted if conditions in the energy industry were to deteriorate nor can we estimate the impact such conditions would have on Anadarko’s ability to perform under our gathering and transportation agreements or note receivable. Further, unless and until we receive full repayment of the $337.6 million note from Anadarko, we will be subject to the risk of non-payment or late payment of the interest payments and principal of the note. Interest income on the note receivable from Anadarko will be allocated in accordance with the general profit and loss allocation provisions included in our partnership agreement. Accordingly, any material non-payment or non-performance by Anadarko could reduce our ability to make distributions to our unitholders.
 
Anadarko’s credit facility and other debt instruments contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future may be affected by Anadarko’s credit rating.
 
We have the ability to incur up to $100 million of indebtedness under Anadarko’s $750 million credit facility. However, this $100 million of borrowing capacity will be available to us only to the extent that sufficient amounts remain unborrowed by Anadarko. As a result, borrowings by Anadarko could restrict our access to credit. In addition, if we or Anadarko were to fail to comply with the terms of Anadarko’s credit facility, we could be unable to make any borrowings under Anadarko’s credit facility, even if capacity were otherwise available. As a result, the restrictions in Anadarko’s credit facility could adversely affect our ability to finance our future operations or capital needs or to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
 
Anadarko’s and our ability to comply with the terms of Anadarko’s debt instruments may be affected by events beyond its and our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Anadarko’s and our ability to comply with the terms of Anadarko’s debt instruments may be impaired. We and Anadarko are subject to financial covenants and ratios under Anadarko’s credit facility. Should we or Anadarko fail to comply with such financial covenants and ratios, we could be unable to make any borrowings under Anadarko’s credit facility. Additionally, a default by Anadarko under one of Anadarko’s debt instruments may cause a cross-default under Anadarko’s other debt instruments, including the credit facility under which we are a co-borrower. Accordingly, a breach by Anadarko of certain of the covenants or ratios in another debt instrument could cause the acceleration of any indebtedness we have outstanding under the credit facility. In the event of an acceleration, we might not have, or be able to obtain, sufficient funds to make the required repayments of debt, finance our operations and pay distributions to unitholders. For more information regarding our debt agreements, please read “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources.”
 
Due to our relationship with Anadarko, our ability to obtain credit will be affected by Anadarko’s credit rating. Even if we obtain our own credit rating or separate financing arrangement, any future change in Anadarko’s credit rating would likely also result in a change in our credit rating. Regardless


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Risk factors
 
 
of whether we have our own credit rating, a downgrading of Anadarko’s credit rating could limit our ability to obtain financing in the future upon favorable terms or at all.
 
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
 
Our future level of debt could have important consequences to us, including the following:
 
Ø  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;
 
Ø  our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
 
Ø  we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
 
Ø  our flexibility in responding to changing business and economic conditions may be limited.
 
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 any 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 or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
 
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
Interest rates may increase in the future to counter possible inflation. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank 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, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
 
RISKS INHERENT IN AN INVESTMENT IN US
 
Anadarko owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Anadarko and our general partner have conflicts of interest and may favor Anadarko’s interests to your detriment.
 
Following this offering, Anadarko will own and control our general partner, as well as appoint all of the officers and directors of our general partner, some of whom will also be officers of Anadarko. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Anadarko. Conflicts of interest may arise between Anadarko and 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


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interests of Anadarko over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
 
Ø  Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.
 
Ø  Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.
 
Ø  Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.
 
Ø  The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly.
 
Ø  Our partnership agreement limits the liability of and reduces the fiduciary duties owed by of our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.
 
Ø  Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
 
Ø  Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
 
Ø  Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.
 
Ø  Our general partner determines which costs incurred by it are reimbursable by us.
 
Ø  Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.
 
Ø  Our partnership agreement permits us to classify up to $27.1 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.
 
Ø  Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
 
Ø  Our general partner intends to limit its liability regarding our contractual and other obligations.
 
Ø  Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
 
Ø  Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
 
Ø  Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
Ø  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 special committee of the board of directors of our general partner or our


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unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
Please read “Conflicts of interest and fiduciary duties.”
 
Anadarko is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.
 
Anadarko is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, Anadarko may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Anadarko may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed.
 
Cost reimbursements due to Anadarko and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to you. The amount and timing of such reimbursements will be determined by our general partner.
 
Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by Anadarko and our general partner in managing and operating us. While our reimbursement of allocated general and administrative expenses is capped under the omnibus agreement, we are required to reimburse Anadarko and our general partner for all direct operating expenses incurred on our behalf. These direct operating expense reimbursements and the reimbursement of incremental general and administrative expenses we will incur as a result of becoming a publicly traded partnership are not capped. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursements to Anadarko and our general partner will reduce the amount of cash otherwise available for distribution to our unitholders.
 
Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
 
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
 
We expect that we will distribute all of our available cash to our unitholders and 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. Furthermore, we anticipate using substantially all of the net proceeds of this offering to


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make a loan to Anadarko, and therefore, the net proceeds of this offering will not be directly used to grow our business.
 
In addition, because we distribute all of our available cash, our growth may not be as fast as that of 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. There are no limitations in our partnership agreement or in Anadarko’s credit facility, under which we are a co-borrower, 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 partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.
 
Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
 
Ø  how to allocate corporate opportunities among us and its affiliates;
 
Ø  whether to exercise its limited call right;
 
Ø  how to exercise its voting rights with respect to the units it owns;
 
Ø  whether to exercise its registration rights;
 
Ø  whether to elect to reset target distribution levels; and
 
Ø  whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.
 
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of interest and fiduciary duties—Fiduciary duties.”
 
Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:
 
Ø  provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;


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Ø  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 such decisions are made in good faith, meaning that it believed that the decision was in the best interest of our partnership;
 
Ø  provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, 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
 
Ø  provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:
 
  (a)  approved by the special committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
 
  (b)  approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
 
  (c)  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
  (d)  fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the special committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 
Our general partner may elect to cause us to issue Class B and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the special committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
 
Our general partner has the right, at any 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 target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal 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.
 
If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of Class B units and general partner 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 to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on


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the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. 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. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued Class B units, which are entitled to distributions 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 a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new Class B units and general partner units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of our partnership agreement relating to cash distributions—General partner’s right to reset target distribution levels.”
 
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 have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will be chosen by Anadarko. Furthermore, if the unitholders are 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. 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.
 
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
 
The unitholders initially will be unable 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 our general partner. Following the closing of this offering, Anadarko will own 58.5% of our 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 our general partner liable for actual fraud, gross negligence 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 our 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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Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
 
Unitholders’ voting rights are further restricted by a provision of our partnership agreement 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 general partner interest or the 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 Anadarko to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner 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 designees and thereby exert significant control over the decisions made by the board of directors and officers.
 
You will experience immediate and substantial dilution in pro forma net tangible book value of $5.09 per common unit.
 
The estimated initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $14.91 per unit. Based on the estimated initial public offering price of $20.00 per common unit, you will incur immediate and substantial dilution of $5.09 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”
 
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:
 
Ø  our existing unitholders’ proportionate ownership interest in us will decrease;
 
Ø  the amount of cash available for distribution on each unit may decrease;
 
Ø  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;
 
Ø  the ratio of taxable income to distributions may increase;
 
Ø  the relative voting strength of each previously outstanding unit may be diminished; and
 
Ø  the market price of the common units may decline.
 
Anadarko may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
 
After the sale of the common units offered by this prospectus, assuming that the underwriters do not exercise their option to purchase additional common units, Anadarko will hold an aggregate of 3,823,925 common units and 22,573,925 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain


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circumstances. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
 
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, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is 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 completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, Anadarko will own approximately 16.9% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Anadarko will own approximately 58.5% of our outstanding common units. For additional information about this right, please read “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 a number of other states. 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 were to determine that:
 
Ø  we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
Ø  your right to act with other unitholders to remove or replace our 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 read “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 an 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 both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.


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Risk factors
 
 
There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.
 
Prior to this offering, there has been no public market for our common units. After this offering, there will be only 18,750,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. In addition, Anadarko will own 3,823,925 common and 22,573,925 subordinated units, representing an aggregate 57.3% ownership interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
 
The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:
 
Ø  our quarterly distributions;
 
Ø  our quarterly or annual earnings or those of other companies in our industry;
 
Ø  the loss of a large customer;
 
Ø  announcements by us or our competitors of significant contracts or acquisitions;
 
Ø  changes in accounting standards, policies, guidance, interpretations or principles;
 
Ø  general economic conditions;
 
Ø  the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;
 
Ø  future sales of our common units; and
 
Ø  other factors described in these “Risk factors.”
 
We will incur increased costs as a result of being a publicly traded partnership.
 
We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the New York Stock Exchange, or the NYSE, have required changes in the corporate governance practices of publicly traded companies. We expect these 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 partnership, we are required to have at least three independent directors, create an audit committee 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 partnership 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 to possibly result in our general partner having to accept reduced policy limits and 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 partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate. These costs are not


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subject to the $6.0 million cap in the omnibus agreement applicable to general and administrative expenses allocable to us by Anadarko.
 
If we are deemed to be an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.
 
Our initial assets will consist of our ownership interests in our operating subsidiaries as well as a $337.6 million note receivable from Anadarko. If this note receivable together with a sufficient amount of our other assets are deemed to be “investment securities,” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or contract rights so as to fall outside of the definition of investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
 
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. If we were taxed as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as an investment company 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. For a discussion of the federal income tax implications that would result from our treatment as a corporation in any taxable year, please read “Material tax consequences—Partnership status.”
 
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.
 
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 IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in our 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 Internal Revenue Service, or the IRS, on this or any other tax matter affecting us.
 
Despite the fact that we are classified as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.


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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, deductions or credits 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, if we are deemed to be an investment company, as described above, we would be subject to such taxation. Moreover, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment such that it would apply to us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
 
At the state level, were we to be subject to federal income tax, we would also be subject to the income tax provisions of many states. Moreover, because of widespread state budget deficits and other reasons, several states are evaluating ways to independently subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Specifically, beginning in 2008, we will be required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by Texas and, if applicable, by any other state will reduce the cash available for distribution to you.
 
Our 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 may be adjusted to reflect the impact of that law on us.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material tax consequences—Disposition of common units—Allocations between transferors and transferees.”
 
If the IRS contests the federal income tax positions we take or the pricing of our related party agreements with Anadarko, the market for our common units may be adversely impacted and the cost of any IRS 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, including the pricing of our related party agreements with Anadarko. The IRS may adopt positions that differ from the conclusions of our


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Risk factors
 
 
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. For example, the IRS may reallocate items of income, deductions, credits or allowances between related parties if the IRS determines that such reallocation is necessary to prevent evasion of taxes or clearly to reflect the income of any such related parties. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. If the IRS were successful in any such challenge, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders and our general partner. Such a reallocation may require us and our unitholders to file amended tax returns. 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 will 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 whether or not you receive 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 the 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. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you, if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material tax consequences—Disposition of common units—Recognition of gain or loss” for a further discussion of the foregoing.
 
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
 
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), 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 U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.


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Risk factors
 
 
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, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine on the validity of such filing positions. 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 your 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. Please read “Material tax consequences—Tax consequences of unit ownership—Section 754 election” for a further discussion of the effect of the depreciation and amortization positions we adopt.
 
We will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
 
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
 
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. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties, if we are unable to determine that a termination occurred. Please read “Material tax consequences—Disposition of common units—Constructive termination” for a discussion of the consequences of our termination for federal income tax purposes.


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Risk factors
 
 
You will likely 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 will likely be subject to 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 conduct business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various 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 states of Kansas, Oklahoma, Texas, Utah and Wyoming. Each of these states, other than Texas and Wyoming, currently imposes a personal income tax, and all of theses states also impose income taxes on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, 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 gross proceeds of approximately $375.0 million from the issuance and sale of 18,750,000 common units offered by this prospectus. We will use these proceeds to (i) make a loan of $337.6 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.00%, (ii) provide $10.0 million for general partnership purposes and (iii) pay underwriting discounts and a structuring fee totaling approximately $24.4 million and other estimated offering expenses of $3.0 million.
 
Our estimates assume an initial public offering price of $20.00 per common unit and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and the structuring fee, to increase or decrease by $17.5 million. If the proceeds increase due to a higher initial public offering price, we will use the additional proceeds to reimburse Anadarko for capital expenditures it incurred with respect to the assets contributed to us during the two-year period prior to this offering. If the proceeds decrease due to a lower initial public offering price, our loan to Anadarko will decrease by such amount.
 
The proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to reimburse Anadarko for capital expenditures it incurred with respect to the assets contributed to us during the two-year period prior to this offering.
 
Anadarko has informed us that it intends to use the $337.6 million of proceeds that we loan to it, and any other proceeds that it receives from this offering, to repay a portion of the amount outstanding under its 354-day credit facility. Affiliates of UBS Securities LLC are lenders under this facility and will receive their proportionate shares of any such repayment. Please read “Underwriting—Affiliations.”


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Capitalization
 
The following table shows:
 
Ø  the historical capitalization of our Predecessor as of September 30, 2007; and
 
Ø  our pro forma as adjusted capitalization as of September 30, 2007, reflecting this offering of 18,750,000 common units at an assumed initial public offering price of $20.00, the other formation transactions described under “Prospectus 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 combined 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.”
 
               
    As of
    September 30, 2007
          Pro forma as
    Historical     adjusted(1)
 
    (in millions)
 
Debt
  $     $
Total partners’ equity/parent net equity:
             
Parent net equity
    273.5        
Common units—public(2)(3)
          347.6
Common units—Anadarko(2)(3)
          48.2
Subordinated units—Anadarko(2)
          284.2
General partner units(2)
          11.6
               
Total partners’ equity/parent net equity
    273.5       691.6
               
Total capitalization
  $ 273.5     $ 691.6
               
 
 
(1) On a pro forma as adjusted basis, as of September 30, 2007, the public and Anadarko would have held 18,750,000 and 3,823,925 common units, respectively, Anadarko would have held 22,573,925 subordinated units and our general partner would have held 921,385 general partner units representing a 2.0% general partner interest in us.
 
(2) An increase or decrease in the initial public offering price of $1.00 per common unit would cause the public common unitholders’ capital to increase or decrease by $17.5 million, and in the case of an increase, would cause a $17.5 million decrease in the partners’ capital of Anadarko.
 
(3) A 1,000,000 unit increase in the number of common units issued to the public would result in an $18.7 million increase in the public common unitholders’ capital and an $18.7 million decrease in the partners’ capital of Anadarko.


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Dilution
 
Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2007, 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 was $686.8 million, or $14.91 per unit. Net tangible book value excludes $4.8 million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:
 
                 
Initial public offering price per common unit
           $ 20.00  
Net tangible book value per unit before the offering(1)
    9.84                
Increase in net tangible book value per unit attributable to purchasers in the offering
    5.07          
                 
Less: Pro forma net tangible book value per unit after the offering(2)
             14.91  
                 
Immediate dilution in tangible net book value per common unit to purchasers in the offering(3)
           $ 5.09  
                 
 
 
(1) Determined by dividing the number of units (3,823,925 common units, 22,573,925 subordinated units and 921,385 general partner units) to be issued to our general partner and its affiliates, including Anadarko, for the contribution of assets and liabilities to Western Gas Partners, LP into the net tangible book value of the contributed assets and liabilities.
 
(2) Determined by dividing the total number of units to be outstanding after the offering (22,573,925 common units, 22,573,925 subordinated units and 921,385 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, then dilution in net tangible book value per common unit would equal $6.09 and $4.47, respectively.
 
The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates 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  
   
                (in thousands)  
 
General partner and affiliates(1)(2)(3)
    27,319,235       59.3 %   $ 273,507       42.2 %
Purchasers in the offering
    18,750,000       40.7 %     375,000       57.8 %
                                 
Total
    46,069,235       100.0 %   $ 648,507       100.0 %
                                 
 
 
(1) The units acquired by our general partner and its affiliates, including Anadarko, consist of 3,823,925 common units, 22,573,925 subordinated units and 921,385 general partner units.
 
(2) The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of September 30, 2007, equals parent net investment, which was $273.5 million and is not affected by this offering.
 
(3) Assumes the underwriters’ option to purchase additional common units is not exercised.


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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 the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “Assumptions and considerations.” In addition, please 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 combined financial statements, and the notes thereto, 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 cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing rather than retaining our available cash. Generally, our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and cash on hand resulting from working capital borrowings made after the end of the quarter.
 
Limitations on cash distributions and our ability to change our cash distribution policy
 
There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:
 
Ø  Our general partner 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 or increase of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. 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.
 
Ø  While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Anadarko) and the Class B units issued upon the reset of incentive distribution rights, if any, voting as a single class after the subordination period has ended. At the closing of this offering, Anadarko will own our general partner and approximately 58.5% of our outstanding common and subordinated units.
 
Ø  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.
 
Ø  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.


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Our cash distribution policy and restrictions on distributions
 
 
Ø  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 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 that of 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. There are no limitations in our partnership agreement, Anadarko’s credit facility, under which we are a co-borrower, or our working capital 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 MINIMUM QUARTERLY DISTRIBUTION
 
Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare a minimum quarterly distribution of $0.30 per unit per complete quarter, or $1.20 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, 2008. This equates to an aggregate cash distribution of $13.8 million per quarter, or $55.3 million per year, based on the number of common, subordinated and general partner units to be outstanding immediately after the completion of this offering.
 
If the underwriters do not exercise their option to purchase additional common units within the 30-day option period, we will issue 2,812,500 common units to Anadarko at the expiration of this period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Anadarko. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Underwriting.”
 
Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest. The table below sets forth the assumed number of outstanding common, subordinated and general partner units upon the closing of this offering, assuming the underwriters do not exercise their option to purchase additional common units, and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $0.30 per unit per quarter ($1.20 per unit on an annualized basis).
 


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Our cash distribution policy and restrictions on distributions
 
 
                   
    Minimum quarterly distributions
    Number of units   One quarter   Annualized
 
 
Publicly held common units
    18,750,000   $ 5,625,000   $ 22,500,000
Common units held by Anadarko(1)
    3,823,925     1,147,178     4,588,710
Subordinated units held by Anadarko
    22,573,925     6,772,178     27,088,710
General partner units held by our general partner
    921,385     276,416     1,105,662
                   
Total
    46,069,235   $ 13,820,772   $ 55,283,082
                   
 
 
(1) Assumes the underwriters do not exercise their option to purchase 2,812,500 common units and that the 2,812,500 common units will be issued to Anadarko upon the expiration of the underwriters’ 30-day option period. Accordingly, irrespective of whether the underwriters exercise their option to purchase additional common units, the total number of common units we have outstanding upon the completion of this offering and the expiration of the option period will not be impacted.
 
The subordination period generally will end if we have earned and paid at least $1.20 on each outstanding common and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2010. If we have earned and paid at least $0.45 (150% of the minimum quarterly distribution, which is $1.80 on an annualized basis) on each outstanding common and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each quarter in 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 read the “Provisions of our partnership agreement relating to cash distributions—Subordination period.”
 
If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of our partnership agreement relating to cash distributions—Subordination period.”
 
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. 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, 2008 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 minimum quarterly distribution of $0.30 per unit each quarter through the quarter ending December 31, 2008. In those sections, we present two tables, consisting of:
 
Ø  “Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution on a pro forma basis for our fiscal year ended December 31, 2006 and the twelve months ended September 30, 2007, derived from our unaudited pro forma combined financial statements that are included in this prospectus, as adjusted to give pro forma effect to the offering and the formation transactions; and

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Our cash distribution policy and restrictions on distributions
 
 
Ø  “Statement of Estimated Adjusted EBITDA,” in which we demonstrate our ability to generate the minimum estimated Adjusted EBITDA necessary for us to pay the minimum quarterly distribution on all units for each quarter in the twelve months ending December 31, 2008.
 
UNAUDITED PRO FORMA AVAILABLE CASH FOR THE YEAR ENDED DECEMBER 31, 2006 AND THE TWELVE MONTHS ENDED SEPTEMBER 30, 2007
 
If we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma available cash generated for the year ended December 31, 2006 would have been approximately $63.3 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of our common and subordinated units for such period.
 
If we had completed the transactions contemplated in this prospectus on October 1, 2006, our pro forma available cash generated for the twelve months ended September 30, 2007 would have been approximately $59.0 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of our common and subordinated units for such period.
 
Unaudited pro forma available cash includes incremental revenue we expect to receive pursuant to the new gas gathering agreements we have entered into with Anadarko. These new gathering agreements include fees for gathering and treating that are higher than those reflected in our historical financial results.
 
Unaudited pro forma available cash also includes general and administrative expenses, which were calculated on a different basis as compared to historical periods. These general and administrative expenses are expected to total $8.5 million annually and consist of $6.0 million of general and administrative expenses allocated to us by Anadarko as well as $2.5 million of general and administrative expenses we expect to incur as a result of becoming a publicly traded partnership. Under the omnibus agreement, our reimbursement to Anadarko for certain general and administrative expenses it allocates to us will be capped at $6.0 million annually through December 31, 2009, subject to adjustments to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.” General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. These expenses are not reflected in the historical combined financial statements of our Predecessor or our pro forma combined 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 combined 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.


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Our cash distribution policy and restrictions on distributions
 
 
The following table illustrates, on a pro forma basis, for the year ended December 31, 2006 and for the twelve months ended September 30, 2007, the amount of cash that would have been available for distribution to our unitholders, assuming in each case that this offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.
 
PARTNERSHIP UNAUDITED PRO FORMA AVAILABLE CASH
 
                 
          Twelve months
 
    Year ended
    ended
 
    December 31,
    September 30,
 
    2006     2007  
   
    (in millions, except per unit data)  
 
Net income(1):
  $ 14.1     $ 21.7  
Add:
               
Other income (expense)
    0.4        
Depreciation(2)
    19.7       22.5  
Income taxes(2)
    6.2       12.5  
Interest expense(2)
    9.1       8.3  
                 
Adjusted EBITDA(3):
    49.5       65.0  
                 
Add:
               
Pro forma net cash interest income(4)
    20.3       20.3  
Pro forma incremental Anadarko contract revenue(5)
    38.5       28.0  
Less:
               
General and administrative expenses of being a publicly traded partnership(6)
    2.5       2.5  
Pro forma net cash interest expense(7)
    0.2       0.2  
Capital expenditures(8)
    42.3       51.6  
                 
Pro forma available cash
  $ 63.3     $ 59.0  
                 
Pro forma cash distributions
               
Distributions per unit(9)
  $ 1.20     $ 1.20  
Distributions to public common unitholders(9)
  $ 22.5     $ 22.5  
Distributions to Anadarko and our general partner(9)
    32.8       32.8  
                 
Total distributions
  $ 55.3     $ 55.3  
                 
Excess
  $ 8.0     $ 3.7  
                 
Percent of minimum quarterly distributions payable to common unitholders
    100 %     100 %
Percent of minimum quarterly distributions payable to subordinated unitholders
    100 %     100 %
 
 
(1) Reflects pro forma net income of our Predecessor as if the acquisition of MIGC occurred on (i) January 1, 2006 for the year ended December 31, 2006 and (ii) October 1, 2006 for the twelve months ended September 30, 2007, derived from our Predecessor’s combined financial statements.
 
(2) Reflects an adjustment to reconcile net income to Adjusted EBITDA.
 
(3) We define Adjusted EBITDA as net income (loss), plus interest expense, income taxes and depreciation, less interest income and other income (expense). For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus Summary—Non-GAAP financial measure.”


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(4) Represents interest income we expect to receive annually with respect to the $337.6 million 30-year note bearing interest at a fixed annual rate of 6.00% that we will receive from Anadarko concurrently with the closing of this offering.
 
(5) Represents incremental revenue we expect to receive pursuant to the new gas gathering agreements we have entered into with Anadarko. These new gathering agreements include fees for gathering and treating that are higher than the fees reflected in our historical financial results. If the new gathering agreements had been in place for the year ended December 31, 2006 and the twelve months ended September 30, 2007, the average rate received for our gathering and treating volumes would have increased by $0.13/Mcf and $0.09/Mcf, respectively.
 
(6) Reflects an adjustment to our Adjusted EBITDA for estimated cash expenses associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. We expect these expenses to total approximately $2.5 million per year.
 
(7) Represents estimated cash interest expense related to annual commitment fees of 0.175% on Anadarko’s credit facility, under which we are a co-borrower, and our working capital facility.
 
(8) For the year ended December 31, 2006 and for the twelve months ended September 30, 2007, our capital expenditures were $42.3 million and $51.6 million, respectively. The capital expenditures are assumed to have occurred ratably throughout the year. For these periods, capital expenditures include both maintenance and expansion capital expenditures (excluding $18.0 million for compressor lease repurchases for the twelve months ended September 30, 2007) because we did not segregate these costs in historic periods. If we were able to isolate these costs, we would reflect borrowings to offset expansion capital expenditures and our pro forma available cash would be reduced by incremental interest expense on those borrowings as opposed to being reduced by the entire amount of such expansion capital expenditures in the table presented above. The $18.0 million for compressor lease repurchases was excluded because during the twelve months ended September 30, 2007, Anadarko exercised its early buyout option contained in three of its compressor leases, under which compressors were leased from a third party to Anadarko and subleased by Anadarko to us. Anadarko then transferred the compressors to us as a contribution to our capital. Absent this offering, these leases would have been refinanced and no capital expenditures would have been incurred.
 
(9) The table above is based on the assumption that the underwriters’ option has not been exercised and the 30-day option period for such exercise has expired. Set forth below is the assumed number of outstanding common, subordinated and general partner units upon the closing of this offering and expiration of the underwriters’ option period, and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $0.30 per unit per quarter ($1.20 per unit on an annualized basis).
 
                       
        Minimum quarterly distributions  
    Number of units   One quarter     Annualized  
   
 
Publicly held common units
    18,750,000   $ 5,625,000     $ 22,500,000  
Common units held by Anadarko(a)
    3,823,925     1,147,178       4,588,710  
Subordinated units held by Anadarko
    22,573,925     6,772,178       27,088,710  
General partner units held by our general partner
    921,385     276,416       1,105,662  
                       
Total
    46,069,235   $ 13,820,772     $ 55,283,082  
                       
 
 
(a) The number of common units held by Anadarko includes 2,812,500 common units subject to the underwriters’ option to purchase additional common units. If and to the extent this option is exercised, the remainder of these common units, if any, will be issued to Anadarko at the expiration of the underwriters’ option period.


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ESTIMATED ADJUSTED EBITDA FOR THE TWELVE MONTHS ENDING DECEMBER 31, 2008
 
Set forth below is a Statement of Estimated Adjusted EBITDA that reflects our ability to generate sufficient cash flow to pay the minimum quarterly distribution on all of our outstanding units for each quarter in the twelve months ending December 31, 2008. The financial forecast presents, to the best of our knowledge and belief, the expected results of operations, Adjusted EBITDA and cash available for distribution for the forecast period. We define Adjusted EBITDA as net income (loss), plus interest expense, income taxes, and depreciation, less interest income and other income (expense).
For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP financial measure.”
 
Our minimum estimated Adjusted 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 pay the minimum quarterly distribution on all of our outstanding units and the corresponding distributions on our general partner’s 2.0% interest for each quarter in the twelve months ending December 31, 2008. The assumptions discussed below under “—Assumptions and considerations” are those that we believe are significant to our ability to generate our minimum estimated Adjusted EBITDA. We believe our actual results of operations and cash flows will be sufficient to generate the minimum estimated Adjusted EBITDA; however, we can give you no assurance that we will generate the minimum estimated Adjusted EBITDA. There will likely be differences between our minimum estimated Adjusted EBITDA and our actual results and those differences could be material. If we fail to generate the minimum estimated Adjusted EBITDA, we may not be able to pay the minimum quarterly distribution on our common units. In order to fund distributions to our unitholders at our initial rate of $1.20 per unit for the twelve months ending December 31, 2008, our minimum estimated Adjusted EBITDA for the twelve months ending December 31, 2008 must be at least $63.7 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 Adjusted EBITDA and related assumptions set forth below to substantiate our belief that we will have sufficient available cash to pay the minimum quarterly distribution to all our unitholders for each quarter in the twelve months ending December 31, 2008. This forecast is a forward-looking statement and should be read together with the historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s discussion and analysis of financial condition and results of operations.” 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, was 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 Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the minimum quarterly distribution to all unitholders for each quarter in the twelve months ending December 31, 2008. 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.
 
Neither our independent auditors nor any other independent accountants have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information.
 
When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk factors.” Any of the risks discussed in this prospectus, to the extent they are


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realized, could cause our actual results of operations to vary significantly from those which would enable us to generate the minimum estimated Adjusted EBITDA.
 
We are providing the minimum estimated Adjusted EBITDA calculation to supplement our pro forma and historical combined financial statements in support of our belief that we will have sufficient available cash to pay the minimum quarterly distribution on all of our outstanding common and subordinated units for each quarter in the twelve months ending December 31, 2008. Please read 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 financial forecast or to update this financial forecast 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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PARTNERSHIP STATEMENT OF ESTIMATED ADJUSTED EBITDA
 
         
    Twelve months ending
 
    December 31,
 
    2008  
   
    (in millions)  
 
Total operating revenues
  $ 126.0  
Costs and expenses:
       
Operating and maintenance expense
    (48.5 )
General and administrative expense
    (8.5 )
Depreciation and amortization expense
    (24.0 )
         
Operating income
    45.0  
Interest expense
    (0.4 )
Interest income — Anadarko note
    20.3  
Texas margin tax
    (0.3 )
         
Net income
  $ 64.6  
Adjustments to reconcile net income to estimated Adjusted EBITDA:
       
Add:
       
Depreciation and amortization expense
    24.0  
Interest expense
    0.4  
Texas margin tax
    0.3  
Less:
       
Interest income — Anadarko note
    (20.3 )
         
Estimated Adjusted EBITDA(1)
  $ 69.0  
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
       
Less:
       
Cash interest expense
    (0.4 )
Estimated expansion capital expenditures
    (15.9 )
Estimated maintenance capital expenditures
    (28.0 )
Texas margin tax
    (0.3 )
Add:
       
Cash interest income — Anadarko note
    20.3  
Cash on hand and borrowings for expansion capital expenditures
    15.9  
         
Estimated cash available for distribution
  $ 60.6  
         
Aggregate annualized minimum quarterly distributions
    55.3  
Excess of cash available for distribution over aggregate annualized minimum quarterly distributions
    5.3  
         
Calculation of minimum estimated Adjusted EBITDA necessary to pay aggregate annualized minimum quarterly distributions:
       
Estimated Adjusted EBITDA
    69.0  
Excess of cash available for distribution over aggregate annualized minimum quarterly distributions
    (5.3 )
         
Minimum estimated Adjusted EBITDA necessary to pay aggregate annualized minimum quarterly distributions
  $ 63.7  
         
 
 
(1) We define Adjusted EBITDA as net income (loss), plus interest expense, income taxes and depreciation, less interest income and other income (expenses). For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP financial measure.”


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ASSUMPTIONS AND CONSIDERATIONS
 
We believe the assumptions and estimates we have made to demonstrate our ability to generate the minimum estimated Adjusted EBITDA, which are set forth below, are reasonable. We define Adjusted EBITDA as net income (loss), plus interest expense, income taxes and depreciation, less interest income and other income (expenses). For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP financial measure.”
 
General considerations
 
Ø  Revenues and operating expenses are net of intercompany transactions.
 
Ø  Realized gathering throughput volume is the primary factor that will influence whether the amount of cash available for distribution for the twelve months ending December 31, 2008 is above or below our forecast. For example, if all other assumptions are held constant, a 5.0% decline in volumes below forecasted levels would result in a $5.0 million decline in revenues. Additionally, a 5.0% decline in the trading margin between condensate and natural gas would result in a $0.2 million decline in cash available for distribution. A decline in forecasted cash flow of greater than $5.3 million would result in our generating less than the minimum cash required to pay distributions.
 
Ø  Transportation volumes are provided pursuant to firm and interruptible transportation arrangements.
 
Total operating revenue
 
We estimated total operating revenue for the twelve months ending December 31, 2008 based on the following significant assumptions:
 
Ø  Gathering and treating volumes.  We estimate that we will gather and/or treat an average of 812 MMcf/d of natural gas for the twelve months ending December 31, 2008 as compared to 845 MMcf/d for the year ended December 31, 2006 and 870 MMcf/d for the twelve months ended September 30, 2007. The decreased volumes estimated for the twelve months ending December 31, 2008 are primarily due to the end of an interim agreement for treating services on approximately 40 MMcf/d at our Pinnacle gas treating facility, together with the natural production declines from the wells connected to our systems, partially offset by new well connections.
 
Ø  Gathering and treating fees.  We estimate that we will receive an average gathering and treating fee of $0.34/Mcf for the twelve months ending December 31, 2008 as compared to $0.21/Mcf for the year ended December 31, 2006 and $0.25/Mcf for the twelve months ended September 30, 2007. The expected increase in our gathering and treating fees is due to the new gathering and treating agreements that we recently negotiated with Anadarko.
 
Ø  Gathering and treating revenues.  We estimate that gathering and treating revenues for the twelve months ending December 31, 2008 will be $102.1 million as compared to $65.0 million for the year ended December 31, 2006 and $78.1 million for the twelve months ended September 30, 2007.
 
The expected increase in gathering and treating revenues for the twelve months ending December 31, 2008 as compared to the year ended December 31, 2006 and the twelve months ended September 30, 2007 of approximately $37.1 million and $24.0 million, respectively, is primarily due to higher gathering and treating revenues of $39.8 million and $29.3 million, respectively, attributable to an increase of $0.13/Mcf and $0.09/Mcf, respectively, in average gathering and treating fees offset by a decrease of $2.7 million and $5.3 million, respectively, due to decreased average volumes.
 
Our higher gathering and treating revenues reflect the employee benefit costs specifically identified and associated with operational personnel working on our assets. All of these costs will be


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recovered by us following this offering through the gathering rates we will charge Anadarko under the new gas gathering agreements. For the year ended December 31, 2006 and the twelve months ended September 30, 2007, only those employee benefit costs reasonably allocated by Anadarko to us were included in and recovered through the gathering and treating fees we charged Anadarko.
 
Ø  Transportation volumes.  We estimate that we will transport an average of 178 MMcf/d of natural gas for the twelve months ending December 31, 2008 as compared to 126 MMcf/d for the year ended December 31, 2006 and 134 MMcf/d for the twelve months ended September 30, 2007. The increase in forecasted volumes is primarily attributable to an additional 45 MMcf/d of firm capacity that was contracted for by Anadarko in connection with the recent expansion of the MIGC system. Our transportation volumes increased by an average of 71 Mcf/d as a result of the inclusion of MIGC for the full year ended December 31, 2006.
 
Ø  Transportation fees.  We estimate that we will receive an average of $0.30/Mcf for the twelve months ended December 31, 2008 as compared to $0.37/Mcf for the year ended December 31, 2006 and $0.37/Mcf for the twelve months ended September 30, 2007. Our anticipated transportation fees are consistent with fees realized on a historical basis and contained in the FERC-approved rates for MIGC.
 
Ø  Transportation revenues.  We estimate that transportation revenues for the twelve months ending December 31, 2008 will be $18.9 million as compared to $17.0 million for the year ended December 31, 2006 and $18.0 million for the twelve months ended September 30, 2007.
 
The expected increase in transportation revenues for the twelve months ending December 31, 2008 as compared to the year ended December 31, 2006 and the twelve months ended September 30, 2007 of approximately $1.9 million and $0.9 million, respectively, is primarily due to higher transportation revenues attributable to increased volumes, partially offset by lower rates.
 
Ø  Condensate margin.  We estimate that we will receive an aggregate condensate margin of $5.0 million for the twelve months ending December 31, 2008 as compared to $3.7 million for the year ended December 31, 2006 and $4.1 million for the twelve months ended September 30, 2007. The expected margin increase is due primarily to a higher forecasted spread between crude oil and natural gas prices in 2008 ($76.00/Bbl and $7.82/Mcf, respectively, based on NYMEX prices as of September 28, 2007) than existed in the year ended December 31, 2006 ($66.22/Bbl and $7.23/Mcf, respectively) and in the twelve months ended September 30, 2007 ($57.64/Bbl and $6.01/Mcf, respectively). Condensate margin is the difference between the revenue from sale of condensate recovered during the gathering of natural gas and the cost of the natural gas required to deliver the same thermal content to the shipper.
 
Operating and maintenance expense
 
We estimate that total operating and maintenance expense for the twelve months ending December 31, 2008 will be $48.5 million as compared to $43.9 million for the year ended December 31, 2006 and $43.8 million for the twelve months ended September 30, 2007. The expected increase in operating and maintenance expense for the twelve months ending December 31, 2008 as compared to the year ended December 31, 2006 and the twelve months ended September 30, 2007 of $4.6 million and $4.7 million, respectively, is primarily due to higher expected labor, maintenance and contract services costs. Operating and maintenance expense is comprised primarily of direct labor, insurance, property taxes, repair and maintenance, contract services, utility costs and services provided to us or on our behalf under our services and secondment agreement.
 
Our higher expected labor expense is attributable to us bearing all of the employee benefit costs specifically identified and associated with the operational personnel working on our assets. For the year

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ended December 31, 2006 and the twelve months ended September 30, 2007, only those employee benefit costs reasonably allocated by Anadarko to us were included in and recovered through the gathering and treating fees we charged Anadarko. Under our new gas gathering agreements entered into with Anadarko, all of these costs will be recovered by us following the offering through the gathering rates we will charge Anadarko. As a result, our gathering and treating revenues will increase by an amount equal to the increase in operating and maintenance expense.
 
General and administrative expense
 
We estimate that general and administrative expense for the twelve months ending December 31, 2008 will be $8.5 million and will consist of $6.0 million of costs reimbursable to Anadarko for services performed on our behalf pursuant to the omnibus agreement and the services and secondment agreement and $2.5 million of general and administrative expense related to operating as a publicly traded partnership. General and administrative expense was $4.5 million and $3.7 million for the year ended December 31, 2006 and the twelve months ended September 30, 2007, respectively. The expected increase in general and administrative expense is driven by $2.5 million in costs associated with being a publicly traded partnership, with the balance of the increase attributable to increased corporate and management services associated with operating our business on a stand-alone basis.
 
Depreciation and amortization expense
 
We estimate depreciation and amortization expense for the twelve months ending December 31, 2008 of $24.0 million as compared to $19.7 million for the year ended December 31, 2006 and $22.5 million for the twelve months ended September 30, 2007. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization is attributable to an expected increase in capital investments in our assets.
 
Interest income and Texas margin tax
 
Interest income.  We will loan $337.6 million of the net proceeds from this offering to Anadarko in exchange for an interest-only, 30-year note bearing interest at a fixed annual rate of 6.00%, resulting in interest income of $20.3 million during the twelve months ending December 31, 2008.
 
Texas margin tax.  We estimate Texas margin tax payments for the twelve months ending December 31, 2008 will be $0.3 million based on a 1.0% tax rate on a maximum of 70% of our projected revenues attributable to operations in Texas for the year ending December 31, 2008.
 
Capital expenditures
 
We estimate total capital expenditures of $43.9 million for the twelve months ending December 31, 2008 as compared to $42.3 million and $51.6 million for the year ended December 31, 2006 and for the twelve months ended September 30, 2007, respectively. Historically, we did not make a distinction between maintenance and expansion capital expenditures. Our estimate is based on the following assumptions:
 
Ø  We estimate that maintenance capital expenditures for the twelve months ending December 31, 2008 will be $28.0 million. These expenditures are expected to include $13.0 million of well connection costs associated with maintaining throughput on our systems. The remainder of the expenditures are primarily expected to be incurred to replace partially or fully depreciated assets and to overhaul existing assets.


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Ø  We estimate that expansion capital expenditures for the twelve months ending December 31, 2008 will be $15.9 million. These expenditures are expected to include $11.5 million associated with the expansion of the sulfur treating capacity at our Bethel plant in East Texas that we expect to complete in 2008. We also expect to spend $3.4 million to add additional compression on our Dew gathering system in East Texas.
 
Financing
 
Our forecast for the twelve months ending December 31, 2008 is based on the following financing assumptions:
 
Ø  We expect to use $10 million of the net proceeds of this offering to finance a portion of our expansion capital expenditures during the forecast period.
 
Ø  We expect to finance the balance of our expansion capital expenditures of $5.9 million through borrowings under Anadarko’s credit facility, under which we are a co-borrower, or our working capital facility.
 
Ø  Our average debt level will be $2.9 million, comprised of funds drawn either on Anadarko’s credit facility, under which we are a co-borrower, or our working capital facility.
 
Ø  We estimate interest expense of $0.4 million for the twelve months ending December 31, 2008, which includes commitment fees of 0.175% on Anadarko’s credit facility, under which we are a co-borrower, and our working capital facility and interest associated with funds expected to be drawn. We estimate our borrowings under Anadarko’s credit facility and our working capital facility to bear an average annualized variable interest rate of 6.00% through December 31, 2008. An increase or decrease of 1.0% in the annual interest rate would not result in a material change to our annual interest expense.
 
Ø  Anadarko and we will remain in compliance with the financial and other covenants in the Anadarko credit facility and other debt instruments.
 
Regulatory, industry and economic factors
 
Our forecast for the twelve months ending December 31, 2008, is based on the following significant assumptions related to regulatory, industry and economic factors:
 
Ø  There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.
 
Ø  There will not be any major adverse change in the midstream energy sector or in market, insurance or general economic conditions.


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Provisions of our partnership agreement relating to cash distributions
 
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 December 31, 2007, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through December 31, 2007.
 
Definition of available cash
 
Available cash, for any quarter, consists of all cash on hand at the end of that quarter:
 
Ø  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 for any one or more of the next four quarters;
 
Ø  plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.
 
Working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within 12 months.
 
Intent to distribute the minimum quarterly distribution
 
We will distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.30 per unit, or $1.20 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.
 
General partner interest and incentive distribution rights
 
Initially, our general partner will be entitled to 2.0% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest will be represented by 921,385 general partner units. General partner units are not deemed outstanding units for purposes of voting rights and such units represent a non-voting general partner interest. 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. Our general partner’s initial 2.0% interest in these distributions may be reduced if we issue


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additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.
 
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.45 per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on units that it owns.
 
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:
 
Ø  $27.1 million (as described below);
 
Ø  all of our cash receipts after the closing of this offering, excluding cash from the following:
 
  borrowings that are not working capital borrowings;
 
  sales of equity and debt securities;
 
  sales or other dispositions of assets outside the ordinary course of business;
 
  the termination of interest rate swap agreements or commodity hedge contracts prior to the termination date specified herein;
 
  capital contributions received; and
 
  corporate reorganizations or restructurings; plus
 
Ø  working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for the quarter; plus
 
Ø  cash distributions paid on equity issued to finance all or a portion of the construction, acquisition or improvement or replacement of a capital asset (such as equipment or facilities) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service or the date that it is abandoned or disposed of; less
 
Ø  all of our operating expenditures (as defined below) after the closing of this offering; less
 
Ø  the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less
 
Ø  all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings.
 
As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $27.1 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be


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Provisions of our partnership agreement relating to cash distributions
 
 
distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity securities in operating surplus would be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash distributions we receive from non-operating sources.
 
If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.
 
We define operating expenditures in the glossary, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner, reimbursement of expenses to Anadarko for services pursuant to the omnibus agreement or personnel provided to us under the services and secondment agreement, payments made in the ordinary course of business under interest rate swap agreements or commodity hedge contracts, manager and officer compensation, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:
 
Ø  repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus above when such repayment actually occurs;
 
Ø  payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;
 
Ø  expansion capital expenditures;
 
Ø  actual maintenance capital expenditures (as discussed in further detail below);
 
Ø  investment capital expenditures;
 
Ø  payment of transaction expenses relating to interim capital transactions;
 
Ø  distributions to our partners (including distributions in respect of our Class B units and incentive distribution rights); or
 
Ø  non-pro rata purchases of units of any class made with the proceeds of a substantially concurrent equity issuance.
 
Capital surplus
 
Capital surplus consists of:
 
Ø  borrowings other than working capital borrowings;
 
Ø  sales of our equity and debt securities; and
 
Ø  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.
 
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. We do not anticipate that we will make any distributions from capital surplus.


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CAPITAL EXPENDITURES
 
For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity or operating income, and expansion capital expenditures are those capital expenditures that we expect will expand our operating capacity or operating income over the long term. Examples of maintenance capital expenditures include capital expenditures associated with the replacement of equipment and well connections, or the construction, development or acquisition of other facilities, to replace expected reductions in hydrocarbons available for gathering, compressing, treating, transporting or otherwise handled by our facilities (which we refer to as operating capacity). Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction, improvement or replacement of an asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date of any such replacement asset commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.
 
Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus.
 
Our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity or operating income over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus for those periods will be subject to review and change by our general partner at least once a year, provided that any change is approved by our special committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Our cash distribution policy and restrictions on distributions.”
 
The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:
 
Ø  it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the initial quarterly distribution to be paid on all the units for the quarter and subsequent quarters;
 
Ø  it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; and
 
Ø  it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.
 
Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new processing capacity, to the extent such capital expenditures are expected to expand our long-term operating capacity or operating income. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction of such capital improvement during the period that commences when we enter into a


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binding obligation to commence construction of a capital improvement and ending on the date any such capital improvement commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.
 
As described below, none of investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset (such as gathering pipelines or treating facilities) during the period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).
 
Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but which are not expected to expand for more than the short term of our operating capacity or operating income.
 
Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our general partner, with the concurrence of our special committee.
 
SUBORDINATION PERIOD
 
General
 
Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.30 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 business day of any quarter beginning after December 31, 2010, that each of the following tests are met:
 
Ø  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


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for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
Ø  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, subordinated units and general partner units during those periods on a fully diluted basis during those periods; and
 
Ø  there are no arrearages in payment of the minimum quarterly distribution on the common units.
 
Early termination of subordination period
 
Notwithstanding the foregoing, 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:
 
Ø  distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded $0.45 per quarter (150.0% of the minimum quarterly distribution) for each calendar quarter in the four-quarter period immediately preceding the date;
 
Ø  the “adjusted operating surplus” (as defined below) generated during each calendar quarter in the four-quarter period immediately preceding the date equaled or exceeded the sum of $0.45 (150.0% of the minimum quarterly distribution) on each of the outstanding common, subordinated and general partner units during that period on a fully diluted basis; and
 
Ø  there are no arrearages in payment of the minimum quarterly distributions on the common units.
 
Expiration of the subordination period
 
When the subordination period ends, 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 no units held by our general partner and its affiliates are voted in favor of such removal:
 
Ø  the subordination period will end and each subordinated unit will immediately convert into one common unit;
 
Ø  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
Ø  our 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.
 
Adjusted operating surplus
 
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus consists of:
 
Ø  operating surplus generated with respect to that period; less
 
Ø  any net increase in working capital borrowings with respect to that period; less
 
Ø  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
 
Ø  any net decrease in working capital borrowings with respect to that period; plus
 
Ø  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.


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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:
 
Ø  first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
Ø  second, 98.0% to the common unitholders, pro rata, and 2.0% to our 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;
 
Ø  third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
Ø  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 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
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 our unitholders and our 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 2.0% general partner interest and assume our general partner has contributed any additional capital to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights.
 
                   
        Marginal percentage
        interest in
        distributions(1)
    Total quarterly distribution
        General
    per unit   Unitholders     partner
 
 
Minimum Quarterly Distribution
  $0.300     98.0%       2.0%
First Target Distribution
  up to $0.345     98.0%       2.0%
Second Target Distribution
  above $0.345 up to $0.375     85.0%       15.0%
Third Target Distribution
  above $0.375 up to $0.450     75.0%       25.0%
Thereafter
  above $0.450     50.0%       50.0%
 
 
(1) Assumes that there are no arrearages on common units and that our general partner maintains its 2.0% general partner interest and continues to own the incentive distribution rights.


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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:
 
Ø  first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
 
Ø  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 2.0% general partner interest and that we do not issue additional classes of equity securities.
 
GENERAL PARTNER INTEREST AND INCENTIVE DISTRIBUTION RIGHTS
 
Our partnership agreement provides that our general partner initially will be entitled to 2.0% 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 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% 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 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.
 
Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) 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 our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.
 
If for any quarter:
 
Ø  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
 
Ø  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:
 
Ø  first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $0.345 per unit for that quarter (the “first target distribution”);
 
Ø  second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.375 per unit for that quarter (the “second target distribution”);
 
Ø  third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $0.45 per unit for that quarter (the “third target distribution”); and
 
Ø  thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.


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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 special 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 and general partner 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. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.
 
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 the quotient determined by dividing (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 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 unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum 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:
 
Ø  first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;
 
Ø  second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;
 
Ø  third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and


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Ø  thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.
 
The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) 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 distribution      
    Quarterly distribution
      General
  Quarterly distribution per unit
 
    per unit prior to reset   Unitholders   partner   following hypothetical reset  
   
 
Minimum Quarterly Distribution
  $0.300   98.0%   2.0%     $0.600  
First Target Distribution
  up to $0.345   98.0%   2.0%     up to $0.690 (1)
Second Target Distribution
  above $0.345 up to $0.375   85.0%   15.0%     above $0.690(1) up to $0.750 (2)
Third Target Distribution
  above $0.375 up to $0.450   75.0%   25.0%     above $0.750(2) up to $0.900 (3)
Thereafter
  above $0.450   50.0%   50.0%     above $0.900 (3)
 
 
(1) This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
 
(2) This amount is 125.0% of the hypothetical reset minimum quarterly distribution.
 
(3) This amount is 150.0% 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 our general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there are 45,147,850 common units outstanding, our general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit is $0.60 for the two quarters prior to the reset.
 
                                         
        Cash
                   
    Quarterly
  distributions
  Cash distributions to general partner prior to reset    
    distribution
  to common
      2.0% general
  Incentive
       
    per unit
  unitholders
  Class B
  partner
  distribution
      Total
    prior to reset   prior to reset   units   interest   rights   Total   distributions
 
 
Minimum Quarterly Distribution
  $0.300   $ 13,544,355   $   $ 276,415   $   $ 276,415   $ 13,820,770
First Target Distribution
  up to $0.345     2,031,653         41,463         41,463     2,073,116
Second Target Distribution
  above $0.345
up to $0.375
    1,354,436         31,869     207,149     239,018     1,593,454
Third Target Distribution
  above $0.375
up to $0.450
    3,386,088         90,296     1,038,401     1,128,697     4,514,785
Thereafter
  above $0.450     6,772,178         270,887     6,501,290     6,772,177     13,544,355
                                         
        $ 27,088,710   $   $ 710,930   $ 7,746,840   $ 8,457,770   $ 35,546,480
                                         


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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 our general partner, including in respect of IDRs, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 45,147,850 common units and 12,911,400 Class B units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit is $0.60. The number of Class B units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its IDRs for the two quarters prior to the reset as shown in the table above, or $7,746,840, by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $0.60.
 
                                         
        Cash
                   
    Quarterly
  distributions
  Cash distributions to general partner after reset    
    distribution
  to common
      2.0% General
  Incentive
       
    per unit
  unitholders
  Class B
  partner
  distribution
      Total
    after reset   after reset   units   interest   rights   Total   distributions
 
 
Minimum Quarterly Distribution
  $0.600   $ 27,088,710   $ 7,746,840   $ 710,930   $   $ 8,457,770   $ 35,546,480
First Target Distribution
  up to $0.690                        
Second Target Distribution
  above $0.690
up to $0.750
                       
Third Target Distribution
  above $0.750
up to $0.900
                       
Thereafter
  above $0.900                        
                                         
        $ 27,088,710   $ 7,746,840   $ 710,930   $   $ 8,457,770   $ 35,546,480
                                         
 
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:
 
Ø  first, 98.0% to all unitholders, pro rata, and 2.0% to our 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;
 
Ø  second, 98.0% to the common unitholders, pro rata, and 2.0% to our 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
 
Ø  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


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distribution levels will be reduced in the same proportion as the corresponding 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 our 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 50.0% being paid to the holders of units and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume our 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:
 
Ø  the minimum quarterly distribution;
 
Ø  target distribution levels;
 
Ø  the unrecovered initial unit price; and
 
Ø  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 do 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 the minimum quarterly distribution and the target distribution levels for each quarter may be reduced 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 our 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


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Provisions of our partnership agreement relating to cash distributions
 
 
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 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 our 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:
 
Ø  first, to our 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;
 
Ø  second, 98.0% to the common unitholders, pro rata, and 2.0% to our 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;
 
Ø  third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our 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;
 
Ø  fourth, 98.0% to all unitholders, pro rata, and 2.0% to our 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 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;
 
Ø  fifth, 85.0% to all unitholders, pro rata, and 15.0% to our 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 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;
 
Ø  sixth, 75.0% to all unitholders, pro rata, and 25.0% to our 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 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence; and
 
Ø  thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner.
 
The percentage interests set forth above for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.
 
If the liquidation occurs after the end of the subordination period, the distinction between common 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.


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Provisions of our partnership agreement relating to cash distributions
 
 
Manner of adjustments for losses
 
If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:
 
Ø  first, 98.0% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
 
Ø  second, 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and
 
Ø  thereafter, 100.0% to our general partner.
 
If the liquidation occurs after the end of the subordination period, the distinction between common 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 (i) the selected combined historical financial and operating data of our Predecessor, which are comprised of Anadarko Gathering Company and Pinnacle Gas Treating, Inc., with MIGC, Inc. (“MIGC”) reported as an acquired business of our Predecessor, and (ii) the selected combined pro forma as adjusted financial and operating data of the Partnership, for the periods and as of the dates indicated. The information in the following table should also be read together with “Management’s discussion and analysis of financial condition and results of operations.’’
 
Our Predecessor’s selected combined historical balance sheet data as of December 31, 2006 and 2005 and selected combined historical statement of income and statement of cash flow data for the years ended December 31, 2006, 2005 and 2004 are derived from the audited historical combined financial statements of our Predecessor included elsewhere in this prospectus. Our Predecessor’s selected combined historical balance sheet data as of December 31, 2004, 2003 and 2002 and selected combined historical statement of income for the years ended December 31, 2003 and 2002 are derived from the unaudited historical combined financial statements of our Predecessor not included in this prospectus. Our Predecessor’s selected combined historical balance sheet data as of September 30, 2007 and selected combined historical statement of income and statement of cash flow data for the nine months ended September 30, 2007 and 2006 are derived from the unaudited historical combined financial statements of our Predecessor included elsewhere in this prospectus. Our Predecessor’s selected combined historical balance sheet data as of September 30, 2006 are derived from the unaudited historical financial statements of our Predecessor not included in this prospectus.
 
The Partnership’s selected combined pro forma as adjusted statement of income data for the year ended December 31, 2006 and the nine months ended September 30, 2007 and selected combined pro forma as adjusted balance sheet data as of September 30, 2007 are derived from the unaudited pro forma combined financial statements of the Partnership included elsewhere in this prospectus.
 
The pro forma adjustments have been prepared as if the acquisition of MIGC by our Predecessor occurred on January 1, 2006 and as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the pro forma balance sheet, and on January 1, 2006, in the case of the pro forma statements of operations for the year ended December 31, 2006 and the nine months ended September 30, 2007. These transactions include:
 
Ø  the receipt by the Partnership of gross proceeds of $375.0 million from the issuance and sale of 18,750,000 common units at an assumed initial offering price of $20.00 per unit;
 
Ø  the use of the proceeds from this offering to pay underwriting discounts and a structuring fee totaling approximately $24.4 million and other estimated offering expenses of $3.0 million; and
 
Ø  the use of the remaining $347.6 million of aggregate net proceeds of this offering to (i) make a loan of $337.6 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.00% and (ii) provide $10.0 million for general partnership purposes.
 
The following table includes our Predecessor’s historical and our pro forma Adjusted EBITDA, which have not been prepared in accordance with GAAP. Adjusted EBITDA is presented because it is helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP financial measure.”


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Selected historical and pro forma financial and operating data
 
 
                                                               
                                    Partnership pro forma
 
    Predecessor combined   as adjusted  
                                    Nine months
       
                            Nine months
  ended
    Year ended
 
    Year ended December 31,     ended September 30,   September 30,
    December 31,
 
    2006   2005     2004   2003   2002     2007   2006   2007     2006  
   
    (in thousands, except operating and per unit data)  
 
Statement of Income Data:
                                                             
Total revenues
  $ 81,152   $ 71,650     $ 68,049   $ 61,401   $ 50,266     $ 85,513   $ 57,481   $ 85,513     $ 93,304  
Costs and expenses
    39,960     35,720       31,301     33,804     31,135       33,184     29,057     33,184       43,857  
Depreciation
    18,009     15,447       14,841     14,294     16,509       17,104     12,635     17,104       19,710  
                                                               
Total operating expenses
    57,969     51,167       46,142     48,098     47,644       50,288     41,692     50,288       63,567  
                                                               
                                                               
Operating income
    23,183     20,483       21,907     13,303     2,622       35,225     15,789     35,225       29,737  
                                                               
Other (expense) income
    26     (66 )                       25           377  
Interest expense (income)
    9,631     8,650       7,146     6,782     9,019       6,643     7,943     (15,022 )     (20,030 )
Income tax expense (benefit)
    3,814     4,789       5,504     2,529     (2,331 )     10,469     1,740     160       978  
Change in accounting principle
                  1,510                                
                                                               
Net income (loss)
  $ 9,712   $ 7,110     $ 9,257   $ 5,502   $ (4,066 )   $ 18,113   $ 6,081   $ 50,087     $ 48,412  
                                                               
General partner interest in pro forma net income
                                                  1,315       968  
Common unitholders’ interest in pro forma net income
                                                  24,386       23,772  
Subordinated unitholders’ interest in pro forma net income
                                                  24,386       23,772  
Net income per common unit (basic and diluted)
                                                $ 1.08     $ 1.05  
Net income per subordinated unit (basic and diluted)
                                                $ 1.08     $ 1.05  
Balance Sheet Data (at period end):
                                                             
Net, property, plant and equipment
  $ 310,871   $ 200,451     $ 196,065   $ 192,415   $ 200,398     $ 353,294   $ 302,057   $ 353,294          
Total assets
    332,228     206,373       199,110     195,747     203,623       360,692     324,772     708,306          
Total parent net equity
    238,531     160,585       162,542     167,881     175,886       273,507     234,063     691,561          


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Selected historical and pro forma financial and operating data
 
 
                                                                 
                                          Partnership pro forma
    Predecessor combined     as adjusted
                                          Nine months
   
                              Nine months
    ended
  Year ended
    Year ended December 31,   ended September 30,     September 30,
  December 31,
    2006     2005     2004     2003   2002   2007     2006     2007   2006
 
    (in thousands, except operating and per unit data)
 
Cash Flow Data:
                                                               
Net cash provided by (used in):
                                                               
Operating activities
    27,323       30,131       31,160                   41,810       12,941              
Investing activities
    (42,713 )     (21,076 )     (16,548 )                 (37,247 )     (27,952 )            
Financing activities
    15,844       (9,067 )     (14,596 )                 (5,021 )     15,007              
Adjusted EBITDA(1)
    41,192       35,930       36,748                   52,329       28,424       52,329     49,447
Capital expenditures, net
    42,299       20,841       16,548                   37,020       27,709              
Operating Data:
                                                               
Affiliate
                                                               
Throughput, MMBtu/d
    820       757       715       667     700     904       778       904     878
Average rate per MMBtu
  $ 0.22     $ 0.21     $ 0.21     $ 0.19   $ 0.17   $ 0.28     $ 0.22     $ 0.28   $ 0.23
Third Party
                                                               
Throughput, MMBtu/d
    72       41       31       32     15     90       64       90     93
Average rate per MMBtu
  $ 0.19     $ 0.16     $ 0.13     $ 0.09   $ 0.14   $ 0.25     $ 0.21     $ 0.25   $ 0.23
Total
                                                               
Throughput, MMBtu/d
    892       798       746       699     715     994       842       994     971
Average rate per MMBtu
  $ 0.21     $ 0.21     $ 0.21     $ 0.18   $ 0.16   $ 0.28     $ 0.22     $ 0.28   $ 0.23
 
 
(1) Adjusted EBITDA is defined in “Prospectus summary—Non-GAAP financial measure.” For a reconciliation of Adjusted EBITDA to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP financial measure.”

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Management’s discussion and analysis of financial condition and results of operations
 
The historical combined financial statements included in this prospectus reflect the assets, liabilities and operations of our Predecessor, which is comprised of Anadarko Gathering Company (“AGC”) and Pinnacle Gas Treating, Inc. (“PGT”), with MIGC, Inc. (“MIGC”) reported as an acquired business of our Predecessor. All of the assets, liabilities and operations of our Predecessor will be contributed to us by Anadarko upon the closing of this offering. The following discussion analyzes the financial condition and results of operations of our Predecessor. You should read the following discussion and analysis of financial condition and results of operations in conjunction with the historical and pro forma combined financial statements, and the notes thereto, included elsewhere in this prospectus. For ease of reference, we refer to the historical financial results of our Predecessor as being “our” historical financial results.
 
OVERVIEW
 
We are a growth-oriented Delaware limited partnership recently formed by Anadarko to own, operate, acquire and develop midstream energy assets. We currently operate in East Texas, the Rocky Mountains, the Mid-Continent and West Texas and are engaged in the business of gathering, compressing, treating and transporting natural gas for our ultimate parent, Anadarko, and third-party producers and customers.
 
OUR OPERATIONS
 
Our results are driven primarily by the volumes of natural gas we gather, compress, treat and transport through our systems. For the nine months ended September 30, 2007, approximately 84% of our revenues were derived from gathering, compression and treating activities and 16% was derived from transportation activities. Approximately 9% of our gathering, compression and treating revenues were comprised of revenues from condensate sales. For the nine months ended September 30, 2007, 89% of our total revenues were generated by transactions with Anadarko.
 
In our gathering operations, we contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering lines through which natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end-users. We also treat a significant portion of the natural gas that we gather so that it will meet required specifications for pipeline transportation.
 
We have secured a significant dedication from our largest customer, Anadarko, in order to maintain or increase our existing throughput levels and to offset the natural production declines of the wells currently connected to our gathering systems. Specifically, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Volumes associated with this dedication averaged approximately 736 MMBtu/d for the year ended December 31, 2006 and 738 MMBtu/d for the nine months ended September 30, 2007.
 
We generally do not take title to the natural gas that we gather, compress, treat or transport. We currently provide all of our gathering and treating services pursuant to fee-based contracts. Under these arrangements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather or treat. This type of contract provides us with a relatively steady revenue stream that is not subject to direct commodity price risk, except to the extent that we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. We have entered into new gathering


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Management’s discussion and analysis of financial condition and results of operations
 
 
contracts with Anadarko pursuant to which we will receive higher fees than we have historically realized. We have some indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering, compressing, treating and transporting by our systems. Please read “—Quantitative and qualitative disclosures about market risk” below for a discussion of our exposure to commodity price risk through our condensate recovery and sales.
 
We provide a significant portion of our transportation services on our MIGC system through firm contracts that obligate our customers to pay a monthly reservation or demand charge, which is a fixed charge applied to firm contract capacity and owed by a customer regardless of the actual pipeline capacity used by that customer. When a customer uses the capacity it has reserved under these contracts, we are entitled to collect an additional commodity usage charge based on the actual volume of natural gas transported. These usage charges are typically a small percentage of the total revenues received from our firm capacity contracts. We also provide transportation services through interruptible contracts, pursuant to which a fee is charged to our customers based upon actual volumes transported through the pipeline.
 
HOW WE EVALUATE OUR OPERATIONS
 
Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput volumes, (2) operating expenses, (3) Adjusted EBITDA, and (4) distributable cash flow.
 
Throughput volumes
 
In order to maintain or increase throughput volumes on our gathering systems, we must connect additional wells to our systems. Our success in connecting additional wells is impacted by successful drilling activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered by our competitors.
 
To maintain and increase throughput volumes on our MIGC system, we must continue to contract our capacity to shippers, including producers and marketers, for transportation of their natural gas. We monitor producer and marketing activities in the area served by our transportation system to identify new opportunities.
 
Operating expenses
 
We analyze operating expenses to evaluate our performance. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses, general and administrative expenses and direct operating expenses. Certain of our operating expenses are classified based on whether the expenses are accrued for or paid to our affiliates or third-party vendors. Neither affiliate expenses nor third-party expenses bear a direct relationship to affiliate revenues or third-party revenues. For example, our third-party expenses are not those expenses necessary for generating our third-party revenues. Third-party expenses include all amounts accrued for or paid to third parties for the operation of our systems, whether in providing services to Anadarko or third parties, including utilities, field labor, measurement and analysis and other third-party disbursements.
 
Operation and maintenance expenses include, among other things, direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf under our services and secondment agreement.


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Management’s discussion and analysis of financial condition and results of operations
 
 
Cost of product expenses include (i) costs associated with the purchase of natural gas pursuant to the gas imbalance provisions contained in our contracts, (ii) costs associated with our obligation under certain contracts to redeliver a volume of natural gas to shippers which is thermally equivalent to condensate retained by us and sold to third parties and (iii) our fuel tracking mechanism, which tracks the difference between actual fuel usage and loss and amounts recovered for estimated fuel usage and loss under our contracts. These expenses are subject to variability. However, for the years ended December 31, 2006, 2005 and 2004, cost of product expenses comprised only 7.8%, 11.7% and 10.8% of total operating expenses, respectively. Thus, we do not expect the variability in our cost of product expenses to have a material impact on our overall results.
 
In our historical combined financial statements, general and administrative expenses included reimbursements of costs incurred by Anadarko on our behalf and allocations from Anadarko in the form of a management service fee in lieu of direct reimbursements for various corporate services. In the future, Anadarko will not receive a management services fee and we expect general and administrative expenses to be comprised primarily of amounts reimbursed by us to Anadarko pursuant to our omnibus agreement with Anadarko and expenses attributable to our status as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees.
 
Pursuant to the omnibus agreement with Anadarko, we will reimburse Anadarko for allocated general and administrative expenses. The amount required to be reimbursed by us to Anadarko for certain allocated general and administrative expenses pursuant to the omnibus agreement will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year.
 
Adjusted EBITDA
 
We define Adjusted EBITDA as net income (loss), plus interest expense, income taxes and depreciation, less interest income and other income (expense). Adjusted EBITDA is not a presentation made in accordance with GAAP. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP financial measure.”
 
Distributable cash flow
 
We define distributable cash flow as Adjusted EBITDA, plus interest income, less net cash paid for interest expense, maintenance capital expenditures and income taxes. Distributable cash flow does not reflect changes in working capital balances. Distributable cash flow is not a presentation made in accordance with GAAP.


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Management’s discussion and analysis of financial condition and results of operations
 
 
Adjusted EBITDA and distributable cash flow are supplemental financial measures that management and external users of our combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
 
Ø  our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;
 
Ø  the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and
 
Ø  the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.
 
ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS
 
Our historical results of operations for the periods presented below may not be comparable to our results of operations in the future for the reasons described below:
 
Ø  We anticipate incurring approximately $2.5 million of general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. These incremental general and administrative expenses are not reflected in our historical or our pro forma combined financial statements.
 
Ø  We anticipate incurring $6.0 million in general and administrative expenses to be allocated to us by Anadarko pursuant to the omnibus agreement. This amount is expected to be greater than the amount allocated to us by Anadarko for the management services fee and reflected in our historical combined financial statements.
 
Ø  The impact of all affiliated transactions historically has been net settled within our combined financial statements because these transactions related to Anadarko and were funded by Anadarko’s working capital. Third-party transactions were funded by our working capital. In the future, all affiliate and third-party transactions will be funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.
 
Ø  Prior to this offering, we incurred interest expense on intercompany notes payable to Anadarko. These balances were extinguished through non-cash transactions prior to this offering; therefore, interest expense attributable to these balances and reflected in our historical combined financial statements will not be incurred in future periods.
 
Ø  We have entered into new gas gathering agreements with Anadarko which include fees for gathering and treating that are higher than those fees reflected in our historical financial results.
 
Ø  Our combined financial statements reflect the gathering fees we historically charged Anadarko under our affiliate cost of service based arrangements. Under these arrangements, we recovered, on an annual basis, our operation and maintenance, general and administrative and depreciation expenses in addition to earning a return on our invested capital. Effective January 1, 2008, we entered into new 10-year gas gathering agreements with Anadarko. Under the terms of these new agreements, we expect our operation and maintenance expense to increase as a result of our bearing all of the cost of employee benefits specifically identified and related to operational personnel working on our assets as compared to bearing only those employee benefit costs reasonably allocated by Anadarko to us in historic periods. Since our new gas gathering agreements are designed to fully recover these costs, our future revenues are expected to increase by an amount equal to the increase in operation and maintenance expense. Although we do not expect this change in methodology for


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Management’s discussion and analysis of financial condition and results of operations
 
 
computing affiliate gathering rates to impact our net cash flows or net income, we do expect this methodology change to impact the components thereof as compared to historic periods. If we applied the methodology employed under our new gas gathering agreements with Anadarko to historic periods, we estimate our gathering revenues and operation and maintenance expense for the years ended December 31, 2006, 2005, and 2004, would have increased by $2.8 million, $1.4 million and $0.9 million, respectively.
 
Ø  Concurrently with the closing of this offering, we will loan $337.6 million to Anadarko in exchange for an interest-only, 30-year note bearing interest at a fixed annual rate of 6.00%. Interest income attributable to the note is not reflected in our historical combined financial statements, but will be included in our combined financial statements in the future.
 
Ø  As a co-borrower under Anadarko’s credit facility, we will incur an annual commitment fee of 0.175% of our committed and unused borrowing capacity of up to $100 million, or up to $175,000. In addition, Anadarko will enter into a working capital facility with us, under which we will incur an annual commitment fee of 0.175% of the unused portion of our committed borrowing capacity of $30 million, or up to $52,500.
 
Ø  Our historical combined financial statements include U.S. federal and state income tax expense incurred by us. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future. However, we will make payments to Anadarko pursuant to a tax sharing agreement for our share of state and local income and other taxes that are included in combined or consolidated tax returns filed by Anadarko.
 
Ø  Following the closing of this offering, we intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.30 per unit per quarter ($1.20 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including commercial bank borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.
 
GENERAL TRENDS AND OUTLOOK
 
We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
 
Natural gas supply and demand
 
Natural gas continues to be a critical component of energy supply in the U.S. According to the Energy Information Administration, or EIA, total annual domestic consumption of natural gas is expected to increase from approximately 21.7 trillion cubic feet, or Tcf, in 2006 to approximately 24.7 Tcf in 2010. During the last three years, the U.S. has, on average, consumed approximately 22.0 Tcf per year, while total domestic production averaged approximately 18.4 Tcf per year during the same period. We believe that high natural gas prices and increasing demand will continue to drive an increase in natural gas drilling and production in the U.S. Natural gas reserves in the U.S. have increased overall in recent years, based on data obtained from the EIA.
 
There is a natural decline in production from existing wells, but in the areas in which we operate there is a significant level of drilling activity that can offset this decline. Although we anticipate continued


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high levels of exploration and production activities in all of the areas in which we operate, we have no control over this activity. Fluctuations in energy prices could affect production rates over time and levels of investment by Anadarko and third parties in exploration for and development of new natural gas reserves.
 
Rising operating costs and inflation
 
The current high level of natural gas exploration, development and production activities across the U.S. has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.
 
Impact of interest rates
 
Interest rates have been volatile in recent periods. If interest rates rise, our future financing costs will increase accordingly. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors, which could limit our ability to raise funds, or increase the price of raising funds, in the capital markets. Though our competitors may face similar circumstances, such an environment could render us less competitive in our efforts to expand our operations or make future acquisitions.
 
Benefits from system expansions
 
We expect that expansion projects, including the following, will allow us to capitalize on increased drilling activity by Anadarko and other third-party producers:
 
Ø  We are installing additional compressors on our Dew system which will add an incremental 16,375 horsepower by the end of 2007;
 
Ø  We are expanding our Bethel treating facility by installing an additional 11 LTD of sulfur treating capacity in order to provide additional sour gas treating capacity for drilling in the area, which we expect to complete in 2008; and
 
Ø  We are expanding our Hugoton gathering system.
 
Acquisition opportunities
 
We may acquire additional midstream energy assets from Anadarko, although Anadarko is under no legal obligation to offer assets or business opportunities to us. In addition, we may also pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s production. However, if we do not make acquisitions on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.


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RESULTS OF OPERATIONS—COMBINED OVERVIEW
 
The following table and discussion presents a summary of our combined results of operations for the years ended December 31, 2006, 2005 and 2004 and for the nine months ended September 30, 2007 and 2006:
 
                                         
    Year ended December 31,     Nine months ended September 30,  
    2006     2005     2004     2007     2006  
   
    (in thousands)  
 
Revenues-affiliates
                                       
Gathering and transportation of natural gas
  $ 65,946     $ 58,363     $ 54,407     $ 69,311     $ 46,546  
Condensate
    7,440       7,006       6,407       6,266       5,374  
Natural gas and other
    1,327       789       4,526       918       324  
                                         
Total
    74,713       66,158       65,340       76,495       52,244  
                                         
Revenues-third parties
                                       
Gathering and transportation of natural gas
    5,022       2,420       1,458       6,067       3,660  
Condensate, natural gas and other
    1,417       3,072       1,251       2,951       1,577  
                                         
Total
    6,439       5,492       2,709       9,018       5,237  
                                         
Total revenues
    81,152       71,650       68,049       85,513       57,481  
                                         
Operating expenses-affiliates
                                       
Cost of product
    3,830       5,551       4,425       4,439       4,196  
General and administrative
    3,198       2,829       2,251       2,370       2,394  
                                         
Total
    7,028       8,380       6,676       6,809       6,590  
                                         
Operating expenses-third parties
                                       
Cost of product
    714       456       553              
Operation and maintenance(1)
    27,585       23,044       20,678       21,840       18,598  
General and administrative
          9       48       751       204  
Property and other taxes
    4,633       3,831       3,346       3,784       3,665  
                                         
Total
    32,932       27,340       24,625       26,375       22,467  
                                         
Depreciation
    18,009       15,447       14,841       17,104       12,635  
                                         
Total operating expenses
    57,969       51,167       46,142       50,288       41,692  
                                         
Operating income
    23,183       20,483       21,907       35,225       15,789  
                                         
Other income (expense)
    (26 )     66                   (25 )
Interest expense
    9,631       8,650       7,146       6,643       7,943  
                                         
Income before income taxes
    13,526       11,899       14,761       28,582       7,821  
Income tax expense
    3,814       4,789       5,504       10,469       1,740  
                                         
Net income
  $ 9,712     $ 7,110     $ 9,257     $ 18,113     $ 6,081  
                                         
Adjusted EBITDA(2)
  $ 41,192     $ 35,930     $ 36,748     $ 52,329     $ 28,424  
 
 
(1) Third-party operation and maintenance expenses do not bear a direct relationship to third-party revenues because all operating expenses ultimately settled with third parties, including utilities, field labor, measurement and analysis and other expenses, are included within third-party operation and maintenance expenses.
 
(2) We define Adjusted EBITDA as net income (loss), plus interest expense, income taxes and depreciation, less interest income and other income (expense). For a reconciliation of this measure to its directly comparable financial measures calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP financial measure.”


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OPERATING RESULTS
 
Our discussion below compares the results for specific periods to the previous comparable period. The discussion compares: (i) the twelve months ended December 31, 2006 to the twelve months ended December 31, 2005, (ii) the twelve months ended December 31, 2005 to the twelve months ended December 31, 2004 and (iii) the nine months ended September 30, 2007 to the nine months ended September 30, 2006.
 
For purposes of the following discussion:
 
Ø  any increases or decreases “for the year ended December 31, 2006” refer to the comparison of the twelve-month period ended December 31, 2006 to the twelve-month period ended December 31, 2005;
 
Ø  any increases or decreases “for the year ended December 31, 2005” refer to the comparison of the twelve-month period ended December 31, 2005 to the twelve-month period ended December 31, 2004; and
 
Ø  any increases or decreases “for the nine months ended September 30, 2007” refer to the comparison of the nine-month period ended September 30, 2007 to the nine-month period ended September 30, 2006.
 
We acquired MIGC on August 23, 2006. The following discussion only includes MIGC operating results since the date of its acquisition.
 
Summary
 
Total revenues increased by $9.5 million and $3.6 million for the year ended December 31, 2006 and for the year ended December 31, 2005, respectively. Total revenues also increased by $28.0 million for the nine months ended September 30, 2007. The primary reason revenues increased for the year ended December 31, 2006 and for the nine months ended September 30, 2007 was the acquisition of MIGC in August 2006; however, the 2006 and 2007 revenue increases were also aided by increased rates and increased throughput volumes, respectively. The revenue increase for the year ended December 31, 2005 was driven by higher throughput volumes. The revenue increases for these periods were partially offset by higher costs and expenses, as described in more detail below.
 
Net income increased by $2.6 million and decreased by $2.1 million for the year ended December 31, 2006 and for the year ended December 31, 2005, respectively. Net income increased by $12.0 million for the nine months ended September 30, 2007. The increase in net income for the year ended December 31, 2006 was attributable to the increase in revenue discussed above, partially offset by increased operating costs. The decrease in net income for the year ended December 31, 2005 was attributable to increased operating expenses, partially offset by increased revenues. The increase in net income for the nine months ended September 30, 2007 was attributable to the revenue increase discussed above, partially offset by increased operating costs and income tax expense.


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Revenues and operating statistics
 
                                         
          Nine months ended
 
    Year ended December 31,     September 30,  
    2006     2005     2004     2007     2006  
   
    (in thousands, except operating and per unit data)  
 
Revenues
                                       
Affiliate
  $ 74,713     $ 66,158     $ 65,340     $ 76,495     $ 52,244  
Third-party
    6,439       5,492       2,709       9,018       5,237  
                                         
Total revenues
  $ 81,152     $ 71,650     $ 68,049     $ 85,513     $ 57,481  
Throughput (MMbtu/d)
                                       
Affiliate
    820       757       715       904       778  
Third-party
    72       41       31       90       64  
                                         
Total throughput
    892       798       746       994       842  
Weighted average price per MMbtu
                                       
Affiliate
  $ 0.22     $ 0.21     $ 0.21     $ 0.28     $ 0.22  
Third-party
  $ 0.19     $ 0.16     $ 0.13     $ 0.25     $ 0.21  
Total
  $ 0.21     $ 0.21     $ 0.21     $ 0.28     $ 0.22  
 
Total revenues.  Total revenues increased by $9.5 million and $3.6 million for the year ended December 31, 2006 and for the year ended December 31, 2005, respectively. Total revenues also increased by $28.0 million for the nine months ended September 30, 2007. Additional discussion regarding increases in affiliate and third-party revenues is provided below.
 
Revenues — affiliate.  Affiliate revenues increased by $8.6 million for the year ended December 31, 2006. Of this amount, $4.2 million was associated with the acquisition of MIGC. Excluding the operating revenue increases associated with the MIGC acquisition, revenues from affiliates increased by $4.4 million primarily due to increased throughput volumes at PGT. AGC gathering revenues also increased by $0.6 million, as a result of increases in gathering volumes and condensate revenues. Increased gathering volumes at AGC were primarily attributable to continued development of the Haley field.
 
The $0.8 million increase in affiliate revenues for the year ended December 31, 2005 was largely related to a 15% increase in throughput volumes at AGC, which resulted in a $3.7 million increase in revenues for the period and was partially offset by a $3.0 million decrease in gas imbalance revenues for AGC. The increase in throughput volume at AGC was primarily attributable to increased production activity at the Haley field.
 
The $24.3 million increase in affiliate revenues for the nine months ended September 30, 2007 included $8.6 million of increased revenues attributable to the inclusion of MIGC operating results for the entire nine-month period ended September 30, 2007 as compared to only 38 days during the nine-month period ended September 30, 2006. The $15.7 million increase not related to MIGC was mostly attributable to a 6% and 3% increase in throughput volumes, combined with a 19% and 39% increase in average rates realized, at AGC and PGT, respectively. This combination of throughput volume and rate increases resulted in increased gathering revenues of $8.8 million and $5.1 million for AGC and PGT, respectively. The increase in affiliate throughput volumes at AGC was attributable to the continued development of the Haley field. The increase in affiliate throughput volumes at PGT was primarily attributable to the connection of additional wells to the Pinnacle system. In addition, condensate and gas imbalance revenues for AGC increased by $0.9 million and $0.7 million, respectively.


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Revenues — third-party.  Third-party revenues increased by $0.9 million for the year ended December 31, 2006. Of this amount, $2.3 million was associated with the acquisition of MIGC. Excluding the revenue increases associated with the MIGC acquisition, revenues from third parties decreased by $1.4 million due to a one-time payment on a volume commitment received in 2005.
 
The $2.8 million increase in third-party revenues for the year ended December 31, 2005 was primarily due to a one-time payment on a volume commitment received in 2005. AGC gathering revenues also increased by $0.7 million due to higher realized rates.
 
The $3.8 million increase in third-party revenues for the nine months ended September 30, 2007 was primarily attributable to an increase of $4.0 million associated with the inclusion of MIGC operating results for the entire nine-month period ended September 30, 2007 as compared to only 38 days during the nine-month period ended September 30, 2006.
 
Operating expenses
 
                                         
          Nine months ended
 
    Year ended December 31,     September 30,  
    2006     2005     2004     2007     2006  
   
    (in thousands)  
 
Operating expenses
                                       
Affiliate
  $ 7,028     $ 8,380     $ 6,676     $ 6,809     $ 6,590  
Third-party
    32,932       27,340       24,625       26,375       22,467  
Depreciation
    18,009       15,447       14,841       17,104       12,635  
                                         
Total operating expenses
  $ 57,969     $ 51,167     $ 46,142     $ 50,288     $ 41,692  
                                         
 
Total operating expenses.  Total operating expenses increased by $6.8 million and $5.0 million for the year ended December 31, 2006 and for the year ended December 31, 2005, respectively. Total operating expenses also increased by $8.6 million for the nine months ended September 30, 2007. Additional discussion regarding changes in affiliate operating expenses, third-party operating expenses and depreciation expense is provided below.
 
Operating expenses — affiliate.  Affiliate operating expenses decreased by $1.4 million for the year ended December 31, 2006. This decrease was largely attributable to a $1.7 million decrease in cost of product expenses related to our fuel tracking mechanism. Specifically, for 2006, actual fuel consumed and line loss was exceeded by fuel volumes recovered pursuant to contractual arrangements.
 
The $1.7 million increase in affiliate operating expenses for the year ended December 31, 2005 was attributable to a $1.1 million increase in cost of product expenses largely attributable to increased replacement cost of gas associated with condensate sales, and a $0.6 million increase in general and administrative expenses related to management fees.
 
Affiliate operating expenses remained relatively flat for the nine months ended September 30, 2007.
 
Operating expenses — third-party.  Third-party operating expenses increased by $5.6 million for the year ended December 31, 2006. The MIGC acquisition resulted in $2.0 million of additional operation and maintenance expenses. Third-party operating expenses, not related to MIGC, increased by $3.6 million, primarily due to increases in operation and maintenance expenses of $1.6 million and $1.0 million for AGC and PGT, respectively, coupled with an $0.8 million increase in property taxes. The AGC increase in operation and maintenance expenses was primarily comprised of surface maintenance and repair and chemical service expense increases at the Helper, Clawson Springs and Dew gathering systems during the period. The increase in operation and maintenance expense at PGT was


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primarily comprised of an increase in salary and contract labor expenses and an increase in equipment rental expense for a rental amine unit and a rental compressor unit.
 
The $2.7 million increase in third-party operating expenses for the year ended December 31, 2005 was largely attributable to a $2.4 million increase in operation and maintenance expenses for AGC primarily due to increased throughput and service level improvements.
 
Third-party operating expenses increased by $3.9 million for the nine months ended September 30, 2007. Of this amount, $3.1 million was due to higher operation and maintenance and general and administrative expenses and property taxes associated with the inclusion of MIGC operating results for the entire nine-month period ended September 30, 2007 as compared to only 38 days during the nine-month period ended September 30, 2006. Third-party operating expenses not related to MIGC increased by $0.8 million, which was principally attributable to a $1.0 million increase in operation and maintenance expenses, partially offset by a $0.3 million decrease in property taxes.
 
Operating expenses — depreciation.  Depreciation expense increased by $2.6 million for the year ended December 31, 2006. This increase included $1.0 million in additional depreciation expense related to the MIGC acquisition. Depreciation expense not related to MIGC increased by $1.6 million due to $1.2 million and $0.4 million increases in deprecation expense related to AGC and PGT, respectively. These increases were primarily attributable to additional capital expenditures related to adding additional compression at the Dew system and additional well connections at PGT.
 
The $0.6 million increase in depreciation expense for the year ended December 31, 2005 was attributable to a $0.3 million increase in depreciation expense related to each of AGC and PGT. The AGC increase in depreciation expense was primarily due to the expansion at the Haley field. The PGT increase in depreciation expense was primarily due to $4.0 million of capital spent on a project to install a tie-in for connecting the PGT system into a nearby intrastate pipeline.
 
Depreciation expense increased by $4.5 million for the nine months ended September 30, 2007. Of this amount, $2.2 million was attributable to the inclusion of MIGC operating results for the entire nine-month period ended September 30, 2007 as compared to only 38 days during the nine-month period ended September 30, 2006. The $2.3 million increase in depreciation expense not related to MIGC was due to an increase in AGC’s depreciation expense resulting from a $9.3 million increase in capital expenditures related to adding compression and connecting additional wells to the Dew system and continued expansion of the Haley field.
 
Operating income
 
                                         
          Nine months ended
 
    Year ended December 31,     September 30,  
    2006     2005     2004     2007     2006  
   
    (in thousands)  
 
Operating income — excluding MIGC
  $ 19,670     $ 20,483     $ 21,907     $ 26,255     $ 15,074  
Operating income — MIGC
    3,513                   8,970       715  
                                         
Operating income — reported
  $ 23,183     $ 20,483     $ 21,907     $ 35,225     $ 15,789  
                                         
 
Reported operating income increased by $2.7 million for the year ended December 31, 2006. This increase included a $3.5 million increase related to the MIGC acquisition. Operating income, excluding operating income related to MIGC, decreased by $0.8 million, primarily due to a $1.6 and $1.0 million increase in AGC and PGT operation and maintenance expense, respectively, and a $1.2 million increase in AGC depreciation expense, partially offset by a $2.3 million and $0.7 million increase in PGT and AGC revenues, respectively.


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Operating income decreased by $1.4 million for the year ended December 31, 2005. This decrease was primarily due to a $2.4 million increase in AGC operation and maintenance expense, a $1.1 million increase in cost of product expenses, and $0.6 million and $0.6 million increases in general and administrative expense and depreciation, respectively, partially offset by a $2.1 million and $1.5 million increase in AGC and PGT revenues, respectively.
 
Operating income increased by $19.4 million for the nine months ended September 30, 2007. This increase included an increase of $8.3 million due to the inclusion of MIGC operating results for the entire nine-month period ended September 30, 2007 as compared to only 38 days during the nine-month period ended September 30, 2006. Excluding the effect of MIGC operating results, operating income increased by $11.1 million due to a $8.1 million and $3.0 million increase in operating income at AGC and PGT, respectively. The $8.1 million increase in AGC’s operating income included an increase of $10.0 million in revenues, and a $0.8 million decrease in operation and maintenance expenses, partially offset by a $2.0 million increase in depreciation expense. The $3.0 million increase in PGT’s operating income was principally attributable to increased throughput volumes and realized gathering rates, which resulted in a $5.4 million increase in revenues, partially offset by a $2.0 million increase in operation and maintenance expenses for the period.
 
Income tax expense
 
                                         
    Year ended December 31,     Nine months ended September 30  
    2006     2005     2004     2007     2006  
   
          (in thousands, except tax rates)        
 
Income before income taxes
  $ 13,526     $ 11,899     $ 14,761     $ 28,582     $ 7,821  
Income tax expense
    3,814       4,789       5,504       10,469       1,740  
Effective tax rate
    28.20 %     40.25 %     37.29 %     36.63 %     22.25 %
 
The decrease in the effective tax rate for the year ended December 31, 2006 was primarily due to the recording of a one-time benefit to deferred state income tax for the new Texas margin tax enacted in May 2006. The increase in the effective tax rate for the year ended December 31, 2005 was primarily due to additional state income taxes attributable to an increase in apportioned income to states with higher statutory tax rates. The increase in the effective rate for the nine months ended September 30, 2007 was primarily due to a one-time benefit to deferred state income tax for the new Texas margin tax recorded in the prior period.
 
The net decrease in income taxes for the year ended December 31, 2006 was primarily due to the recording of a one-time benefit to deferred state income tax for the new Texas margin tax enacted in May 2006, partially offset by the tax impact of the increase in income before income taxes. The net decrease in income taxes for the year ended December 31, 2005 was primarily due to a decrease in income before income taxes, partially offset by additional state income taxes attributable to an increase in apportioned income to states with higher statutory rates. The net increase in income taxes for the nine months ended September 30, 2007 was primarily due to a one-time benefit to deferred state income tax for the new Texas margin tax recorded in the prior period and higher income before income taxes in the nine months ended September 30, 2007.
 
Texas House Bill 3, signed into law in May 2006, eliminated the taxable capital and earned surplus components of the existing franchise tax and replaced these components with a taxable margin tax calculated on a combined group reporting basis. Our Predecessor was required to include the impact of the new law in income for the period which included the date of the law’s enactment. The adjustment, a


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reduction in deferred state income taxes in the amount of approximately $1.1 million, net of federal tax benefit, was included in 2006 income tax expense.
 
LIQUIDITY AND CAPITAL RESOURCES
 
Our ability to finance operations and fund maintenance capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these expenses. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. Please read “Risk factors” included elsewhere in this prospectus.
 
Historically, our sources of liquidity included cash generated from operations and funding from Anadarko. We historically participated in Anadarko’s cash management program, whereby Anadarko, on a periodic basis, swept cash balances residing in our bank accounts. Thus, our historical combined financial statements reflect little or no cash balances. Unlike our transactions with third parties which ultimately settle in cash, our affiliate transactions are settled on a net basis through an adjustment to parent net equity.
 
Prospectively, we will maintain our own bank accounts and sources of liquidity and will utilize Anadarko’s cash management system and expertise.
 
Subsequent to this offering, we expect our sources of liquidity to include:
 
Ø  $10 million of net offering proceeds to be retained for general partnership purposes;
 
Ø  cash generated from operations;
 
Ø  borrowings under Anadarko’s credit facility up to the amount of our borrowing limit;
 
Ø  borrowings under our working capital facility with Anadarko;
 
Ø  interest income from our $337.6 million note receivable from Anadarko;
 
Ø  issuances of additional partnership units; and
 
Ø  debt offerings.
 
We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements, and quarterly cash distributions to unitholders.
 
Working capital
 
Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by factors such as credit extended to, and the timing of collections from, our customers and our level of spending for maintenance and expansion activity. Historically, all affiliated transactions were not cash settled within our combined financial statements, and did not require independent working capital borrowings. Prospectively, to the extent transactions with Anadarko and third parties require working capital, such amounts will be independently obtained by us.
 
Historical combined cash flow
 
The following table and discussion presents a summary of our combined net cash provided by (used in) operating activities, combined net cash provided by (used in) investing activities and combined net cash provided by (used in) financing activities for the years ended December 31, 2006, 2005 and 2004 and for the nine months ended September 30, 2007 and 2006.


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For all periods presented below, our net cash from operating activities and capital contributions from our parent were used to service our cash requirements, which included our operating expenses, maintenance capital expenditures and expansion capital expenditures.
 
                                         
    Year ended December 31,     Nine months ended September 30,  
    2006     2005     2004     2007     2006  
   
    (in thousands)  
 
Net cash provided by (used in):
                                       
Operating activities
  $ 27,323     $ 30,131     $ 31,160     $ 41,810     $ 12,941  
Investing activities
  $ (42,713 )   $ (21,076 )   $ (16,548 )   $ (37,247 )   $ (27,952 )
Financing activities
  $ 15,844     $ (9,067 )   $ (14,596 )   $ (5,021 )   $ 15,007  
Net increase (decrease) in cash
  $ 454     $ (12 )   $ 16     $ (458 )   $ (4 )
 
Operating Activities.  Net cash provided by operating activities decreased by $2.8 million, or 9%, for the year ended December 31, 2006. Net cash provided by operating activities decreased by $1.0 million, or 3%, for the year ended December 31, 2005. Net cash provided by operating activities increased by $31.1 million, or 240%, for the nine months ended September 30, 2007.
 
The $2.8 million decrease in net cash provided by operating activities during the year ended December 31, 2006 was primarily due to a $6.9 million decrease in net accounts payable and accrued expenses, natural gas imbalances, and accounts receivable, offset by $4.4 million of additional net cash provided by operating activities related to MIGC.
 
The $1.0 million decrease in net cash provided by operating activities during the year ended December 31, 2005 was primarily due to a $2.2 million decrease in net income, partially offset by a $1.2 million increase in net cash provided from changes in assets and liabilities.
 
The $28.9 million increase in net cash provided by operating activities during the nine months ended September 30, 2007 was primarily due to a $10.4 million increase in net cash provided by operating activities related to MIGC, a $13.4 million increase in net income, not related to MIGC, adjusted for non-cash items and a $6.6 million increase from changes in accounts payable and accrued expenses.
 
Investing Activities.  Net cash used in investing activities for the year ended December 31, 2006 increased by $21.6 million, or 103%. Net cash used in investing activities increased by $4.5 million, or 27%, for the year ended December 31, 2005. Net cash used in investing activities increased by $9.3 million, or 33%, for the nine months ended September 30, 2007.
 
Our investing activities included $21.5 million, $4.5 million, and $9.3 million in capital expenditure increases for the year ended December 31, 2006, the year ended December 31, 2005, and the nine months ended September 30, 2007, respectively.
 
The increase in capital expenditures for the year ended December 31, 2006 was related to additional compression and well connections on the Dew system and additional well connections on the Haley system.
 
The increase in capital expenditures for the year ended December 31, 2005 was attributable to increased activity within the Haley field and the Dew gathering system.
 
The increase in capital expenditures for the nine months ended September 30, 2007 was attributable to adding compression and connecting additional wells to the Dew system.
 
Financing Activities.  Net cash provided by financing activities for the year ended December 31, 2006 increased by $24.9 million. Net cash used in financing activities decreased by $5.5 million for the year


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Management’s discussion and analysis of financial condition and results of operations
 
 
ended December 31, 2005. Net cash provided by financing activities decreased by $20.0 million for the nine months ended September 30, 2007. All increases and decreases were attributable to period-to-period variances in cash contributions from or cash payments to Anadarko.
 
Off-balance sheet arrangements
 
We do not have any off-balance sheet arrangements.
 
Capital requirements
 
Our businesses can be capital-intensive, requiring significant investment to maintain and improve existing facilities. We categorize capital expenditures as either:
 
Ø  Maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory or legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or
 
Ø  Expansion capital expenditures, which include those expenditures incurred in order to extend the useful lives of our assets, increase gathering, treating and transmission throughput from current levels, reduce costs or increase revenues.
 
Our historical accounting records did not differentiate between maintenance and expansion capital expenditures. We estimate that expansion capital expenditures represented approximately 63%, 49% and 35% of total capital expenditures for the years ended December 31, 2006, 2005 and 2004, respectively. Our total historical capital expenditures were as follows:
 
                                         
    Year ended December 31,     Nine months ended September 30,  
    2006     2005     2004     2007     2006  
   
    (in thousands)  
 
Total capital expenditures, net
  $ 42,299     $ 20,841     $ 16,548     $ 37,020     $ 27,709  
 
We expect our maintenance and expansion capital expenditures for the twelve months ending December 31, 2008 to be $28.0 million and $15.9 million, respectively. Two components of our strategy are growth through organic expansion and pursuit of accretive acquisitions, and we expect to invest capital in a manner that positions us to execute on our strategy. Our future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under Anadarko’s credit facility, the issuance of additional partnership units and debt offerings.
 
Our borrowing capacity under Anadarko’s credit facility
 
On December 14, 2007, Anadarko amended its $750 million credit facility, which is available for borrowings and letters of credit, to permit us to borrow up to $100 million under the facility. Anadarko’s credit facility has a maturity date of August 31, 2009. Our $100 million borrowing limit under Anadarko’s credit facility is available for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Anadarko and its other subsidiaries. At September 30, 2007, letters of credit totaling $3.0 million had been issued on behalf of Anadarko by the participating institutions under this facility and no revolving credit loans were outstanding.


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Management’s discussion and analysis of financial condition and results of operations
 
 
Interest on borrowings under this credit facility is calculated based on the election by the borrower of either: (i) a floating rate equal to the federal funds effective rate plus 0.5% or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. We are required to pay a commitment fee based on the unused portion of our $100 million borrowing capacity under the facility, currently 0.175% annually. The applicable margin, which is currently 0.675%, and the commitment fees are based on Anadarko’s senior unsecured long-term debt rating. Under the credit facility, Anadarko and we are required to comply with certain covenants, including a financial covenant that requires both Anadarko and us to maintain a debt-to-book capitalization ratio of 60% or less. Anadarko was in compliance with this ratio at September 30, 2007. Should we or Anadarko fail to comply with this or any other covenant in Anadarko’s credit facility, we may not be allowed to borrow under Anadarko’s credit facility. Pursuant to the credit facility, Anadarko is a guarantor of all borrowings under the credit facility, including our borrowings. We are not a guarantor of Anadarko’s borrowings under the credit facility.
 
Our working capital facility
 
Concurrently with the closing of this offering, we will enter into a $30 million, three-year, revolving credit facility with Anadarko as the lender. The facility will be available exclusively to fund working capital borrowings. Borrowings under the facility will bear interest at the same rate as would apply to borrowings under the Anadarko revolving credit facility described above. We will pay a commitment fee to Anadarko on the unused portion of the working capital facility of 0.175% annually.
 
We will be required to reduce all borrowings under our working capital facility to zero for a period of at least 15 consecutive days at least once during each of the twelve-month periods prior to the maturity date of the facility.
 
Credit risk
 
We bear credit risk represented by our exposure to non-payment or non-performance by our customers, including Anadarko. Generally, non-payment or non-performance results from a customer’s inability to satisfy receivables for services rendered or volumes owed pursuant to gas imbalance agreements. We examine the creditworthiness of third-party customers to whom we grant credit and establish credit limits in accordance with our credit policy. We are dependent upon a single producer, Anadarko, for the majority of our natural gas volumes, and we do not have a credit policy with respect to Anadarko. Consequently, we are subject to the risk of non-payment or late payment by Anadarko of gathering, treating and transmission fees, and this risk is greater than it would be with a broader customer base with a similar credit profile. We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues.
 
While Anadarko currently has investment grade credit ratings, if Anadarko becomes unable to perform under the terms of our gathering and transportation agreements, its note payable to us or the omnibus agreement, it may significantly reduce our ability to make distributions to our unitholders. We will be exposed to credit risk on the note receivable from Anadarko that will be issued by Anadarko to us concurrently with the closing of this offering. In addition, we will enter into an omnibus agreement with Anadarko under which Anadarko is required to indemnify us for certain environmental claims, losses arising from rights-of-way claims, failures to obtain required consents or governmental permits, and income taxes.


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Management’s discussion and analysis of financial condition and results of operations
 
 
Total contractual cash obligations
 
A summary of our total contractual cash obligations as of December 31, 2006, which consisted of four compressor leases, is as follows:
 
                                         
          Less than
                More than
 
    Total     1 year     2-3 years     4-5 years     5 years  
   
    (in thousands)  
 
Lease commitments
  $ 13,359     $ 3,123     $ 4,177     $ 4,277         $ 1,782  
 
During the nine months ended September 30, 2007, Anadarko exercised its option to purchase three of the four compressors which were under lease from a third party to Anadarko and subleased by Anadarko to us. Anadarko then transferred the compressors to us as a contribution to our capital. This transaction is expected to reduce operation and maintenance expense by approximately $1.7 million annually, which will be partially offset by a $1.5 million increase in depreciation expense. As a result of this transaction, our contractual cash obligations changed, and at September 30, 2007 were as follows:
 
                                         
          Less than
                More than
 
    Total     1 year     2-3 years     4-5 years     5 years  
   
    (in thousands)  
 
Lease commitments
  $ 5,360     $ 799     $ 1,936     $ 1,958          $ 667  
 
In addition to the obligations listed above, we will enter into an omnibus agreement with Anadarko whereby we will reimburse Anadarko for certain operating and general and administrative expenses it incurs for our benefit with respect to our assets and operations. Under the omnibus agreement, our reimbursement to Anadarko for certain general and administrative expenses it allocates to us will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year.
 
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Commodity price risk
 
We bear a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. As part of this arrangement, we are required to provide a thermally equivalent volume of natural gas or the cash equivalent thereof to the shipper. Thus, our revenues for this portion of our contractual arrangement are based on the price received for the condensate and our costs for this portion of our contractual arrangement are dependent upon the price of natural gas. Condensate historically sells at a price representing a slight discount to the price of crude oil. We consider our exposure to commodity price risk associated with these arrangements to be minimal based on the amount of operating income generated under these arrangements compared to our overall operating income and the fact that the balance of our operating income is fee-based. For the years ended December 31, 2006, 2005 and 2004, a 10% change in the trading margin between condensate and natural gas would have resulted in a $375,000, or 1.6%, $250,000, or 1.2%, and $206,000, or 1.0%, change in operating income for those periods, respectively.


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Management’s discussion and analysis of financial condition and results of operations
 
 
Interest rate risk
 
Interest rates during the periods discussed above were low compared to rates over the last 50 years. If interest rates were to rise, our financing costs would increase accordingly. Although increased borrowing costs could limit our ability to raise funds in the capital markets, we expect our competitors would be similarly affected. We expect to have immaterial amounts of borrowings through December 31, 2008. Accordingly, we do not expect to have any material interest rate risk.
 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
The preparation of combined financial statements in accordance with accounting principles generally accepted in the U.S. requires our management to make estimates and assumptions that affect the amounts reported in the combined financial statements and the accompanying notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results may vary significantly from those estimates. Management considers an understanding of our critical accounting policies and estimates to be essential to gaining a full understanding of our combined financial results. For additional information concerning our accounting policies not discussed below, see the Notes to the Combined Financial Statements included elsewhere in this prospectus.
 
Depreciation and impairment policy
 
Depreciation expense is generally computed using the straight-line method over the estimated useful life of the assets. Determination of depreciation expense requires judgment regarding the estimated useful lives and salvage values of property, plant and equipment. As circumstances warrant, depreciation estimates are reviewed to determine if any changes in the underlying assumptions are necessary.
 
Each reporting period, management assesses whether facts and circumstances indicate that the carrying amounts of property, plant and equipment may not be recoverable from expected undiscounted cash flows from the use and eventual disposition of an asset. If the carrying amount of the asset is not expected to be recoverable from future undiscounted cash flows, an impairment may be recognized. Any impairment is measured as the excess of the carrying amount of the asset over its estimated fair value. The weighted average life of our long-lived assets is approximately 21 years. If the depreciable lives of our assets were reduced by 10%, we estimate that depreciation expense would increase by $2.5 million, which would result in a corresponding reduction in our operating income.
 
In assessing long-lived assets for impairment, management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. Since a significant portion of our revenues arises from gathering and transporting natural gas production from Anadarko-operated properties, significant downward revisions in reserve estimates or changes in future development plans by Anadarko, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability. Such assessment requires application of judgment regarding the use and ultimate disposition of the asset, long-range revenue and expense estimates, global and regional economic conditions, including commodity prices and drilling activity by our customers, as well as other factors affecting estimated future net cash flows. The measure of impairment to be recognized, if any, depends upon management’s estimate of the asset’s fair value, which may be determined based on the estimates of future net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. For the periods presented, we believe that no facts were present that would indicate the carrying amount of assets may not be recoverable. However, given the degree of judgment about highly uncertain matters involved in assessing our key assets for impairment, it is reasonably possible that such assessments in future periods would have material effects on our financial conditions and results of operations. If an assessment of impairment resulted in a reduction of 1% of our assets, our operating income would decrease by $3.5 million.


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Business
 
OVERVIEW
 
We are a growth-oriented Delaware limited partnership recently formed by Anadarko (NYSE: APC) to own, operate, acquire and develop midstream energy assets. We currently operate in East Texas, the Rocky Mountains, the Mid-Continent and West Texas and are engaged in the business of gathering, compressing, treating and transporting natural gas for our ultimate parent, Anadarko, and third-party producers and customers. We principally provide our midstream services under long-term contracts with fee-based rates extending for primary terms of up to 20 years. We generally do not take title to the natural gas that we gather and, therefore, are able to avoid significant direct commodity price exposure.
 
We believe that one of our principal strengths is our relationship with Anadarko. During each of the year ended December 31, 2006 and the nine months ended September 30, 2007, over 90% of our total natural gas gathering and transportation volumes were comprised of natural gas production owned or controlled by Anadarko. In addition, Anadarko Petroleum Corporation has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Volumes associated with this dedication were approximately 736 MMBtu/d for the year ended December 31, 2006 and approximately 738 MMBtu/d for the nine months ended September 30, 2007.
 
We expect to utilize the significant experience of Anadarko’s management team to execute our growth strategy, which includes acquiring and constructing additional midstream assets. For the nine months ended September 30, 2007, as adjusted for divestitures prior to this offering and including the assets being contributed to us, Anadarko’s total domestic midstream asset portfolio generated approximately $250 million of cash flow from operations and consisted of 25 gathering systems and one transportation system with an aggregate throughput of approximately 3.0 Bcf/d, approximately 11,200 miles of pipeline and 25 processing and/or treating facilities.
 
OUR ASSETS AND AREAS OF OPERATION
 
Our assets consist of six gathering systems, five natural gas treating facilities and one interstate pipeline. Our assets are located in East Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma) and West Texas. The following table provides information regarding our assets by operating area as of or for the nine months ended September 30, 2007:
 
                                       
            Approximate #
  Gas
  Treating
  Average
   
        Length
  of
  compression
  capacity
  throughput
   
Area   Asset type   (miles)   receipt points   (horsepower)   (MMcf/d)   (MMcf/d)    
     
 
East Texas
  Gathering and Treating     577     789     45,633     510     304 (1 )
Rocky Mountains
  Gathering and Treating     114     162     20,385     92     55    
    Transportation     264     19     29,696         137    
Mid-Continent
  Gathering     1,753     1,507     130,720         123    
West Texas
  Gathering     87     50             185    
                                     
Total
    2,795     2,527     226,434     602     804    
                                 
 
 
(1)  To avoid duplicating volumes, 213 MMcf/d that is gathered on our Dew gathering system and delivered into our Pinnacle gas treating system is included only once in the calculation of average throughput.


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STRATEGY
 
Our primary business objective is to increase our cash distribution per unit over time. We intend to accomplish this objective by executing the following strategy:
 
Ø  Pursuing accretive acquisitions.  We expect to pursue accretive acquisition opportunities within the midstream energy industry from Anadarko and third parties. Given Anadarko’s large portfolio of midstream assets, we believe that we will have access to an array of acquisition opportunities, though Anadarko is under no legal obligation to offer assets or business opportunities to us. In addition, we may also pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or Anadarko’s existing asset base or allow us to capture operational efficiencies from Anadarko’s production.
 
Ø  Capitalizing on organic growth opportunities.  The significant dedication to us by Anadarko provides us with a platform for organic growth. We expect to achieve this growth by meeting Anadarko’s gathering needs, which we expect to increase as a result of its anticipated drilling activity in our areas of operation. We also intend to actively pursue new volumes associated with Anadarko’s development of undeveloped acreage that is accessible by our gathering systems. Examples of organic growth opportunities potentially arising from our relationship with Anadarko include:
 
  Anadarko’s active drilling program in the East Texas Bossier play, including the Cotton Valley Lime formations; and
 
  Anadarko’s increased drilling and recompletion activity in the Hugoton field as a result of recent rule changes by the Kansas Corporation Commission.
 
Ø  Attracting additional third-party volumes to our systems.  We intend to actively market our midstream services to and pursue strategic relationships with third-party producers to attract additional volumes and/or expansion opportunities. Recent examples of such expansions include:
 
  the planned expansion of the sour gas treating capacity of our Bethel plant to accommodate the recent drilling activity by third parties in the Cotton Valley Lime formations; and
 
  the expansion of the Hugoton gathering system to obtain volumes previously gathered by a competitor’s system.
 
Ø  Minimizing commodity price exposure.  Our midstream services are provided under fee-based arrangements which minimize our direct commodity price exposure. We expect to utilize hedging to manage any significant future commodity price risk that could result from contracts we may acquire or enter into in the future.
 
COMPETITIVE STRENGTHS
 
We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective because of the following competitive strengths:
 
Ø  Affiliation with Anadarko.  We believe that Anadarko, as the owner of our general partner interest, all of our incentive distribution rights and a 57.3% limited partner interest in us, is motivated to promote and support the successful execution of our business plan and to pursue projects that enhance the value of our business. We believe that our relationship with Anadarko will enhance our ability to achieve our primary business objective through, for example, the following:
 
  Anadarko Petroleum Corporation has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future;


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  as Anadarko develops the acreage in proximity to our gathering systems or acquires additional acreage in our areas of operation, we believe that it will deliver additional volumes to our facilities, although it is not obligated to do so;
 
  Anadarko manages a large portfolio of midstream assets in highly active oil and natural gas producing areas, such as the Rocky Mountains, and we believe that Anadarko may offer us the opportunity to purchase some or all of such assets in the future, although it is not obligated to do so; and
 
  we have access to Anadarko’s broad operational, commercial, technical, risk management and administrative infrastructure, its significant pool of management talent and its strong commercial relationships throughout the energy industry.
 
Ø  Relatively stable and predictable cash flow.  Given the fee-based, long-term nature of our midstream service agreements, our cash flow is largely protected from fluctuations caused by commodity price volatility. In addition, our contracts have primary terms ranging up to 20 years, and we generally do not take title to the natural gas that we gather, compress, treat or transport. Moreover, our systems are connected to wells in producing basins that generally have long lives with predictable flow rates.
 
Ø  Well-positioned, well-maintained and efficient assets.  We believe that our established positions in our areas of operation provide us with opportunities to expand and attract additional volumes to our systems. Moreover, our systems consist of high-quality, well-maintained assets for which we have implemented modern treating, measuring and operating technologies. These applications have allowed us to manage our operations efficiently with limited field personnel, resulting in lower costs and minimal downtime.
 
Ø  Financial flexibility to pursue expansion and acquisition opportunities.  We have up to $100 million of borrowing capacity available to us under Anadarko’s $750 million credit facility and, concurrently with the closing of this offering, we expect to obtain a $30 million working capital facility from Anadarko. In addition, we will have no indebtedness outstanding at the closing of this offering. We believe that our borrowing capacity and our ability to effectively access debt and equity capital markets provide us with the financial flexibility necessary to achieve our organic expansion and acquisition strategy.
 
Ø  Experienced management team.  Our general partner’s management team, which includes senior executives of Anadarko, has on average over 15 years of industry experience. Members of our general partner’s management team have extensive experience in building, acquiring, integrating, financing and managing midstream assets. In addition, our relationship with Anadarko provides us with the services of experienced personnel who successfully managed our assets and operations while they were owned by Anadarko.
 
We believe that we will effectively leverage our competitive strengths to successfully implement our strategy; however, our business involves numerous risks and uncertainties which may prevent us from achieving our primary business objective. For a more complete description of the risks associated with an investment in us, please read “Risk factors.”
 
OUR RELATIONSHIP WITH ANADARKO
 
One of our principal attributes is our relationship with Anadarko. It will own our general partner and a significant interest in us following this offering. Anadarko is one of the largest independent oil and gas exploration and production companies in the world. Anadarko, which trades on the NYSE under the symbol “APC,” has major operations in established onshore areas of the U.S., including the Rocky Mountains, as well as in the deepwater Gulf of Mexico and Algeria. Anadarko also has production in China, a development project in Brazil and is executing strategic exploration programs in several other countries.


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Anadarko’s upstream oil and gas business finds and produces natural gas, crude oil, condensate and NGLs. Anadarko is growth-oriented and annually pursues one of the most active drilling programs in the industry, with over 1,400 development wells drilled onshore in the U.S. in 2006. Anadarko has identified the Rocky Mountains and its Southern region (which includes the Mid-Continent and Texas) as core areas from which it expects to derive a significant portion of its future production growth from development drilling activity. We expect Anadarko to remain active in our areas of operation, which we believe will provide us with both organic and acquisition-related growth opportunities.
 
At September 30, 2007, including the assets being contributed to us but adjusted for divestitures prior to this offering, Anadarko’s total domestic midstream asset portfolio consisted of 25 gathering systems and one transportation system with an aggregate throughput of approximately 3.0 Bcf/d, approximately 11,200 miles of pipeline and 25 processing and/or treating facilities. Following this offering, Anadarko’s remaining midstream business will consist of 19 gathering systems with an aggregate throughput of approximately 2.2 Bcf/d, 8,400 miles of pipeline and 20 processing and/or treating facilities. The assets to be retained by Anadarko generated approximately $191 million of cash flow from operating activities for the nine months ended September 30, 2007. Anadarko has invested significant capital in its domestic midstream business, including the assets being contributed to us, with investments of approximately $290 million in 2006 and planned investments of approximately $600 million in 2007, of which approximately $475 million had been invested as of September 30, 2007.
 
Although our relationship with Anadarko provides us with a significant advantage in the midstream natural gas market, it is also a source of potential conflicts. For example, Anadarko is not restricted from competing with us. Please read “Conflicts of interest and fiduciary duties.” Given Anadarko’s significant ownership of limited and general partner interests in us following this offering, we believe it will be in Anadarko’s best interest for it to sell additional assets to us over time; however, Anadarko continually evaluates acquisitions and divestitures and may elect to acquire, construct or dispose of midstream assets in the future without offering us the opportunity to acquire or construct those assets. Anadarko is under no contractual obligation to offer any such opportunities to us, nor are we obligated to participate in any such opportunities. We cannot state with any certainty which, if any, opportunities to acquire assets from Anadarko may be made available to us or, if given the opportunity, that we will elect to pursue any such acquisitions.
 
At the close of this offering, we will enter into an omnibus agreement with Anadarko and our general partner that will govern our relationship regarding certain reimbursement and indemnification matters. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”


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Business
 
 
 
INDUSTRY OVERVIEW
 
The midstream natural gas industry is the link between the exploration and production of natural gas from the wellhead or lease and the delivery of the gas and its other components to end-use markets. Companies within this industry create value at various stages along the natural gas value chain by gathering natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs, and then routing the separated dry gas and NGL streams for delivery to end-markets or to the next intermediate stage of the value chain. The following diagram illustrates the groups of assets commonly found along the natural gas value chain:
 
GROUP ASSETS DIAGRAM
 
Service types
 
The services provided by us and other midstream natural gas companies are generally classified into the categories described below. As indicated below, we do not currently provide all of these services, although we may do so in the future.
 
Gathering.  At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures. In connection with our gathering services, we retain and sell condensate, which falls out of the natural gas stream during gathering.
 
Compression.  Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be delivered into a higher pressure system. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.
 
Treating and Dehydration.  To the extent that gathered natural gas contains contaminants, such as water vapor, carbon dioxide and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.
 
Processing.  Most decontaminated rich natural gas does not meet the quality standards for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components, which are extracted as NGLs. Our assets do not currently include processing facilities.


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Fractionation.  Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. It is accomplished by controlling the temperature and pressure of the stream of mixed NGLs in order to take advantage of the different boiling points of separate products. Our assets do not currently include fractionation operations.
 
Transportation and Storage.  Once the raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts. Our assets do not currently include storage facilities.
 
Typical Contractual Arrangements.  Midstream natural gas services, other than transportation and storage, are usually provided under contractual arrangements which vary in the amount of commodity price risk they carry. Three typical contract types are described below:
 
Ø  Fee-Based.  Fee-based arrangements may be used for gathering, compression, treating and processing services. Under these arrangements, the service provider typically receives a fee for each unit of natural gas gathered and compressed at the wellhead and an additional fee per unit of natural gas treated or processed at its facility. As a result, the service provider bears no direct commodity price risk exposure. We provide our gathering, compression and treating services to Anadarko and third-party producers under fee-based arrangements which minimize our direct commodity price exposure.
 
Ø  Percent-of-Proceeds, Percent-of-Value or Percent-of-Liquids.  Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue gas and/or NGLs or a percentage of the actual residue gas and/or NGLs at the tailgate. These types of arrangements expose the processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and NGLs. We do not currently have any percent-of-proceeds, percent-of-value or percent-of-liquids arrangements.
 
Ø  Keep-Whole.  Keep-whole arrangements may be used for processing services. Under these arrangements, the service provider keeps 100% of the NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer. Since some of the gas is used and removed during processing, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs. We do not currently have any keep-whole arrangements.
 
There are two forms of contracts utilized in the transportation and storage of natural gas, as described below:
 
Ø  Firm.  Firm transportation service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas transported. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.
 
Ø  Interruptible.  Interruptible transportation and storage service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm


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customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.
 
Natural gas demand and production
 
Natural gas is a critical component of energy supply in the U.S. According to the Energy Information Administration, or the EIA, total annual domestic consumption of natural gas is expected to increase from approximately 21.7 trillion cubic feet, or Tcf, in 2006 to approximately 24.7 Tcf in 2010. The industrial and electricity generation sectors are the largest consumers of natural gas in the U.S. During the last three years, these sectors accounted for approximately 57% of the total natural gas consumed in the U.S. In 2006, natural gas provided approximately 22% of all end-user commercial and residential energy requirements. During the last three years, the U.S. has, on average, consumed approximately 22.0 Tcf per year, with average annual domestic production of approximately 18.4 Tcf during the same period. Driven by growth in natural gas demand and high natural gas prices, domestic natural gas production is projected to increase from 18.6 Tcf per year to 19.6 Tcf per year between 2006 and 2016. The graph below represents projected U.S. natural gas production versus U.S. natural gas consumption (in Tcf) through the year 2030.
 
NATURAL GAS CHART
 
Source: Energy Information Administration
 
OUR ASSETS
 
We own and operate all of our assets, which consist of six gathering systems, five natural gas treating facilities and one interstate pipeline, in East Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma) and West Texas. Other than the natural gas that is gathered by our Hugoton gathering system, which is currently processed by third parties, none of the natural gas serviced by our assets requires processing. The following sections describe in more detail the services provided by our assets in our areas of operation.
 
East Texas
 
Dew gathering system
 
General.  The 317-mile Dew gathering system is located in Anderson, Freestone, Leon and Robertson Counties of East Texas. The Dew gathering system was placed into service in November 1998 to provide gathering services for Anadarko’s active drilling program in the Bossier play. The system provides gathering, dehydration and compression services and ultimately delivers into the Pinnacle gas treating system for any required treating.


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Average throughput on the Dew gathering system for the year ended December 31, 2006 and the nine months ended September 30, 2007 was 235 MMcf/d and 217 MMcf/d, respectively, from approximately 725 receipt points. The Dew gathering system has pipeline diameters ranging from three to 12 inches and has 14 compressor stations with a combined 44,368 horsepower of compression.
 
Customers.  Anadarko is the only significant shipper on the Dew gathering system. Anadarko’s equity gas accounted for 213 MMcf/d of throughput during the nine months ended September 30, 2007, which represented approximately 98% of the total volume on the system.
 
Delivery Points.  The Dew gathering system’s primary delivery point is Pinnacle Gas Treating, Inc., which is described in more detail below, but it also has a connection to Kinder Morgan’s Tejas pipeline.
 
Supply.  Anadarko has drilled over 750 gross wells to date in the Bossier play and controls approximately 230,000 gross acres in the area. For the last three years, Anadarko has maintained an active drilling program in the Bossier play utilizing four or five rigs to drill approximately 30 gross wells per year. With this level of activity, we believe Anadarko has a drilling location inventory of over five years.
 
Pinnacle Gas Treating LLC
 
General.  Pinnacle Gas Treating LLC includes our Pinnacle gathering system and our Bethel treating plant. Pinnacle Gas Treating provides sour gas gathering and treating service in Anderson, Freestone, Leon, Limestone and Robertson Counties of East Texas. The gathering system consists of 256 miles of pipeline with diameters ranging from three to 24 inches and one compressor station with 1,265 horsepower.
 
The Bethel treating plant, located in Anderson County, has total CO2 treating capacity of 500 MMcf/d and nine long tons per day, or LTD, of sulfur treating capacity. We are currently expanding the plant by installing an additional 11 LTD of sulfur treating capacity, which we expect to have completed in 2008, in order to provide additional sour gas treating capacity for drilling in the area.
 
Average throughput on the Pinnacle gathering system for the year ended December 31, 2006 and the nine months ended September 30, 2007 was 307 MMcf/d and 300 MMcf/d, respectively, from approximately 70 receipt points.
 
Customers.  Anadarko is the largest shipper on the Pinnacle gathering system with 272 MMcf/d of throughput for the nine months ended September 30, 2007, which represented approximately 91% of the total throughput on the system during such period. Eighty percent of Anadarko’s throughput is equity production, which includes Bossier natural gas delivered from the Dew gathering system and several wells directly connected to the Pinnacle system that produce from the Cotton Valley Lime formations. The remaining 20% of Anadarko’s throughput consists of natural gas purchased by Anadarko from third parties.
 
Other shippers on the Pinnacle gathering system are ConocoPhillips Company, Hunt Petroleum Corp., EnCana Oil & Gas (USA) Inc., Paragon Energy Inc. and Newfield Exploration Company. These shippers accounted for 27 MMcf/d for the nine months ended September 30, 2007, which represented approximately 9% of total throughput on the system during such period.
 
Delivery Points.  The Pinnacle gathering system is connected to Enterprise Texas Pipeline, LP’s pipeline, the Energy Transfer Fuels pipeline, the ETC Texas pipeline, Kinder Morgan’s Tejas pipeline, the ATMOS Texas pipeline and the Enbridge Pipelines (East Texas) LP pipeline. These pipelines provide transportation to the Carthage, Waha and Houston Ship Channel market hubs in Texas.
 
Supply.  The Pinnacle gathering system is well positioned to provide gathering and treating services to the five county area over which it extends. With an average of 400 wells drilled in each of the last five


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years, this area has experienced significant recent growth and, as of September 30, 2007, had a total well count exceeding 5,000 wells and production of over 1.5 Bcf/d.
 
With the recent drilling activity in the Cotton Valley Lime formations, which contain higher concentrations of H2S and CO2, we were able to obtain a commitment from a third-party producer that allows us to expand the Bethel treating facilities. With this expansion, we believe that we are well positioned to benefit from future sour gas production in the area.
 
Rocky Mountains
 
MIGC system
 
General.  The MIGC system is a 264-mile interstate pipeline operating within the Powder River Basin of Wyoming that is regulated by the Federal Energy Regulatory Commission, or FERC. The MIGC system traverses the Powder River Basin from north to south, extending approximately 150 miles to Glenrock, Wyoming. As a result, the MIGC system is well positioned to provide transportation for the extensive natural gas volumes received from various coal-bed methane gathering systems and conventional gas processing plants throughout the Powder River Basin. MIGC offers both forward-haul and backhaul transportation services, and additional capacity is available from time to time on an interruptible basis.
 
Average throughput on the MIGC system for the year ended December 31, 2006 and the nine months ended September 30, 2007 was 126 MMcf/d and 137 MMcf/d, respectively, from approximately 20 receipt points.
 
MIGC recently completed the installation of, and placed into service, the Python compression station, which increased capacity on the MIGC system by approximately 50 MMcf/d. In April 2007, Anadarko entered into a firm transportation contract for 45 MMcf/d of this additional capacity. MIGC is currently certificated for 175 MMcf/d of firm transportation capacity, all of which is fully subscribed.
 
Customers.  Anadarko is the largest firm shipper on the MIGC system, with approximately 72% and 71% of throughput for the year ended December 31, 2006 and the nine months ended September 30, 2007, respectively. For the year ended December 31, 2006 and the nine months ended September 30, 2007, Williams Production RMT Company and KFx Plant, LLC together accounted for approximately 28% and 29%, respectively, of throughput on the system.
 
Revenues on the MIGC system are generated from contract demand charges and volumetric fees paid by shippers under firm and interruptible gas transportation agreements. Our current firm transportation agreements range in term from approximately three months to 11 years. Of the current certificated capacity of 175 MMcf/d, 40 MMcf/d is contracted through October 2018, 45 MMcf/d is contracted through September 2012, 85 MMcf/d is contracted through January 2009 and 5 MMcf/d is contracted through December 2007. Most of our interruptible gas transportation agreements are month-to-month with the remainder generally having terms of less than one year. Approximately 64% and 85% of our revenues for the year ended December 31, 2006 and the nine months ended September 30, 2007, respectively, were associated with firm transportation demand charges.
 
Delivery Points.  MIGC volumes can be redelivered to five interstate market pipelines, including the Williston Basin Interstate pipeline at the northern end of the Powder River Basin, the MGTC pipeline, a pipeline that supplies local markets in Wyoming, the Wyoming Interstate Company’s Medicine Bow lateral pipeline, the Colorado Interstate Gas pipeline and the Kinder Morgan interstate pipeline at the southern end of the Powder River Basin near Glenrock, Wyoming.
 
Supply.  Anadarko has an interest in over one million gross acres within the prolific Powder River Basin. It currently operates approximately 3,500 gross coal-bed methane wells and has non-operating interests in more than 3,400 additional gross coal-bed methane wells. Anadarko’s acreage is


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approximately 50% developed with a substantial undeveloped acreage position in the expanding Big George coal fairway. The historical development pace on Anadarko acreage has been 600 to 800 gross wells per year, suggesting that a five- to seven-year development inventory remains.
 
Helper gathering system
 
General.  The 67-mile Helper gathering system, located in Carbon County, Utah, was built to provide gathering services for Anadarko’s coal-bed methane development of the Ferron Coal. The Helper gathering system provides gathering, dehydration, compression and treating services for coal-bed methane gas. The Helper gathering system has pipeline diameters ranging from four to 20 inches and includes two compressor stations with a combined 11,575 horsepower and two CO2 treating facilities.
 
Average throughput on the Helper gathering system for the year ended December 31, 2006 and the nine months ended September 30, 2007, was 38 MMcf/d and 36 MMcf/d, respectively, from approximately 120 receipt points.
 
Customers.  Anadarko is the largest shipper on the Helper gathering system. For the nine months ended September 30, 2007, Anadarko’s equity production represented approximately 99% of the Helper gathering system’s volume.
 
Delivery Points.  The Helper gathering system delivers into the Questar Transportation Services Company’s pipeline. Questar provides transportation to regional markets in Wyoming, Colorado and Utah and also delivers into the Kern River Pipeline, which provides transportation to markets in the western U.S., primarily California.
 
Supply.  Helper Field is an Anadarko-operated field on the southwestern edge of the Uinta Basin that produces from the Cretaceous Ferron sands and coals. Helper Field consists of approximately 19,000 gross acres and currently has 116 gross producing wells. Cardinal Draw, which lies immediately to the east of Helper Field, currently has 24 gross producing wells and covers another approximately 15,000 gross acres.
 
In 2003, Anadarko entered into an agreement with Westport Oil and Gas Company, LP, which was acquired by Kerr-McGee Corporation in 2004, to gather volumes from its Cardinal Draw development play. Since the acquisition of Kerr-McGee by Anadarko in 2006, Anadarko has continued the development of the Cardinal Draw area. During the nine months ended September 30, 2007, Anadarko drilled 12 gross wells in the Cardinal Draw area and it has disclosed that it has identified an additional 56 drilling locations. Production in the Helper Field/Cardinal Draw area began in 1994 and since then has produced over 92 Bcf.
 
Clawson gathering system
 
General.  The 47-mile Clawson gathering system, located in Carbon and Emery Counties of Utah, was built in 2001 to provide gathering services for Anadarko’s coal-bed methane development of the Ferron Coal. The Clawson gathering system provides gathering, dehydration, compression and treating services for coal-bed methane gas. The Clawson gathering system has pipeline diameters ranging from four to 18 inches and includes one compressor station, with 8,810 horsepower, and a CO2-treating facility.
 
Average throughput on the Clawson gathering system for the year ended December 31, 2006 and the nine months ended September 30, 2007 was 22 MMcf/d and 19 MMcf/d, respectively, from approximately 45 receipt points.
 
Customers.  Anadarko is the largest shipper on the Clawson gathering system with approximately 96% of the total throughput delivered into the system during the nine months ended September 30, 2007. The remaining throughput on the system was comprised of production from third-party producers.


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Delivery Points.  The Clawson gathering system delivers into the Questar Transportation Services Company’s pipeline.
 
Supply.  Clawson Springs Field consists of 45 gross wells on approximately 7,200 gross acres. Production for Clawson Springs is primarily from the Cretaceous Ferron sands and coals. First gas sales in Clawson Springs occurred in 2001 and the field has produced over 54 Bcf.
 
Mid-Continent
 
Hugoton gathering system
 
General.  The 1,753-mile Hugoton gathering system provides gathering service to the Hugoton field and is primarily located in Seward, Stevens, Grant and Morton Counties of Southwest Kansas and Texas County in Oklahoma.
 
Average throughput on the Hugoton gathering system for the year ended December 31, 2006 and the nine months ended September 30, 2007, was 117 MMcf/d and 123 MMcf/d, respectively, from approximately 1,500 receipt points. The Hugoton gathering system has pipeline diameters ranging from two to 26 inches and 44 compressor stations with a combined 130,720 horsepower of compression.
 
Customers.  Anadarko is the largest customer on the Hugoton gathering system with 112 MMcf/d of average throughput during the nine months ended September 30, 2007, representing 86% of the total volume on the system during such period. Of these volumes, 63% represent Anadarko’s equity production and 37% represent volumes purchased by Anadarko from third parties, including EOG Resources, Inc. and Merit Energy Company, among others.
 
Other significant shippers on the Hugoton gathering system, including DCP Midstream, LP, Oxy Oil and Gas, Pioneer Natural Resources USA, Inc. and ExxonMobil Gas & Power Marketing Company, LP, collectively comprised fourteen percent of the system throughput volume for the nine months ended September 30, 2007.
 
Delivery Points.  The Hugoton gathering system is connected to DCP Midstream, LP’s National Helium Plant, which extracts NGLs and helium and redelivers residue gas into the Panhandle Eastern Pipeline. The system is also connected to Pioneer Natural Resources Corporation’s Satanta Plant for NGL processing and to the adjacent Mid-Continent Market Center, which provides access to the Panhandle Eastern pipeline, the Northern Natural Gas pipeline, the Natural Gas (NGPL) pipeline, the Southern Star pipeline, and the ANR pipeline. These pipelines provide transportation and market access to Midwestern and Northeastern markets.
 
Supply.  The Hugoton Field is one of the largest natural gas fields in North America. Anadarko operates approximately 1,250 gross wells in the area and has an extensive acreage position with approximately 425,000 gross acres in the Hugoton Field. We believe that recent changes to the Hugoton and Panoma Council Grove Proration Orders will provide opportunities for significant recompletion, redrilling and density drilling activities.
 
By virtue of a farmout agreement between EOG Resources, Inc. and Anadarko, EOG gained the right to explore below the primary formations in the Hugoton Field. EOG plans to drill approximately 50 gross wells in 2008 and 60 gross wells in 2009 in proximity to the Hugoton gathering system. We believe we are well-positioned to gather volumes that may be produced from these new wells.


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West Texas
 
Haley gathering system
 
General.  The 87-mile Haley gathering system is located in Loving County, Texas and gathers Anadarko’s production from the Delaware Basin. The Haley gathering system provides gathering and dehydration services and has pipeline diameters ranging from four to 16 inches.
 
Average throughput on the Haley gathering system for the year ended December 31, 2006 and the nine months ended September 30, 2007 was 139 MMcf/d and 185 MMcf/d, respectively, from approximately 50 wells. The Haley gathering system has experienced rapid growth as a result of Anadarko’s successful drilling activity in the area. Since 2004, volumes gathered by the Haley system have increased from 13 MMcf/d to over 200 MMcf/d. Anadarko has maintained an active drilling program in the area, utilizing eight to nine rigs to explore and develop its Delaware Basin acreage.
 
Customers.  Anadarko’s and its partners’ production represented 99% of the Haley gathering system’s throughput for the nine months ended September 30, 2007.
 
Delivery Points.  The Haley gathering system has multiple delivery points. The primary delivery points are to the El Paso Natural Gas pipeline or the Enterprise GC, L.P. pipeline for ultimate delivery into Energy Transfer’s Oasis pipeline. We also have the ability to deliver into Southern Union Energy Services’ pipeline for further delivery into the Oasis Pipeline. The pipelines at these delivery points provide transportation to both the Waha and Houston Ship Channel Markets.
 
Supply.  In the greater Delaware basin, Anadarko has access to over 400,000 gross undeveloped acres, currently operates nine rigs and is a non-operating partner in three additional rigs. Within the area serviced by the Haley gathering system, over 60 gross wells have already been drilled and completed and we anticipate that four to five rigs will continuously operate on 100,000 Anadarko-controlled acres. We believe that this activity and Anadarko’s controlled acreage indicate a 5 to 10-year drilling inventory on the acreage serviced by the Haley gathering system.
 
COMPETITION
 
Given that over 90% of the volume on our systems is owned or controlled by Anadarko and Anadarko has dedicated to us future production from acreage surrounding our gathering systems, we do not currently face significant competition for our natural gas volumes. In the future, we may face competition for Anadarko’s production drilled outside the dedication and in attracting third-party volumes to our systems.
 
Competition on gathering systems
 
The natural gas gathering, compression, treating and transportation business is very competitive. Our competitors include other midstream companies, producers, intrastate and interstate pipelines. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. Our major competitors for each area include:
 
Ø  Dew gathering and Pinnacle gas treating:  ETC Texas Pipeline, Ltd., Enbridge Pipelines (East Texas) LP, XTO Energy and Kinder Morgan Tejas Pipeline, LP.
 
Ø  Helper and Clawson gathering systems:  Questar Transportation Services Company.
 
Ø  Hugoton gathering system:  ONEOK Gas Gathering Company, DCP Midstream, LP, Pioneer Resources.
 
Ø  Haley gathering system:  Enterprise GC, LP, Southern Union Energy Services Company.


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Competition on MIGC
 
MIGC competes with other pipelines that service regional market and transport gas volumes from the Powder River Basin to Glenrock, Wyoming. MIGC competitors seek to attract and connect new gas volumes throughout the Powder River Basin, including the volumes currently being transported on MIGC. An increase in competition could result from new pipeline installations or expansions by existing pipelines. Competitive factors include the commercial terms, available capacity, fuel efficiencies, the interconnected pipelines and gas quality issues MIGC major competitors are Fort Union Gas Gathering, L.L.C. and ThunderCreek Gas Services.
 
SAFETY AND MAINTENANCE
 
We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, of the Department of Transportation, or the DOT, pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. Our transportation pipeline system, MIGC, includes no high consequence areas and thus these particular integrity management programs are not applicable.
 
We or the entities in which we own an interest inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.
 
States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines that those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
 
In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety


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requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.
 
REGULATION OF OPERATIONS
 
Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of our business and the market for our products and services.
 
Interstate transportation pipeline regulation
 
MIGC, our interstate natural gas transportation system, is subject to regulation by FERC under the Natural Gas Act of 1938, or the NGA.
 
Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation extends to such matters as:
 
Ø  rates, services, and terms and conditions of service;
 
Ø  the types of services MIGC may offer to its customers;
 
Ø  the certification and construction of new facilities;
 
Ø  the acquisition, extension, disposition or abandonment of facilities;
 
Ø  the maintenance of accounts and records;
 
Ø  relationships between affiliated companies involved in certain aspects of the natural gas business;
 
Ø  the initiation and discontinuation of services;
 
Ø  market manipulation in connection with interstate sales, purchases or transportation of natural gas; and
 
Ø  participation by interstate pipelines in cash management arrangements.
 
Natural gas companies are prohibited from charging rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
 
The rates and terms and conditions for our interstate pipeline services are set forth in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation service.
 
Commencing in 2003, FERC issued a series of orders adopting rules for new Standards of Conduct for Transmission Providers (Order No. 2004), which apply to interstate natural gas pipelines and certain natural gas storage companies that provide storage services in interstate commerce. Order No. 2004 became effective in 2004. Among other matters, Order No. 2004 required interstate pipeline and storage companies to operate independently from their energy affiliates, prohibited interstate pipeline and storage companies from providing non-public transportation or shipper information to their energy affiliates, prohibited interstate pipeline and storage companies from favoring their energy affiliates in providing service and obligated interstate pipeline and storage companies to post on their websites a number of items of information concerning the company, including its organizational structure, facilities shared with energy affiliates, discounts given for service and instances in which the company has agreed to waive discretionary terms of its tariff.
 
Late in 2006, the D.C. Circuit vacated and remanded Order No. 2004 as it relates to natural gas transportation providers, including MIGC. The D.C. Circuit found that FERC had not adequately justified its expansion of the prior standards of conduct to include energy affiliates, and vacated the


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entire rule as it relates to natural gas transportation providers. On January 9, 2007, and as clarified on March 21, 2007, FERC issued an interim rule re-promulgating on an interim basis the standards of conduct that were not challenged before the court, while FERC decides how to respond to the court’s decision on a permanent basis. The interim rule makes the standards of conduct apply to the relationship between natural gas transportation providers and their marketing affiliates, but not to energy affiliates who are not also marketing affiliates. Several companies requested rehearing and clarification of the interim rule. The March 21, 2007 order on clarification granted some of the requested clarifications and stated that FERC would address the other requests in its proceeding establishing a permanent rule. FERC has issued a notice of proposed rulemaking, or NOPR, that proposes permanent standards of conduct that FERC states will avoid the aspects of the previous standards of conduct rejected by the court. With respect to natural gas transportation providers, the NOPR proposes (1) that the permanent standards of conduct apply only to the relationship between natural gas transportation providers and their marketing affiliates, and (2) to make permanent the changes adopted in the interim rule permitting risk management employees to be shared by natural gas transportation providers and their marketing affiliates and requiring that tariff waivers be maintained in a written waiver log and available upon request.
 
On July 7, 2004, FERC issued an order providing MIGC with a partial waiver of the independent functioning and information access provisions of the standards of conduct. FERC has stated that waivers of the standards of conduct have not been impacted by the D.C. Circuit’s decision to vacate the attempted expansion of the standards of conduct as to natural gas transmission providers, by the implementation of the interim rule, or by the currently pending NOPR. Nonetheless, we have no way to predict with certainty the scope of FERC’s permanent rules on the standards of conduct. However, we do not believe that MIGC will be affected by any action taken previously or in the future on these matters in a fashion which is materially different than that affecting similarly situated natural gas service providers.
 
In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through partnership entity, if the pipeline proves that the ultimate owner of its equity interests has an actual or potential income tax liability on public utility income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. In August 2005, FERC dismissed requests for rehearing of its new policy statement. On December 16, 2005, FERC issued its first significant case-specific review of the income tax allowance issue in a pipeline partnership’s rate case. FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16, 2005 order were appealed to the D.C. Circuit. The D.C. Circuit issued an order on May 29, 2007 in which it denied these appeals and upheld FERC’s new tax allowance policy and the application of that policy in the December 16, 2005 order on all points subject to appeal. The D.C. Circuit denied rehearing of the May 29, 2007 decision on August 20, 2007, and the D.C. Circuit’s decision is final.
 
On December 8, 2006, FERC issued another order addressing the income tax allowance in rates. In the December 8, 2006 order, FERC refined and reaffirmed prior statements regarding its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline filed a request for rehearing on this issue, which is currently pending


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before FERC. The ultimate outcome of this proceeding is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service and to potential adjustment in a future rate case of our pipelines’ respective equity rate of return that underlies its recourse rates to the extent that cash distributions in excess of taxable income are allowed to some unitholders. If FERC were to disallow a substantial portion of MIGC’s income tax allowance, it may cause its recourse rates to be set at a level that is different, and in some instances lower, than the level otherwise in effect.
 
On July 19, 2007, FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate return on equity for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of distributions capped at a master limited partnership’s reported earnings in calculating the equity returns of a proxy group of pipeline enterprises under the Discounted Cash Flow, or DCF, analysis. The determination of which master limited partnerships should be included will be made on a case by case basis, after a review of whether a master limited partnership’s earnings have been stable over a multi-year period. In November 2007, the FERC requested additional comments and announced a technical conference regarding the method to be used for creating growth forecasts for publicly traded partnerships. FERC proposes to apply the final policy statement to all natural gas rate cases that have not completed the hearing phase as of the date FERC issues the final policy statement. FERC’s proposed policy statement is subject to change based on comments it has received, and therefore, we cannot predict the scope of the final policy statement.
 
On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or the EPAct 2005. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and, furthermore, provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rules make it unlawful for any entity, directly or indirectly: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC or the purchase or sale of transportation services subject to the jurisdiction of FERC to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rules apply to interstate gas pipelines and storage companies and intrastate gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. The new anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent such transactions do not have a “nexus” to jurisdictional transactions. EPAct 2005 also amends the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes, up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. Should we fail to comply with all applicable FERC-administered statutes, rule, regulations and orders, we could be subject to substantial penalties and fines.
 
Gathering pipeline regulation
 
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas pipelines meet the traditional tests that FERC has used to determine that a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering


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facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
 
Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our system due to these regulations.
 
During the 2007 legislative session, the Texas State Legislature passed H.B. 3273, or the Competition Bill, and H.B. 1920, or the LUG Bill. The Texas Competition Bill and LUG Bill contain provisions applicable to gathering facilities. The Competition Bill allows the Railroad Commission of Texas, or the TRRC, the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering in formal rate proceedings. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters and gatherers for taking discriminatory actions against shippers and sellers. The LUG Bill modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested and gives the TRRC the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. We cannot predict what effect, if any, either the Competition Bill or the LUG Bill might have on our gathering operations.
 
ENVIRONMENTAL MATTERS
 
General
 
Our operation of pipelines, plants and other facilities for the gathering, compressing, treating and transporting of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of


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these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
 
Ø  requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;
 
Ø  limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
 
Ø  requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and
 
Ø  enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations.
 
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes 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.
 
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.
 
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.
 
Hazardous substances and waste
 
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs


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of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of CERCLA Section 101(14), which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
 
We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
 
We currently own or lease, and our Predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
 
Air emissions
 
Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.


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Water discharges
 
The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flow.
 
Endangered species
 
The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.
 
Global warming and climate control
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our services.
 
Anti-terrorism measures
 
The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. We have not yet determined the extent


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to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.
 
TITLE TO PROPERTIES AND RIGHTS-OF-WAY
 
Our real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our predecessors, have leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
 
Some of the leases, easements, rights-of-way, permits and licenses to be transferred to us at the close of this offering require the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner expects to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to the close of this offering, the closing will not occur unless a reasonable basis exists that permits our general partner to conclude that such consents, permits or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.
 
Anadarko may initially continue to hold record title to portions of certain assets until we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, Anadarko may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from Anadarko holding the title to any part of such assets subject to future conveyance or as our nominee.


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EMPLOYEES
 
We do not have any employees. The officers of our general partner will manage our operations and activities. As of September 30, 2007, Anadarko employed approximately 110 people who will provide direct, full-time support to our operations. All of the employees required to conduct and support our operations will be employed by Anadarko and all of our direct, full-time personnel are subject to a service and secondment agreement between our general partner and Anadarko. None of these employees are covered by collective bargaining agreements, and Anadarko considers its employee relations to be good.
 
LEGAL PROCEEDINGS
 
We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “—Regulation of operations—Interstate transportation pipeline regulation” and “—Environmental matters.”


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MANAGEMENT OF THE PARTNERSHIP
 
Western Gas Holdings, LLC, our general partner, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. The directors of our general partner oversee our operations. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, our general partner owes a fiduciary duty to our unitholders. There are no existing arrangements pursuant to which a person has been named as a member of the board of directors of our general partner. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it.
 
Upon the closing of this offering, we expect that our general partner will have nine directors, four of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. One of such independent directors will be appointed prior to the effectiveness of the registration statement of which this prospectus forms a part. The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.
 
At least two independent members of the board of directors of our general partner will serve on a special committee to review specific matters that the board believes may involve conflicts of interest (including certain transactions with Anadarko).           will serve as the initial members of the special committee. The special committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the special committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, including Anadarko, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements. Any matters approved by the special committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
 
In addition, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act.           will serve as the initial independent members of the audit committee. The audit committee will assist the board of directors in its oversight of the integrity of our combined financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to (1) retain and terminate our independent registered public accounting firm, (2) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (3) pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.
 
All of the executive officers of our general partner listed below will manage and conduct our operations. The executive officers of our general partner will allocate their time between managing our business and affairs and the business and affairs of Anadarko. The executive officers of our general partner may face a conflict regarding the allocation of their time between our business and the other business interests of Anadarko. We expect that the officers of our general partner will initially devote less than a majority of their time to our business, although we expect the amount of time that they


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devote may increase or decrease in future periods as our business develops. These officers of our general partner and other Anadarko employees will operate our business and provide us with general and administrative services pursuant to the omnibus agreement and the services and secondment agreement described in “Certain relationships and related party transactions—Agreements governing the transactions—Services and secondment agreement.” We will reimburse Anadarko for allocated expenses of operational personnel who perform services for our benefit, and certain direct expenses.
 
Our general partner will not receive any management fee or other compensation for its management of our partnership under the omnibus agreement, the services and secondment agreement or otherwise. Under the omnibus agreement, our reimbursement to Anadarko for certain general and administrative expenses it allocates to us will be capped at $6.0 million annually through December 31, 2009, subject to adjustments to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”
 
DIRECTORS AND EXECUTIVE OFFICERS
 
The following table shows information regarding the current executive officers and directors of our general partner. Directors are appointed for a term of one year.
 
             
Name   Age   Position with Western Gas Holdings, LLC
 
 
Robert G. Gwin
    44     President, Chief Executive Officer and Director
Danny J. Rea
    49     Senior Vice President, Chief Operating Officer and Director
Michael C. Pearl
    36     Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Lora W. Mays
    44     Vice President and General Counsel
Jeremy M. Smith
    35     Vice President and Treasurer
R.A. Walker
    50     Chairman of the Board and Director
Karl F. Kurz
    46     Director
Robert K. Reeves
    50     Director
 
Our directors hold office until their successors shall have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
 
Robert G. Gwin has served as President and Chief Executive Officer and as a director of our general partner since August 2007 and as Vice President, Finance and Treasurer of Anadarko since January 2006. Prior to joining Anadarko, he served as Chief Executive Officer of Community Broadband Ventures, LP from November 2004 to January 2006. Prior to this position, he was with Prosoft Learning Corporation, serving as Chairman and Chief Executive Officer from November 2002 to November 2004 and Chief Financial Officer from 2000 to November 2002. Previously, Mr. Gwin spent 10 years at Prudential Capital Group in merchant banking roles of increasing responsibility, including serving as Managing Director with responsibility for the firm’s energy investments worldwide. Mr. Gwin holds a Bachelor of Science degree from the University of Southern California and a Master of Business Administration degree from the Fuqua School of Business at Duke University, and he is a Chartered Financial Analyst.


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Danny J. Rea has served as Senior Vice President and Chief Operating Officer and as a director of our general partner since August 2007 and as Vice President, Midstream of Anadarko since May 2007. Previously, Mr. Rea served as Manager, Midstream Services from May 2004 to May 2007 and Manager, Gas Field Services from August 2000 to May 2007. Mr. Rea joined Anadarko as an engineer in 1981 and has held positions of increasing responsibility over his 26 years with the Company. He holds a Bachelor of Science degree in petroleum engineering from Louisiana Tech University, and a Master of Business Administration degree from the University of Houston. He currently serves on the board of directors for the Wyoming Pipeline Authority and is a member of the Gas Processors Association and the Society of Petroleum Engineers.
 
Michael C. Pearl has served as Senior Vice President and Chief Financial Officer of our general partner since August 2007 and as Director, Corporate Tax of Anadarko since August 2006. Prior to this position, he served as corporate tax manager for Anadarko from September 2004 to August 2006. Prior to joining Anadarko, Mr. Pearl joined Ernst & Young LLP in 1995, where he held positions of increasing responsibility, including senior manager, and advised multinational energy companies on structured acquisitions, divestitures, and financings, including advising on partnership taxation and accounting matters. He holds a Bachelor of Business Administration degree and a Master of Science degree in Accounting from Texas A&M University and is a Certified Public Accountant.
 
Lora W. Mays has served as Vice President and General Counsel of our general partner since August 2007 and as Associate General Counsel of Anadarko since January 2003. Ms. Mays joined Anadarko in 1997, and prior to being promoted to her current position, she held the positions of Senior Attorney, Counsel, Senior Counsel and Assistant General Counsel within Anadarko. Prior to joining Anadarko, Ms. Mays was in private practice. She holds a Bachelor of Arts degree and a Juris Doctor degree from the University of Houston.
 
Jeremy M. Smith has served as Vice President and Treasurer of our general partner since August 2007 and as Assistant Treasurer, Corporate Finance of Anadarko since July 2006. Prior to joining Anadarko, he served as Assistant Treasurer to Plains Exploration & Production Company from June 2003 to June 2006 and as Assistant Treasurer of 3TEC Energy Corporation from May 2000 until its sale to Plains Exploration & Production Company in June 2003. Mr. Smith holds a Bachelor of Arts degree in Economics from Rice University, a Master of Science degree in Accounting from Texas A&M University and a Master of Business Administration degree from Rice University, and he is a Chartered Financial Analyst.
 
R.A. Walker has served as Chairman of the Board and a director of our general partner since August 2007 and as Senior Vice President, Finance and Chief Financial Officer of Anadarko since 2005. Prior to joining Anadarko, he was a Managing Director for the Global Energy Group of UBS Investment Bank from 2003 to 2005 and was President, Chief Financial Officer and a director of 3TEC Energy Corporation from 2000 to 2003, until its sale to Plains Exploration. From 1987 to 2000, he worked for Prudential Financial in a variety of merchant banking positions, including Senior Managing Director and co-head of Prudential Capital at the time of his departure. Mr. Walker has served on the boards of directors of numerous publicly traded companies, including TEPPCO Partners, L.P. (a NYSE-listed publicly traded partnership) where he served as chairman of the audit committee.
 
Karl F. Kurz has served as a director of our general partner since August 2007 and as Chief Operating Officer of Anadarko since December 2006. He began his employment at Anadarko in 2000, and he has served in a number of leadership positions at Anadarko, including Senior Vice President, Marketing, General Manager, U.S. Onshore, Vice President, Marketing and Manager, Energy Marketing.
 
Robert K. Reeves has served as a director of our general partner since August 2007 and as Senior Vice President, General Counsel and Chief Administrative Officer of Anadarko since February 2007. He previously served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer beginning in 2004. He has also served as a director of Key Energy Services, Inc., a publicly traded oil


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field services company, since October 2007. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004 and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003.
 
EXECUTIVE COMPENSATION
 
We and our general partner were formed in August 2007. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for our directors and officers for the fiscal year ended December 31, 2006, or for any prior periods. Because the executive officers of our general partner are employees of Anadarko, compensation other than the long-term incentive plan benefits described below will be determined and paid by Anadarko. The officers of our general partner, as well as the employees of Anadarko who provide services to us, may participate in employee benefit plans and arrangements sponsored by Anadarko, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of our officers. We anticipate that, in connection with the closing of this offering, the board of directors of our general partner will grant awards to our key employees and our outside directors pursuant to the long-term incentive plan described below in connection with the closing of this offering; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.
 
COMPENSATION OF DIRECTORS
 
Officers or employees of Anadarko who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that independent directors who are not officers or employees of Anadarko will receive compensation for attending meetings of the board of directors and committees of the board. Such compensation will consist of an annual retainer of $     , a fee of $      for each board meeting attended and an additional fee of $      for each committee meeting attended. The chairman of the audit and special committees will each receive an additional annual retainer of $     . The independent, non-management directors will also receive an annual grant of           restricted units, which will vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control). In addition, each non-employee director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us, pursuant to individual indemnification agreements and our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law.
 
COMPENSATION DISCUSSION AND ANALYSIS
 
Overview
 
We do not directly employ any of the persons responsible for managing our business, and we do not have a compensation committee. Western Gas Holdings, LLC, our general partner, will manage our operations and activities, and its board of directors and officers will make decisions on our behalf.
 
Some of the officers of our general partner also serve as officers of Anadarko. The compensation of Anadarko’s employees that perform services on our behalf (other than the long-term incentive plan benefits described below), including our executive officers, will be approved by Anadarko’s management. Awards under our long-term incentive plan will be recommended by Anadarko’s management and approved by the board of directors of our general partner. Our reimbursement for the compensation of executive officers is governed by, and subject to the limitations contained in, the omnibus agreement and will be based on Anadarko’s methodology used for allocating general and administrative expenses to us. Under the omnibus agreement, our reimbursement of certain general and


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administrative expenses will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year. Please read “Certain relationships and related party transactions—Agreements governing the transactions—Omnibus agreement.”
 
As previously discussed, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the fiscal year ended December 31, 2006, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. Following the consummation of this offering, we expect that the most highly compensated executive officers of our general partner for 2007 will be Robert G. Gwin (the principal executive officer), Danny J. Rea (principal operating officer), and Michael C. Pearl (the principal financial officer and principal accounting officer) (collectively, the “named executive officers”). We expect that the named executive officers will have less than a majority of their total compensation allocated to us as compensation expense in 2007. Compensation paid or awarded by us in 2007 with respect to the named executive officers will reflect only the portion of compensation expense that is allocated to us pursuant to Anadarko’s allocation methodology and subject to the terms of the omnibus agreement. Anadarko has the ultimate decision-making authority with respect to the total compensation of the named executive officers and, subject to the terms of the omnibus agreement, the portion of such compensation that is allocated to us pursuant to Anadarko’s allocation methodology. The following discussion relating to compensation paid by Anadarko is based on information provided to us by Anadarko and does not purport to be a complete discussion and analysis of Anadarko’s executive compensation philosophy and practices. The elements of compensation discussed below, and Anadarko’s decisions with respect to the levels of such compensation, will not be subject to approvals by the board of directors of our general partner, including the audit or special committee thereof. Awards under our long-term incentive plan to our general partner’s independent, non-management directors will be made by the board of directors of our general partner.
 
Anadarko’s executive compensation program objectives, design and process
 
The objectives of Anadarko’s executive compensation program are as follows:
 
Ø  to align the interests of Anadarko’s executives with those of its shareholders;
 
Ø  to attract and retain highly qualified and talented executives to lead Anadarko; and
 
Ø  to foster a team approach to achievement of Anadarko’s business objectives.
 
Anadarko establishes target total compensation levels for each executive officer, which are generally designed to place Anadarko’s executive compensation at or near the top quartile as compared to an Anadarko industry peer group, if Anadarko performance exceeds that of its peers and individual performance targets are achieved. In addition, in setting total compensation levels of each executive officer, Anadarko compares target compensation levels among each of its executive officers to ensure they are appropriate when considering each executive’s role, experience level and contribution to the organization. In the case of our executive officers, we would expect Anadarko to take into account the additional duties, as applicable, our executive officers will assume in connection with their roles as officers of our general partner.
 
With respect to compensation objectives and decisions regarding the named executive officers for 2007, we anticipate that Anadarko’s management will review market data for determining relevant


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compensation levels and compensation program elements. In addition, Anadarko’s management may review and, in certain cases, participate in, various relevant compensation surveys and consult with compensation consultants with respect to determining 2007 compensation for our named executive officers. All compensation determinations are discretionary and, as noted above, subject to Anadarko’s decision-making authority.
 
Elements of compensation
 
The primary elements of Anadarko’s compensation program are a combination of annual cash and long-term equity-based compensation. For 2007, the principal elements of compensation for the named executive officers are expected to be the following:
 
Ø  base salary;
 
Ø  bonuses;
 
Ø  equity compensation, which may include both equity-based compensation under Anadarko’s 1999 Stock Incentive Plan as well as Western Gas Holdings, LLC’s long-term incentive plan; and
 
Ø  Anadarko’s other benefits, including welfare and retirement benefits, perquisites, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible Anadarko employees.
 
Base Salary.  Anadarko’s management is expected to establish base salaries for our named executive officers based on the historical salaries for services rendered to Anadarko, competitive market data and responsibilities of our named executive officers that may or may not be related to our business. As discussed above, a portion of the base salaries of our named executive officers will be allocated to us based on Anadarko’s methodology used for allocating general and administrative expenses, subject to the limitations in the omnibus agreement.
 
Bonuses.  Anadarko’s management also may award annual cash awards to our named executive officers in 2007 under Anadarko’s Annual Incentive Plan. Anadarko is expected to use cash incentive awards for achieving financial and operational goals for Anadarko, including us, and for achieving individual performance objectives. The plan puts a significant portion of an executive’s compensation at risk by linking potential annual compensation to Anadarko’s achievement of specific performance metrics during the year related to operational, financial and safety measures internal to Anadarko. Executives may receive up to 200% of their individual bonus target if Anadarko significantly exceeds the specified performance metrics and, conversely, no bonus is paid if Anadarko does not achieve a minimum threshold level of performance. Actual bonus awards are determined by the compensation and benefits committee of Anadarko’s board of directors, or Anadarko’s compensation committee, according to Anadarko’s and each named executive officer’s level of achievement against the established performance metrics. The bonus targets are intended to provide a designated level of compensation opportunity when the executive officers achieve their specified performance metrics as approved by Anadarko’s compensation committee.
 
The portion of any annual cash awards allocable to us will be based on Anadarko’s methodology used for allocating general and administrative expenses, subject to the limitations in the omnibus agreement. Anadarko’s general policy is to pay these awards during the first quarter of each calendar year.
 
Long-Term Incentive Awards Under Anadarko’s 1999 Stock Incentive Plan.  Anadarko periodically makes equity-based awards under its 1999 Stock Incentive Plan to align the interests of its executive officers with those of Anadarko shareholders by emphasizing the long-term growth in Anadarko’s value. For 2006, the annual equity awards consisted of a combination of stock options, time-based restricted stock and performance unit awards. The annual long-term incentive target value of the awards has been allocated so that approximately one-third of the value is provided by each of the three incentive vehicles. This award structure is intended to provide a combination of equity-based vehicles that is


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performance-based in absolute and relative terms, while also encouraging retention. In addition, the use of performance unit awards and restricted shares enables Anadarko to better manage its stock dilution.
 
Our Long-Term Incentive Plan.  Our general partner intends to adopt a long-term incentive plan for the employees, consultants and directors of our general partner and its affiliates, including Anadarko, who perform services for us. The long-term incentive plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. For a more detailed description of this plan, please read “—Long-term incentive plan.”
 
The equity-based awards to both the named executive officers and the directors of our general partner are intended to align their long-term interests with those of our unitholders. As discussed above, a portion of the equity-based awards to be granted to the named executive officers will be allocated to us upon the completion of this offering, and a portion of any future awards under our long-term incentive plan will be allocable to us in accordance with the allocation of general and administrative expenses pursuant to the omnibus agreement.
 
Other Benefits.  In addition to the compensation discussed above, Anadarko also provides other benefits to certain of our executive officers who are also executive officers of Anadarko, including:
 
Ø  retirement benefits to match competitive practices in Anadarko’s industry, including the Anadarko Employee Savings Plan, Anadarko’s Savings Restoration Plan, and the Anadarko Retirement Plan and Retirement Restoration Plan;
 
Ø  severance benefits under the Anadarko Severance Plan or the Anadarko Officer Severance Plan, as applicable;
 
Ø  certain change of control benefits under key employee change of control contracts or key manager change of control contracts;
 
Ø  director and officer indemnification agreements;
 
Ø  a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management disability insurance, and personal excess liability insurance; and
 
Ø  medical, dental, vision, flexible spending accounts, life insurance and disability coverage, which are also provided to all other eligible U.S.-based Anadarko employees.
 
For a more detailed summary of Anadarko’s executive compensation program and the benefits provided thereunder, please read “Compensation Discussion and Analysis” in Anadarko’s proxy statement for its annual meeting of stockholders, which was filed with the SEC on March 27, 2007.
 
Role of executive officers in executive compensation
 
Anadarko’s management determines the compensation (other than the long-term incentive plan benefits described above) payable to each of our named executive officers. The board of directors of our general partner determines compensation for the independent, non-management directors of our general partner’s board of directors.
 
Compensation mix
 
We believe that the mix of base salary, cash awards, awards under our long-term incentive plan and other compensation fit Anadarko’s and our overall compensation objectives. We believe this mix of compensation provides competitive compensation opportunities to align and drive employee performance in support of Anadarko’s business strategies, as well as our own, and to attract, motivate and retain high quality talent with the skills and competencies required by Anadarko and us.


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LONG-TERM INCENTIVE PLAN
 
General
 
Our general partner intends to adopt a Long-Term Incentive Plan, which we refer to as the Plan, for employees, consultants and directors of our general partner and its affiliates, including Anadarko, who perform services for us. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. The Plan provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and substitute awards. Subject to adjustment for certain events, an aggregate of           common units may be delivered pursuant to awards under the Plan. Units that are cancelled, forfeited or are withheld to satisfy our general partner’s tax withholding obligations or payment of an award’s exercise price are available for delivery pursuant to other awards. The Plan will be administered by our general partner’s board of directors. The Plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of our common unitholders.
 
Unit awards
 
Our general partner’s board of directors may grant unit awards to eligible individuals under the Plan. A unit award is an award of common units that are fully vested upon grant and are not subject to forfeiture.
 
Restricted units and phantom units
 
A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our general partner’s board of directors, cash equal to the fair market value of a common unit. Our general partner’s board of directors may make grants of restricted and phantom units under the Plan that contain such terms, consistent with the Plan, as the board may determine are appropriate, including the period over which restricted phantom units will vest. The board may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or our general partner, subject to any contrary provisions in the award agreement.
 
If a grantee’s employment, consulting or membership on the board of directors terminates for any reason, the grantee’s restricted and phantom units will be automatically forfeited unless, and to the extent that the award agreement or the board provides otherwise.
 
Distributions made by us with respect to awards of restricted units may, in the board’s discretion, be subject to the same vesting requirements as the restricted units. The board, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units.
 
We intend for the restricted and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.
 
Unit options and unit appreciation rights
 
The Plan also permits the grant of options covering common units and unit appreciation rights. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common


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units over a specified exercise price, either in cash or in common units as determined by the board. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the board may determine, consistent with the Plan; however, a unit option or unit appreciation right must have an exercise price equal to the fair market value of a common unit on the date of grant.
 
Distribution equivalent rights
 
Distribution equivalent rights are rights to receive all or a portion of the distributions otherwise payable on units during a specified time. Distribution equivalent rights may be granted alone or in combination with another award.
 
Substitute awards
 
The board, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, our general partner or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.
 
Source of common units; cost
 
Common units to be delivered with respect to awards may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units. With respect to unit options, our general partner will be entitled to reimbursement from us for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.
 
Amendment or termination of long-term incentive plan
 
Our general partner’s board of directors, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not previously been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the Plan. Our general partner’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time or to amend any outstanding award made under the Plan; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.


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Security ownership of certain beneficial owners and management
 
The following table sets forth the beneficial ownership of our units that, upon the consummation of this offering and the related transactions and assuming that underwriters do not exercise their option to purchase up to 2,812,500 additional common units, will be owned by:
 
Ø  each person or group of persons known by us to be a beneficial owner of 5% or more of the then outstanding units;
 
Ø  each member of the board of directors of our general partner;
 
Ø  each named executive officer of our general partner; and
 
Ø  all directors and officers of our general partner as a group.
 
                               
                Percentage of
  Percentage of
        Percentage of
      subordinated
  total common
        common units
  Subordinated
  units
  and subordinated
    Common units
  to be
  units to be
  to be
  units to be
Name and address of
  to be
  beneficially
  beneficially
  beneficially
  beneficially
beneficial owner(1)   beneficially owned   owned   owned   owned   owned
 
 
Anadarko Petroleum Corporation(2)
    3,823,925     16.9%     22,573,925     100.0%     58.5%
WGR Holdings, LLC(2)
    3,823,925     16.9%     22,573,925     100.0%     58.5%
Robert G. Gwin
          %           %     %
Danny J. Rea
          %           %     %
Michael C. Pearl
          %           %     %
Jeremy M. Smith
          %           %     %
Lora W. Mays
          %           %     %
R.A. Walker
          %           %     %
Karl F. Kurz
          %           %     %
Robert K. Reeves
          %           %     %
All directors and executive officers as a group (8 persons)
          %           %     %
 
 
* Less than 1%
 
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
 
(2) Anadarko Petroleum Corporation is the ultimate parent company of WGR Holdings, LLC and may, therefore, be deemed to beneficially own the units held by WGR Holdings, LLC. Following this offering, WGR Holdings, LLC will own a 100% interest in our general partner and a 57.3% limited interest in us.
 
The following table set forth, as of          , the number of shares of common stock of Anadarko owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.
 


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Security ownership of certain beneficial owners and management
 
 
                         
        Shares
      Percentage of
    Shares of
  underlying
  Total shares of
  total shares of
    common stock
  options
  common stock
  common stock
Name and address of
  owned directly
  exercisable
  beneficially
  beneficially
beneficial owner(1)   or indirectly   within 60 days   owned   owned
 
 
Robert G. Gwin
                      %
Danny J. Rea
                      %
Michael C. Pearl
                      %
Jeremy M. Smith
                      %
Lora W. Mays
                      %
R.A. Walker
                      %
Karl F. Kurz
                      %
Robert K. Reeves
                      %
All directors and executive officers as a group (8 persons)
                      %
 
 
* Less than 1%
 
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.

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Certain relationships and related party transactions
 
After this offering, Anadarko will indirectly own 3,823,925 common units and 22,573,925 subordinated units, representing an aggregate 57.3% limited partner interest in us. In addition, our general partner will own 921,385 general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights.
 
DISTRIBUTIONS AND PAYMENTS TO OUR GENERAL PARTNER AND ITS AFFILIATES
 
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of Western Gas Partners, LP, assuming that the underwriters do not exercise their option to purchase additional common units. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
 
Formation stage
 
The consideration received by Anadarko and its subsidiaries for the contribution of the assets and liabilities to us
Ø 3,823,925 common units;
 
Ø 22,573,925 subordinated units;
 
Ø 921,385 general partner units, and
 
Ø our incentive distribution rights.
 
Operational stage
 
Distributions of available cash to our general partner and its affiliates We will generally make cash distributions 98.0% to our unitholders pro rata, including Anadarko as the indirect holder of an aggregate 3,823,925 common units and 22,573,925 subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.
 
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.1 million on their general partner units and $31.7 million on their common and subordinated units.
 
Payments to our general partner and its affiliates Our general partner and its affiliates will be entitled to reimbursement for all expenses incurred on our behalf, including salaries and employee benefit costs for employees who provide services to us, and all other necessary or


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appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The partnership agreement provides that our general partner will determine in good faith the amount of such expenses that are allocable to us.
 
Withdrawal or removal of our general partner If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The partnership agreement—Withdrawal or removal of the general partner.”
 
Liquidation stage
 
Liquidation Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
 
AGREEMENTS GOVERNING THE TRANSACTIONS
 
We and other parties have or will enter into the various documents and agreements that will effect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and as such, they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as the parties could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.
 
Omnibus agreement
 
Upon the closing of this offering, we will enter into an omnibus agreement with Anadarko and our general partner that will address the following matters:
 
Ø  Anadarko’s obligation to indemnify us for certain liabilities and our obligation to indemnify Anadarko for certain liabilities;
 
Ø  our obligation to reimburse Anadarko for all expenses incurred or payments made on our behalf in conjunction with Anadarko’s provision of general and administrative services to us, including salary and benefits of Anadarko personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are employees of Anadarko; and
 
Ø  our obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to our assets.


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Certain relationships and related party transactions
 
 
The table below reflects the categories of expenses for which we are obligated to reimburse Anadarko pursuant to the omnibus agreement, and, by category, sets forth an estimate of the amount that we will pay to Anadarko for the twelve months ending December 31, 2008.
 
       
    Estimates for the
    twelve months
    ending
    December 31,
    2008
 
    (in millions)
 
Reimbursement of general and administrative expenses
  $ 6.0
Reimbursement of public company expenses
  $ 2.5
 
Our general partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption “—Contracts with affiliates.”
 
Any or all of the provisions of the omnibus agreement will be terminable by Anadarko at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also generally terminate in the event of a change of control of us or our general partner.
 
Services and secondment agreement
 
Concurrently with the closing of this offering, Anadarko and our general partner will enter into a services and secondment agreement pursuant to which we anticipate that specified employees of Anadarko will be seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner will reimburse Anadarko pursuant to the omnibus agreement for the services provided by the seconded employees pursuant to the services and secondment agreement. The initial term of the services and secondment agreement will be 10 years. The term will extend for additional 12-month periods unless either party provides 180 days written notice otherwise prior to the expiration of the applicable 12-month period. Either party may terminate the agreement at any time upon 180 days written notice.
 
Tax sharing agreement
 
Prior to the closing of this offering, we intend to enter into a tax sharing agreement pursuant to which we will reimburse Anadarko for our share of state and local income and other taxes borne by Anadarko as a result of our results being included in a combined or consolidated tax return filed by Anadarko. Anadarko may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless reimburse Anadarko for the tax we would have owed had the attributes not been available or used for our benefit, even though Anadarko had no cash expense for that period.
 
Administrative services and reimbursement
 
Under the omnibus agreement, we will reimburse Anadarko for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit with respect to the assets contributed to us at the closing of this offering. The omnibus agreement will further provide that we will reimburse Anadarko for all expenses it incurs or payments it makes with respect to our assets.
 
Pursuant to these arrangements, Anadarko will perform centralized corporate functions for us, such as legal, accounting, treasury, cash management, insurance administration and claims processing, risk


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management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, tax, marketing and midstream. We will reimburse Anadarko for all of the expenses it incurs or payments it makes on our behalf, including salary and benefits of Anadarko personnel, our public company expenses, our general and administrative expenses and salaries and benefits of our executive management who are also employees of Anadarko.
 
Under the omnibus agreement, our reimbursement to Anadarko for certain general and administrative expenses it allocates to us will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner’s board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will determine the general and administrative expenses to be allocated to us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses that we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year.
 
Indemnification
 
Under the omnibus agreement, Anadarko will indemnify us for a period of three years after the closing of this offering against certain potential environmental claims, losses and expenses associated with the operation of our assets, which occur before the closing date of this offering or relate to any investigation, claim or proceeding under environmental laws relating to such assets and pending as of the closing of this offering. Anadarko will have no indemnification obligation with respect to environmental claims made as a result of additions to or modifications of environmental laws that are promulgated after the closing date of this offering.
 
Additionally, Anadarko will indemnify us for losses attributable to the following:
 
(1)  our failure, as of the closing date of this offering, to have valid easements, fee title or leasehold interests in and to the lands on which our assets are located, to the extent such failure renders us unable to use or operate our assets in substantially the same manner in which they were used and operated immediately prior to the closing of this offering;
 
(2)  our failure, as of the closing date of this offering, to have any consent or governmental permit necessary to allow (i) the transfer of assets from Anadarko to us at the closing of this offering or (ii) us to use or operate our assets in substantially the same manner in which they were used and operated immediately prior to the closing of this offering;
 
(3)  all income tax liabilities
 
(i)  attributable to the pre-closing operations of our assets,
 
(ii)  arising from or relating to the formation transactions, or
 
(iii)  arising under Treasury Regulation Section 1.1502-6 and any similar provision from state, local or foreign applicable law, by contract, as successor or transferee or otherwise, provided that such income tax is attributable to having been a member of any consolidated, combined or unitary group prior to the closing of this offering;
 
(4)  all liabilities, other than covered environmental laws and other than liabilities incurred in the ordinary course of business conducted in compliance with the applicable laws, that arise prior to the closing date; and
 
(5)  all liabilities attributable to any assets or entities retained by Anadarko.


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Anadarko’s maximum liability for indemnification is unlimited in amount. Anadarko will not have any obligation to indemnify us, unless a claim for indemnification specifying in reasonable detail the basis for such claim is furnished to us in good faith (a) with respect to a claim under clause (1) or (2) above, prior to the third anniversary date of the closing of this offering or (b) with respect to a claim under clause (3) above, prior to the first day after expiration of the statute of limitations period applicable to such claim. In no event shall Anadarko be obligated to indemnify us for any losses or income taxes to the extent we have made reservations for any such losses or income taxes in our combined financial statements as of December 31, 2006, or to the extent we recover any such losses or income taxes under available insurance coverage or from contractual rights against any third party.
 
Under the omnibus agreement, we have agreed to indemnify Anadarko for all claims, losses and expenses attributable to the post-closing operations of the gathering, compression, treating and transportation assets contributed to us at the closing of this offering, to the extent not that such losses are not subject to Anadarko’s indemnification obligations.
 
CONTRACTS WITH AFFILIATES
 
Gas Gathering Agreements
 
Our gathering agreements with Anadarko accounted for approximately 94% of our gathering throughput for the nine months ended September 30, 2007. Eighty–eight percent of this throughput came from volumes of natural gas owned by Anadarko and its partners and the remainder was comprised of volumes purchased from third parties by Anadarko Energy Services Company, Anadarko’s wholly owned marketing affiliate.
 
Anadarko Petroleum Corporation. We have entered into new gas gathering agreements with Anadarko Petroleum Corporation for each of our gathering systems. These agreements provide us with dedication of all of the natural gas owned or controlled by Anadarko and produced from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as additional wells are connected to our gathering systems. Each gas gathering agreement is fee-based, and we provide gathering, compression, treating, dehydration and well connections within the dedicated area for the specified gathering fee per MMbtu or Mcf. The gathering fee varies on each system and is subject to an automatic annual escalator and may also be adjusted if Anadarko requests improvements to the level of service we currently provide under the agreement. Each of the gas gathering agreements has a 10-year primary term. After the expiration of the primary term, either party may annually request a re-determination of the gathering fee. If a re-determination of the fee takes place, the same methodology which was utilized to calculate the original gathering fee will be utilized to calculate the new fee and the new fee will take into account production forecasts, capital expenditures and operating expenses. The agreements allow us to retain and sell the condensate that is recovered from gas during gathering. The gas gathering agreements are assignable by Anadarko to an affiliate without our consent and Anadarko will be permitted to sell the production which is dedicated to our systems to an affiliate or third-party purchaser, provided that the purchaser of the dedicated gas will be subject to the terms and conditions of our agreements and Anadarko will remain liable under the agreements in the event the purchaser defaults. The fees we will charge Anadarko under our new gas gathering agreements are higher than the fees reflected in our historical financial results.
 
Anadarko Energy Services Company (“AESC”).  AESC is Anadarko’s marketing affiliate that purchases gas and is a shipper on our gathering systems. Approximately 12% of the throughput we gathered for the nine months ended September 30, 2007 was comprised of third-party volumes purchased by AESC, and gathered under gathering agreements we have in place with AESC. We provide our services to AESC under fixed-fee arrangements whereby gathering fees and contract terms are based on a variety of


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factors, including gas quality and level of service provided. The term of our agreements with AESC can vary from month-to-month to 20 years.
 
Transportation Agreements
 
Western Gas Resources, Inc. and MGTC, Inc., affiliates of Anadarko, have contracted for 170,000 MMBtu/d of firm capacity on our MIGC system in agreements ranging in term from just over one year to 11 years. Anadarko has released 40,000 MMBtu/d of firm capacity under one agreement to a third party, and this released capacity will revert back to Anadarko in February 2009 for the duration of the term, which expires in 2018. For the nine months ended September 30, 2007, our transportation agreements with Anadarko accounted for approximately 70% of the throughput on the MIGC system.


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CONFLICTS OF INTEREST
 
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Anadarko, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.
 
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.
 
Our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:
 
Ø  approved by the special committee of our general partner, although our general partner is not obligated to seek such approval;
 
Ø  approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
 
Ø  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
 
Ø  fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
 
Our general partner may, but is not required to, seek the approval of such resolution from the special committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the special committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the special committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.
 
Conflicts of interest could arise in the situations described below, among others.


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Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Anadarko’s directors have a fiduciary duty to make these decisions in the best interests of the owners of Anadarko, which may be contrary to our interests.
 
Because certain of the directors of our general partner are also directors and/or officers of Anadarko, such directors have fiduciary duties to Anadarko that may cause them to pursue business strategies that disproportionately benefit Anadarko or which otherwise are not in our best interests.
 
Anadarko is not limited in its ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.
 
Neither our partnership agreement nor the omnibus agreement between us and Anadarko will prohibit Anadarko from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Anadarko 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. Anadarko 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 these entities with respect to commercial activities as well as for acquisitions candidates. As a result, competition from these entities could adversely impact our results of operations and cash available for distribution.
 
Our general partner and its affiliates are allowed to take into account the interests of parties other than us in resolving conflicts of interest.
 
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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 our limited partners. Examples include our general partner’s limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.
 
The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly.
 
All of our executive management personnel will be employees of Anadarko and will devote a portion of their time to our business and affairs. We will also utilize a significant number of employees of Anadarko to operate our business and provide us with general and administrative services for which we will reimburse Anadarko for allocated expenses of operational personnel who perform services for our benefit and we will reimburse Anadarko for allocated general and administrative expenses. Our general partner and Anadarko will also conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to Anadarko.


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Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of its fiduciary duty.
 
In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty. For example, our partnership agreement:
 
Ø  provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning it believed that the decision was in the best interest of our partnership;
 
Ø  provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the special committee of the board of directors of our general partner and not involving a vote of the common unitholders must either be (1) on terms no less favorable to us than those generally provided to or available from unrelated third parties or (2) “fair and reasonable” to us, as determined by our general partner in good faith, provided 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; and
 
Ø  provides that our general partner and its officers and directors will not be liable for monetary damages to us, or our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct.
 
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
 
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought special committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:
 
Ø  the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;
 
Ø  the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;
 
Ø  the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;
 
Ø  the negotiation, execution and performance of any contracts, conveyances or other instruments;
 
Ø  the distribution of our cash;
 
Ø  the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
 
Ø  the maintenance of insurance for our benefit and the benefit of our partners;
 
Ø  the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;


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Ø  the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;
 
Ø  the indemnification of any person against liabilities and contingencies to the extent permitted by law;
 
Ø  the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and
 
Ø  the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.
 
Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The partnership agreement—Voting rights” for information regarding matters that require unitholder approval.
 
Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
 
The amount of cash that is available for distribution to our unitholders is affected by the decisions of our general partner regarding such matters as:
 
Ø  the amount and timing of asset purchases and sales;
 
Ø  cash expenditures;
 
Ø  borrowings;
 
Ø  the issuance of additional units; and
 
Ø  the creation, reduction or increase of reserves in any quarter.
 
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.
 
In addition, our general partner may use an amount, initially equal to $27.1 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of our partnership agreement relating to cash distributions.”
 
In addition, borrowings by us and our affiliates do not constitute a breach of any duty owned by our general partner to our unitholders, including borrowings that have the purpose or effect of:
 
Ø  enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or
 
Ø  hastening the expiration of the subordination period.
 
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common and subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all of our outstanding


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units. Please read “Provisions of our partnership agreement related to cash distributions—Subordination period.”
 
Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may borrow funds from us, or our operating company and its operating subsidiaries.
 
Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.
 
We will reimburse our general partner and its affiliates for the costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
 
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or from entering into additional contractual arrangements with any of these entities on our behalf.
 
Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that will be in effect as of the closing of this offering, will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the special committee of our general partner may make a determination on our behalf with respect to such arrangements.
 
Our general partner will determine, in good faith, the terms of any such transactions entered into after the close of this offering.
 
Our general partner and its affiliates will have no obligation to permit us to use any of its or its affiliates’ facilities or assets, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
 
Our general partner intends to limit its liability regarding our obligations.
 
Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.
 
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of our common units.
 
Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may be required to sell his common units at an undesirable time or price. Please read “The partnership agreement—Limited call right.”


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Our general partner controls the enforcement of its and its affiliates’ obligations to us.
 
Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.
 
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the special committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
 
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 special committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
 
Our general partner has the right, at any 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 target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution 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.
 
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 we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect 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 specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount 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 read “Provisions of our partnership agreement relating to cash distributions—General partner interest and incentive distribution rights.”


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FIDUCIARY DUTIES
 
Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.
 
Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner that is beneficial to its owners, as well as to you. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:
 
State-law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.
 
The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.
 
Partnership agreement modified standards Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in


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its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
 
In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.
 
Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest that are not approved by a vote of common unitholders and that are not approved by the special committee of the board of directors of our general partner must be on terms no less favorable to us than those generally being provided to, or available from, unrelated third parties; or “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
 
If our general partner does not seek approval from the special committee and the board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.
 
By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.
 
We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our


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Conflicts of interest and fiduciary duties
 
 
general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The partnership agreement—Indemnification.”


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Description of the common units
 
THE UNITS
 
The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common and subordinated units in and to partnership distributions, please read this section and “Our cash distribution policy and restrictions on distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The partnership agreement.”
 
TRANSFER AGENT AND REGISTRAR
 
Duties
 
           will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:
 
Ø  surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
 
Ø  special charges for services requested by a common unitholder; and
 
Ø  other similar fees or charges.
 
There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
 
Resignation or removal
 
The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
 
TRANSFER OF COMMON UNITS
 
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:
 
Ø  represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
 
Ø  automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and
 
Ø  is deemed to have given the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.


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Description of the common units
 
 
A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.
 
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
 
Common units are securities that are transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.
 
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.


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The partnership agreement
 
The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.
 
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
 
Ø  with regard to distributions of available cash, please read “Provisions of our partnership agreement relating to cash distributions;”
 
Ø  with regard to the fiduciary duties of our general partner, please read “Conflicts of interest and fiduciary duties;”
 
Ø  with regard to the transfer of common units, please read “Description of the common units—Transfer of common units;” and
 
Ø  with regard to allocations of taxable income and taxable loss, please read “Material tax consequences.”
 
ORGANIZATION AND DURATION
 
Our partnership was organized in August 2007 and will have a perpetual existence.
 
PURPOSE
 
Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
 
Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of gathering, compressing, treating and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
 
POWER OF ATTORNEY
 
Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.
 
CASH DISTRIBUTIONS
 
Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of our partnership agreement relating to cash distributions.”


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CAPITAL CONTRIBUTIONS
 
Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited liability.”
 
If we issue additional units, our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our general partner’s 2.0% 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 to maintain its 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.
 
VOTING RIGHTS
 
The following is a summary of the unitholder vote required for approval of the matters specified below. General partner units are not deemed outstanding units for purposes of voting rights and such units represent a non-voting general partner interest. Matters that require the approval of a “unit majority” require:
 
Ø  during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and
 
Ø  after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a single class.
 
In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.
 
Issuance of additional units No approval right.
 
Amendment of the partnership agreement Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the partnership agreement.”
 
Merger of our partnership or the sale of all or substantially all of our assets Unit majority in certain circumstances. Please read “—Merger, consolidation, conversion, sale or other disposition of assets.”
 
Dissolution of our partnership Unit majority. Please read “—Termination and dissolution.”
 
Continuation of our business upon dissolution Unit majority. Please read “—Termination and dissolution.”
 
Withdrawal of the general partner Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to December 31, 2017 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or removal of the general partner.”


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Removal of the general partner Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or removal of the general partner.”
 
Transfer of the general partner interest Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2017. Please read “—Transfer of general partner units.”
 
Transfer of incentive distribution rights Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2017. Please read “—Transfer of incentive distribution rights.”
 
Transfer of ownership interests in our general partner No approval required at any time. Please read “—Transfer of ownership interests in the general partner.”
 
LIMITED LIABILITY
 
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:
 
Ø  to remove or replace the general partner;
 
Ø  to approve some amendments to the partnership agreement; or
 
Ø  to take other action under the partnership agreement;
 
constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does


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not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
 
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
 
Our subsidiaries conduct business in five states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of the operating partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our subsidiaries to do business there.
 
Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our partnership interest in our operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
 
ISSUANCE OF ADDITIONAL SECURITIES
 
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.
 
It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.
 
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.


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Upon issuance of additional partnership securities (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% interest in us will 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 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.
 
AMENDMENT OF THE PARTNERSHIP AGREEMENT
 
General
 
Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
 
Prohibited amendments
 
No amendment may be made that would:
 
Ø  enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
 
Ø  enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.
 
The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately 58.5% of our outstanding common and subordinated units.
 
No unitholder approval
 
Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:
 
Ø  a change in our name, the location of our principal place of business, our registered agent or our registered office;


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Ø  the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
 
Ø  a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
 
Ø  an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;
 
Ø  an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or the right to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:
 
  the adjustments of the minimum quarterly distribution, first target distribution, second target distribution and third target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “Provisions of our partnership agreement relating to cash distributions—General partner’s right to reset incentive distribution levels,” or
 
  any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the special committee of our general partner;
 
Ø  any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
 
Ø  an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
 
Ø  any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
 
Ø  a change in our fiscal year or taxable year and related changes;
 
Ø  conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or
 
Ø  any other amendments substantially similar to any of the matters described in the clauses above.
 
In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:
 
Ø  do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
 
Ø  are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;


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Ø  are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;
 
Ø  are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
 
Ø  are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
 
Opinion of counsel and unitholder approval
 
Our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.
 
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.
 
MERGER, CONSOLIDATION, CONVERSION, SALE OR OTHER DISPOSITION OF ASSETS
 
A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.
 
In addition, the partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.
 
If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or


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conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in the partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.
 
TERMINATION AND DISSOLUTION
 
We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
 
Ø  the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
 
Ø  there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
 
Ø  the entry of a decree of judicial dissolution of our partnership; or
 
Ø  the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.
 
Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:
 
Ø  the action would not result in the loss of limited liability of any limited partner; and
 
Ø  neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.
 
LIQUIDATION AND DISTRIBUTION OF PROCEEDS
 
Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of our partnership agreement relating to cash distributions—Distributions of cash upon liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.
 
WITHDRAWAL OR REMOVAL OF THE GENERAL PARTNER
 
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2017 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2017, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a


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violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one unitholder and its affiliates, other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of general partner units” and “—Transfer of incentive distribution rights.”
 
Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Termination and dissolution.”
 
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a single class, and the outstanding subordinated units, voting as a single class. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the close of this offering, our general partner and its affiliates will own 58.5% of our outstanding common and subordinated units.
 
Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and the units held by the general partner and its affiliates are not voted in favor of that removal:
 
Ø  the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
 
Ø  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
Ø  our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.
 
In the event of the removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.


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If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
 
In addition, we will be required to reimburse the departing general partner for all amounts due to the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.
 
TRANSFER OF GENERAL PARTNER UNITS
 
Except for transfer by our general partner of all, but not less than all, of its general partner units to:
 
Ø  an affiliate of our general partner (other than an individual); or
 
Ø  another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,
 
our general partner may not transfer all or any of its general partner units to another person prior to December 31, 2017 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.
 
Our general partner and its affiliates may, at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.
 
TRANSFER OF OWNERSHIP INTERESTS IN THE GENERAL PARTNER
 
At any time, Anadarko and its affiliates may sell or transfer all or part of its partnership interests in our general partner to an affiliate or third party without the approval of our unitholders.
 
TRANSFER OF INCENTIVE DISTRIBUTION RIGHTS
 
Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of the holder’s assets to that entity without the prior approval of the unitholders; provided that, in the case of the sale of ownership interests in the holder, the initial holder of the incentive distribution rights continues to remain the general partner following such sale. Prior to December 31, 2017, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2017, the incentive distribution rights will be freely transferable.
 
CHANGE OF MANAGEMENT PROVISIONS
 
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Western Gas Holdings, LLC as our general partner or from otherwise changing our management. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting


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rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.
 
Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
 
Ø  the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
 
Ø  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
Ø  our 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 based on the fair market value of those interests at that time.
 
LIMITED CALL RIGHT
 
If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:
 
Ø  the highest cash price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and
 
Ø  the current market price as of the date three days before the date the notice is mailed.
 
As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material tax consequences—Disposition of common units.”
 
MEETINGS; VOTING
 
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.
 
Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting, if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a


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quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
 
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of additional securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.
 
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
 
STATUS AS LIMITED PARTNER
 
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.
 
NON-CITIZEN ASSIGNEES; REDEMPTION
 
If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by that limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days of a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.
 
INDEMNIFICATION
 
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
 
Ø  our general partner;
 
Ø  any departing general partner;
 
Ø  any person who is or was an affiliate of a general partner or any departing general partner;


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Ø  any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;
 
Ø  any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and
 
Ø  any person designated by our general partner.
 
Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.
 
REIMBURSEMENT OF EXPENSES
 
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with the operation of our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.
 
BOOKS AND REPORTS
 
Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
 
We will furnish or make available to record holders of our common units, within 120 days after the close of each fiscal year, an annual report containing audited combined financial statements and a report on those combined financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
 
We will furnish each record holder with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.
 
RIGHT TO INSPECT OUR BOOKS AND RECORDS
 
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:
 
Ø  a current list of the name and last known address of each partner;
 
Ø  a copy of our tax returns;
 
Ø  information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;


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Ø  copies of our partnership agreement, our certificate of limited partnership and related amendments and powers of attorney under which they have been executed;
 
Ø  information regarding the status of our business and our financial condition; and
 
Ø  any other information regarding our affairs as is just and reasonable.
 
Our general partner may, and intends to, keep confidential from the limited partners’ trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.
 
REGISTRATION RIGHTS
 
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Western Gas Holdings, LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and fees. Please read “Units eligible for future sale.”


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Units eligible for future sale
 
After the sale of the common units offered hereby, Anadarko will hold an aggregate of 3,823,925 common units, assuming that the underwriters do not exercise their option to purchase up to 2,812,500 additional common units, and 22,573,925 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.
 
The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
 
Ø  1% of the total number of the securities outstanding, or
 
Ø  the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.
 
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.
 
The partnership agreement does not restrict our ability to issue any partnership securities. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read “The partnership agreement—issuance of additional securities.”
 
Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or the prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and fees. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.
 
Anadarko, our partnership, our general partner and its affiliates, including the executive officers and directors of our general partner, and the participants in our directed unit program have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”


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This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Western Gas Partners, LP and our operating company.
 
The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs), employee benefit plans or mutual funds. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.
 
All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.
 
No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which the common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
 
For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax consequences of unit ownership—Treatment of short sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of common units—Allocations between transferors and transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax consequences of unit ownership—Section 754 election” and “—Uniformity of units”).
 
PARTNERSHIP STATUS
 
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not


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taxable to the partner unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.
 
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.
 
A publicly traded partnership may not rely upon the Qualifying Income Exception if it is registered under the Investment Company Act of 1940, or the Investment Company Act. If we were required to register under the Investment Company Act, we would be taxed as a corporation even if we met the Qualifying Income Exception. Vinson & Elkins L.L.P. is of the opinion that we may rely on the Qualifying Income Exception.
 
No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating company for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, Treasury Regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.
 
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:
 
(a)  Neither we nor the operating company has elected or will elect to be treated as a corporation;
 
(b)  For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and
 
(c)  Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.
 
If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock


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in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
 
If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.
 
The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.
 
LIMITED PARTNER STATUS
 
Unitholders who have become limited partners of Western Gas Partners, LP will be treated as partners of Western Gas Partners, LP for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Western Gas Partners, LP for federal income tax purposes.
 
A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax consequences of unit ownership—Treatment of short sales.”
 
Income, gain, deductions or losses are not reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Western Gas Partners, LP. References to “unitholders” in the discussion that follows are to persons who are treated as partners in Western Gas Partners, LP for federal income tax purposes.
 
TAX CONSEQUENCES OF UNIT OWNERSHIP
 
Flow-through of taxable income
 
We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.
 
Treatment of distributions
 
Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his


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common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis in his common units generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of common units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, the unitholder must recapture any losses deducted in previous years. Please read “—Tax consequences of unit ownership—Limitations on deductibility of losses.”
 
A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.
 
Ratio of taxable income to distributions
 
We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending          , will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be          % or less of the cash distributed to the unitholder with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to pay the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:
 
Ø  gross income from operations exceeds the amount required to pay the minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or
 
Ø  we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or


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amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.
 
Basis of common units
 
A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of common units—Recognition of gain or loss.”
 
Limitations on deductibility of losses
 
The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals) or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk or basis limitations in excess of that gain would no longer be utilizable.
 
In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.
 
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when the unitholder disposes of his entire investment in us in a fully taxable transaction with an


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unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.
 
A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
 
Limitations on interest deductions
 
The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:
 
Ø  interest on indebtedness properly allocable to property held for investment;
 
Ø  our interest expense attributed to portfolio income; and
 
Ø  the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
 
The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.
 
Entity-level collections
 
If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.
 
Allocation of income, gain, loss and deduction
 
In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.
 
Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of


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property contributed to us by the general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future “Reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference, at the time of the future transaction, between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.
 
An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c) of the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect.
 
In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
 
Ø  his relative contributions to us;
 
Ø  the interests of all the partners in profits and losses;
 
Ø  the interest of all the partners in cash flow; and
 
Ø  the rights of all the partners to distributions of capital upon liquidation.
 
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Tax consequences of unit ownership—Section 754 election,” “—Uniformity of units” and “—Disposition of common units—Allocations between transferors and transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.
 
Treatment of short sales
 
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
 
Ø  any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;
 
Ø  any cash distributions received by the unitholder as to those units would be fully taxable; and
 
Ø  all of these distributions would appear to be ordinary income.


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Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of common units—recognition of gain or loss.”
 
Alternative minimum tax
 
Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.
 
Tax rates
 
In general, the highest effective U.S. federal income tax rate for individuals is currently 35%, and the maximum U.S. federal income tax rate for net capital gains of an individual where the asset disposed of was held for more than twelve months at the time of disposition, is scheduled to remain at 15% for years 2008-2010 and then increase to 20% beginning January 1, 2011.
 
Section 754 election
 
We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.
 
Where the remedial allocation method is adopted (which we will generally adopt as to our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of units.”
 
Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s


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unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of common units—Recognition of gain or loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.
 
A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.
 
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.


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TAX TREATMENT OF OPERATIONS
 
Accounting method and taxable year
 
We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of common units—Allocations between transferors and transferees.”
 
Initial tax basis, depreciation and amortization
 
The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner. Please read “—Tax consequences of unit ownership—Allocation of income, gain, loss and deduction.”
 
To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
 
If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax consequences of unit ownership—Allocation of income, gain, loss and deduction” and “—Disposition of common units—Recognition of gain or loss.”
 
The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts we incur will be treated as syndication expenses.
 
Valuation and tax basis of our properties
 
The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.


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DISPOSITION OF COMMON UNITS
 
Recognition of gain or loss
 
Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities attributable to the common units sold. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.
 
Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.
 
Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.
 
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.
 
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated”


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partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
 
Ø  a short sale;
 
Ø  an offsetting notional principal contract; or
 
Ø  a futures or forward contract with respect to the partnership interest or substantially identical property.
 
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
 
Allocations between transferors and transferees
 
In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.
 
The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. We use this method because it is not administratively feasible to make these allocations on a more frequent basis. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
 
A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
 
Notification requirements
 
A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of any such transfer of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.


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Constructive termination
 
We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits or assets within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a taxable year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.
 
UNIFORMITY OF UNITS
 
Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax consequences of unit ownership—Section 754 election.”
 
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax consequences of unit ownership—Section 754 election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. Our counsel, Vinson & Elkins L.L.P., is unable to opine on the validity of any of these positions. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of common units—Recognition of gain or loss.”
 


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TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS
 
Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.
 
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.
 
Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold tax at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
 
In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
 
Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a U.S. trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in trade or business in the U.S. by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or other disposition of units. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.
 
ADMINISTRATIVE MATTERS
 
Information returns and audit procedures
 
We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes each unitholder’s share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in


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court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.
 
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.
 
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.
 
The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action.
 
A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.
 
Nominee reporting
 
Persons who hold an interest in us as a nominee for another person are required to furnish to us:
 
(a)  the name, address and taxpayer identification number of the beneficial owner and the nominee;
 
(b)  a statement regarding whether the beneficial owner is:
 
(i)  a person that is not a U.S. person;
 
(ii)  a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or
 
(iii)  a tax-exempt entity;
 
(c)  the amount and description of units held, acquired or transferred for the beneficial owner; and
 
(d)  specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
 
Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.


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Material tax consequences
 
 
Accuracy-related penalties
 
An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
 
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
 
(1)  for which there is, or was, “substantial authority”; or
 
(2)  as to which there is a reasonable basis if the pertinent facts of that position are adequately disclosed on the return.
 
If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us.
 
A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis. For individuals, no penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%.
 
Reportable transactions
 
If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or a “transaction of interest” or that it produces certain kinds of losses for partnerships, individuals, S corporations and trusts in excess of $2 million in any single year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Administrative matters—Information returns and audit procedures.”
 
Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:
 
Ø  accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Administrative matters—Accuracy-related penalties;”
 
Ø  for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and


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Ø  in the case of a listed transaction, an extended statute of limitations.
 
We do not expect to engage in any “reportable transactions.”
 
STATE, LOCAL, FOREIGN AND OTHER TAX CONSIDERATIONS
 
In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in the states of Kansas, Oklahoma, Texas, Utah and Wyoming. Each of these states, other than Texas and Wyoming, currently imposes a personal income tax, and all of theses states also impose taxes on income of corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions if your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax consequences of unit ownership—Entity-level collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.
 
It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.


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Investment in Western Gas Partners, LP by employee benefit plans
 
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:
 
Ø  whether the investment is prudent under Section 404(a)(1)(B) of ERISA;
 
Ø  whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and
 
Ø  whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material tax consequences—Tax-Exempt organizations and other investors.”
 
The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
 
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code.
 
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.
 
The Department of Labor regulations provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:
 
(a)  the equity interests acquired by the employee benefit plan are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under some provision of the federal securities laws;
 
(b)  the entity is an “operating company,”—i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or
 
(c)  there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.
 
Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.
 
In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code.


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Underwriting
 
We are offering our common units described in this prospectus through the underwriters named below. UBS Securities LLC is the representative of the underwriters and the sole bookrunning manager of this offering. Subject to the terms and conditions of the underwriting agreement, dated as of the date of this prospectus, which will be filed as an exhibit to the registration statement, each of the underwriters has severally agreed to purchase the number of common units listed next to its name in the following table:
 
         
    Number of
 
Underwriters   common units  
   
 
UBS Securities LLC
       
         
Total
    18,750,000  
         
 
The underwriting agreement provides that the underwriters must buy all of the common units if they buy any of them. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ option to purchase additional common units described below.
 
Our common units and the common units to be sold upon the exercise of the underwriters’ option to purchase additional common units, if any, are offered subject to a number of conditions, including:
 
Ø  receipt and acceptance of our common units by the underwriters;
 
Ø  the validity of the representations and warranties made to the underwriters;
 
Ø  the absence of any material change in the financial markets;
 
Ø  our delivery of customary closing documents to the underwriters; and
 
Ø  the underwriters’ right to reject orders in whole or in part.
 
We have been advised by the representative that the underwriters intend to make a market in our common units, but they are not obligated to do so and may discontinue making a market at any time without notice.
 
OPTION TO PURCHASE ADDITIONAL COMMON UNITS
 
We have granted the underwriters an option to purchase up to 2,812,500 additional common units. This option may be exercised if the underwriters sell more than 18,750,000 common units in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional common units approximately in proportion to the amounts specified in the table above. If and to the extent the underwriters exercise their option, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Anadarko. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to reimburse Anadarko for capital expenditures it incurred with respect to the assets contributed to us during the two-year period prior to this offering.
 
COMMISSIONS AND DISCOUNTS
 
Common units sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount of up to $      per common unit from the initial public offering price. Any of these securities dealers may resell any common units purchased from the underwriters to other brokers or dealers at a discount of up to $      per common unit from the initial public offering price. If all the common units are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms. Sales of common units made outside of the U.S. may be


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made by affiliates of the underwriters. Upon execution of the underwriting agreement, the underwriters will be obligated to purchase the common units at the prices and upon the terms stated therein, and, as a result, will thereafter bear any risk associated with changing the offering price to the public or other selling terms.
 
The following table shows the per unit and total underwriting discounts we will pay to the underwriters, assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 2,812,500 units.
 
                 
    No exercise     Full exercise  
   
 
Per Unit
  $       $    
Total
  $       $  
 
We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and the structuring fee, will be approximately $3.0 million.
 
In addition, we will pay the representatives a structuring fee of $           of the gross proceeds of this offering and any exercise of the underwriters’ option to purchase additional common units for their role in the evaluation, analysis and structuring of our partnership.
 
NO SALES OF SIMILAR SECURITIES
 
We, Anadarko and our general partner and its affiliates, including the executive officers and directors of our general partner, and the participants in our directed unit program will enter into lock-up agreements with the underwriters. Under these agreements, we and each of these persons may not, without the prior written approval of UBS Securities LLC, offer, sell, contract to sell or otherwise dispose of or hedge our common units or securities convertible into or exchangeable for our common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, make any demand for or exercise any right or file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or publicly disclose the intention to do any of the foregoing. These restrictions will be in effect for a period of 180 days after the date of this prospectus. The lock-up period will be extended under certain circumstances where either (i) we release our earnings or announce material news or a material event during the 15 calendar days plus three business days preceding the termination of the 180-day period or (ii) we pre-announce that we will release our earnings during the 16 days following the termination of the 180-day period. In either case, the restrictions described above will continue to apply until the expiration of the period that extends 15 calendar days plus three business days after the date of the issuance of the earnings release or the announcement of the material news or material event, as the case may be. At any time and without public notice, UBS Securities LLC may in its discretion, release all or some of the securities from these lock-up agreements. The representatives have no present understanding or intent to release any of the securities from these lock-up agreements.
 
INDEMNIFICATION
 
We and our general partner and certain of its affiliates, have agreed to indemnify the underwriters and their controlling persons against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below. If we are unable to provide this indemnification, we will contribute to payments the underwriters and their controlling persons may be required to make in respect of those liabilities.
 


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NEW YORK STOCK EXCHANGE
 
We have applied to list our common units on the New York Stock Exchange under the trading symbol “WES.”
 
PRICE STABILIZATION, SHORT POSITIONS
 
In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common units including:
 
Ø  stabilizing transactions;
 
Ø  short sales;
 
Ø  purchases to cover positions created by short sales;
 
Ø  imposition of penalty bids; and
 
Ø  syndicate covering transactions.
 
Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common units while this offering is in progress. These transactions may also include making short sales of our common units, which involves the sale by the underwriters of a greater number of common units than they are required to purchase in this offering, and purchasing common units on the open market to cover positions created by short sales. Short sales may be “covered” short sales, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” short sales, which are short positions in excess of that amount.
 
The underwriters may close out any covered short position by either exercising their option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units.
 
Naked short sales are in excess of the underwriters’ option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering.
 
The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of that underwriter in stabilizing or short covering transactions.
 
As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.
 
DETERMINATION OF OFFERING PRICE
 
Prior to this offering, there has been no public market for our common units. The initial public offering price was determined by negotiation by us and the representatives of the underwriters. The principal factors considered in determining the initial public offering price include:
 
Ø  the information set forth in this prospectus and otherwise available to the representatives;


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Ø  our history and prospects, and the history and prospects of the industry in which we compete;
 
Ø  our past and present financial performance and an assessment of the directors and officers of our general partner;
 
Ø  our prospects for future earnings and cash flow and the present state of our development;
 
Ø  the general condition of the securities markets at the time of this offering;
 
Ø  the recent market prices of, and demand for, publicly traded common units of generally comparable master limited partnerships; and
 
Ø  other factors determined relevant by the underwriters and us.
 
DIRECTED UNIT PROGRAM
 
At our request, certain of the underwriters have reserved up to                of the common units being offered by this prospectus for sale at the initial public offering price to the officers, directors and employees of our general partner and its affiliates, including Anadarko, and certain other persons associated with us, as designated by us. The sales will be made by UBS Financial Services, Inc., an affiliate of UBS Securities LLC, through a directed unit program. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units prior to the effectiveness of the registration statement relating to this offering. Any directed unit participants purchasing these reserved units will be subject to the restrictions described in “—No sale of similar securities” above.
 
ELECTRONIC DISTRIBUTION
 
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
 
Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
 
DISCRETIONARY SALES
 
The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed five percent of the total number of units offered by them.
 
STAMP TAXES
 
If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.


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Underwriting
 
 
 
AFFILIATIONS
 
Certain of the underwriters and their affiliates have in the past provided and may from time to time in the future provide services to Anadarko and us for which they have received and, in the future, will be entitled to receive, customary fees and expenses. In particular:
 
Ø  Affiliates of UBS Securities LLC and           are lenders under Anadarko’s $750 million credit facility, under which we are a co-borrower;
 
Ø  In July 2007, UBS Securities LLC provided advisory services to Anadarko in connection with the disposition of certain assets;
 
Ø  In the ordinary course of its business, Anadarko engages in numerous interest rate and commodity hedging transactions with a variety of counterparties, including affiliates of UBS Securities LLC and           ; and
 
Ø  In April 2007, UBS Securities LLC served as a Co-Advisor, Joint Lead Arranger and Joint Bookrunning Manager of Anadarko’s 354-day credit facility. An affiliate of UBS Securities LLC serves as the Administrative Agent of this facility.
 
In addition, affiliates of UBS Securities LLC and           are lenders under Anadarko’s 354-day credit facility. Anadarko has informed us that it intends to use the $337.6 million of proceeds that we loan to it, and any other proceeds that it receives from this offering, to repay a portion of the amount outstanding under this facility, and the affiliates of UBS Securities LLC and           will receive their proportionate shares of any such repayment.
 
Because the Financial Industry Regulatory Authority, or the FINRA (formerly known as the National Association of Securities Dealers, Inc., or the NASD), views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules (which are part of the FINRA rules). Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.


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Underwriting
 
 
 
Validity of the common units
 
The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas.
 
Experts
 
The combined financial statements of Western Gas Partners Predecessor as of December 31, 2006 and 2005 and for each of the years in the three-year period ended December 31, 2006, have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
 
The balance sheet of Western Gas Partners, LP as of August 21, 2007 and the balance sheet of Western Gas Holdings, LLC as of August 21, 2007, have been included herein in reliance upon the reports of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
 
The financial statements of MIGC, Inc. as of December 31, 2005 and for the period from January 1 to August 23, 2006 and for the year ended December 31, 2005, have been included herein in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
 
Where you can find more information
 
We have filed with the SEC a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.
 
We intend to furnish our unitholders annual reports containing our audited combined financial statements and to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.


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Forward-looking statements
 
Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.


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Western Gas Partners, LP
 
 
 
Index to financial statements
 
         
WESTERN GAS PARTNERS, LP UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS:
       
Introduction     F-2  
Unaudited Pro Forma Combined Statement of Income for the year ended December 31, 2006     F-4  
Unaudited Pro Forma Combined Statement of Income for the nine months ended September 30, 2007     F-5  
Unaudited Pro Forma Combined Balance Sheet as of September 30, 2007     F-6  
Notes to the Unaudited Pro Forma Combined Financial Statements     F-7  
       
WESTERN GAS PARTNERS PREDECESSOR COMBINED FINANCIAL STATEMENTS:
       
Report of Independent Registered Public Accounting Firm     F-10  
Combined Statements of Income for the years ended December 31, 2006, 2005 and 2004     F-11  
Combined Balance Sheets as of December 31, 2006 and 2005     F-12  
Combined Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004     F-13  
Combined Statements of Parent Net Equity for the years ended December 31, 2006, 2005 and 2004     F-14  
Notes to Combined Financial Statements     F-15  
Unaudited Combined Statements of Income for the nine months ended September 30, 2007 and 2006     F-26  
Unaudited Combined Balance Sheets as of September 30, 2007 and December 31, 2006     F-27  
Unaudited Combined Statements of Cash Flows for the nine months ended September 30, 2007 and 2006     F-28  
Unaudited Combined Statements of Parent Net Equity for the nine months ended September 30, 2007 and 2006     F-29  
Notes to the Unaudited Combined Financial Statements     F-30  
       
MIGC, INC. FINANCIAL STATEMENTS:
       
Report of Independent Registered Public Accounting Firm     F-35  
Statements of Income for the period from January 1, 2006 through August 23, 2006 and for the year ended December 31, 2005     F-36  
Balance Sheet as of December 31, 2005     F-37  
Statements of Cash Flows for the period from January 1, 2006 through August 23, 2006 and for the year ended December 31, 2005     F-38  
Statements of Parent Net Equity for the period from January 1, 2006 through August 23, 2006 and for the year ended December 31, 2005     F-39  
Notes to Financial Statements     F-40  
       
WESTERN GAS PARTNERS, LP FINANCIAL STATEMENTS:        
Report of Independent Registered Public Accounting Firm     F-47  
Balance Sheet as of August 21, 2007     F-48  
Note to the Balance Sheet     F-49  
       
WESTERN GAS HOLDINGS, LLC FINANCIAL STATEMENTS:        
Report of Independent Registered Public Accounting Firm     F-50  
Balance Sheet as of August 21, 2007     F-51  
Note to the Balance Sheet     F-52  


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Western Gas Partners, LP
 
 
 
Unaudited pro forma combined financial statements
 
INTRODUCTION
 
The unaudited pro forma combined statement of income of Western Gas Partners, LP (the “Partnership”) for the year ended December 31, 2006 and the nine months ended September 30, 2007 and the unaudited pro forma combined balance sheet as of September 30, 2007 are based upon the audited historical combined and unaudited interim financial statements of Western Gas Partners Predecessor (the “Predecessor”), which is comprised of Anadarko Gathering Company (“AGC”) and Pinnacle Gas Treating, Inc. (“PGT”), with MIGC, Inc. (“MIGC”) being reported as an acquired business of the Predecessor. The assets contributed to the Partnership include AGC, PGT and MIGC (collectively the “Contributed Assets”). Each of AGC, PGT, MIGC, and the Partnership is an indirect subsidiary of Anadarko. For purposes of these financial statements, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries.
 
The contribution by Western Gas Holdings, LLC, (“Holdings GP”) and WGR Holdings, LLC (“Holdings LP”), both Anadarko affiliates, of the Contributed Assets to the Partnership will be recorded at historical cost as these contributions are considered reorganizations of entities under common control.
 
The unaudited pro forma combined statement of income for the year ended December 31, 2006 has been prepared as if the acquisition of MIGC by the Predecessor occurred on January 1, 2006, as opposed to the actual date of acquisition, August 23, 2006. Offering adjustments have been prepared as if the transactions to be effected at the closing of this offering occurred on September 30, 2007, in the case of the pro forma balance sheet, and as of January 1, 2006, in the case of the pro forma statements of income for the year ended December 31, 2006 and the nine months ended September 30, 2007. The unaudited pro forma combined financial statements have been prepared based on the assumption that the Partnership will be treated as a partnership for federal and state income tax purposes and therefore will not be subject to U.S. federal income taxes and state income taxes, except for the Texas margin tax. The unaudited pro forma combined financial statements should be read in conjunction with the notes accompanying such unaudited pro forma combined financial statements and with the unaudited and audited combined financial statements and the notes thereto set forth elsewhere in this Prospectus.
 
The unaudited pro forma combined balance sheet and the unaudited pro forma combined statements of income were derived by adjusting the audited historical and unaudited interim combined financial statements of the Predecessor and its acquired business, MIGC. These adjustments are based upon currently available information and certain assumptions and estimates; therefore, the actual effects of these transactions will differ from the pro forma adjustments. However, the Partnership’s management is of the opinion that the estimates applied and the assumptions made provide a reasonable basis for the presentation of the significant effects of contemplated transactions that are expected to have a continuing impact on the Partnership. In addition, the Partnership’s management considers the pro forma adjustments to be factually supportable and to appropriately represent the expected impact of items that are directly attributable to the formation of the Partnership and the transfer of the Contributed Assets to the Partnership.
 
The unaudited pro forma combined financial statements reflect the following significant assumptions and transaction:
 
Ø  Holdings GP and Holdings LP will contribute the Contributed Assets to the Partnership;


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Unaudited pro forma combined financial statements
 
 
Ø  The Partnership will issue to Holdings GP 921,385 general partner units representing a 2.0% general partner interest in the Partnership and 100% of the Partnership incentive distribution rights, which will entitle Holdings GP to increasing percentages of cash distributions. Please read “Our cash distribution policy and restrictions on distributions,” contained elsewhere in this prospectus;
 
Ø  The Partnership will issue 3,823,925 common units and 22,573,925 subordinated units, representing an aggregate 57.3% limited partner interest in the Partnership, to Holdings LP, assuming that the underwriters do not exercise their option to purchase additional common units;
 
Ø  The Partnership will issue 18,750,000 common units to the public in connection with this offering, representing a 40.7% limited partner interest;
 
Ø  The Partnership will receive gross proceeds of $375.0 million from the issuance and sale of the 18,750,000 common units at an assumed initial offering price of $20.00 per unit;
 
Ø  The Partnership will use proceeds from this offering to pay underwriting discounts and a structuring fee totaling $24.375 million and other offering expenses estimated to be $3.0 million;
 
Ø  The Partnership will use the remaining $347.625 million of aggregate net proceeds of this offering to (i) make a loan of $337.625 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.00% and (ii) provide $10.0 million for general partnership purposes;
 
Ø  The Partnership is a co-borrower under Anadarko’s $750 million credit facility and has up to $100 million of long-term borrowing capacity available to it;
 
Ø  The Partnership will enter into a $30 million working capital facility with Anadarko as the lender;
 
Ø  The Partnership will enter into an omnibus agreement with Anadarko and Holdings GP pursuant to which, among other things, (i) the Partnership will reimburse Anadarko and Holdings GP for certain expenses incurred on behalf of the Partnership, including expenses for various general and administrative services rendered by Anadarko and Holdings GP to the Partnership, and (ii) the parties will agree to certain indemnification obligations; and
 
Ø  Holdings GP will enter into a services and secondment agreement with Anadarko, pursuant to which certain employees of Anadarko will be under the control of and render services to or on behalf of the Partnership.
 
The unaudited pro forma combined financial statements are not necessarily indicative of the results that would have occurred if the Predecessor had acquired MIGC or if the Partnership had assumed the operations of the Predecessor on the dates indicated nor is it indicative of the future operating results of the Partnership. The pro forma adjustments do not include the effects of an exercise by the underwriters of their option to purchase additional common units in the Partnership. If and to the extent the underwriters exercise their option to purchase up to 2,812,500 additional common units within 30 days of this offering, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Anadarko. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to reimburse Anadarko for capital expenditures it incurred with respect to the assets contributed to the Partnership during the two-year period prior to this offering.


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Western Gas Partners, LP
 
 
Pro forma combined statement of income
 
Year ended December 31, 2006
unaudited
 
                                             
        MIGC
                       
        January 1,
                       
    Western Gas
  2006
                       
    Partners
  through
    Pro forma
        Offering
       
    Predecessor
  August 23,
    adjustments
        adjustments
    Pro forma
 
    historical   2006     (see note 2)     Pro forma   (see note 3)     as adjusted  
   
    (in thousands, except unit and per unit data)  
 
Revenues — affiliates
                                           
Gathering and transportation of natural gas
  $ 65,946   $ 7,583     $     $ 73,529   $     $ 73,529  
Condensate
    7,440                 7,440           7,440  
Natural gas and other
    1,327     103             1,430           1,430  
                                             
Total revenues — affiliates
    74,713     7,686             82,399           82,399  
                                             
Revenues — third parties
                                           
Gathering and transportation of natural gas
    5,022     3,427             8,449           8,449  
Condensate, natural gas and other
    1,417     1,039             2,456           2,456  
                                             
Total revenues — third parties
    6,439     4,466             10,905           10,905  
                                             
Total Revenues
    81,152     12,152             93,304           93,304  
                                             
Operating Expenses — affiliates
                                           
Cost of product
    3,830                 3,830           3,830  
General and administrative
    3,198                 3,198           3,198  
                                             
Total operating expenses — affiliates
    7,028                 7,028           7,028  
                                             
Operating Expenses — third parties
                                           
Cost of product
    714                 714           714  
Operation and maintenance
    27,585     2,592             30,177           30,177  
General and administrative
        1,305             1,305           1,305  
Property and other taxes
    4,633                 4,633           4,633  
                                             
Total operating expenses — third parties
    32,932     3,897             36,829           36,829  
                                             
Depreciation
    18,009     918       783 (a)     19,710           19,710  
                                             
Total Operating Expenses
    57,969     4,815       783       63,567           63,567  
                                             
Operating Income
    23,183     7,337       (783 )     29,737           29,737  
Interest expense (income) — affiliates
    9,631     (574 )             9,057     (9,057 )(a)     (20,030 )
                                  (20,258 )(b)        
                                  228  (c)        
Other expense
    26     351             377           377  
                                             
Income Before Income Taxes
    13,526     7,560       (783 )     20,303     29,087       49,390  
Income Tax Expense
    3,814     2,647       (245 )(b)     6,216     (5,238 )(d)     978  
                                             
Net Income
  $ 9,712   $ 4,913     $ (538 )   $ 14,087   $ 34,325     $ 48,412  
                                             
General partner’s interest in net income
                                      $ 968  
Common limited partners’ interest in net income
                                      $ 23,722  
Subordinated limited partners’ interest in net income
                                      $ 23,722  
Net income per limited partner unit
                                           
Common units (basic and diluted)
                                      $ 1.05  
                                             
Subordinated units (basic and diluted)
                                      $ 1.05  
                                             
Weighted average number of limited partner units outstanding
                                           
Common units (basic and diluted)
                                        22,573,925  
                                             
Subordinated units (basic and diluted)
                                        22,573,925  
                                             
 
See the accompanying notes to the unaudited pro forma combined financial statements.


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Western Gas Partners, LP
 
Pro forma combined statement of income
 
Nine months ended September 30, 2007
unaudited
 
                       
    Western Gas
           
    Partners
  Offering
    Pro forma
 
    Predecessor
  adjustments
    as
 
    historical   (see note 3)     adjusted  
   
    (in thousands except unit and per unit data)  
 
Revenues — affiliates
                     
Gathering and transportation of natural gas
  $ 69,311   $     $ 69,311  
Condensate
    6,266           6,266  
Natural gas and other
    918           918  
                       
Total revenues — affiliates
    76,495           76,495  
                       
Revenues — third parties
                     
Gathering and transportation of natural gas
    6,067           6,067  
Condensate, natural gas and other
    2,951           2,951  
                       
Total revenues — third parties
    9,018           9,018  
                       
Total Revenues
    85,513           85,513  
                       
Operating Expenses — affiliates
                     
Cost of product
    4,439           4,439  
General and administrative
    2,370           2,370  
                       
Total operating expenses — affiliates
    6,809           6,809  
                       
Operating Expenses — third parties
                     
Operation and maintenance
    21,840           21,840  
General and administrative
    751           751  
Property and other taxes
    3,784           3,784  
                       
Total operating expenses — third parties
    26,375           26,375  
Depreciation
    17,104           17,104  
                       
Total Operating Expenses
    50,288           50,288  
                       
Operating Income
    35,225           35,225  
                       
Interest expense (income) — affiliates
    6,643     (6,643 )(a)     (15,022 )
            (15,193 )(b)        
            171  (c)        
                       
Income Before Income Taxes
    28,582     21,665       50,247  
Income Tax Expense
    10,469     (10,309 )(d)     160  
                       
Net Income
  $ 18,113   $ 31,974     $ 50,087  
                       
General partner’s interest in net income
                $ 1,315  
Common limited partners’ interest in net income
                $ 24,386  
Subordinated limited partners’ interest in net income
                $ 24,386  
Net income per limited partner unit
                     
Common units (basic and diluted)
                  1.08  
Subordinated units (basic and diluted)
                  1.08  
Weighted average number of limited partner units outstanding
                     
Common units (basic and diluted)
                  22,573,925  
                       
Subordinated units (basic and diluted)
                  22,573,925  
                       
 
See the accompanying notes to the unaudited pro forma combined financial statements.


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Western Gas Partners, LP
 
Pro forma combined balance sheet
 
September 30, 2007
unaudited
 

                         
    Western Gas Partners
    Offering
    Pro forma
 
    Predecessor
    adjustments
    as
 
    historical     (see note 3)     adjusted  
   
    (in thousands)  
 
Current Assets
                       
Cash
  $     $ 375,000  (e)   $ 10,000  
              (27,375 )(f)        
              (337,625 )(g)        
Accounts receivable
    1,732               1,732  
Natural gas imbalance receivable — affiliate
    820               820  
Deferred tax asset
    16       (11 )(d)     5  
                         
Total current assets
    2,568       9,989       12,557  
Other assets
    47               47  
Property, Plant and Equipment
                       
Cost
    477,251               477,251  
Less accumulated depreciation
    (123,957 )             (123,957 )
                         
Net property, plant and equipment
    353,294               353,294  
Note Receivable — Affiliate
            337,625  (g)     337,625  
Goodwill
    4,783               4,783  
                         
Total Assets
  $ 360,692     $ 347,614     $ 708,306  
                         
Current Liabilities
                       
Accounts payable
  $ 1,197             $ 1,197  
Natural gas imbalance payables
    453               453  
Accrued ad valorem taxes
    3,498               3,498  
Income taxes payable
    3,406       (3,247 )(d)     159  
Accrued liabilities
    3,128               3,128  
                         
Total current liabilities
    11,682       (3,247 )     8,435  
Long-term Liabilities
                       
Deferred income taxes
    68,176       (67,193 )(d)     983  
Asset retirement obligations
    7,327               7,327  
                         
Total long-term liabilities
    75,503       (67,193 )     8,310  
                         
Total Liabilities
    87,185       (70,440 )     16,745  
Partners’ Capital/Parent Net Equity
                       
Parent net investment
    273,507       70,429  (d)        
              (343,936 )(h)        
Common unitholders — public
            375,000  (e)     347,625  
              (27,375 )(f)        
Common unitholders — affiliate
            48,141  (h)     48,141  
Subordinated unitholders — affiliate
            284,195  (h)     284,195  
General partner interest
            11,600  (h)     11,600  
                         
Total Partners’ Capital/Parent Net Equity
    273,507       418,054       691,561  
Commitments and Contingencies
                   
                         
Total Liabilities and Parent Net Equity
  $ 360,692     $ 347,614     $ 708,306  
                         
 
See the accompanying notes to the unaudited pro forma combined financial statements.


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Western Gas Partners, LP
 
 
 
Notes to unaudited pro forma combined financial statements
 
1.  BASIS OF PRESENTATION, OTHER TRANSACTIONS AND THE OFFERING
 
The unaudited pro forma combined statement of income of Western Gas Partners, LP (the “Partnership”) for the year ended December 31, 2006 and the nine months ended September 30, 2007 and the unaudited pro forma combined balance sheet as of September 30, 2007 are based upon the audited historical and unaudited interim combined financial statements of Western Gas Partners Predecessor (the “Predecessor”), which is comprised of Anadarko Gathering Company (“AGC”) and Pinnacle Gas Treating, Inc. (“PGT”), with MIGC, Inc. being reported as an acquired business of the Predecessor. The assets contributed to the Partnership include AGC, PGT and MIGC (collectively the “Contributed Assets”). Each of AGC, PGT, MIGC and the Partnership is an indirect subsidiary of Anadarko. For purposes of these financial statements, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries.
 
Upon completion of this offering, the Partnership anticipates incurring incremental general and administrative expense of approximately $2.5 million per year as a result of being a publicly traded partnership, including expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. The unaudited pro forma combined financial statements do not reflect these additional public company costs.
 
In addition, while other general and administrative expenses have not yet been determined, the Partnership intends to enter into an omnibus agreement with Anadarko pursuant to which reimbursement of general and administrative expenses by the Partnership to Anadarko will be capped at $6.0 million annually through December 31, 2009, subject to increases based on increases in the Consumer Price Index and, with the concurrence of the special committee of the board of directors of the general partner of the Partnership, subject to further increases arising in connection with expansions of the Partnership’s operations through the acquisition or construction of new assets or businesses. The $6.0 million cap does not apply to any reimbursement by the Partnership to Anadarko for additional public company costs.
 
2.  PRO FORMA ADJUSTMENTS
 
The following pro forma adjustments have been prepared to reflect the Predecessor’s acquisition of MIGC as if it occurred on January 1, 2006:
 
(a)  Reflects depreciation expense in excess of historical amounts recorded for MIGC, computed based on MIGC’s adjusted basis, as determined under the purchase method of accounting.
 
(b)  Reflects the related income tax effects of the depreciation expense adjustment in item (a) above, based on applicable effective tax rates.
 
3.  OFFERING ADJUSTMENTS
 
The following offering adjustments for the Partnership have been prepared as if the transactions to be effected at the closing of this offering had taken place on September 30, 2007, in the case of the pro forma balance sheet, and as of January 1, 2006 or 2007, in the case of the pro forma statements of


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Notes to unaudited pro forma combined financial statements of Western Gas Partners, LP
 
 
income for the year ended December 31, 2006 and for the nine months ended September 30, 2007, respectively:
 
(a)  Reflects the elimination of historical interest expense resulting from the non-cash settlement of receivables held by Anadarko prior to the offering.
 
(b)  Reflects the inclusion of interest income on the Partnership’s $337.625 million 30-year note receivable from Anadarko, which bears interest at a fixed annual rate of 6.00%.
 
(c)  Reflects the payment by the Partnership of a commitment fee of 0.175% with respect to each of the Partnership’s $30.0 million working capital facility and $100.0 million of available borrowing capacity under Anadarko’s credit facility, for a total of $227,500 and $170,625 in aggregate commitment fees for the year ended December 31, 2006 and for the nine months ended September 30, 2007, respectively.
 
(d)  Reflects the elimination of historical current and deferred income taxes as a result of operating as a partnership for tax purposes. Texas margin taxes have not been eliminated and will continue to be borne by the Partnership subsequent to the closing of this offering.
 
(e)  Reflects the assumed gross offering proceeds to the Partnership of $375.0 million from the issuance and sale of 18,750,000 common units at an assumed initial public offering price of $20.00 per unit.
 
(f)  Reflects the payment of underwriting discounts and a structuring fee totaling $24.375 million and estimated offering expenses of $3.0 million for a total of $27.375 million, all of which will be allocated to the public common units. The $3.0 million of estimated offering expenses will be paid to Anadarko to reimburse it for offering expenses that it incurred on our behalf.
 
(g)  Reflects the loan of $337.625 million by the Partnership to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.00%.
 
(h)  Reflects the conversion of adjusted parent net investment of $343.936 million to common, subordinated and general partner capital of the Partnership. The conversion is allocated as follows:
 
Ø  $48.141 million for 3,823,925 common units;
 
Ø  $284.195 million for 22,573,925 subordinated units; and
 
Ø  $11.600 million for 921,385 general partner units.
 
After the conversion, the equity amounts of the common and subordinated units will be 49.0% and 49.0%, respectively, with the general partner units representing the remaining 2.0%.
 
The adjustments described above assume no exercise the underwriters’ option to purchase additional common units. If the underwriters exercise their option to purchase additional common units in full, the Partnership would receive approximately $52.6 million in exchange for 2,812,500 common units and will use the proceeds from the issuance of these units to reimburse Anadarko for capital expenditures it incurred in respect of the Contributed Assets during the two-year period prior to the formation of the Partnership.
 
4.  PRO FORMA NET INCOME PER UNIT
 
Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the provisions of the limited partnership agreement, to the common and subordinated unitholders by the number of common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that (1) pro forma cash distributions were equal to pro forma earnings and (2) 22,573,925 common units and


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Notes to unaudited pro forma combined financial statements of Western Gas Partners, LP
 
 
22,573,925 subordinated units were outstanding, since the beginning of the periods presented. Because the limited partnership agreement requires the Partnership to distribute available cash rather than the earnings reflected in the Partnership’s income statement, actual cash distributions declared and paid by the Partnership may vary significantly from reported pro forma net income per unit. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income being proportionately allocated to the general partner than to the holders of common and subordinated units. The pro forma net income per unit is sufficient to have generated incentive distribution payments to our general partner for the nine months ended September 30, 2007, but not for the twelve months ended December 31, 2006. Incentive distributions allocated to the general partner would have been $313,000 for the nine months ended September 30, 2007.


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Western Gas Partners Predecessor
 
 
Report of independent registered public accounting firm
 
The Board of Directors
Anadarko Petroleum Corporation:
 
We have audited the accompanying combined balance sheets of Western Gas Partners Predecessor (the “Predecessor”) as of December 31, 2006 and 2005, and the related combined statements of income, parent net equity and cash flows for each of the years in the three-year period ended December 31, 2006. These combined financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
 
/s/ KPMG LLP
 
Houston, Texas
October 13, 2007


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Western Gas Partners Predecessor
 
Combined statements of income
 
                         
    Years ended December 31,  
    2006     2005     2004  
   
    (in thousands)  
 
Revenues — affiliates
                       
Gathering and transportation of natural gas
  $ 65,946     $ 58,363     $ 54,407  
Condensate
    7,440       7,006       6,407  
Natural gas and other
    1,327       789       4,526  
                         
Total revenues — affiliates
    74,713       66,158       65,340  
                         
Revenues — third parties
                       
Gathering and transportation of natural gas
    5,022       2,420       1,458  
Condensate, natural gas and other
    1,417       3,072       1,251  
                         
Total revenues — third parties
    6,439       5,492       2,709  
                         
Total Revenues
    81,152       71,650       68,049  
                         
                         
Operating Expenses — affiliates
                       
Cost of product
    3,830       5,551       4,425  
General and administrative
    3,198       2,829       2,251  
                         
Total operating expenses — affiliates
    7,028       8,380       6,676  
                         
                         
Operating Expenses — third parties
                       
Cost of product
    714       456       553  
Operation and maintenance
    27,585       23,044       20,678  
General and administrative
          9       48  
Property and other taxes
    4,633       3,831       3,346  
                         
Total operating expenses — third parties
    32,932       27,340       24,625  
                         
Depreciation
    18,009       15,447       14,841  
                         
Total Operating Expenses
    57,969       51,167       46,142  
                         
Operating Income
    23,183       20,483       21,907  
                         
Interest expense — affiliates
    9,631       8,650       7,146  
Other income (expense)
    (26 )     66        
                         
Income Before Income Taxes
    13,526       11,899       14,761  
                         
Income Tax Expense
    3,814       4,789       5,504  
                         
Net Income
  $ 9,712     $ 7,110     $ 9,257  
                         
 
See the accompanying notes to the combined financial statements.


F-11


Table of Contents

Western Gas Partners Predecessor
 
Combined balance sheets
 
                 
    December 31,  
    2006     2005  
   
    (in thousands)  
 
Current Assets
               
Cash
  $ 458     $ 4  
Accounts receivable
    817       872  
Natural gas imbalance receivables
    673       798  
Deferred tax asset
    14,569       4,248  
                 
Total current assets
    16,517       5,922  
Other assets
    57        
Property, Plant and Equipment
               
Cost
    417,951       289,936  
Less accumulated depreciation
    (107,080 )     (89,485 )
                 
Net property, plant and equipment
    310,871       200,451  
Goodwill
    4,783        
                 
Total Assets
  $ 332,228     $ 206,373  
                 
Current Liabilities
               
Accounts payable
  $ 4,581     $ 5,706  
Natural gas imbalance payables
    2,365       235  
Accrued ad valorem taxes
    975       770  
Accrued liabilities
    3,297       1,413  
                 
Total current liabilities
    11,218       8,124  
Long-term Liabilities
               
Deferred income taxes
    75,665       36,741  
Asset retirement obligations
    6,814       923  
                 
Total long-term liabilities
    82,479       37,664  
                 
Total Liabilities
    93,697       45,788  
Parent Net Equity
    238,531       160,585  
Commitments and Contingencies (see Note 11)
           
                 
Total Liabilities and Parent Net Equity
  $ 332,228     $ 206,373  
                 
 
See the accompanying notes to the combined financial statements.


F-12


Table of Contents

Western Gas Partners Predecessor
 
Combined statements of cash flows
 
                         
    Years ended December 31,  
    2006     2005     2004  
   
    (in thousands)  
 
Cash Flow from Operating Activities
                       
Net income
  $ 9,712     $ 7,110     $ 9,257  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation
    18,009       15,447       14,841  
Deferred income taxes
    3,814       4,789       5,504  
Changes in assets and liabilities:
                       
(Increase) decrease in accounts receivable
    374       (662 )     933  
Increase (decrease) in accounts payable and accrued expenses
    (4,556 )     3,373       (551 )
Increase (decrease) in other items, net
    (30 )     74       1,176  
                         
Cash provided by operating activities
    27,323       30,131       31,160  
                         
Cash Flow from Investing Activities
                       
Capital expenditures, net
    (42,299 )     (20,841 )     (16,548 )
Other investing activities
    (414 )     (235 )      
                         
Cash used in investing activities
    (42,713 )     (21,076 )     (16,548 )
Cash Flow from Financing Activities
                       
Increase (decrease) in parent net equity (see Note 5)
    15,844       (9,067 )     (14,596 )
                         
Cash provided by (used in) financing activities
    15,844       (9,067 )     (14,596 )
                         
Net Increase (Decrease) in Cash
    454       (12 )     16  
                         
Cash at Beginning of Year
    4       16        
                         
Cash at End of Year
  $ 458     $ 4     $ 16  
                         
Supplemental Disclosures
                       
Significant non-cash investing and financing transactions:
                       
Acquisition, net of cash received
  $ 52,390     $     $  
 
See the accompanying notes to the combined financial statements.


F-13


Table of Contents

Western Gas Partners Predecessor
 
Combined statements of parent net equity
 
         
    Parent net
 
    equity  
   
    (in thousands)  
 
Balance, January 1, 2004
  $ 167,881  
         
Net income
    9,257  
Net advance to parent
    (14,596 )
         
Balance, December 31, 2004
    162,542  
         
Net income
    7,110  
Net advance to parent
    (9,067 )
         
Balance, December 31, 2005
    160,585  
         
Net income
    9,712  
Net advance from parent
    15,844  
Investment by parent
    52,390  
         
Balance, December 31, 2006
  $ 238,531  
         
 
See the accompanying notes to the combined financial statements.


F-14


Table of Contents

Western Gas Partners Predecessor
 
 
Notes to combined financial statements
 
1.   DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
 
These financial statements of Western Gas Partners Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering of limited partner units in Western Gas Partners, LP (the “Partnership”), which was formed in Delaware on August 21, 2007 and is expected to own the operations and assets of the Predecessor upon closing. The Predecessor is comprised of Anadarko Gathering Company (“AGC”) and Pinnacle Gas Treating, Inc. (“PGT”), with MIGC, Inc. (“MIGC”) being reported as an acquired business of the Predecessor. PGT, AGC and MIGC, collectively, constitute the assets to be contributed to the Partnership (the “Contributed Assets”). Each of AGC, PGT, MIGC and the Partnership is an indirect subsidiary of Anadarko. For purposes of these financial statements, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries.
 
The Predecessor’s assets consist of six gathering systems, five natural gas treating facilities and one interstate pipeline. The Predecessor’s assets are located in East Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma) and West Texas. As part of the initial public offering of limited partner units of the Partnership, Western Gas Holdings, LLC (“Holdings GP”) and WGR Holdings, LLC, both Anadarko affiliates, will collectively contribute the Contributed Assets to the Partnership. Holdings GP will serve as the general partner of the Partnership and together with Anadarko will provide services to the Partnership pursuant to an omnibus agreement and a services and secondment agreement between the parties.
 
On August 23, 2006, Anadarko acquired Western Gas Resources, Inc. (“Western”), including Western’s subsidiary, MIGC. Under the purchase method of accounting, Anadarko allocated $52.4 million of the Western purchase price to MIGC. These financial statements are prepared as if MIGC was acquired by the Predecessor on August 23, 2006, the date of Anadarko’s acquisition of Western.
 
The combined financial statements of the Predecessor have been prepared in accordance with accounting principles generally accepted in the United States on the basis of Anadarko’s historical ownership of the Contributed Assets. These combined financial statements have been prepared from the separate records maintained by Anadarko and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net equity, in lieu of owner’s equity, in the combined financial statements.
 
The Predecessor’s costs of doing business incurred by Anadarko on behalf of the Predecessor have been reflected in the accompanying financial statements. These costs include general and administrative expenses charged as a management services fee by Anadarko to the Predecessor in exchange for:
 
Ø  business services, such as payroll, accounts payable and facilities management;
 
Ø  corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy;
 
Ø  executive compensation, but not including share-based compensation; and
 
Ø  pension and other post-retirement benefit costs.
 
Transactions between the Predecessor and Anadarko have been identified in the combined financial statements as transactions between affiliates (see Note 5).


F-15


Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Use of estimates
 
To conform to generally accepted accounting principles in the United States, management makes estimates and assumptions that affect the amounts reported in the combined financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with outside advisers and other methods considered reasonable in the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results could differ. Effects on the Predecessor’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.
 
Property, plant and equipment
 
Property, plant and equipment are stated at the lower of historical cost, less accumulated depreciation or fair value, if impaired. The Predecessor capitalizes all construction-related direct labor and material costs. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is computed over the asset’s estimated useful life using the straight-line method.
 
Goodwill
 
Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the identifiable assets acquired and liabilities assumed.
 
Asset retirement obligations
 
The Predecessor recognizes a liability based on estimated costs of retiring tangible long-lived assets. The liability is recognized at the fair value of the asset retirement obligation when the obligation is incurred, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with corresponding adjustments to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled.
 
Goodwill and long-lived asset impairment
 
The Predecessor evaluates whether goodwill or long-lived assets have been impaired. In the case of goodwill, impairment testing is performed annually, unless facts and circumstances make it necessary to test more frequently. Goodwill impairment assessment is a two-step process. Step one focuses on identifying a potential impairment by comparing the fair value of the reporting unit with the carrying amount of the reporting unit. If the fair value of the reporting unit exceeds its carrying amount, no further action is required. However, if the carrying amount of the reporting unit exceeds its fair value, step two of the process is performed, directed at measuring the goodwill impairment, if any.
 
For long-lived assets, the Predecessor evaluates circumstances that indicate the carrying amount of the asset may not be recoverable. Impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under


F-16


Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value, such that the asset’s carrying amount is adjusted to its estimated fair value.
 
Management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such determinations. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset or a change in management’s intent to utilize the asset would generally require management to re-assess the cash flows related to the long-lived assets.
 
No long-lived asset or goodwill impairment has been recognized in these financial statements.
 
Natural gas imbalances
 
The combined balance sheets include natural gas imbalance receivables or payables resulting from differences in gas volumes received and gas volumes delivered to customers. Natural gas volumes owed to or by the Predecessor that are subject to tariffs are valued at market index prices, as of the balance sheet dates, and are subject to cash settlement procedures. Other natural gas volumes owed to or by the Predecessor are valued at the Predecessor’s weighted average cost of natural gas as of the balance sheet dates and are settled in-kind. Accounts receivable related to gas imbalances were $673,000 and $798,000 as of December 31, 2006 and 2005, respectively.
 
Environmental expenditures
 
The Predecessor expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are probable and may be reasonably estimated.
 
Revenue recognition
 
Revenues for natural gas gathering, compression, treating and transportation services are recognized when the service is provided. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the Federal Energy Regulatory Commission, and reserves are established as necessary. During the periods presented, there were no pending rate cases, and no such reserves have been required.
 
Income taxes
 
Anadarko files various United States federal and state income tax returns. Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases as if the Predecessor filed tax returns as a stand-alone entity.


F-17


Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
New accounting standards
 
The following new accounting standards were adopted by the Predecessor during the year ended December 31, 2005:
 
SFAS No. 154 “Accounting Changes and Error Corrections.” In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, “Accounting Changes” and SFAS 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also (1) provides that a change in depreciation or amortization of a long-lived non-financial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 did not have an impact on the Predecessor’s combined results of operations, cash flows or financial position.
 
FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations.” In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS 143. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN 47 were effective for the Predecessor as of December 31, 2005. The adoption of FIN 47 did not have an impact on the Predecessor’s combined results of operations, cash flows or financial position.
 
Recently issued accounting standards not yet adopted
 
The following new accounting standards have been issued, but as of December 31, 2006 had not yet been adopted by the Predecessor:
 
FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.” FIN 48 was issued in 2006 and became effective January 1, 2007 for the Predecessor. FIN 48 defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. FIN 48 also provides guidance on the measurement of the income tax benefit associated with uncertain tax positions, de-recognition, classification, interest and penalties and financial statement disclosures. Management does not expect the adoption of FIN 48 to have a material impact on the Predecessor financial statements.
 
SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115.” In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities and mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS 159 is effective for the Predecessor on January 1, 2008. The Predecessor does not expect to apply the provisions of SFAS 159 on its combined results of operations, cash flows or financial position.


F-18


Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
SFAS No. 157 “Fair Value Measurements.” In September 2006, the FASB issued SFAS 157, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements. However, in some cases, the application of SFAS 157 may change the Predecessor’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For the Predecessor, SFAS 157 is effective as of January 1, 2008 and must be applied prospectively, except in certain cases. The Predecessor is currently evaluating the impact of adopting SFAS 157 and cannot currently estimate the impact of adoption on its combined results of operations, cash flows or financial position.
 
3.   ACQUISITION
 
On August 23, 2006, Anadarko completed its acquisition of Western. This transaction included MIGC, a subsidiary of Western, which was allocated a fair value of $52.4 million under the purchase method of accounting. MIGC will be contributed to the Partnership upon the closing of this offering, and the Predecessor’s combined financial statements are prepared as if MIGC had been acquired by the Predecessor on August 23, 2006, when Anadarko acquired Western.
 
The acquisition of MIGC was accounted for under the purchase method of accounting. Accordingly, the assets and liabilities of MIGC are recorded at their estimated fair values by the Predecessor as of the date of Anadarko’s acquisition of Western.
 
The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed in the MIGC acquisition, as of the acquisition date:
 
         
    Allocation of
 
    purchase price  
   
    (in thousands)  
 
Current assets
  $ 193  
Other assets
    27  
Property, plant, and equipment
    79,273  
Goodwill
    4,783  
Current liabilities
    (5,813 )
Deferred income taxes
    (24,790 )
Asset retirement obligations
    (1,283 )
         
Total purchase price
  $ 52,390  
         
 
The purchase price allocation was based on an assessment of the fair value of the MIGC assets acquired and liabilities assumed. Other assets and liabilities were recorded at their historical book values, which the Predecessor believed to represent the best estimate of fair value at the date of acquisition. The liabilities assumed included certain amounts associated with contingencies, such as legal and environmental, the fair values of which were estimated by management.


F-19


Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
The following table presents selected pro forma results of operations data for the Predecessor as if the MIGC acquisition occurred on January 1, 2006 and 2005:
 
             
    Years ended December 31,
    2006   2005
 
    (in thousands)
 
Revenues
  $ 93,304   $ 88,809
Operating income
  $ 29,737   $ 27,533
Net income
  $ 14,087   $ 11,497
 
The pro forma information set forth above is presented for illustration purposes only, in accordance with the assumptions set forth below, and is not necessarily indicative of the operating results that would have occurred had the acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined enterprise. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes that the estimates and assumptions are reasonable and that the significant effects of the transaction are properly reflected.
 
The pro forma information for 2006 and 2005 is a result of combining the income statements of the Predecessor with the pre-acquisition results from January 1, 2006 and 2005 of MIGC, adjusted for (1) depreciation expense for MIGC property, plant and equipment calculated by reference to the adjusted basis of the properties acquired, and (2) the related income tax effects of these adjustments based on the applicable effective tax rates.
 
4.   GOODWILL
 
For 2006, the Predecessor recognized goodwill of $4.8 million in connection with the acquisition of MIGC. None of the Predecessor’s goodwill is deductible for income tax purposes.
 
5.   TRANSACTIONS WITH AFFILIATES
 
Affiliate transactions
 
The Predecessor provides natural gas gathering, compression, treating and transportation services to Anadarko resulting in affiliate transactions. The Predecessor’s expenditures are paid through Anadarko, which also results in affiliate transactions. Unlike transactions with third parties that settle in cash, settlement of these affiliate transactions occurs on a net basis through an adjustment to parent net equity. Anadarko also charges the Predecessor interest on the amounts settled through parent net equity. Interest is computed based on an interest rate equal to Anadarko’s weighted average cost of capital.
 
Centralized cash management
 
Anadarko operates a cash management system whereby excess cash from most of its various subsidiaries, held in separate bank accounts, is swept to a centralized account. Sales and purchases related to third-party transactions are settled in cash but are received or paid by Anadarko within the centralized cash management system and are deemed to have occurred through parent net equity.
 
Allocation of costs
 
The employees supporting the Predecessor’s operations are employees of Anadarko. The combined financial statements of the Predecessor include costs allocated by Anadarko in the form of a


F-20


Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
management services fee and related to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources and (iii) compensation, benefit, and pension and post-retirement costs. Costs were allocated to the Predecessor based on its proportionate share of Anadarko’s assets and revenues. Management believes these allocation methodologies are reasonable.
 
The following table summarizes the affiliate transactions and other payments made to or received from Anadarko which are settled through parent net equity:
 
                         
    Years ended December 31,  
    2006     2005     2004  
   
    (in thousands)  
 
Revenues — affiliates
  $ (74,713 )   $ (66,158 )   $ (65,340 )
Operating expense — affiliates
    7,028       8,380       6,676  
Interest expense — affiliates
    9,631       8,650       7,146  
                         
Affiliate transactions
    (58,054 )     (49,128 )     (51,518 )
                         
                         
Cash used in investing activities
    42,713       21,076       16,548  
Other third-party payments
    31,185       18,985       20,374  
                         
Third-party transactions
    73,898       40,061       36,922  
                         
                         
Net advance from (to) parent
  $ 15,844     $ (9,067 )   $ (14,596 )
                         
 
6.   INCOME TAXES
 
Components of income tax expense are as follows:
 
                         
    Years ended December 31,  
    2006     2005     2004  
   
    (in thousands)  
 
Current income taxes
                       
Federal
  $     $     $  
State
                 
                         
Total current income taxes
                 
                         
Deferred income taxes
                       
Federal
    5,237       3,823       4,985  
State
    (1,423 )     966       519  
                         
Total deferred income taxes
    3,814       4,789       5,504  
                         
Total income tax expense
  $ 3,814     $ 4,789     $ 5,504  
                         


F-21


Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
Total income taxes differed from the amounts computed by applying the statutory income tax rate to “Income before income taxes.” The sources of these differences are as follows:
 
                         
    Years ended December 31,  
    2006     2005     2004  
   
    (in thousands)  
 
Income before income taxes
  $ 13,526     $ 11,899     $ 14,761  
Income tax expense, computed at the statutory rate of 35%
    4,734       4,165       5,166  
Adjustments resulting from:
                       
State income tax, net of federal income tax effect
    179       628       337  
Texas law change, net of federal income tax effect
    (1,104 )            
Other items
    5       (4 )     1  
                         
Total income tax expense
  $ 3,814     $ 4,789     $ 5,504  
                         
Effective tax rate
    28.20 %     40.25 %     37.29 %
                         
 
Texas House Bill 3, signed into law in May 2006, eliminates the taxable capital and earned surplus components of the existing franchise tax and replaces these components with a taxable margin tax calculated on a combined group reporting basis. There is no impact for the Texas law change on the Predecessor’s 2006 current state income taxes as the new tax is effective for reports due on or after January 1, 2008 (based on business activity during 2007). The Predecessor is required to record the impact of the law change to its deferred state income taxes for the period which includes the date of the law’s enactment. The adjustment, a reduction to the Predecessor’s deferred state income taxes in the amount of approximately $1.1 million, net of the federal tax benefit, is included in 2006 tax expense.
 
The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities at December 31, 2006 and 2005 are as follows:
 
                 
    December 31,  
    2006     2005  
   
    (in thousands)  
 
Net operating loss and credit carryforwards
  $ 14,569     $ 4,248  
                 
Net current deferred income tax assets
    14,569       4,248  
                 
Depreciable properties
    (75,887 )     (53,055 )
Net operating loss carryforward
    222       16,314  
                 
Net long-term deferred income tax liabilities
    (75,665 )     (36,741 )
                 
Total net deferred income tax liabilities
  $ (61,096 )   $ (32,493 )
                 
 
Tax loss and credit carryforwards at December 31, 2006, generated by the Predecessor, are as follows:
 
                 
Net operating loss — federal
  $ 40,527 statutory expiration 2022-2024  
Net operating loss — state
  $ 22,602 statutory expiration 2013-2014  
State credit
  $ 14 statutory expiration 2027        


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Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
7.   CONCENTRATION OF CREDIT RISK
 
The customers accounting for 10% or more of combined revenues for the years ended December 31, 2006, 2005 and 2004 are as follows:
 
                         
    Years ended December 31,  
Customer   2006     2005     2004  
   
 
Anadarko
    92 %     92 %     96 %
Other
    8 %     8 %     4 %
                         
Total
    100 %     100 %     100 %
                         
 
The Predecessor’s principal customer for natural gas gathering, compression, treating and transportation services is Anadarko. Total revenues were approximately $81.2 million, $71.7 million and $68.0 million for the periods ended December 31, 2006, 2005 and 2004, respectively. Except for Anadarko, no other customer accounted for greater than 10% of revenue during any of the three years ended December 31, 2006. Where exposed to third-party credit risk, it is the policy of the Predecessor to (1) analyze the counterparties’ financial condition prior to entering into an agreement, (2) establish credit limits and (3) monitor the appropriateness of those limits on an ongoing basis. The Predecessor maintains no credit policy with respect to Anadarko.
 
8.   PROPERTY, PLANT AND EQUIPMENT
 
A summary of the historical cost of the Predecessor’s property, plant and equipment is as follows:
 
                     
    Estimated
  December 31,  
    useful life   2006     2005  
   
    (in thousands, except for estimated useful life)  
 
Land
  n/a   $ 229     $ 229  
Gathering systems
  15 to 25 years     312,514       277,495  
Pipeline and equipment
  30 years     79,956        
Compressor improvements
  7 years     9,615       9,615  
Assets under construction
  n/a     12,613        
Other
  5 to 25 years     3,024       2,597  
                     
Total property, plant and equipment
        417,951       289,936  
Accumulated depreciation
        (107,080 )     (89,485 )
                     
Total net property, plant and equipment
      $ 310,871     $ 200,451  
                     
 
Depreciation is calculated using the straight-line method, based on estimated useful lives and salvage values of assets. Uncertainties that may impact these estimates include, among others, changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, the Predecessor makes estimates with respect to useful lives and salvage values that the Predecessor believes are reasonable. However, subsequent events could cause a change in estimates, thereby impacting future depreciation amounts. The cost of property classified as “Assets under construction” is excluded from capitalized costs being depreciated. This amount represents property elements that are work-in-progress and not yet suitable to be placed into productive service as of the balance sheet date.


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Notes to combined financial statements of Western Gas Partners Predecessor
 
 
9.   ASSET RETIREMENT OBLIGATIONS
 
The Predecessor’s asset retirement obligations are related to the capping or dismantling of its gathering and transportation pipelines. The liability for asset retirement obligations is initially recorded at estimated fair value, with an offsetting increase to property, plant and equipment. Accretion expense is recognized over the estimated productive life of the related assets, increasing the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.
 
The following table provides a rollforward of asset retirement obligations. Revisions in estimated liabilities during the period relate primarily to revisions of estimated cost escalation rates and current cost estimates, which may include, among other things, changes in property lives and the expected timing of settling asset retirement obligations.
 
                 
    2006     2005  
   
    (in thousands)  
 
Carrying amount of asset retirement obligations at beginning of year
  $ 923     $ 970  
Additions
    55       2  
Liabilities assumed with MIGC acquisition
    1,283        
Accretion expense
    197       62  
Revisions in estimated liabilities:
               
Increase in cost escalation assumption
    2,331        
Change in other estimates
    2,025       (111 )
                 
Carrying amount of asset retirement obligations at end of year
  $ 6,814     $ 923  
                 
 
10.   SEGMENT INFORMATION
 
The Predecessor’s operations are organized into a single business segment, all of the assets of which consist of natural gas pipelines and related plant and equipment.
 
11.   COMMITMENTS AND CONTINGENCIES
 
Environmental
 
The Predecessor is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are no such matters that are expected to have a material adverse effect on the Predecessor’s results of operations, cash flows or financial position.
 
Litigation and legal proceedings
 
From time to time, the Predecessor is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which a final disposition could have a material adverse effect on the Predecessor’s results of operations, cash flows or financial position.
 
Lease commitments
 
The Predecessor enters into leases primarily for compression equipment. These leases have original terms ranging from 10 to 15 years and meet the criteria for classification as operating leases. Each compression equipment lease contains a purchase option, which is exercisable at various times over the term of the respective lease. Each compressor lease also contains a renewal provision. Rent expense


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Table of Contents

 
Notes to combined financial statements of Western Gas Partners Predecessor
 
 
under the compressor operating leases was approximately $3.0 million, $2.8 million and $2.7 million for 2006, 2005 and 2004, respectively. Future minimum rent payments due under the compressor leases are as follows:
 
       
    Minimum
    rental
    payments
 
    (in thousands)
 
2007
  $ 3,123
2008
    2,050
2009
    2,127
2010
    2,132
2011
    2,145
Thereafter
    1,782
       
Total
  $ 13,359
       
 
12.   PENSION PLANS, OTHER POSTRETIREMENT AND EMPLOYEE SAVINGS PLANS
 
The Predecessor does not sponsor any pension, postretirement or employee savings plan. However, the Predecessor participates in certain plans sponsored by Anadarko. The Predecessor participates in Anadarko’s non-contributory defined pension plans, including both qualified and supplemental plans. Anadarko also provides certain health care and life insurance benefits for retired employees. Effective December 31, 2006, Anadarko adopted SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132(R),” which requires the recognition of the overfunded or underfunded status of a defined postretirement plan in its balance sheet, measured as the difference between the fair value of plan assets and the benefit obligation and the recognition of changes in the funded status of a plan during the reporting period as a component of accumulated other comprehensive income.
 
Anadarko also sponsors, and the Predecessor participates in, an employee defined contribution savings plan that matches a portion of each employee’s contributions.
 
Pension, postretirement and employee savings plan costs included in the management services fee charged to the Predecessor by Anadarko were approximately $250,000, $200,000 and $125,000 for 2006, 2005 and 2004, respectively.


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Western Gas Partners Predecessor
 
Combined statements of income
 
                 
    Nine months ended September 30,  
    2007     2006  
   
    (unaudited)  
    (in thousands)  
 
Revenues — affiliates
               
Gathering and transportation of natural gas
  $ 69,311     $ 46,546  
Condensate
    6,266       5,374  
Natural gas and other
    918       324  
                 
Total revenues—affiliates
    76,495       52,244  
                 
Revenues — third parties
               
Gathering and transportation of natural gas
    6,067       3,660  
Condensate, natural gas and other
    2,951       1,577  
                 
Total revenues — third parties
    9,018       5,237  
                 
Total Revenues
    85,513       57,481  
                 
Operating Expenses — affiliates
               
Cost of product
    4,439       4,196  
General and administrative
    2,370       2,394  
                 
Total operating expenses — affiliates
    6,809       6,590  
                 
Operating Expenses — third parties
               
Operation and maintenance
    21,840       18,598  
General and administrative
    751       204  
Property and other taxes
    3,784       3,665  
                 
Total operating expenses — third parties
    26,375       22,467  
Depreciation
    17,104       12,635  
                 
Total Operating Expenses
    50,288       41,692  
                 
Operating Income
    35,225       15,789  
                 
Interest expense — affiliates
    6,643       7,943  
Other expense
          25  
                 
Income Before Income Taxes
    28,582       7,821  
Income Tax Expense (Benefit)
    10,469       1,740  
                 
Net Income
  $ 18,113     $ 6,081  
                 
 
See the accompanying notes to the unaudited combined financial statements.


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Western Gas Partners Predecessor
 
Combined balance sheet
 
                 
    September 30,
    December 31,
 
    2007     2006  
   
    (unaudited)  
    (in thousands)  
 
Current Assets
               
Cash
  $     $ 458  
Accounts receivable
    1,732       817  
Natural gas imbalance receivables
    820       673  
Deferred tax asset
    16       14,569  
                 
Total current assets
    2,568       16,517  
Other assets
    47       57  
Property, Plant and Equipment
               
Cost
    477,251       417,951  
Less accumulated depreciation
    (123,957 )     (107,080 )
                 
Net property, plant and equipment
    353,294       310,871  
Goodwill
    4,783       4,783  
                 
Total Assets
  $ 360,692     $ 332,228  
                 
Current Liabilities
               
Accounts payable
  $ 1,197     $ 4,581  
Natural gas imbalance payables
    453       2,365  
Accrued ad valorem taxes
    3,498       975  
Income taxes payable
    3,406        
Accrued liabilities
    3,128       3,297  
                 
Total current liabilities
    11,682       11,218  
Long-term Liabilities
               
Deferred income taxes
    68,176       75,665  
Asset retirement obligations
    7,327       6,814  
                 
Total long-term liabilities
    75,503       82,479  
                 
Total Liabilities
    87,185       93,697  
Parent Net Equity
    273,507       238,531  
Commitments and Contingencies (see Note 6)
           
                 
Total Liabilities and Parent Net Equity
  $ 360,692     $ 332,228  
                 
 
See the accompanying notes to the unaudited combined financial statements.


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Table of Contents

Western Gas Partners Predecessor
 
Combined statements of cash flows
 
                 
    Nine months ended
 
    September 30,  
    2007     2006  
   
    (unaudited)  
    (in thousands)  
 
Cash Flow from Operating Activities
               
Net income
  $ 18,113     $ 6,081  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation
    17,104       12,635  
Deferred income taxes
    7,063       1,740  
Changes in assets and liabilities:
               
(Increase) in accounts receivable
    (915 )     (1,160 )
(Increase) in natural gas imbalance receivable
    (147 )     (250 )
 Increase (decrease) in accounts payable and accrued expenses
    580       (6,015 )
(Increase) decrease in other items, net
    12       (90 )
                 
Cash provided by operating activities
    41,810       12,941  
                 
Cash Flow used in Investing Activities
               
Capital expenditures, net
    (37,020 )     (27,709 )
Other investing activities
    (227 )     (243 )
                 
Cash used in investing activities
    (37,247 )     (27,952 )
Cash Flow from Financing Activities
               
Increase (decrease) in parent investment
    (5,021 )     15,007  
                 
Cash flow provided by (used in) financing activities
    (5,021 )     15,007  
                 
Net Decrease in Cash
    (458 )     (4 )
                 
Cash at Beginning of Year
    458       4  
                 
Cash at End of Period
  $     $  
                 
Supplemental Disclosures:
               
Significant non-cash investing and financing transactions:
               
Property, plant and equipment contributed by parent
  $ 21,884     $  
Acquisition, net of cash received
  $     $ 52,390  
 
See the accompanying notes to the unaudited combined financial statements.


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Table of Contents

Western Gas Partners Predecessor
 
Combined statements of parent net equity
 
         
    Parent net
 
    equity  
   
    (unaudited)  
    (in thousands)  
 
Balance, December 31, 2005
  $ 160,585  
Net income
    6,081  
Net advance from parent
    15,007  
Investment by parent
    52,390  
         
Balance, September 30, 2006
  $ 234,063  
         
         
Balance, December 31, 2006
  $ 238,531  
Net income
    18,113  
Net advance from parent
    (5,021 )
Investment by parent
    21,884  
         
Balance, September 30, 2007
  $ 273,507  
         
 
See the accompanying notes to the unaudited combined financial statements.


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Table of Contents

Western Gas Partners Predecessor
 
Notes to unaudited combined financial statements
 
1.   DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
 
These financial statements of Western Gas Partners Predecessors (the “Predecessor”) have been prepared in connection with the proposed initial public offering of limited partner units of Western Gas Partners, LP (the “Partnership”), which was formed in Delaware on August 21, 2007 and is expected to own the operations and assets of the Predecessor upon closing. The Predecessor is comprised of Anadarko Gathering Company (“AGC”) and Pinnacle Gas Treating, Inc. (“PGT”), with MIGC, Inc. (“MIGC”) being reported as an acquired business of the Predecessor. The assets contributed to the Partnership include AGC, PGT and MIGC (collectively the “Contributed Assets”). Each of AGC, PGT, MIGC and the Partnership is an indirect subsidiary of Anadarko. For purposes of these financial statements, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries.
 
The Predecessor’s assets consist of six gathering systems, five natural gas treating facilities and one interstate pipeline. The Predecessor’s assets are located in East Texas, the Rocky Mountains (Utah and Wyoming), the Mid-Continent (Kansas and Oklahoma) and West Texas. As part of the initial public offering of limited partner units of the Partnership, Western Gas Holdings LLC (“Holdings GP”) and WGR Holdings LLC, both Anadarko affiliates, will collectively contribute the Contributed Assets to the Partnership. Holdings GP will serve as the general partner of the Partnership and together with Anadarko will provide services to the Partnership pursuant to an omnibus agreement and the service and secondment agreement between the parties.
 
On August 23, 2006 Anadarko acquired Western Gas Resources, Inc. (“Western”), including Western’s subsidiary, MIGC, and, under the purchase method of accounting, Anadarko allocated $52.4 million of the Western purchase price to MIGC. These financial statements are prepared as if MIGC was acquired by the Predecessor on August 23, 2006, the date of Anadarko’s acquisition of Western.
 
The combined financial statements of the Predecessor have been prepared in accordance with accounting principles generally accepted in the United States on the basis of Anadarko’s historical ownership of the Contributed Assets. These combined financial statements have been prepared from the separate records maintained by Anadarko and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as parent net equity, in lieu of owner’s equity, in the combined financial statements.
 
The Predecessor’s costs of doing business incurred by Anadarko on behalf of the Predecessor have been reflected in the accompanying financial statements. These costs include general and administrative expenses charged as a management services fee Anadarko to the Predecessor in exchange for:
 
Ø  business services, such as payroll, accounts payable and facilities management;
 
Ø  corporate services, such as finance and accounting, legal, human resources, investor relations and public and regulatory policy;
 
Ø  allocation of executive compensation, but not including share-based compensation; and
 
Ø  pension and other post-retirement benefit costs.
 
These financial statements should be read in conjunction with the Predecessor’s combined financial statements for the year ended December 31, 2006. These financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present the Predecessor’s results of operations and financial position. Amounts reported in the combined statement of operations are not necessarily indicative of amounts expected for the respective annual periods.


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Table of Contents

 
Notes to unaudited combined financial statements of Western Gas Partners Predecessor
 
 
2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Use of estimates
 
To conform to generally accepted accounting principles in the United States, management makes estimates and assumptions that affect the amounts reported in the combined financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience, consultation with outside advisers and other methods considered reasonable in the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results could differ. Effects on the Predecessor’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.
 
Income taxes
 
Anadarko files various United States federal and state income tax returns. Deferred federal and state income taxes are provided on all temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases as if the Predecessor filed tax returns as a stand-alone entity.
 
New accounting standards
 
The following new accounting standards were adopted by the Predecessor during the periods subsequent to June 30, 2006, and the impact of such adoption, if applicable, has been presented in the accompanying combined financial statements when appropriate:
 
FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.” FIN 48 was issued in 2006 and became effective January 1, 2007 for the Predecessor. FIN 48 defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. FIN 48 also provides guidance, among other things, on the measurement of the income tax benefit associated with uncertain tax positions, de-recognition, classification, interest and penalties and financial statement disclosures. As of the date of adoption, the Predecessor had no unrecognized tax benefits recorded. The Predecessor has elected to classify income tax interest and penalties as income tax expense.
 
Anadarko is in administrative appeals or under examination by the Internal Revenue Service for the 2000-2006 United States tax returns.
 
Recently issued accounting standards not yet adopted
 
The following new accounting standards have been issued, but as of September 30, 2007, had not yet been adopted by the Predecessor:
 
SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115.” In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for the Predecessor on January 1, 2008. The Predecessor is currently evaluating the impact of SFAS 159 on our combined results of operations, cash flows or financial position.
 
SFAS No. 157 “Fair Value Measurements.” In September 2006, the FASB issued SFAS 157, which defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures


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Table of Contents

 
Notes to unaudited combined financial statements of Western Gas Partners Predecessor
 
 
about fair value measurements. SFAS 157 does not require any new fair value measurements. However, in some cases, the application of SFAS 157 may change the Predecessor’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For the Predecessor, SFAS 157 is effective as of January 2008 and must be applied prospectively, except in certain cases. The Predecessor is currently evaluating the impact of adopting SFAS 157, and cannot currently estimate the impact of SFAS 157 on its combined results of operations, cash flows or financial position.
 
3.   ACQUISITION
 
On August 23, 2006, Anadarko completed its acquisition of Western. This transaction included MIGC, a subsidiary of Western, which was allocated a fair value of $52.4 million under the purchase method of accounting. MIGC will be contributed to the Partnership upon the closing of this offering and the Predecessor’s combined financial statements are prepared as if MIGC was acquired by the Predecessor on August 23, 2006, when Anadarko acquired Western.
 
The acquisition of MIGC is accounted for under the purchase method of accounting. The assets and liabilities of MIGC are recorded at their estimated fair value by the Predecessor as of the date of Anadarko’s acquisition of Western.
 
The following table presents the allocation of the purchase price to the MIGC assets acquired and liabilities assumed in the MIGC acquisition, as of the acquisition date:
 
         
    Allocation of
 
    purchase price  
   
    (in thousands)  
 
Current assets
    193  
Other assets
    27  
Property and equipment
    79,273  
Goodwill
    4,783  
Current liabilities
    (5,813 )
Deferred income taxes
    (24,790 )
Asset retirement obligations
    (1,283 )
         
Total purchase price
  $ 52,390  
         
 
The purchase price allocation is based on an assessment of the fair value of the MIGC assets acquired and liabilities assumed. Other assets and liabilities were recorded at their historical book values, which the Predecessor believes to represent the best estimate of fair value at the date of acquisition. The liabilities assumed included certain amounts associated with contingencies, such as legal and environmental, the fair values of which were estimated by management.
 
The following table presents selected pro forma results of operations data for the Predecessor as if the MIGC acquisition occurred on January 1, 2006:
 
       
    Nine months
    ended
    September 30,
    2006
 
    (in thousands)
 
Revenues
  $ 69,633
Operating income
  $ 22,343
Net income
  $ 10,456


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Table of Contents

 
Notes to unaudited combined financial statements of Western Gas Partners Predecessor
 
 
The pro forma information set forth above is presented for illustration purposes only and in accordance with the assumptions set forth below. The pro forma information is not necessarily indicative of the operating results that would have occurred had the acquisition been completed at the assumed date, nor is it necessarily indicative of future operating results of the combined enterprise. The pro forma adjustments include estimates and assumptions based on currently available information. Management believes that the estimates and assumptions are reasonable and that the significant effects of the transaction are properly reflected.
 
The pro forma information for 2006 is a result of combining the income statements of the Predecessor with the pre-acquisition results from January 1, 2006 of MIGC adjusted for (1) depreciation expense for MIGC property, plant and equipment, calculated by reference to the adjusted basis of the properties acquired, and (2) the related income tax effects of these adjustments based on the applicable effective rates.
 
4.   GOODWILL
 
For the third quarter of 2006, the Predecessor recognized goodwill of $4.8 million in connection with the acquisition of MIGC. None of the Predecessor’s goodwill is deductible for income tax purposes.
 
5.   TRANSACTIONS WITH AFFILIATES
 
Affiliate transactions
 
The Predecessor provides natural gas gathering, compression, treating and transportation services to Anadarko resulting in affiliate transactions. The Predecessor’s expenditures are paid through Anadarko in the form of a management services fee, which also results in affiliate transactions. Unlike transactions with third parties that settle in cash, settlement of these affiliate transactions occurs on a net basis through an adjustment to parent net equity. Anadarko also charges the Predecessor interest on the amounts settled through parent net equity. Interest is computed based on an interest rate equal to Anadarko’s weighted average cost of capital.
 
Centralized cash management
 
Anadarko operates a cash management system whereby excess cash from most of its various subsidiaries, held in separate bank accounts, is swept to a centralized account. Sales and purchases related to third-party transactions are settled in cash but are received or paid by Anadarko within the centralized cash management system and are deemed to have occurred through parent net equity.
 
Allocation of costs
 
The employees supporting the Predecessor’s operations are employees of Anadarko. The combined financial statements of the Predecessor include costs allocated by Anadarko in the form of a management fee and related to: (i) various business services, including, but not limited to, payroll, accounts payable and facilities management, (ii) various corporate services, including, but not limited to, legal, accounting, treasury, information technology and human resources and (iii) compensation, benefit, and pension and post-retirement costs. Costs were allocated to the Predecessor based on its proportionate share of Anadarko’s assets and revenues. Management believes these allocation methodologies are reasonable.


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Table of Contents

 
Notes to unaudited combined financial statements of Western Gas Partners Predecessor
 
 
 
The following table summarizes the affiliate transactions and other payments made to or received from Anadarko which are settled through parent net equity:
 
                 
    Nine months ended
 
    September 30,  
    2007     2006  
   
    (in thousands)  
 
Revenues — affiliates
  $ (76,495 )   $ (52,244 )
Operating expense — affiliates
    6,809       6,590  
Interest expense — affiliates
    6,643       7,943  
                 
Affiliate transactions
    (63,043 )     (37,711 )
                 
                 
Cash used in investing activities
    37,247       27,952  
Other third-party payments
    20,775       24,766  
                 
Third-party transactions
    58,022       52,718  
                 
                 
Net advance from (to) parent
  $ (5,021 )   $ 15,007  
                 
 
6.   COMMITMENTS AND CONTINGENCIES
 
Environmental
 
The Predecessor is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are no such matters that are expected to have a material adverse effect on the Predecessor’s results of operations, cash flows or financial position.
 
Litigation and legal proceedings
 
From time to time, the Predecessor is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which a final disposition could have a material adverse effect on the Predecessor’s results of operations, cash flows or financial position.
 
7.  PENSION PLANS, OTHER POSTRETIREMENT AND EMPLOYEE SAVINGS PLANS
 
The Predecessor does not sponsor any pension, postretirement or employee savings plans. However, the Predecessor participates in certain plans sponsored by Anadarko, including Anadarko’s qualified and supplemental non-contributory defined benefit pension plans. In addition, Anadarko also provides certain health care and life insurance benefits for retired employees. Anadarko also sponsors, and the predecessor participates in, an employee defined contribution savings plan that matches a portion of each employee’s contribution.
 
Pension, postretirement and employee savings plan costs included in the management services fee charged to the Predecessor by Anadarko were approximately $175,000 and $175,000 for the nine month periods ended September 30, 2007 and 2006, respectively.


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MIGC, Inc.
 
 
Report of independent registered public accounting firm
 
The Board of Directors
Anadarko Petroleum Corporation:
 
We have audited the accompanying balance sheet of MIGC, Inc. (the “Company”) as of December 31, 2005, and the related statements of income, parent net equity, and cash flows for the period from January 1, 2006 through August 23, 2006 and for the year ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2005, and its results of operations and cash flows for the period from January 1, 2006 through August 23, 2006 and for the year ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
 
/s/ KPMG LLP
 
Denver, Colorado
October 11, 2007


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MIGC, Inc.
 
 
 
Statements of income
 
                 
    January 1,
       
    2006
    For the
 
    through
    year ended
 
    August 23,
    December 31,
 
    2006     2005  
   
    (in thousands)  
 
Revenues
               
Transportation of natural gas — affiliates
  $ 7,583     $ 11,887  
Transportation of natural gas — third parties
    3,427       5,111  
Sale of natural gas — third parties
    1,039        
Other — affiliates
    103       161  
                 
Total revenues
    12,152       17,159  
                 
Operating expenses — third parties
               
Cost of product
          703  
Operation and maintenance
    2,592       5,517  
General and administrative
    1,305       1,247  
Depreciation
    918       631  
                 
Total operating expenses
    4,815       8,098  
                 
Operating Income
    7,337       9,061  
                 
Interest (income) — affiliates
    (574 )     (526 )
Other expense
    351       986  
                 
Income Before Income Taxes
    7,560       8,601  
Income Tax Expense
    2,647       3,011  
                 
Net Income
  $ 4,913     $ 5,590  
                 
 
See the accompanying notes to the financial statements.


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MIGC, Inc.
 
 
Balance sheet
 
         
    December 31,
 
    2005  
   
    (in thousands)  
 
Current Assets
       
Cash
  $  
Accounts receivable
    523  
Accounts receivable — affiliates
    42,659  
         
Total current assets
    43,182  
Other assets
    81  
Property, Plant and Equipment
       
Cost
    46,121  
Less accumulated depreciation
    (17,389 )
         
Net property, plant and equipment
    28,732  
         
Total Assets
  $ 71,995  
         
Current Liabilities
       
Accounts payable
  $ 58  
Natural gas imbalance payables
    1,944  
Natural gas imbalance payable — affiliates
    846  
Accrued ad valorem taxes
    318  
Income taxes payable
    3,118  
Accrued expenses — other
    61  
         
Total current liabilities
    6,345  
Long-term Liabilities
       
Deferred income taxes
    3,643  
Asset retirement obligations
    1,233  
         
Total long-term liabilities
    4,876  
         
Total Liabilities
    11,221  
Parent Net Equity
    60,774  
Commitments and Contingencies (see Note 8)
     
         
Total Liabilities and Parent Net Equity
  $ 71,995  
         
 
See the accompanying notes to the financial statements.


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MIGC, Inc.
 
 
Statements of cash flows
 
                 
    January 1,
       
    2006
    For the year
 
    through
    ended
 
    August 23,
    December 31,
 
    2006     2005  
   
    (in thousands)  
 
Cash Flow from Operating Activities
               
Net income
  $ 4,913     $ 5,590  
Adjustments to reconcile net income to net cash used in operating activities:
               
Depreciation
    918       631  
Deferred income taxes
    (67 )     (107 )
Changes in assets and liabilities:
               
Decrease in accounts receivable
    329       354  
Increase in accounts receivable — affiliates
    (6,206 )     (14,749 )
Increase in accounts payable and accrued expenses
    252       1,824  
Increase (decrease) in natural gas imbalances — affiliates
    (784 )     846  
Increase in other items, net
    104       17  
                 
Net cash used in operating activities
    (541 )     (5,594 )
                 
Cash Flow from Investing Activities
               
Retirements of property, plant and equipment, net
    541       5,594  
                 
Cash provided by investing activities
    541       5,594  
                 
Cash Flow from Financing Activities
           
                 
Net Change in Cash
           
                 
Cash at Beginning of Period
           
                 
Cash at End of Period
  $     $  
                 
 
See the accompanying notes to the financial statements.


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MIGC, Inc.
 
 
Statements of parent net equity
 
       
    Parent net
    equity
 
    (in thousands)
 
Balance, January 1, 2005
  $ 55,184
       
Net income
    5,590
       
Balance, December 31, 2005
    60,774
       
Net income
    4,913
       
Balance, August 23, 2006
  $ 65,687
       
 
See the accompanying notes to the financial statements.


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MIGC, Inc.
 
Notes to financial statements
 
1.   DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
 
These financial statements of MIGC, Inc. (“MIGC” or the “Company”) have been prepared in connection with the proposed initial public offering of limited partner units of Western Gas Partners, LP (the “Partnership”), which was formed on August 21, 2007 and will own the operations and assets of the Company upon the closing of this offering. On August 23, 2006, Anadarko Petroleum Corporation acquired Western Gas Resources, Inc. (“Western”). This transaction included the assets of the Company. The Company was a wholly owned subsidiary of Western for the periods presented in these financial statements. For purposes of these financial statements, “Anadarko” refers to Anadarko Petroleum Corporation and its consolidated subsidiaries.
 
As part of the initial public offering of limited partnership units of the Partnership, Western Gas Holdings, LLC (“Holdings GP”) and WGR Holdings, LLC, both Anadarko affiliates, will collectively contribute MIGC, along with certain other assets, to the Partnership. Holdings GP will serve as the general partner of the Partnership and together with Anadarko will provide services to the Partnership pursuant to an omnibus agreement and a services and secondment agreement between the parties.
 
MIGC owns a 264-mile natural gas interstate pipeline located in the Powder River Basin of Wyoming. MIGC charges a Federal Energy Regulatory Commission (“FERC”) approved tariff and earns revenues through firm contracts that obligate its customers to pay a monthly reservation or demand charge, which is a fixed charge applied to firm contract capacity and owed by a customer regardless of the pipeline capacity used by that customer. When a customer uses the capacity it has reserved under these contracts, MIGC is entitled to collect an additional commodity usage charge based on the actual volume of natural gas transported. These usage charges are typically a small percentage of the total revenues received from firm capacity contracts. Revenues are also generated from interruptible contracts pursuant to which a fee is charged by MIGC to the customer based upon volumes transported through the pipeline.
 
Western maintained a centralized treasury function wherein individual cash accounts maintained by the Company were swept to a Western corporate account, creating an intercompany receivable between Western and the Company. Therefore, the Company’s balance sheet reflects no cash balance.
 
The Company’s financial statements have been prepared in accordance with United States generally accepted accounting principles on the basis of the Company’s ownership of the assets that will be contributed to the Partnership. These financial statements have been prepared from the separate records maintained by the Company and may not necessarily be indicative of the actual results of operations that would have occurred if the Company had been separately operated during those periods. Net investment in the Company is shown as parent net equity, in lieu of owner’s equity in the combined financial statements.
 
The Company’s costs of doing business have been reflected in the financial statements of the Company for the periods presented. These costs, which include direct costs and allocations, were calculated and then directly charged to the Company for:
 
Ø  business services, such as payroll, accounts payable and facilities management; and
 
Ø  corporate services, such as finance and accounting, legal, human resources, investor relations, public and regulatory policy and senior executives.
 
Transactions between the Company and Western or Western’s affiliates are described in the financial statements as transactions between affiliates (see Note 3). In the opinion of management, the assumptions underlying the financial statements are reasonable.


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Notes to financial statements of MIGC, Inc.
 
 
2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
Use of estimates
 
To conform to generally accepted accounting principles in the United States, management makes estimates and assumptions that affect the amounts reported in the financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historic experience, consultation with outside advisers and other methods considered reasonable under certain circumstances. Although these estimates are based on management’s best available knowledge at the time, actual results could differ. Effects on the Company’s business, financial position or results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.
 
Property, plant and equipment
 
Property, plant and equipment are stated at the lower of historical cost, less accumulated depreciation or fair value, if impaired. The Company capitalizes all construction-related direct labor and material costs. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.
 
Asset retirement obligations
 
The Company recognizes a liability based on estimated costs of retiring tangible long-lived assets. The liability is recognized at the fair value of the asset retirement obligation when the obligation is incurred, which generally is when the asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with corresponding adjustments to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled.
 
Long-lived asset impairment
 
The Company evaluates whether long-lived assets have been impaired when circumstances indicate the carrying amount of those assets may not be recoverable. For such long-lived assets, impairment exists when the carrying amount exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence. If the carrying amount of the long-lived asset is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying amount over its fair value, such that the asset’s carrying amount is adjusted to its estimated fair value.
 
Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one source in making such a determination. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset or a change in management’s intent to utilize the asset would generally require management to re-assess the cash flows related to the long-lived assets.


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Notes to financial statements of MIGC, Inc.
 
 
Natural gas imbalances
 
The Company’s balance sheet includes a natural gas imbalance payable as a result of differences in gas volumes received and delivered for customers. Natural gas volumes owed to or by the Company are subject to FERC tariffs, valued at market index prices as of the balance sheet date and subject to cash settlement procedures.
 
Environmental expenditures
 
The Company expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are probable and may be reasonably estimated.
 
Revenue recognition
 
Revenues for the transportation of natural gas are recognized when the service is provided. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before FERC and reserves are established where appropriate. During the periods presented herein, there were no pending rate cases, and no related reserves have been established.
 
Income taxes
 
The Company files a United States federal tax return. Deferred federal income taxes are provided on all temporary differences between the financial statement carrying amounts of recognized assets and liabilities and their respective tax bases.
 
New accounting standards
 
The following new accounting standard was adopted by the Company for the period from January 1, 2006 through August 23, 2006:
 
FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations.” In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS 143. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS 143 if the fair value of the liability can be reasonably estimated. The adoption of FIN 47 did not have an impact on the Company’s results of operations, cash flows or financial position.
 
Recently issued accounting standards not yet adopted
 
FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109.” FIN 48 was issued in 2006 and became effective January 1, 2007 for the Company. FIN 48 defines the criteria an individual tax position must meet for any part of the benefit of that position to be recognized in the financial statements. FIN 48 also provides guidance on the measurement of the income tax benefit associated with uncertain tax positions, de-recognition, classification, interest and penalties and financial statement disclosures. The Company does not expect the adoption of FIN 48 to have a material impact on its financial statements.


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Notes to financial statements of MIGC, Inc.
 
 
3.   TRANSACTIONS WITH AFFILIATES
 
The Company provides natural gas transportation services to Western and its affiliates. The Company’s costs of doing business have been reflected in the financial statements of the Company for the periods presented. These costs include, but are not limited to, legal, accounting, treasury, information technology and human resources. These costs were calculated based on the cost of actual services provided and directly charged to the Company. Management believes the allocations upon which these charges are based to be reasonable; however, these estimates and allocations may not represent the amounts that would have been incurred had the Company operated as a separate entity and contracted with third parties for these services.
 
It is the Company’s policy that all transactions entered into between the Company and its affiliates be carried out in the ordinary course of business and on terms comparable to terms that could reasonably be obtained from third parties.
 
Advances made by or to the Company are carried as interest-bearing accounts receivable or accounts payable and are classified as current assets and current liabilities, respectively. Increases in advances to the Company generally result from advances made by Western to the Company in connection with funding for operations and capital expenditures. Decreases in advances to the Company generally result from crediting, against advances made by Western to the Company, (1) amounts owed by Western to the Company for services rendered, and (2) the amount of cash which is swept from the Company’s bank account to a Western corporate account, in accordance with Western’s cash management policy.
 
4.   INCOME TAXES
 
Components of income tax expense are as follows:
 
                 
    January 1,
       
    2006
       
    through
    Year ended
 
    August 23,
    December 31,
 
    2006     2005  
   
    (in thousands)  
 
Current income taxes
               
Federal
  $ 2,714     $ 3,118  
                 
Total current income taxes
    2,714       3,118  
                 
Deferred income taxes
               
Federal
    (67 )     (107 )
                 
Total deferred income taxes
    (67 )     (107 )
                 
Total income tax expense
  $ 2,647     $ 3,011  
                 


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Notes to financial statements of MIGC, Inc.
 
 
Total income taxes differed from the amounts computed by applying the statutory income tax rate to “Income before income taxes.” The sources of these differences are as follows:
 
                 
    January 1,
       
    2006
       
    through
    Year ended
 
    August 23,
    December 31,
 
    2006     2005  
   
    (in thousands)  
 
Income before income taxes
  $ 7,560     $ 8,601  
Income tax expense, computed at the statutory rate of 35%
    2,646       3,010  
Adjustments resulting from:
               
Other items
    1       1  
                 
Total income tax expense
  $ 2,647     $ 3,011  
                 
Effective tax rate
    35.01 %     35.01 %
                 
 
The tax effects of temporary differences that give rise to the deferred tax liability at December 31, 2005 is as follows:
 
         
    December 31,
 
    2005  
   
    (in thousands)  
 
Depreciable properties
  $ (3,643 )
         
Total deferred income tax liability
  $ (3,643 )
         
 
5.   CONCENTRATION OF CREDIT RISK
 
The customers that individually accounted for 10% or more of revenues for the period from January 1, 2006 through August 23, 2006 and year ended December 31, 2005, are as follows:
 
             
    Percent of revenues
    January 1,
   
    2006
   
    through
  Year ended
    August 23,
  December 31,
Customer   2006   2005
 
 
Western
    63%     70%
Williams Production RMT Company
    27%     30%
Other
    10%     —%
             
Total
    100%     100%
             
 
Total revenues were approximately $12.2 million and $17.2 million for the period from January 1, 2006 through August 23, 2006 and for the year ended December 31, 2005, respectively. Western, an affiliate of the Company, and Williams Production RMT Co., a non-affiliate of the Company, were the only customers that separately accounted for greater than 10% of the Company’s revenues for the period from January 1, 2006 through August 23, 2006 and for the year ended December 31, 2005.
 
Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of accounts receivable. Where exposed to credit risk, the Company (1) analyzes the


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Notes to financial statements of MIGC, Inc.
 
 
counterparties’ financial condition prior to entering into an agreement, (2) establishes credit limits and (3) monitors the appropriateness of those credit limits on an ongoing basis. The Company maintains no credit policy with respect to Western and its subsidiaries.
 
6.   PROPERTY, PLANT AND EQUIPMENT
 
A summary of the historical cost of the Company’s property, plant and equipment is as follows:
 
               
    Estimated
     
    useful life
  December 31,
 
    (years)   2005  
   
    (in thousands, except for estimated useful life)  
 
Pipeline and equipment
    33 to 49   $ 45,651  
General plant and other
    3 to 10     470  
               
Total property, plant and equipment
          46,121  
Total accumulated depreciation
          (17,389 )
               
Total net property, plant and equipment
        $ 28,732  
               
 
The Company generally calculates depreciation using the straight-line method, based on estimated useful lives and salvage values of assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are placed into service, the Company makes estimates with respect to estimated useful lives and salvage values that it believes to be reasonable. However, subsequent events may cause a change in estimate, thereby impacting the future depreciation amounts.
 
7.   ASSET RETIREMENT OBLIGATIONS
 
The Company’s asset retirement obligations are related to the capping and dismantling of its pipeline and equipment. The liability for asset retirement obligations is initially recorded at estimated fair value, with an offsetting increase to properties and equipment. Accretion expense is recognized over the estimated productive life of the related assets, increasing the liability to its expected settlement value. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded for both the asset retirement obligation and the asset retirement cost.
 
The following table provides a rollforward of the Company’s asset retirement obligations. Liabilities settled include, among other things, asset retirement obligations that were assumed by purchasers of divested properties.
 
         
    Year ended
 
    December 31,
 
    2005  
   
    (in thousands)  
 
Carrying amount of asset retirement obligations at beginning of year
  $ 1,204  
Liabilities transferred
    (45 )
Accretion expense
    74  
         
Carrying amount of asset retirement obligations at end of year
  $ 1,233  
         


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Notes to financial statements of MIGC, Inc.
 
 
8.   COMMITMENTS AND CONTINGENCIES
 
Environmental
 
The Company is subject to federal, state and local regulations governing air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are no such matters that are expected to have a material adverse effect on the Company’s results of operations, cash flows or financial position.
 
Litigation and legal proceedings
 
From time to time, the Company is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding for which a final disposition could have a material adverse effect on the Company’s results of operations, cash flows or financial position.
 
Obligations and commitments
 
The following is a summary of the Company’s future payment obligations as of December 31, 2005:
 
                               
    Obligations by Period
        2-3
  4-5
  Later
   
    1 Year   Years   Years   Years   Total
 
    (in thousands)
 
Operating leases
  $ 170   $ 120   $  —   $  —   $ 290
Transportation agreements
    5,678     3,782             9,460
                               
    $ 5,848   $ 3,902   $  —   $  —   $ 9,750
                               
 
Operating leases
 
The Company entered into various agreements to obtain access to compressors. Rent expense related to compressor equipment leases was $99,919 and $367,359 for the period from January 1, 2006 through August 23, 2006 and the year ended December 31, 2005, respectively. There are no future minimum lease obligations or payments beyond December 31, 2008.
 
Transportation agreements
 
The Company entered into various transportation agreements with interstate pipeline companies in order to access downstream markets. Rent expense for leased capacity on third-party pipelines was $26,226 and $36,000 for the period from January 1, 2006 through August 23, 2006 and the year ended December 31, 2005, respectively. The table above includes future payments under these transportation commitments of $9.46 million for all future years beyond 2005.


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Western Gas Partners, LP
 
Report of independent registered public accounting firm
 
The Board of Directors
Anadarko Petroleum Corporation:
 
We have audited the accompanying balance sheet of Western Gas Partners, LP (the “Partnership”) as of August 21, 2007. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.
 
In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of the Partnership as of August 21, 2007, in conformity with U.S. generally accepted accounting principles.
 
/s/ KPMG LLP
 
Houston, Texas
October 11, 2007


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Western Gas Partners, LP
 
 
Balance sheet
 
         
    August 21, 2007  
   
 
Assets
       
Total Assets
  $  
         
Partners’ Equity
       
Limited partner equity
  $ 2,940  
General partner equity
    60  
Less receivables from WGR Asset Holding Company, LLC and Western Gas Holdings, LLC
    (3,000 )
         
Total Partners’ Equity
  $  
         
 
See the accompanying note to the balance sheet.


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Table of Contents

Western Gas Partners, LP
 
 
Note to the balance sheet
 
1.   NATURE OF OPERATIONS
 
Western Gas Partners, LP (the “Partnership”) is a Delaware limited partnership formed on August 21, 2007 and will acquire the assets owned by Anadarko Gathering Company, Pinnacle Gas Treating, Inc. and MIGC, Inc.
 
Western Gas Holdings, LLC (“Holdings GP”), as general partner, contributed $60 and WGR Asset Holding Company, LLC (“WGR Asset Holdings”) contributed $2,940, all in the form of receivables, to the Partnership on August 21, 2007. The receivables from Holdings GP and WGR Asset Holdings have been reflected as a reduction to Partners’ Equity on the accompanying balance sheet.
 
On September 11, 2007, WGR Asset Holdings transferred 100% of its interest in the Partnership to WGR Holdings, LLC (“Holdings LP”). There have been no other transactions involving the Partnership.
 
The Partnership will issue common and subordinated units, each representing limited partner interests in the Partnership, to Holdings LP and has issued a 2.0% general partner interest in the Partnership to Holdings GP. The Partnership also intends to issue and sell common units to the public in connection with its initial public offering.


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Western Gas Holdings, LLC
 
 
Report of independent registered public accounting firm
 
The Board of Directors
Anadarko Petroleum Corporation:
 
We have audited the accompanying balance sheet of Western Gas Holdings, LLC (the “Company”) as of August 21, 2007. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.
 
In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of the Company as of August 21, 2007, in conformity with U.S. generally accepted accounting principles.
 
/s/ KPMG LLP
 
Houston, Texas
October 11, 2007


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Western Gas Holdings, LLC
 
 
Balance sheet
 
         
    August 21, 2007  
   
 
Assets
       
Investment in Western Gas Partners, LP
  $ 60  
         
Total Assets
  $ 60  
         
Liabilities and Member’s Equity
       
Payable to Western Gas Partners, LP
  $ 60  
Member’s Equity
       
Member equity
    1,000  
Less receivable from WGR Asset Holding Company, LLC
    (1,000 )
         
Total member equity
     
         
Total Liabilities and Member’s Equity
  $ 60  
         
 
See the accompanying note to the balance sheet.


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Western Gas Holdings, LLC
 
 
Note to the balance sheet
 
1.   NATURE OF OPERATIONS
 
Western Gas Holdings, LLC (the “Company”), is a limited liability company formed on August 21, 2007 to become the general partner of Western Gas Partners, LP (the “Partnership”). The Company owns a 2.0% general partner interest in the Partnership.
 
WGR Asset Holding Company, LLC (“WGR Asset Holdings”), as sole member, contributed $1,000, in the form of a receivable, to the Company on August 21, 2007 in exchange for a 100% membership interest. On August 21, 2007, the Company contributed $60, in the form of a receivable, to the Partnership in exchange for a 2.0% general partner interest in the Partnership.
 
The receivable from WGR Asset Holdings has been reflected as a reduction of Member Equity on the accompanying balance sheet. There have been no other transactions involving the Company.


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Appendix A
 
Amended and restated
agreement of limited partnership
of Western Gas Partners, LP


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Table of Contents

 
Appendix B
 
 
Glossary of terms
 
adjusted operating surplus:  For any period, operating surplus generated during that period is adjusted to:
 
(a)  increase operating surplus by any net decreases made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period;
 
(b)  decrease operating surplus by any net reduction in cash reserves for operating expenditures during that period not relating to an operating expenditure made during that period; and
 
(c)  increase operating surplus by any net increase in cash reserves for operating expenditures during that period required by any debt instrument for the repayment of principal, interest or premium.
 
Adjusted operating surplus does not include the portion of operating surplus described in subpart (a)(2) of the definition of “operating surplus” in this Appendix B.
 
available cash:   For any quarter ending prior to liquidation:
 
(a)  the sum of:
 
(1)  all cash and cash equivalents of Western Gas Partners, LP and its subsidiaries on hand at the end of that quarter; and
 
(2)  if our general partner so determines all or a portion of any additional cash or cash equivalents of Western Gas Partners, LP and its subsidiaries on hand on the date of determination of available cash for that quarter;
 
(b)  less the amount of cash reserves established by our general partner to:
 
(1)  provide for the proper conduct of the business of Western Gas Partners, LP and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Western Gas Partners, LP and its subsidiaries) after that quarter;
 
(2)  comply with applicable law or any debt instrument or other agreement or obligation to which Western Gas Partners, LP or any of its subsidiaries is a party or its assets are subject; and
 
(3)  provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;
 
provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.
 
backhaul:  Refers to pipeline transportation service in which the nominated gas flow from receipt point to delivery point is in the opposite direction as the pipeline’s physical gas flow.
 
Bbls:  Barrels.
 
Bcf/d:  One billion cubic feet per day.
 
capital account:   The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common


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Glossary of terms
 
 
unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Western Gas Partners, LP held by a partner.
 
capital surplus:  All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus from the closing of the initial public offering through the end of the quarter immediately preceding that distribution. Any excess available cash distributed by us on that date will be deemed to be capital surplus.
 
closing price:  The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by the our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.
 
condensate:  A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions.
 
cumulative common unit arrearage:  The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.
 
current market price:  For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.
 
drilling location inventory:  The estimated number of potential drilling locations within a given exploration area.
 
dry gas:  A gas primarily composed of methane and ethane where heavy hydrocarbons and water either do not exist or have been removed through processing.
 
end-use markets:  The ultimate users/consumers of transported energy products.
 
forward-haul:  Refers to pipeline transportation service in which the nominated gas flow from receipt point to delivery point is in the same direction as the pipeline’s physical gas flow.
 
interim capital transactions:  The following transactions if they occur prior to liquidation:
 
(a)  borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for items purchased on open account in the ordinary course of business) by Western Gas Partners, LP or any of its subsidiaries;
 
(b)  sales of equity interests by Western Gas Partners, LP or any of its subsidiaries;
 
(c)  sales or other voluntary or involuntary dispositions of any assets of Western Gas Partners, LP or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);
 
(d)  the termination of interest rate swap agreements;


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Glossary of terms
 
 
(e)  capital contributions; and
 
(f)  corporate reorganizations or restructurings.
 
long ton:  A British unit of weight equivalent to 2,240 pounds.
 
LTD:  One long ton per day.
 
MMBtu:  One million British Thermal Units.
 
MMBtu/d:  One million British Thermal Units per day.
 
MMcf:  One million cubic feet of natural gas.
 
MMcf/d:  One million cubic feet per day.
 
NGLs:  Natural gas liquids. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
 
operating expenditures: All of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner, reimbursement of expenses to Anadarko for services pursuant to the omnibus agreement or personnel provided to us under the services and secondment agreement, payments made in the ordinary course of business under interest rate swap agreements or commodity hedge contracts, manager and officer compensation, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures, provided that operating expenditures will not include:
 
  •  repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus below when such repayment actually occurs;
 
  •  payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;
 
  •  expansion capital expenditures;
 
  •  actual maintenance capital expenditures;
 
  •  investment capital expenditures;
 
  •  payment of transaction expenses relating to interim capital transactions;
 
  •  distributions to our partners (including distributions in respect of Class B units and our incentive distribution rights); or
 
  •  non-pro rata purchases of units of any class made with the proceeds of a substantially concurrent equity issuance.
 
operating surplus: Operating surplus consists of:
 
  •  $27.1 million (as described below); plus
 
  •  all of our cash receipts after the closing of this offering, excluding cash from the following:
 
  •  borrowings that are not working capital borrowings and sales of debt securities,
 
  •  sales of equity securities,
 
  •  sales or other dispositions of assets outside the ordinary course of business,
 
  •  the termination of interest rate swap agreements or commodity hedge contracts prior to the termination date specified herein,
 
  •  capital contributions received, and
 
  •  corporate reorganizations or restructurings; plus


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Glossary of terms
 
 
 
  •  working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus
 
  •  cash distributions paid on equity issued to finance all or a portion of the construction, improvement or replacement of a capital improvement or capital asset (such as equipment or facilities) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service or the date that it is abandoned or disposed of; less
 
  •  our operating expenditures (as defined above) after the closing of this offering; less
 
  •  the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less
 
  •  all working capital borrowings not repaid within twelve months after having been incurred.
 
play:  A proven geological formation that contains commercial amounts of petroleum and/or natural gas.
 
psia:  Pounds per square inch, absolute.
 
receipt point:  The point where production is received by or into a gathering system or transportation pipeline.
 
residue gas:  The natural gas remaining after being processed or treated.
 
sour gas:  Gas containing more than four parts per million of hydrogen sulfide.
 
tailgate:  Refers to the point at which processed natural gas and/or natural gas liquids leave a processing facility for end-use markets.
 
Tcf:  One trillion cubic feet of natural gas.
 
wellhead:  The equipment at the surface of a well used to control the well’s pressure; the point at which the hydrocarbons and water exit the ground.


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(WESTERN GAS PARTNERS LOGO)
 
 
Through and including          , 2008 (the 25th day after the date of this prospectus), federal securities law may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus, This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
 


Table of Contents

 
Part II
 
 
Information required in the registration statement
 
ITEM 13.   OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
 
Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the amounts set forth below are estimates.
 
         
SEC registration fee
  $ 13,920  
FINRA filing fee
    45,781  
Printing and engraving expenses
       
Fees and expenses of legal counsel
       
Accounting fees and expenses
       
Transfer agent and registrar fees
       
New York Stock Exchange listing fee
       
Miscellaneous
       
         
Total
  $ 3,000,000  
         
 
ITEM 14.   INDEMNIFICATION OF OFFICERS AND MEMBERS OF OUR BOARD OF DIRECTORS.
 
The section of the prospectus entitled “The partnership agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section           of the underwriting agreement to be filed as an exhibit to this registration statement in which we and our general partner will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.
 
ITEM 15.   RECENT SALES OF UNREGISTERED SECURITIES.
 
On August 21, 2007, in connection with the formation of Western Gas Partners, LP (the “Partnership”), the Partnership issued to (i) its general partner the 2.0% general partner interest in the Partnership for $60 and (ii) WGR Asset Holding Company LLC the 98.0% limited partner interest in the Partnership for $2,940. The 98.0% limited partner in trust was subsequently contributed to WGR Holdings, LLC on September 11, 2007. The issuance and contribution were exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.


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Table of Contents

 
Part II
 
 
ITEM 16.   EXHIBITS.
 
The following documents are filed as exhibits to this registration statement:
 
                 
Exhibit
       
number       Description
 
 
  1 .1*         Form of Underwriting Agreement
  3 .1**         Certificate of Limited Partnership of Western Gas Partners, LP
  3 .2*         Amended and Restated Limited Partnership Agreement of Western Gas Partners, LP (included as Appendix A in the prospectus included in this Registration Statement)
  3 .3**         Certificate of Formation of Western Gas Holdings, LLC
  3 .4*         Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC
  5 .1*         Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
  8 .1*         Opinion of Vinson & Elkins L.L.P. relating to tax matters
  10 .1*         Form of Credit Agreement
  10 .2*         Form of Omnibus Agreement
  10 .3*         Form of Services and Secondment Agreement
  10 .4†         Dew Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation
  10 .5†         Haley Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation
  10 .6†         Hugoton Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation
  10 .7†         Pinnacle Gas Gathering Agreement between Pinnacle Gas Treating LLC and Anadarko Petroleum Corporation
  10 .8*         Form of Working Capital Facility
  10 .9*         Form of Contribution, Conveyance and Assumption Agreement
  10 .10*         Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors
  10 .11*         Long-Term Incentive Plan
  10 .12*         Form of Tax Sharing Agreement
  10 .13         Revolving Credit Agreement, dated as of September 1, 2004, by and among Anadarko Petroleum Corporation, Anadarko Canada Corporation, JPMorgan Chase Bank, JPMorgan Chase Bank, Toronto Branch, ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch, Harris Nesbitt Financing, Inc. and Credit Suisse First Boston, and each of the Lenders named therein.
  10 .14         First Amendment to Revolving Credit Agreement, dated as of August 31, 2006, by and among Anadarko Petroleum Corporation, Anadarko Canada Corporation, JPMorgan Chase Bank, N.A., JPMorgan Chase Bank, N.A., Toronto Branch, ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch, BMO Capital Markets Financing, Inc. and Credit Suisse, Cayman Islands Branch, and each of the Lenders named therein.
  10 .15         Second Amendment to Revolving Credit Agreement, dated as of December 14, 2007, by and among Anadarko Petroleum Corporation, Western Gas Partners LP, JPMorgan Chase Bank, N.A., ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch, BMO Capital Markets Financing, Inc., and Credit Suisse, Cayman Islands Branch, and each of the Lenders named therein.
  21 .1*         List of Subsidiaries of Western Gas Partners, LP


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Table of Contents

 
Part II
 
 
                 
Exhibit
       
number       Description
 
 
  23 .1         Consent of KPMG LLP
  23 .2         Consent of KPMG LLP
  23 .3         Consent of KPMG LLP
  23 .4*         Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
  23 .5*         Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
  24 .1**         Powers of Attorney
 
 
* To be filed by amendment.
 
** Previously filed.
 
Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
 
ITEM 17.   UNDERTAKINGS.
 
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
 
The undersigned registrant hereby undertakes that:
 
(1)  For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
 
(2)  For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
 
The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Anadarko or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to Anadarko or its subsidiaries for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
 
The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.


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Table of Contents

 
Signatures
 
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this amendment to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on December 26, 2007.
 
WESTERN GAS PARTNERS, LP
 
  By:  Western Gas Holdings, LLC,
its general partner
 
  By: 
/s/  Robert G. Gwin
Name:     Robert G. Gwin
  Title:  President, Chief Executive Officer and Director
 
Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.
 
             
Signature   Title   Date
 
 
/s/  Robert G. Gwin

Robert G. Gwin
  President, Chief Executive Officer and Director   December 26, 2007
         
*

Danny J. Rea
  Senior Vice President, Chief Operating Officer and Director   December 26, 2007
         
/s/  Michael C. Pearl

Michael C. Pearl
  Senior Vice President, Chief Financial Officer and Chief Accounting Officer   December 26, 2007
         
*

R. A. Walker
  Chairman of the Board and Director   December 26, 2007
         
*

Karl F. Kurz
  Director   December 26, 2007
         
*

Robert K. Reeves
  Director   December 26, 2007
             
*By:  
/s/  Robert G. Gwin

Robert G. GwinAttorney-in-fact
       


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Table of Contents

 
Exhibit index
 
             
Exhibit
       
number       Description
 
 
  1 .1*     Form of Underwriting Agreement
  3 .1**     Certificate of Limited Partnership of Western Gas Partners, LP
  3 .2*     Amended and Restated Limited Partnership Agreement of Western Gas Partners, LP (included as Appendix A in the prospectus included in this Registration Statement)
  3 .3**     Certificate of Formation of Western Gas Holdings, LLC
  3 .4*     Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC
  5 .1*     Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
  8 .1*     Opinion of Vinson & Elkins L.L.P. relating to tax matters
  10 .1*     Form of Credit Agreement
  10 .2*     Form of Omnibus Agreement
  10 .3*     Form of Services and Secondment Agreement
  10 .4†     Dew Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation
  10 .5†     Haley Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation
  10 .6†     Hugoton Gas Gathering Agreement between Anadarko Gathering Company LLC and Anadarko Petroleum Corporation
  10 .7†     Pinnacle Gas Gathering Agreement between Pinnacle Gas Treating LLC and Anadarko Petroleum Corporation
  10 .8*     Form of Working Capital Facility
  10 .9*     Form of Contribution, Conveyance and Assumption Agreement
  10 .10*     Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors
  10 .11*     Long-Term Incentive Plan
  10 .12*     Form of Tax Sharing Agreement
  10 .13     Revolving Credit Agreement, dated as of September 1, 2004, by and among Anadarko Petroleum Corporation, Anadarko Canada Corporation, JPMorgan Chase Bank, JPMorgan Chase Bank, Toronto Branch, ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch, Harris Nesbitt Financing, Inc. and Credit Suisse First Boston, and each of the Lenders named therein.
  10 .14     First Amendment to Revolving Credit Agreement, dated as of August 31, 2006, by and among Anadarko Petroleum Corporation, Anadarko Canada Corporation, JPMorgan Chase Bank, N.A., JPMorgan Chase Bank, N.A., Toronto Branch, ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch, BMO Capital Markets Financing, Inc. and Credit Suisse, Cayman Islands Branch, and each of the Lenders named therein.
  10 .15     Second Amendment to Revolving Credit Agreement, dated as of December 14, 2007, by and among Anadarko Petroleum Corporation, Western Gas Partners LP, JPMorgan Chase Bank, N.A., ABN AMRO Bank N.V. and Deutsche Bank AG New York Branch, BMO Capital Markets Financing, Inc., and Credit Suisse, Cayman Islands Branch, and each of the Lenders named therein.
  21 .1*     List of Subsidiaries of Western Gas Partners, LP
  23 .1     Consent of KPMG LLP
  23 .2     Consent of KPMG LLP
  23 .3     Consent of KPMG LLP
  23 .4*     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
  23 .5*     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
  24 .1**     Powers of Attorney
 
 
* To be filed by amendment.
 
** Previously filed.
 
Portions of this exhibit have been omitted pursuant to a request for confidential treatment.


II-5