424B4 1 d23608b4e424b4.htm WILLIAMS PARTNERS L.P. e424b4
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PROSPECTUS
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-124517 and 333-127655
(WILLIAMS PARTNERS L.P. LOGO)
5,000,000 Common Units
Representing Limited Partner Interests
 
We are a limited partnership recently formed by The Williams Companies, Inc. This is the initial public offering of our common units. The common units have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol “WPZ.”
Investing in our common units involves risks. Please read “Risk Factors” beginning on page 15.
These risks include the following:
  •  We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of natural gas supply, which is dependent on factors beyond our control, including Discovery’s ability to complete its Tahiti lateral expansion project. Any decrease in supplies of natural gas could adversely affect our business and operating results.
 
  •  Our processing, fractionation and storage businesses could be affected by any decrease in the price of natural gas liquids or a change in the price of natural gas liquids relative to the price of natural gas.
 
  •  Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.
 
  •  Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.
 
  •  Even if unitholders are dissatisfied, they cannot initially remove our general partner without its consent.
 
  •  You will experience immediate and substantial dilution of $6.07 per common unit.
 
  •  You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
                 
    Per Common Unit   Total
         
Initial public offering price
  $ 21.50     $ 107,500,000  
Underwriting discount (1)
  $ 1.37     $ 6,850,000  
Proceeds to Williams Partners L.P. (before expenses)
  $ 20.13     $ 100,650,000  
 
(1)  Excludes structuring fees of $403,125.
The selling unitholders have granted the underwriters a 30-day option to purchase up to an additional 750,000 common units from them on the same terms and conditions as set forth above if the underwriters sell more than 5,000,000 common units in this offering. We will not receive any proceeds from any common units to be sold by the selling unitholders upon any exercise of the underwriters’ option to purchase additional common units.
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.
Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about August 23, 2005.
 
Lehman Brothers
  Citigroup
  RBC Capital Markets
  Wachovia Securities
August 17, 2005


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(ENERGY SERVICES)

 


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      You should rely only on the information contained in this prospectus. We have not, and the underwriters and selling unitholders 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 and selling unitholders are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.
      Until September 12, 2005 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
      References in this prospectus to “Williams Partners L.P.,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the assets of The Williams Companies, Inc. and its subsidiaries that are being contributed to Williams Partners L.P. and its subsidiaries in connection with this offering. When used in the present tense or prospectively, those terms refer to Williams Partners L.P. and its subsidiaries. In either case, references to “we,” “our” and “us” include the operations of Discovery Producer Services LLC, or Discovery, in which we own a 40% interest, unless the context clearly indicates otherwise. When we refer to Discovery by name, we are referring exclusively to its businesses and operations. References to The Williams Companies, Inc., or Williams, with respect to periods prior to the closing of this offering, mean The Williams Companies, Inc., together with its subsidiaries, as the historical owner and operator of our businesses, while references to The Williams Companies, Inc., or Williams, with respect to periods from and after the closing of this offering, mean The Williams Companies, Inc., together with its subsidiaries, as the owner of our general partner. References in this prospectus to the “selling unitholders” refer to Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Discovery Pipeline LLC and Williams Partners Holding LLC.

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PROSPECTUS SUMMARY
      This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes that the underwriters’ option to purchase additional units is not exercised. You should read “— Williams Partners L.P. — Summary of Risk Factors” and “Risk Factors” for information about important factors to consider before buying the common units. We include a glossary of some of the terms used in this prospectus as Appendix B.
Williams Partners L.P.
      We are a Delaware limited partnership recently formed by The Williams Companies, Inc., or Williams, to own, operate and acquire a diversified portfolio of complementary energy assets. This is the initial public offering of our common units. Holders of common units are entitled to receive distributions of available cash of $0.35 per unit per quarter, or $1.40 per unit on an annualized basis, before any distributions are paid to the holders of our subordinated units.
      We are principally engaged in the business of gathering, transporting and processing natural gas and the fractionating and storing of natural gas liquids. Fractionation is the process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane. These natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives, among other applications. We intend to acquire additional assets in the future and have a management team dedicated to a growth strategy.
      Our initial asset portfolio consists of:
  •  a 40% interest in Discovery Producer Services LLC, or Discovery, which owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and a natural gas liquids fractionator in Louisiana;
 
  •  the Carbonate Trend natural gas gathering pipeline off the coast of Alabama; and
 
  •  three integrated natural gas liquids storage facilities and a 50% interest in a natural gas liquids fractionator near Conway, Kansas.
      Discovery provides integrated “wellhead to market” services to natural gas producers operating in the shallow and deep waters of the Gulf of Mexico off the coast of Louisiana. Discovery consists of a 105-mile mainline, 168 miles of lateral gathering pipelines, a natural gas processing plant and a natural gas liquids fractionation facility. Discovery has interconnections with five natural gas pipeline systems, which will allow producers to benefit from flexible and diversified access to a variety of natural gas markets. The Discovery mainline was placed into service in 1998 and has a design capacity of 600 million cubic feet per day.
      Our Carbonate Trend gathering pipeline is a 34-mile pipeline that gathers sour gas production from the Carbonate Trend area off the coast of Alabama. “Sour” gas is natural gas that has relatively high concentrations of acidic gases, such as hydrogen sulfide and carbon dioxide, that exceed normal gas transportation specifications. The pipeline was built and placed into service in 2000 and has a maximum design capacity of 120 million cubic feet per day.
      We are also engaged in the storage and fractionation of natural gas liquids near Conway, Kansas, which is the principal natural gas liquids market hub for the Mid-Continent region of the United States. We believe our integrated natural gas liquids storage facility at Conway is one of the largest in the Mid-Continent region. These storage facilities consist of a network of interconnected underground caverns that hold large volumes of natural gas liquids and other hydrocarbons and have an aggregate capacity of approximately 20 million barrels. Our Conway storage facilities connect directly with the Mid-America, or MAPL, and Kinder Morgan natural gas liquids pipeline systems and indirectly with three other large interstate natural gas liquids pipelines. We also own a 50% undivided interest in the Conway natural gas liquids fractionation facility, which is strategically located at the junction of the south, east and west legs of MAPL. This fractionation facility also benefits from its proximity to other natural gas liquids pipelines in the Conway area, and from its proximity to our Conway storage facility. Our share of the fractionator’s capacity is approximately 53,500 barrels per day.

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      We account for our 40% interest in Discovery as an equity investment, and therefore do not consolidate its financial results. Please read “— Summary Historical and Pro Forma Combined Financial and Operating Data” for information regarding our and Discovery’s financial and operating results.
Business Strategies
      Our primary business objectives are to generate stable cash flows sufficient to make quarterly cash distributions to our unitholders and to increase quarterly cash distributions over time by executing the following strategies:
  •  grow through accretive acquisitions of complementary energy assets from third parties, Williams or both;
 
  •  capitalize on expected long-term increases in natural gas production in proximity to Discovery’s pipelines in the Gulf of Mexico;
 
  •  optimize the benefits of our scale, strategic location and pipeline connectivity serving the Mid- Continent natural gas liquids market; and
 
  •  manage our existing and future asset portfolio to minimize the volatility of our cash flows.
Competitive Strengths
      We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:
  •  our ability to grow through acquisitions is enhanced by our affiliation with Williams, and we expect this relationship to provide us access to attractive acquisition opportunities;
 
  •  our assets are strategically located in areas with high demand for our services;
 
  •  our assets are diversified geographically and encompass important aspects of the midstream natural gas and natural gas liquids businesses;
 
  •  the senior management team and board of directors of our general partner have extensive industry experience and include the most senior officers of Williams; and
 
  •  Williams has established a reputation in the midstream natural gas and natural gas liquids industry as a reliable and cost-effective operator, and we believe that we and our customers will benefit from Williams’ scale and operational expertise as well as our access to the broad array of midstream services Williams offers.
Our Relationship with Williams
      One of our principal attributes is our relationship with Williams, an integrated energy company with 2004 revenues in excess of $12.4 billion that trades on the New York Stock Exchange under the symbol “WMB”. Williams is engaged in numerous aspects of the energy industry, including natural gas exploration and production, interstate natural gas transportation and midstream services. Williams has been in the midstream natural gas and natural gas liquids industry for more than 20 years.
      Williams has a long history of successfully pursuing and consummating energy acquisitions and intends to use our partnership as a growth vehicle for its midstream, natural gas, natural gas liquids and other complementary energy businesses. Although we expect to have the opportunity to make acquisitions directly from Williams in the future, we cannot say with any certainty which, if any, of these acquisition opportunities may be made available to us or if we will choose to pursue any such opportunity. In addition, through our relationship with Williams, we will have access to a significant pool of management talent and strong commercial relationships throughout the energy industry. While our relationship with Williams and its subsidiaries is a significant attribute, it is also a source of potential conflicts. For example, Williams is not restricted from competing with us. Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”
      Williams will have a significant interest in our partnership through its indirect ownership of a 63% limited partner interest and all of our 2% general partner interest. Additionally, a subsidiary of Williams markets substantially all of the natural gas liquids to which Discovery takes title. We will enter into an omnibus agreement

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with certain affiliates of Williams that will govern our relationship with them regarding certain reimbursement, indemnification and licensing matters. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”
Summary of Risk Factors
      An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. Those risks are described under the caption “Risk Factors” and include:
Risks Inherent in Our Business
  •  We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
 
  •  The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.
 
  •  Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of natural gas supply, which is dependent on factors beyond our control, including Discovery’s ability to complete its Tahiti lateral expansion project. Any decrease in supplies of natural gas could adversely affect our business and operating results.
 
  •  Our processing, fractionation and storage businesses could be affected by any decrease in the price of natural gas liquids or a change in the price of natural gas liquids relative to the price of natural gas.
 
  •  Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.
 
  •  We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and natural gas liquids. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.
 
  •  If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and natural gas liquids or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.
 
  •  Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.
Risks Inherent in an Investment in Us
  •  Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.
 
  •  Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
 
  •  Even if unitholders are dissatisfied, they cannot initially remove our general partner without its consent.
 
  •  The control of our general partner may be transferred to a third party without unitholder consent.
 
  •  Increases in interest rates may cause the market price of our common units to decline.
 
  •  You will experience immediate and substantial dilution of $6.07 per common unit.
 
  •  We may issue additional common units without your approval, which would dilute your ownership interests.
 
  •  Williams and its affiliates may compete directly with us and have no obligation to present business opportunities to us.

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Tax Risks
  •  Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash available to pay distributions to you would be substantially reduced.
 
  •  A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.
 
  •  You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
 
  •  The tax gain or loss on the disposition of our common units could be different than expected.
The Transactions and Partnership Structure
General
      We have recently been formed as a Delaware limited partnership to own and operate certain natural gas gathering, transportation and processing and natural gas liquids fractionation and storage assets that Williams currently owns or in which it has an ownership interest. As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries.
      At the closing of this offering, the following transactions will occur:
  •  Williams will contribute certain of its assets and liabilities to us or our subsidiaries;
 
  •  we will issue to Williams 2,000,000 common units and 7,000,000 subordinated units representing an aggregate 63% limited partner interest in us;
 
  •  we will issue to our general partner, a wholly owned subsidiary of Williams, a 2% general partner interest in us and all of our incentive distribution rights, which entitle our general partner to increasing percentages of the cash we distribute in excess of $0.4025 per unit per quarter;
 
  •  we will issue 5,000,000 common units to the public in this offering, representing a 35% limited partner interest in us, and will use the net proceeds from this offering as described under “Use of Proceeds;”
 
  •  we will become a party to Williams’ revolving credit facility and will have a borrowing limit of $75 million available to fund acquisitions and for other general partnership purposes;
 
  •  we will enter into a working capital credit facility with Williams as the lender, with a borrowing capacity of $20 million; and
 
  •  we will enter into an omnibus agreement with certain affiliates of Williams that will govern our relationship with them regarding certain reimbursement, indemnification and licensing matters.
Management of Williams Partners L.P.
      Our general partner, Williams Partners GP LLC, will manage our operations and activities. Some of the executive officers and directors of Williams also serve as executive officers and directors of our general partner. For more information about these individuals, please read “Management — Directors and Executive Officers of Our General Partner.” Our general partner will not receive any management fee or other compensation in connection with the management of our business or this offering, other than as described above under “— General,” but it will be entitled to reimbursement of all direct and indirect expenses incurred on our behalf, subject to a partial credit for general and administrative expenses. Our general partner will also be entitled to distributions on its general partner interest and, if specified requirements are met, on its incentive distribution rights. Please read “Cash Distribution Policy and Restrictions on Distributions,” “Management — Executive Compensation” and “Certain Relationships and Related Transactions.”
      Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or its directors.

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Principal Executive Offices and Internet Address
      Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172-0172, and our telephone number is (918) 573-2000. Our website is located at http://www.williamslp.com. We expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.
Summary of Conflicts of Interest and Fiduciary Duties
      Williams Partners GP, our general partner, has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary” duty. However, because our general partner is indirectly wholly owned by Williams, the officers and directors of our general partner have fiduciary duties to manage the business of our general partner in a manner beneficial to Williams. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest of our general partner, please read “Risk Factors — Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.”
      Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to unitholders. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.
      For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Transactions.”

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Organizational Structure After the Transactions
      The following diagram depicts our organizational structure after giving effect to the transactions.
Ownership of Williams Partners L.P.
           
Public Common Units
    35.0 %
The Williams Companies, Inc. and Affiliates Common and Subordinated Units
    63.0 %
General Partner Interest
    2.0 %
       
 
Total
    100.0 %
       
(CHART)

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The Offering
Common units offered by us 5,000,000 common units.
 
Common units offered by the selling unitholders 750,000 common units, if the underwriters exercise their option to purchase additional units in full.
 
Units outstanding after this offering 7,000,000 common units and 7,000,000 subordinated units, each representing a 49% limited partner interest in us.
 
Use of proceeds We intend to use the net proceeds of $100.2 million from this offering to:
 
• distribute $58.7 million to affiliates of Williams, in part to reimburse Williams for capital expenditures relating to the assets contributed to us;
 
• provide $24.4 million to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;
 
• provide $12.8 million of additional working capital; and
 
• pay $4.3 million of expenses associated with this offering and related formation transactions.
 
We will not receive any proceeds from any common units to be sold by the selling unitholders upon any exercise of the underwriters’ option to purchase additional common units.
 
Cash distributions We intend to make minimum quarterly distributions of $0.35 per common unit 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 in reimbursement for all expenses incurred by it on our behalf. In general, we will pay any cash distributions we make each quarter in the following manner:
 
• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.35 plus any arrearages from prior quarters;
 
• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.35; and
 
• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.4025.
 
If cash distributions exceed $0.4025 per unit in a quarter, our general partner will receive increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.”
 
We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner in its discretion to provide for the proper conduct of our business, to comply with any applicable debt instruments or to provide funds for future distributions. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix B. The amount of available cash may be greater than or less than the minimum quarterly distribution to be distributed on all units.

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We believe, based on the estimates contained and the assumptions listed under “Cash Distribution Policy and Restrictions on Distributions — Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery for the Twelve-Month Period Ending June 30, 2006” of this prospectus, that we will have sufficient cash available to pay distributions to enable us to pay the full minimum quarterly distribution of $0.35 on all units for each quarter through June 30, 2006. The amount of estimated cash available to pay distributions generated during 2004 and the twelve-month period ended March 31, 2005 would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and on the subordinated units during these periods. Please read “Cash Distribution Policy and Restrictions on Distributions — Pro Forma Cash Available to Pay Distributions for the Year Ended December 31, 2004 and the Twelve-Month Period Ended March 31, 2005.”
 
Subordination period During 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. The subordination period will end once we meet the financial tests in the partnership agreement. Except as described below, it generally cannot end before June 30, 2008.
 
When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
 
Early termination of subordination period If we have earned and paid an amount that equals or exceeds $2.10 (150% of the annualized minimum quarterly distribution) on each outstanding unit for any four-quarter period, the subordination period will automatically terminate and all of the subordinated units will convert into common units. Please read “How We Make Cash Distributions — Subordination Period.”
 
Issuance of additional units We can issue an unlimited number of common units without the consent of unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”
 
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 the directors of our general partner. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 64.3% of our common and subordinated units. This will give our general partner the practical ability to prevent its involuntary removal.
 
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, but not less than all, of the remaining common units at a price not less than the then-current market price of the common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of this limited call right.

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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, 2007, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 20% of the cash distributed to you with respect to that period. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership” for the basis of this estimate.
 
Material tax consequences For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”
 
Exchange listing The common units have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol “WPZ”.

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Summary Historical and Pro Forma
Combined Financial and Operating Data
      The following table shows summary historical financial and operating data of Williams Partners Predecessor, pro forma financial data of Williams Partners L.P. and summary historical financial and operating data of Discovery Producer Services LLC for the periods and as of the dates indicated. The summary historical financial data of Williams Partners Predecessor for the years ended December 31, 2002, 2003 and 2004 are derived from the audited combined financial statements of Williams Partners Predecessor appearing elsewhere in this prospectus. The summary historical financial data of Williams Partners Predecessor for the three months ended March 31, 2004 and 2005 are derived from the unaudited combined financial statements of Williams Partners Predecessor appearing elsewhere in this prospectus and from our financial records. The results of operations for the interim period are not necessarily indicative of the operating results for the entire year or any future period.
      The summary pro forma financial data of Williams Partners L.P. as of March 31, 2005 and for the year ended December 31, 2004 and three months ended March 31, 2005 are derived from the unaudited pro forma financial statements of Williams Partners L.P. included elsewhere in this prospectus. These pro forma financial statements show the pro forma effect of this offering, including our use of the anticipated net proceeds. The pro forma balance sheet assumes this offering and the application of the net proceeds occurred as of March 31, 2005, and the pro forma statement of operations assumes this offering and the application of the net proceeds occurred on January 1, 2004.
      The summary historical financial data of Discovery Producer Services LLC for the years ended December 31, 2002, 2003 and 2004 are derived from the audited consolidated financial statements of Discovery Producer Services LLC appearing elsewhere in this prospectus. The summary historical financial data of Discovery Producer Services LLC for the three months ended March 31, 2004 and 2005 are derived from the unaudited consolidated financial statements of Discovery Producer Services LLC appearing elsewhere in this prospectus and from our financial records. The results of operations for the interim period are not necessarily indicative of the operating results for the entire year or any future period.
      The following table includes Adjusted EBITDA Excluding Investment in Discovery, a non-GAAP financial measure, for Williams Partners L.P. and Adjusted EBITDA for our interest in Discovery. These measures are presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. As described further below in “— Non-GAAP Financial Measures,” management believes that the presentation of EBITDA is useful to lenders and investors because of its use in the natural gas industry and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Our 40% ownership interest in Discovery is not consolidated in our financial results; rather we account for it using the equity method of accounting. In order to evaluate EBITDA for the impact of our investment in Discovery on our results, we calculate Adjusted EBITDA Excluding Investment in Discovery separately for Williams Partners L.P. and Adjusted EBITDA for our equity interest in Discovery. We expect distributions we receive from Discovery to represent a significant portion of the cash we distribute to our unitholders. Discovery’s limited liability company agreement provides for quarterly distributions of available cash to its members. Please read “Cash Distribution Policy and Restrictions on Distributions — General — Discovery’s Cash Distribution Policy.”
      For Williams Partners L.P., we define Adjusted EBITDA Excluding Investment in Discovery as net income (loss) plus interest (income) expense and depreciation and accretion less our equity earnings in Discovery plus the impairment of our investment in Discovery in 2004. We also adjust for certain non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003, which we added back to net income in that year.
      For Discovery, we define Adjusted EBITDA as net income plus interest (income) expense, depreciation and accretion. We also adjust for certain non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003, which we added back to net income in that year. Our equity share of Discovery’s Adjusted EBITDA is 40%.
      For a reconciliation of these measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”

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      We derived the information in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the historical combined and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
                                                           
    Williams Partners Predecessor — Historical   Williams Partners L.P.
        Pro Forma
             
        Three Months Ended       Three Months
    Year Ended December 31,   March 31,   Year Ended   Ended
            December 31,   March 31,
    2002   2003   2004   2004   2005   2004   2005
                             
    (In thousands, except per unit data)
Statement of Income Data:
                                                       
Revenues
  $ 25,725     $ 28,294     $ 40,976     $ 7,953     $ 11,369     $ 40,976     $ 11,369  
Costs and expenses
    16,542       21,250       32,935       5,256       10,266       32,935       10,266  
                                           
Operating income
    9,183       7,044       8,041       2,697       1,103       8,041       1,103  
Equity earnings — Discovery
    2,026       3,447       4,495       1,982       2,212       4,495       2,212  
Impairment of investment in Discovery
                (13,484 )(a)                 (13,484 )      
Interest expense
    (3,414 )     (4,176 )     (12,476 )     (3,110 )     (3,004 )     (778 )     (270 )
Cumulative effect of change in accounting principle
          (1,099 )                              
                                           
Net income (loss) (b)
  $ 7,795     $ 5,216     $ (13,424 )   $ 1,569     $ 311     $ (1,726 )   $ 3,045  
                                           
Pro forma net income (loss) per limited partner unit:
                                                       
 
Common unit
                                          $ (0.12 )   $ 0.21  
 
Subordinated unit
                                            (0.12 )     0.21  
Balance Sheet Data (at period end):
                                                       
Total assets
  $ 125,069     $ 230,150 (c)   $ 219,361     $ 229,628     $ 220,293             $ 233,447  
Property, plant and equipment, net
    72,062       69,695       67,793       69,000       67,146               67,146  
Investment in Discovery
    49,323       156,269 (c)     147,281 (a)     158,251       149,493               120,897  
Advances from affiliate
    90,996       187,193 (c)     186,024       187,949       190,291                
Total owners’ equity/ Partners’ capital
    22,914       30,092       16,668       31,661       16,979               220,424  
Other Financial Data:
                                                       
Williams Partners Predecessor:
                                                       
 
Adjusted EBITDA Excluding Investment in Discovery
  $ 12,758     $ 10,751     $ 11,727     $ 3,587     $ 2,008     $ 11,727     $ 2,008  
 
Maintenance capital expenditures (d)
    295       1,176       1,622       95       212       1,622       212  
Discovery Producer Services — our 40%:
                                                       
 
Adjusted EBITDA
    15,314       16,614       13,566       4,267       4,544                  
 
Maintenance capital expenditures
    1,131       1,128       338       86       746                  
Operating Information:
                                                       
Williams Partners Predecessor:
                                                       
 
Conway storage revenues
  $ 10,854     $ 11,649     $ 15,318     $ 3,109     $ 4,388                  
 
Conway fractionation volumes (bpd) — our 50%
    38,234       34,989       39,062       34,314       41,296                  
 
Carbonate Trend gathered volumes (MMBtu/d)
    57,060       67,638       49,981       59,815       41,567                  
Discovery Producer Services — 100%:
                                                       
 
Gathered volumes (MMBtu/d)
    425,388       378,745       348,142       430,466       335,727                  
 
Gross processing margin (¢/MMBtu) (e)
    12¢       17¢       17¢       14¢       21¢                  
 
(a) The $13.5 million impairment of our equity investment in Discovery in 2004 reduced the investment balance. See Note 5 of the Notes to Combined Financial Statements.
 
(b) Following the completion of the initial public offering, our operations will be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. Therefore, we have excluded income tax expense from this financial information.
 
(c) In December 2003, Williams Partners Predecessor made a $101.6 million capital contribution to Discovery, which Discovery subsequently used to repay maturing debt. Williams Partners Predecessor funded this contribution with an advance from Williams.
 
(d) Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Requirements” for a definition of maintenance capital expenditures.
 
(e) Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General — How We Evaluate Our Operations — Gross Processing Margins” for a discussion of gross processing margin.

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Non-GAAP Financial Measures
      Adjusted EBITDA Excluding Investment in Discovery, in our case, and Adjusted EBITDA, in Discovery’s case, are used as supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess:
  •  the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 
  •  the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and
 
  •  our operating performance and return on invested capital as compared to those of other publicly traded master limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.
      Our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA exclude some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

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      The following tables present a reconciliation of the non-GAAP financial measures, our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA, to the GAAP financial measures of net income (loss) and of net cash provided (used) by operating activities, on a historical basis and on a pro forma basis, as adjusted for this offering and the application of the net proceeds, as applicable.
                                                           
    Williams Partners Predecessor — Historical    
        Williams Partners L.P.
            Pro Forma
        Three Months    
        Ended       Three Months
    Year Ended December 31,   March 31,   Year Ended   Ended
            December 31,   March 31,
    2002   2003   2004   2004   2005   2004   2005
                             
    ($ in thousands)
Williams Partners Predecessor
                                                       
Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Investment in Discovery” to GAAP
                                                       
“Net income (loss)”
                                                       
Net income (loss)
  $ 7,795     $ 5,216     $ (13,424 )   $ 1,569     $ 311     $ (1,726 )   $ 3,045  
Interest expense
    3,414       4,176       12,476       3,110       3,004       778       270  
Depreciation and accretion
    3,575       3,707       3,686       890       905       3,686       905  
Impairment of investment in Discovery Producer Services
                13,484                   13,484        
Cumulative effect of change in accounting principle
          1,099                                
Equity earnings — Discovery Producer Services
    (2,026 )     (3,447 )     (4,495 )     (1,982 )     (2,212 )     (4,495 )     (2,212 )
                                           
Adjusted EBITDA Excluding Investment in Discovery
  $ 12,758     $ 10,751     $ 11,727     $ 3,587     $ 2,008     $ 11,727     $ 2,008  
                                           
Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Investment in Discovery” to GAAP “Net cash provided (used) by operating activities”
                                                       
Net cash provided (used) by operating activities
  $ 8,144     $ 6,644     $ 2,703     $ (661 )   $ (4,055 )                
Interest expense
    3,414       4,176       12,476       3,110       3,004                  
Changes in operating working capital:
                                                       
 
Accounts receivable
    958       850       (261 )     (1,760 )     (678 )                
 
Other current assets
    185       187       362       (49 )     45                  
 
Accounts payable
    (593 )     274       (2,711 )     (616 )     1,495                  
 
Accrued liabilities
    1,218       320       417       (41 )     209                  
 
Deferred revenue
    765       (1,108 )     (775 )     2,474       3,200                  
Other, including changes in noncurrent assets and liabilities
    (1,333 )     (592 )     (484 )     1,130       (1,212 )                
                                           
Adjusted EBITDA Excluding Investment in Discovery
  $ 12,758     $ 10,751     $ 11,727     $ 3,587     $ 2,008                  
                                           

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    Discovery Producer Services — Historical
     
        Three Months Ended
    Year Ended December 31,   March 31,
         
    2002   2003   2004   2004   2005
                     
    ($ in thousands)
Discovery Producer Services
                                       
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP
                                       
“Net income”
                                       
Net income 
  $ 5,498     $ 8,781     $ 11,670     $ 5,062     $ 5,531  
Interest (income) expense
    10,851       9,611       (550 )     (52 )     (284 )
Depreciation and accretion
    21,935       22,875       22,795       5,658       6,113  
Cumulative effect of change in accounting principle
          267                    
                               
Adjusted EBITDA — 100%
  $ 38,284     $ 41,534     $ 33,915     $ 10,668     $ 11,360  
                               
Adjusted EBITDA — our 40% interest
  $ 15,314     $ 16,614     $ 13,566     $ 4,267     $ 4,544  
                               
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net cash provided by operating activities”
                                       
Net cash provided by operating activities
  $ 19,572     $ 44,025     $ 35,623     $ 11,093     $ 7,981  
Interest (income) expense
    10,851       9,611       (550 )     (52 )     (284 )
Loss on disposal of equipment
    (1,913 )                        
Changes in operating working capital:
                                       
 
Accounts receivable
    6,008       (7,860 )     1,658       (961 )     4,057  
 
Inventory
    122       229       240       (368 )     138  
 
Other current assets
    330       761       1       (436 )     (218 )
 
Accounts payable
    7,538       1,415       (1,256 )     2,630       713  
 
Other current liabilities
    1,163       (2,223 )     668       (564 )     (443 )
 
Accrued liabilities
    (5,387 )     (4,424 )     (2,469 )     (674 )     (584 )
                               
Adjusted EBITDA — 100%
  $ 38,284     $ 41,534     $ 33,915     $ 10,668     $ 11,360  
                               

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RISK FACTORS
      Limited partner interests are inherently different from the 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 a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus when evaluating an investment in our common units.
      If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.
Risks Inherent in Our Business
We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.
      We may not have sufficient available cash each quarter to pay the minimum quarterly distribution. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
  •  the prices we obtain for our services;
 
  •  the prices of, level of production of, and demand for, natural gas and natural gas liquids, or NGLs;
 
  •  the volumes of natural gas we gather, transport and process and the volumes of NGLs we fractionate and store;
 
  •  the level of our operating costs, including payments to our general partner; and
 
  •  prevailing economic conditions.
      In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:
  •  the level of capital expenditures we make;
 
  •  the restrictions contained in our and Williams’ debt agreements and our debt service requirements;
 
  •  the cost of acquisitions, if any;
 
  •  fluctuations in our working capital needs;
 
  •  our ability to borrow for working capital or other purposes;
 
  •  the amount, if any, of cash reserves established by our general partner;
 
  •  the amount of cash that Discovery distributes to us; and
 
  •  reimbursement payments to us by, and credits from, Williams under the omnibus agreement.
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.
      The amount of cash we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, 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, and we may not make cash distributions during periods when we record net income.
      The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common units, the subordinated units and the general partner interest to be outstanding immediately after this offering is $20 million. The amount of pro forma available cash to pay distributions that we generated during 2004 and the twelve-month period ended March 31, 2005 would have been sufficient to allow us to pay the full minimum quarterly distribution on the common and subordinated units and the 2% general partner interest during these periods. For a calculation of our ability to make distributions to unitholders based on our pro forma results in 2004 and for the twelve-month period ended March 31, 2005 and for an estimate of our ability to pay the full

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minimum quarterly distribution on the common and subordinated units and the 2% general partner interest for the twelve-month period ending June 30, 2006, please read “Cash Distribution Policy and Restrictions on Distributions.”
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of natural gas supply, which is dependent on factors beyond our control, including Discovery’s ability to complete its Tahiti lateral expansion project. Any decrease in supplies of natural gas could adversely affect our business and operating results.
      Our pipelines receive natural gas directly from offshore producers. The production from existing wells connected to our pipelines will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. We do not produce an aggregate reserve report on a regular basis or regularly obtain or update independent reserve evaluations. The amount of natural gas reserves underlying these wells may be less than we anticipate, and the rate at which production will decline from these reserves may be greater than we anticipate. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas processing plant and fractionator, we and Discovery must continually obtain new supplies of natural gas. The primary factors affecting our ability to obtain new supplies of natural gas and attract new customers to our pipelines include: (1) the level of successful drilling activity near these pipelines; (2) our ability to compete for volumes from successful new wells and (3) our and Discovery’s ability to successfully complete lateral expansion projects to connect to new wells.
      We have no current lateral expansion projects planned at Carbonate Trend, and Discovery has only one currently planned lateral expansion project. Discovery recently reached an agreement with Chevron, Shell and Statoil to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. The Tahiti pipeline lateral expansion project, however, is subject to “project sanctioning” by the Tahiti producers, which means that the producers must still formally decide to proceed with the project. The Tahiti producers have no obligation to sanction the Tahiti lateral expansion project and may decide not to do so in their discretion.
      The level of offshore drilling activity is dependent on economic and business factors beyond our control. The primary factors that impact drilling decisions are oil and natural gas prices. A sustained decline in oil and natural gas prices could result in a decrease in exploration and development activities in the fields served by our pipelines, which would lead to reduced throughput levels on these pipelines. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. Because of these factors, even if new oil or natural gas reserves were discovered in areas served by our pipelines, producers may choose not to develop those reserves. If we were not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells, due to reductions in drilling activity, competition, or difficulties in completing lateral expansion projects to connect to new supplies of natural gas, such as Discovery’s Tahiti project, throughput on our pipelines and the utilization rates of Discovery’s natural gas processing plant and fractionator would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.
Our processing, fractionation and storage businesses could be affected by any decrease in NGL prices or a change in NGL prices relative to the price of natural gas.
      Lower NGL prices would reduce the revenues we generate from the sale of NGLs for our own account. Under certain gas processing contracts, referred to as “percent-of-liquids” contracts, Discovery receives NGLs removed from the natural gas stream during processing, which it fractionates and sells. In addition, product optimization at our Conway fractionator generally leaves us with excess propane, an NGL, which we sell. We also sell excess storage volumes resulting from measurement variances at our Conway storage facilities.
      The relationship between natural gas prices and NGL prices also affects our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for Discovery and its customers to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, Discovery may experience periods in which higher natural gas prices reduce the volumes of natural gas processed at its Larose plant, which would reduce its gross

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processing margins. Finally, higher natural gas prices relative to NGL prices could also reduce volumes of gas processed generally, reducing the volumes of mixed NGLs available for fractionation.
Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.
      Lower natural gas and oil prices could result in a decline in the production of natural gas and NGLs resulting in reduced throughput on our pipelines and those of others. Any such decline would reduce the amount of NGLs we fractionate and store, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.
      In general terms, the prices of natural gas, NGLs and other hydrocarbon products fluctuate in response to changes in supply, changes in demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include:
  •  worldwide economic conditions;
 
  •  weather conditions and seasonal trends;
 
  •  the levels of domestic production and consumer demand;
 
  •  the availability of imported natural gas and NGLs;
 
  •  the availability of transportation systems with adequate capacity;
 
  •  the price and availability of alternative fuels;
 
  •  the effect of energy conservation measures;
 
  •  the nature and extent of governmental regulation and taxation; and
 
  •  the anticipated future prices of natural gas, NGLs and other commodities.
We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.
      We rely on a limited number of customers for a significant portion of revenues. Our three largest customers for the year ended December 31, 2004 and the three months ended March 31, 2005, BP Products North America, Inc., SemStream, L.P. and Enterprise Products Partners, all customers of our Conway facilities, accounted for approximately 52.7% and 44.0% of our revenues for the year ended December 31, 2004 and the three months ended March 31, 2005, respectively. Discovery’s largest customer for the year ended December 31, 2004 and the three months ended March 31, 2005, other than a subsidiary of Williams that markets NGLs for Discovery, was Eni Petroleum Co., Inc., which accounted for 10.9% and 9.5% of Discovery’s revenues for the year ended December 31, 2004 and the three months ended March 31, 2005, respectively. While some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts, on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas or NGLs, as applicable, supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you, unless we were able to acquire comparable volumes from other sources.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.
      We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. For example, MAPL delivers customers’ mixed NGLs to our Conway fractionator and provides access to multiple end markets for our storage customers’ NGL products. If MAPL were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, our customers would be unable to store or deliver NGL products and we would be unable to receive deliveries of mixed NGLs at our Conway fractionator. This would have an immediate impact on our ability to enter into short-term storage contracts and on the volumes of mixed NGLs fractionated at Conway. As another example, Shell’s

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Yellowhammer sour gas treatment facility in Coden, Alabama is the only sour gas treatment facility currently connected to our Carbonate Trend pipeline. Natural gas produced from the Carbonate Trend area must pass through a Shell-owned pipeline and Shell’s Yellowhammer sour gas treatment facility before delivery to end markets. If the Shell-owned pipeline or the Yellowhammer facility were to become unavailable for current or future volumes of natural gas delivered to it through the Carbonate Trend pipeline due to repairs, damages to the facility, lack of capacity or any other reason, our Carbonate Trend customers would be unable to continue shipping natural gas to end markets. Since we generally receive revenues for volumes shipped on the Carbonate Trend pipeline, this would reduce our revenues. Any temporary or permanent interruption in operations at MAPL, Yellowhammer or any other third party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or processed and fractionated at our facilities and NGLs stored at our Conway facilities could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.
Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.
      We will have the ability to incur up to $75 million of indebtedness under Williams’ $1.275 billion revolving credit facility. However, this $75 million of borrowing capacity will only be available to us to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. As a result, borrowings by Williams could restrict our access to credit. In addition, Williams’ public indentures contain covenants that restrict Williams’ and our ability to incur liens to support indebtedness. As a result, if Williams were not in compliance with these covenants, we could be unable to make any borrowings under our $75 million borrowing limit, even if capacity were otherwise available. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
      Williams’ ability to comply with the covenants contained in its debt instruments may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ ability to comply with these covenants may be impaired. While we will not be individually subject to any financial covenants or ratios under Williams’ revolving credit facility, Williams and its subsidiaries as a whole are subject to these tests. Accordingly, any breach of these or other covenants, ratios or tests, would terminate our and Williams’ and its other subsidiaries’ ability to make additional borrowings under the credit facility and, as a result, could limit our ability to finance our operations, make acquisitions or pay distributions to unitholders. In addition, a breach of these covenants by Williams would cause the acceleration of Williams’ and, in some cases, our outstanding borrowings under the facility. In the event of acceleration of indebtedness, Williams, the other borrowers or we might not have, or be able to obtain, sufficient funds to make required repayments of the accelerated indebtedness. 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 Williams, our ability to obtain credit will be affected by Williams’ credit ratings. If we obtain our own credit rating, any future down grading of a Williams’ credit rating would likely also result in a down grading of our credit rating. Regardless of whether we have our own credit rating, a down grading of a Williams’ credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.
We do not own all of the interests in the Conway fractionator and in Discovery, which could adversely affect our ability to respond to changing conditions.
      Because we do not wholly own the Conway fractionator and Discovery, we may have limited flexibility to control the operation of, dispose of, encumber or receive cash from these assets. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, results of operations financial condition and ability to make cash distributions to you.
Discovery may reduce its cash distributions to us in some situations
      Discovery’s limited liability company agreement, as amended to be effective at the time of closing, provides that it will distribute its available cash to its members on a quarterly basis. However, Discovery has historically

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retained all its cash generated from operations to fund its expansion capital expenditures and has not made any cash distributions to its members. Discovery’s available cash (just as ours) includes cash on hand less any reserves that may be appropriate for operating its business. As a result, reserves established by Discovery, including those for working capital, will reduce the amount of available cash. The amount of Discovery’s quarterly distributions, including the amount of cash reserves not distributed, will be determined by the members of Discovery’s management committee representing a majority-in-interest in Discovery. We will own a 40.0% interest in Discovery and an affiliate of Williams will own a 26.7% interest in Discovery although the third member has an option to acquire a 6.7% interest in Discovery from Williams that expires October 31, 2005. In addition, to the extent Discovery requires working capital in excess of applicable reserves, the Williams affiliate that is a Discovery member (Williams Energy, L.L.C.) must make working capital advances to Discovery of up to the amount of Discovery’s two most recent prior quarterly distributions of available cash, but Discovery must repay any such advances before it can make future distributions to its members. As a result, the repayment of advances could reduce the amount of cash distributions we would otherwise receive from Discovery. In addition, if Williams Energy, L.L.C. cannot advance working capital to Discovery as described above, Discovery’s business and financial condition may be adversely affected.
We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.
      Williams will operate Discovery and Chevron will operate our Carbonate Trend pipeline. We will have a limited ability to control our operations or the associated costs of such operations. The success of these operations is therefore dependent upon a number of factors that are outside our control, including the competence and financial resources of the operator. We also rely on Williams for services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams as an operator and Williams’ outsourcing relationships, our reliance on Chevron and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.
Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.
      We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. Discovery competes with other natural gas gathering and transportation and processing facilities and other NGL fractionation facilities located in south Louisiana, offshore in the Gulf of Mexico and along the Gulf Coast, including the Manta Ray/ Nautilus systems, Trunkline pipeline and the Venice Gathering System and the processing and fractionation facilities that are connected to these pipelines. Our Conway fractionation facility competes for volumes of mixed NGLs with a ONEOK-owned fractionator located in Hutchinson, Kansas, a ONEOK-owned fractionator located in Medford, Oklahoma, a ONEOK-owned fractionator located in Bushton, Kansas, the other joint owners of the Conway fractionation facility and, to a lesser extent, with fractionation facilities on the Gulf Coast. Our Conway storage facilities compete with ONEOK-owned storage facilities in Bushton, Kansas and in Conway, Kansas, an NCRA-owned facility in Conway, Kansas, a ONEOK-owned facility in Hutchinson, Kansas and a Ferrellgas-owned facility in Hutchinson, Kansas and, to a lesser extent, with storage facilities on the Gulf Coast and in Canada. In addition, our customers who are significant producers or consumers of NGLs may develop their own processing, fractionation and storage facilities in lieu of using ours. Similarly, competitors may establish new connections with pipeline systems that would create additional competition for services we provide to our customers. For example, other than the producer gathering lines that connect to the Carbonate Trend pipeline, there are no other sour gas pipelines near our Carbonate Trend pipeline, but the producers that are currently our customers could construct or commission such pipelines in the future. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

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Our results of storage and fractionation operations are dependent upon the demand for propane and other NGLs. A substantial decrease in this demand could adversely affect our business and operating results.
      Our Conway storage and fractionation operations are impacted by demand for propane more than any other NGL. Conway, Kansas is one of the two major trading hubs for propane and other NGLs in the continental United States. Demand for propane at Conway is principally driven by demand for its use as a heating fuel. However, propane is also used as an engine and industrial fuel and as a petrochemical feedstock in the production of ethylene and propylene. Demand for propane as a heating fuel is significantly affected by weather conditions and the availability of alternative heating fuels such as natural gas. Weather-related demand is subject to normal seasonal fluctuations, but an unusually warm winter could cause demand for propane as a heating fuel to decline significantly. Demand for other NGLs, which include ethane, butane, isobutane and natural gasoline, could be adversely impacted by general economic conditions, a reduction in demand by customers for plastics and other end products made from NGLs, an increase in competition from petroleum-based products, government regulations or other reasons. Any decline in demand for propane or other NGLs could cause a reduction in demand for our Conway storage and fractionation services.
      When prices for the future delivery of propane and other NGLs that we store at our Conway facilities fall below current prices, customers are less likely to store these products, which could reduce our storage revenues. This market condition is commonly referred to as “backwardation.” When the market for propane and other NGLs is in backwardation, the demand for storage capacity at our Conway facilities may decrease. While this would not impact our long-term capacity leases, customers could become less likely to enter into short-term storage contracts.
We may not be able to grow or effectively manage our growth.
      A principal focus of our strategy is to continue to grow by expanding our business. Our future growth will depend upon a number of factors, some of which we can control and some of which we cannot. These factors include our ability to:
  •  identify businesses engaged in managing, operating or owning pipeline, processing, fractionation and storage assets, or other midstream assets for acquisitions, joint ventures and construction projects;
 
  •  control costs associated with acquisitions, joint ventures or construction projects;
 
  •  consummate acquisitions or joint ventures and complete construction projects, including Discovery’s Tahiti lateral expansion project;
 
  •  integrate any acquired or constructed business or assets successfully with our existing operations and into our operating and financial systems and controls;
 
  •  hire, train and retain qualified personnel to manage and operate our growing business; and
 
  •  obtain required financing for our existing and new operations.
      A deficiency in any of these factors would adversely affect our ability to achieve anticipated growth in the level of cash flows or realize anticipated benefits. In addition, competition from other buyers could reduce our acquisition opportunities or cause us to pay a higher price than we might otherwise pay. In addition, Williams is not restricted from competing with us. Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.
      We may acquire new facilities or expand our existing facilities to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, our new or expanded facilities may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into our operations may result in unforeseen operating difficulties, may absorb significant management attention and may require financial resources that would otherwise be available for the ongoing development and expansion of our existing operations. Future acquisitions or construction projects could result in the incurrence of indebtedness and additional liabilities and excessive costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. Further, if we issue additional common units in connection with future acquisitions, your interest in the partnership will be diluted and distributions to you may be reduced.

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Discovery’s interstate tariff rates are subject to review and possible adjustment by federal regulators, which could have a material adverse effect on our business and operating results. Moreover, because Discovery is a non-corporate entity, it may be disadvantaged in calculating its cost of service for rate-making purposes.
      The Federal Energy Regulatory Commission, or FERC, pursuant to the Natural Gas Act, regulates Discovery’s interstate pipeline transportation service. Under the Natural Gas Act, interstate transportation rates must be just and reasonable and not unduly discriminatory. If the tariff rates Discovery is permitted to charge its customers are lowered by FERC, on its own initiative, or as a result of challenges raised by Discovery’s customers or third parties, FERC could require refunds of amounts collected under rates which it finds unlawful. An adverse decision by FERC in approving Discovery’s regulated rates could adversely affect our cash flows. Although FERC generally does not regulate the natural gas gathering operations of Discovery under the Natural Gas Act, federal regulation influences the parties that gather natural gas on the Discovery gas gathering system.
      Discovery’s maximum regulated rate for mainline transportation is scheduled to decrease in 2008. At that time, Discovery will be required to reduce its mainline transportation rate on all of its contracts that have rates above the new maximum rate. This could reduce the revenues generated by Discovery. Discovery may elect to file a rate case with FERC seeking to alter this scheduled maximum rate reduction. However, if filed, a rate case may not be successful in even partially preventing the rate reduction. If Discovery makes such a filing, all aspects of Discovery’s cost of service and rate design could be reviewed, which could result in additional reductions to its regulated rates.
      In a decision last year involving an oil pipeline limited partnership, BP West Coast Products, LLC v. FERC, the United States Court of Appeals for the District of Columbia Circuit vacated FERC’s Lakehead policy. In its Lakehead decision, FERC allowed an oil pipeline limited partnership to include in its cost of service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which it has stated it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all entities or individuals owning public utility assets, if the pipeline proves that the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Although the new policy affords pipelines that are organized as pass-through entities an opportunity to recover a tax allowance, FERC has not indicated what evidence is required to establish such actual or legal income tax liability for all owners. The new tax allowance policy is subject to rehearing and further action by FERC. Further, the new tax allowance policy and the BP West Coast decision are subject to review by the United States Court of Appeals for the District of Columbia Circuit. Therefore, the ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service. If Discovery were to file a rate case, as discussed above, it would be required to prove pursuant to the new policy’s standard that the inclusion of an income tax allowance in Discovery’s cost of service was permitted. If FERC were to disallow a substantial portion of Discovery’s income tax allowance, it may be more difficult for Discovery to justify its rates.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
      There are operational risks associated with the gathering, transporting and processing of natural gas and the fractionation and storage of NGLs, including:
  •  hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural disasters and acts of terrorism;
 
  •  damages to pipelines and pipeline blockages;
 
  •  leakage of natural gas (including sour gas), NGLs, brine or industrial chemicals;
 
  •  collapse of NGL storage caverns;
 
  •  operator error;

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  •  pollution;
 
  •  fires, explosions and blowouts;
 
  •  risks related to truck and rail loading and unloading; and
 
  •  risks related to operating in a marine environment.
      Any of these or any other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of life, property damage, damage to the environment or other significant exposure to liability. For example, last year we experienced a temporary interruption of service on one of our pipelines due to an influx of seawater while connecting a new lateral. In addition, this year the Carbonate Trend pipeline could experience a temporary shut down in connection with restoration activities due to the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for additional information. Insurance may be inadequate, and in some instances, we may be unable to obtain insurance on commercially reasonable terms, if at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to you.
Pipeline integrity programs and repairs may impose significant costs and liabilities on us.
      In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for gas transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The final rule requires operators to (1) perform ongoing assessments of pipeline integrity, (2) identify and characterize applicable threats to pipeline segments that could impact a high consequence area, (3) improve data collection, integration and analysis, (4) repair and remediate the pipeline as necessary and (5) implement preventive and mitigating actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002, a new bill signed into law in December 2002. The final rule became effective on January 14, 2004. In response to this new Department of Transportation rule, we have initiated pipeline integrity testing programs that are intended to assess pipeline integrity. In addition, we have voluntarily initiated a testing program to assess the integrity of the brine pipelines of our Conway storage facilities. The results of these testing programs could cause us to incur significant capital and operating expenditures in response to any repair, remediation, preventative or mitigating actions that are determined to be necessary.
      Additionally, the transportation of sour gas in our Carbonate Trend pipeline necessitates a corrosion control program in order to protect the integrity of the pipeline and prolong its life. Our corrosion control program may not be successful and the sour gas could compromise pipeline integrity. Our inability to reduce corrosion on our Carbonate Trend pipeline to acceptable levels could significantly reduce the service life of the pipeline and could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. Please read “Business — The Carbonate Trend Pipeline — General” for additional information on our corrosion control program.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
      We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs to retain necessary land use. 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 and financial condition and our ability to make cash distributions to you.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.
      The risk of substantial environmental costs and liabilities is inherent in natural gas gathering, transportation and processing, and in the fractionation and storage of NGLs, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to stringent federal, state and local laws and regulations relating to protection of the environment. These laws include, for example: (1) the

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Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions; (2) the Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act, or CWA, and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters; (3) 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 have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and (4) the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities. Various governmental authorities, including the U.S. Environmental Protection Agency, or EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under CERCLA, RCRA and analogous state laws for the remediation of contaminated areas.
      There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of the products we gather, transport, process, fractionate and store, air emissions related to our operations, historical industry operations, waste disposal practices, and the prior use of flow meters containing mercury, some of which may be material. Private parties, including the owners of properties through which our pipeline systems pass, may 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 arising from our operations. Some sites we operate are located near current or former third party hydrocarbon storage and processing operations and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material.
      For example, the Kansas Department of Health and Environment, or the KDHE, regulates the storage of NGLs and natural gas in the state of Kansas. This agency also regulates the construction, operation and closure of brine ponds associated with such storage facilities. In response to a significant incident at a third party facility, the KDHE recently promulgated more stringent regulations regarding safety and integrity of brine ponds and storage caverns. These regulations are subject to interpretation and the costs associated with compliance with these regulations could vary significantly depending upon the interpretation of these regulations. The KDHE has advised us that one such regulation relating to the metering of NGL volumes that are injected and withdrawn from our caverns may be interpreted and enforced to require the installation of meters at each of our well bores. We have informed the KDHE that we disagree with this interpretation, and the KDHE has asked us to provide it with additional information. We estimate that the cost of installing a meter at each of our well bores at two of our Conway storage facilities would total approximately $3.9 million over three years. Additionally, incidents similar to the incident at a third party facility that prompted the recent KDHE regulations could prompt the issuance of even stricter regulations.
      Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, new environmental regulations might adversely affect our products and activities, including processing, fractionation, storage and transportation, as well as waste management and air emissions. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability.
Potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.
      Recently-discovered accounting irregularities in various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosure, the relationships between companies and their independent auditors, and retirement plan practices. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

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Terrorist attacks have resulted in increased costs, and attacks directed at our facilities or those of our suppliers and customers could disrupt our operations.
      On September 11, 2001, the United States was the target of terrorist attacks of unprecedented scale. Since the September 11 attacks, the United States government has issued warnings that energy assets may be the future target of terrorist organizations. These developments have subjected our operations to increased risks and costs. The long-term impact that terrorist attacks and the threat of terrorist attacks may have on our industry in general, and on us in particular, is not known at this time. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways. In addition, uncertainty regarding future attacks and war cause global energy markets to become more volatile. Any terrorist attack on our facilities or those of our suppliers or customers could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.
      Changes in the insurance markets attributable to terrorists attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in financial markets as a result of terrorism or war could also affect our ability to raise capital.
We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.
      We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.
Risks Inherent in an Investment in Us
Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.
      Following the offering, Williams will own indirectly the 2% general partner interest and its affiliates will own directly a 63% limited partner interest in us and will own and control our general partner. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
  •  our general partner is allowed to take into account the interests of parties other than us, such as Williams, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;
 
  •  our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
 
  •  our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our unitholders;
 
  •  in some instances, 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;
 
  •  our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
 
  •  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
  •  our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

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  •  our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
      Please read “Certain Relationships and Related Transactions — Omnibus Agreement” and “Conflicts of Interest and Fiduciary Duties.”
Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
      Our partnership agreement contains provisions that reduce the 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 any limited partner;
 
  •  provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decision is in our best interests;
 
  •  generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
 
  •  provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
      By purchasing a common unit, a common unitholder will be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”
Even if unitholders are dissatisfied, they cannot initially remove our general partner without its consent.
      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 to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Williams. 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.
      Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Accordingly, the unitholders will be unable initially to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon completion of the offering to be able to prevent the general partner’s removal. 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 be converted into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.
      Cause is narrowly defined in our partnership agreement 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

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of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.
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 the members of our general partner from transferring their member interest in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of the general partner with their own choices and to control the decisions taken by the board of directors and officers of the general partner. In addition, pursuant to the omnibus agreement with Williams, any new owner of the general partner would be required to change our name so that there would be no further reference to Williams.
Increases in interest rates may cause the market price of our common units to decline.
      An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.
You will experience immediate and substantial dilution of $6.07 per common unit.
      The initial public offering price of $21.50 per common unit exceeds pro forma net tangible book value of $15.43 per common unit. You will incur immediate and substantial dilution of $6.07 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. Please read “Dilution.”
We may issue additional common units without your approval, which would dilute your ownership interests.
      Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional units.
      The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
  •  our unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available to pay distributions on each unit may decrease;
 
  •  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
 
  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
Williams and its affiliates may compete directly with us and have no obligation to present business opportunities to us.
      The omnibus agreement will not prohibit Williams and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. Williams 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. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to Williams and its affiliates. As a result, neither Williams nor any of its affiliates will have any obligation to present business opportunities to us. Please read “Certain Relationships and Related Transactions — Omnibus Agreement” and “Conflicts of Interest and Fiduciary Duties.”

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Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.
      If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would not longer be subject to the reporting requirements of the Securities Exchange Act of 1934. For additional information about this call right, please read “The Partnership Agreement — Limited Call Right.”
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
      Our partnership agreement restricts unitholders’ voting rights by 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 and 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. The 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.
Cost reimbursements due our general partner and its affiliates will reduce cash available to pay distributions to you.
      Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole discretion. These expense will include all costs incurred by the general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. Please read “Certain Relationships and Related Transactions” and “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.” The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates could adversely affect our ability to pay cash distributions to you.
You may not have limited liability if a court finds that unitholder action constitutes control of our business. You may also have liability to repay distributions.
      As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. 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. Please read “The Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.
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 the offering, there has been no public market for the common units. After the offering, there will be only 5,000,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional units. 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.

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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:
  •  our quarterly distributions;
 
  •  our quarterly or annual earnings or those of other companies in our industry;
 
  •  loss of a large customer;
 
  •  announcements by us or our competitors of significant contracts or acquisitions;
 
  •  changes in accounting standards, policies, guidance, interpretations or principles;
 
  •  general economic conditions;
 
  •  the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;
 
  •  future sales of our common units; and
 
  •  the other factors described in these “Risk Factors.”
Tax Risks
      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 entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash available to pay distributions to you would be substantially reduced.
      The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.
      If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. 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 to pay distributions to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of the common units.
      Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions to you would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

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A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.
      We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this prospectus. 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 the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
      You will be required to pay 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 your share of our taxable income.
The gain or loss on the disposition of our common units could be different than expected.
      If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.
Tax-exempt entities, regulated investment companies and foreign 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 individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. The American Jobs Creation Act of 2004 generally treats income derived from the ownership of publicly traded partnerships as qualifying income to a regulated investment company, effective for taxable years of the regulated investment company beginning after October 22, 2004. For taxable years of a regulated investment company beginning on or before October 22, 2004, very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.
We will treat each purchaser of units as having the same tax benefits without regard to the 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 will all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from 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 — Uniformity of Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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You will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.
      In addition to federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You will likely be required to file 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 property and conduct business in Kansas, Louisiana and Alabama. We may own property or conduct business in other states or foreign countries in the future. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.
The sale or exchange of 50% or more of our capital and profits interests will result in the termination of our partnership for federal income tax purposes.
      We will be considered to have terminated 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 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please 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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USE OF PROCEEDS
      We expect to receive net proceeds of approximately $100.2 million from the sale of 5,000,000 common units offered by this prospectus, after deducting estimated underwriting discounts and structuring fees but before paying estimated offering expenses. We base this amount on the initial public offering price of $21.50 per common unit.
      We intend to use the net proceeds of this offering to:
  •  distribute $58.7 million to affiliates of Williams, in part to reimburse Williams for capital expenditures relating to the assets contributed to us;
 
  •  provide $24.4 million to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;
 
  •  provide $12.8 million of additional working capital; and
 
  •  pay $4.3 million of expenses associated with the offering and related formation transactions.
The $12.8 million of additional working capital includes $7.4 million to offset an estimated balance of an equal amount of deferred revenues as of June 30, 2005. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
      We will not receive any proceeds from any common units to be sold by the selling unitholders upon any exercise of the underwriters’ option to purchase additional common units.

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CAPITALIZATION
      The following table shows:
  •  the historical capitalization of our predecessor as of March 31, 2005; and
 
  •  our pro forma capitalization as of March 31, 2005, as adjusted to reflect the offering of the common units and related transactions and the application of the net proceeds of this offering as described under “Use of Proceeds.”
      This table is derived from and should be read together with our historical and unaudited pro forma consolidated 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 March 31, 2005
     
        Pro Forma
    Actual   As Adjusted
         
    ($ in thousands)
Cash and cash equivalents
  $     $ 31,400 (a)
             
Long-term debt, including current portion:
               
 
Advances from Williams
  $ 190,291     $  
 
Our borrowings under Williams’ revolving credit facility
           
 
Working capital facility with Williams
           
             
     
Total long-term debt
    190,291        
             
Equity:
               
 
Owners’ equity
    16,979        
 
Held by public:
               
   
Common units
          77,148  
 
Held by the general partner and its affiliates:
               
   
Common units
          30,860  
   
Subordinated units
          108,008  
   
General partner interest
          4,408  
             
     
Total equity
    16,979       220,424  
             
     
Total capitalization
  $ 207,270     $ 220,424  
             
 
(a)  Excludes an additional $7.4 million in proceeds from this offering that we will retain for working capital purposes to offset an estimated balance of an equal amount of deferred revenues as of June 30, 2005. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

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DILUTION
      Dilution is the amount by which the offering price paid by purchasers of common units sold in this offering will exceed the net tangible book value per common unit after the offering. Based on the initial public offering price of $21.50 per common unit, on a pro forma basis as of March 31, 2005, after giving effect to the offering of common units and the related transactions, our net tangible book value was $220.4 million, or $15.43 per common unit. 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.
                   
Assumed initial public offering price per common unit
          $ 21.50  
 
Pro forma net tangible book value per common unit before the offering(a)
  $ 1.83          
 
Increase in net tangible book value per common unit attributable to purchasers in the offering
    13.60          
             
Less: Pro forma net tangible book value per common unit after the offering(b)
            15.43  
             
Immediate dilution in net tangible book value per common unit to purchasers in the offering
          $ 6.07  
             
 
(a)  Determined by dividing the total number of units (2,000,000 common units, 7,000,000 subordinated units, and the 2% general partner interest, which has a dilutive effect equivalent to 285,714 units) to be issued to our general partner and its affiliates for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities. Our general partner’s dilutive effect equivalent was determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of common and subordinated units outstanding divided by 98%) by our general partner’s 2% general partner interest.
(b)  Determined by dividing the total number of units (7,000,000 common units, 7,000,000 subordinated units, and the 2% general partner interest, which has a dilutive effect equivalent to 285,714 units) to be outstanding after the offering into our pro forma net tangible book value, after giving effect to the application of the net proceeds of the offering.
      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 millions)
General partner and its affiliates (a)(b)
    9,285,714       65.0 %     $124.5       53.7 %
New investors
    5,000,000       35.0       107.5       46.3  
                         
 
Total
    14,285,714       100.0 %     $232.0       100.0 %
                         
 
(a)  Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 2,000,000 common units, 7,000,000 subordinated units, and a 2% general partner interest having a dilutive effect equivalent to 285,714 units.
(b)  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 March 31, 2005 was $124.5 million.

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
General
Rationale for our Cash Distribution Policy
      Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it. Our available cash includes cash generated from the operation of our assets and businesses, which include the gathering, transporting and processing of natural gas and the fractionating and storing of NGLs, as described elsewhere in this prospectus. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash on a quarterly basis. Please read “How We Make Cash Distributions.” Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to such tax.
Limitations on Our Ability to Make Quarterly Distributions
      There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may become subject to limitations and restrictions and may be changed at any time, including:
  •  Our board of directors has broad discretion to establish reserves for the prudent conduct of our business and the establishment of those reserves could result in a reduction in the amount of cash available to pay distributions.
 
  •  Although our ability to make distributions is not currently restricted under Williams’ revolving credit agreement, Williams’ other debt instruments or our working capital facility with Williams, we or Williams may enter into future debt arrangements that could subject our ability to pay distributions to compliance with certain tests or ratios or otherwise restrict our ability to pay distributions.
 
  •  Our ability to make distributions of available cash will depend, to a significant extent, on Discovery’s ability to make cash distributions to us. In addition, although Discovery’s limited liability company agreement has been amended to provide for quarterly distributions of available cash, Discovery has no prior history of making distributions to its members. Discovery’s management committee, on which we are represented, also will have broad discretion to establish reserves for the prudent conduct of its business. The establishment of those reserves could result in a reduction in Discovery’s cash available to pay distributions, which could cause a corresponding reduction in the amount of our cash available to pay distributions.
 
  •  Even if our cash distribution policy is not modified, the amount of distributions we pay and the decision to make any distribution is at the discretion of our general partner, taking into consideration the terms of our partnership agreement.
 
  •  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.
 
  •  Although our partnership agreement requires us to distribute our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without approval of nonaffiliated common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units after the subordination period has ended. At the closing of this offering, Williams will own approximately 28.6% of the outstanding common units and 100% of the outstanding subordinated units.
Our Cash Distribution Policy May Limit Our Ability to Grow
      Because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. We intend generally to rely upon external financing sources, including borrowings and issuances of debt and equity securities, to fund our acquisition and growth capital expenditures. However, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

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Discovery’s Cash Distribution Policy
      A substantial portion of our cash available to pay distributions will be cash we receive as distributions from Discovery. Please read “— Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery for the Twelve-Month Period Ending June 30, 2006.” As in our partnership agreement, Discovery’s limited liability company agreement, as amended to be effective at the closing of this offering, provides for the distribution of available cash on a quarterly basis, with available cash defined to mean, for each fiscal quarter, cash generated from Discovery’s business less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law or any debt instrument or other agreement to which it is a party. Under Discovery’s limited liability company agreement, the amount of Discovery’s quarterly distributions, including the amount of cash reserves not distributed, will be determined by the members of Discovery’s management committee representing a majority-in-interest in Discovery. We will own a 40% interest in Discovery, and an affiliate of Williams will own a 26.7% interest in Discovery although the third member has an option to acquire a 6.7% interest in Discovery from Williams that expires October 31, 2005. Discovery’s limited liability agreement may only be amended with the unanimous approval of all its members.
Cash Distributions
Overview
      The amount of the minimum quarterly distribution is $0.35 per unit, or $1.40 per year. The amount of available cash from operating surplus, which we also refer to as cash available to pay distributions, needed to pay the minimum quarterly distribution on all of the common units and subordinated units and the 2% general partner interest to be outstanding immediately after this offering for one quarter and for four quarters will be approximately:
                           
        Minimum Quarterly
        Distribution
         
    Number of Units   One Quarter   Four Quarters
             
Common Units
    7,000,000     $ 2,450,000     $ 9,800,000  
Subordinated Units
    7,000,000       2,450,000       9,800,000  
2% General Partner Interest
          100,000       400,000  
                   
 
Total
    14,000,000     $ 5,000,000     $ 20,000,000  
                   
      The amounts in the table above will not change upon any exercise by the underwriters of their option to purchase additional common units from the selling unitholders.
Our Initial Distribution Rate
      We will pay the minimum quarterly distribution on all of our outstanding common and subordinated units for the twelve-month period ended June 30, 2006. Within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2005, we will 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 September 30, 2005 based on the actual length of the period.
      During the subordination period, before we make any quarterly distributions to subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages from prior quarters. Please read “How We Make Cash Distributions — Subordination Period.” The amount of the minimum quarterly distribution is $0.35 per unit, or $1.40 per year. However, we cannot guarantee that we will pay the minimum quarterly distribution or any amount on the common units in any quarter.
      As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. 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.

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      In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash from operating surplus to pay the minimum quarterly distribution on all of our outstanding common and subordinated units for each quarter through June 30, 2006. In those sections, we present two tables, including:
  •  “Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery,” in which we present certain operating assumptions for the four quarters ending June 30, 2006; and
 
  •  “Unaudited Pro Forma Cash Available to Pay Distributions,” in which we present the amount of available cash we would have generated in 2004 and in the twelve-month period ended March 31, 2005.
      Our pro forma available cash for 2004 and for the twelve-month period ended March 31, 2005 would have been sufficient to pay the minimum quarterly distribution of $0.35 per unit on all common and subordinated units and the 2% general partner interest to be outstanding following the completion of this offering.
      If we had completed the transactions contemplated in this prospectus on January 1, 2004, pro forma available cash generated during 2004 would have been approximately $23.2 million. If we had completed the transactions contemplated in this prospectus on April 1, 2004, pro forma available cash generated during the twelve-month period ended March 31, 2005 would have been approximately $21.1 million. These amounts of pro forma available cash generated would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common and subordinated units and the 2% general partner interest for 2004 and for the twelve-month period ended March 31, 2005.
      Pro forma cash available to pay distributions excludes any cash from working capital or other borrowings and cash on hand as of the closing date of this offering plus $10.0 million that is included in the cumulative calculation of operating surplus under our partnership agreement. As described in “How We Make Cash Distributions — Operating Surplus and Capital Surplus,” cash from these sources may also be used to pay distributions.
      As a result of the factors described in “— Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery for the Twelve-Month Period Ending June 30, 2006” and “— Assumptions and Considerations” below, we believe we will be able to pay the minimum quarterly distribution of $0.35 per unit on all common and subordinated units and the 2% general partner interest for each quarter in the twelve-month period ending June 30, 2006.
Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery for the Twelve-Month Period Ending June 30, 2006
      In order to fund the minimum quarterly distribution of $0.35 to our common and subordinated unitholders and the 2% distribution to our general partner over the four quarters ending June 30, 2006, our cash available to pay distributions must be at least $20.0 million over that period. We have calculated the minimum amount of Estimated Adjusted EBITDA Excluding Investment in Discovery for the twelve-month period ending June 30, 2006 necessary to generate cash available to pay distributions of $20.0 million over that period, which we refer to as the Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery. In calculating Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery, we have also calculated Discovery’s Estimated Adjusted EBITDA for the same period. In our case, we define Adjusted EBITDA Excluding Investment in Discovery as net income (loss) plus net interest (income) expense and depreciation and accretion less our equity earnings in Discovery plus the impairment of our investment in Discovery in 2004. We also adjust for certain non-cash, non-recurring items. In the case of Discovery, we define Adjusted EBITDA as net income plus interest (income) expense, depreciation and accretion, and we also adjust for certain non-cash, non-recurring items. Our equity share of Discovery’s Adjusted EBITDA is 40%. Adjusted EBITDA Excluding Investment in Discovery, in our case, and Adjusted EBITDA, in the case of Discovery, should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity or ability to service debt obligations.
      In the table below entitled “Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery,” we calculate that our Estimated Adjusted EBITDA Excluding Investment in Discovery must be approximately $0.1 million for the four quarters ending June 30, 2006 for us to be able to generate cash available to pay distributions of $20.0 million. In calculating the Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery, we have estimated that our 40% equity share of Discovery’s Estimated Adjusted EBITDA for the same period will be approximately $14.9 million. Although we believe that we will be able to achieve these results based on the assumptions and considerations set forth later in this section, we can give you no assurance that we will

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actually generate the Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery and estimated cash available to pay distributions of $20.0 million. There will likely be differences between these amounts and our actual results of operations and cash flows, and those differences could be material. If we are not able to achieve the Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery described above and if our estimate of our 40% equity share of Discovery’s Estimated Adjusted EBITDA for the twelve-month period ending June 30, 2006 is not realized, we may not be able to pay the full minimum quarterly distribution or any amount on our outstanding common and subordinated units.
      In calculating the Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery, we have included estimates of maintenance and expansion capital expenditures for the twelve-month period ending June 30, 2006. Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain current operations and that do not increase operating capacity or revenues from existing levels. Expansion capital expenditures consist of capital expenditures we expect to make to expand the operating capacity of our current operations. The Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery includes our assumption that Discovery will make expansion capital expenditures associated with the Tahiti pipeline lateral expansion project during the twelve-month period ending June 30, 2006 that will be funded by capital contributions from its members, including us. We will retain proceeds from this offering to make a capital contribution to Discovery to fund our share of an escrow account to fund capital expenditures relating to the Tahiti pipeline lateral expansion project. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business — The Discovery Assets.” We do not expect these expansion capital expenditures by Discovery to generate earnings or cash flow from operations in the twelve-month period ending June 30, 2006, so they are not necessary to achieve Discovery’s Estimated Adjusted EBITDA. The Tahiti pipeline lateral expansion project is subject to “project sanctioning” which means the Tahiti producers must still formally decide to proceed with the project.
      You should read “— Assumptions and Considerations” below for a discussion of the material assumptions underlying our belief that we will be able to generate the Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery and that Discovery will be able to generate Estimated Adjusted EBITDA in the amount disclosed for the twelve-month period ending June 30, 2006. Our belief is based on certain assumptions and 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 over the twelve-month period ending June 30, 2006. The assumptions we disclose are those that we believe are significant to our ability to generate the Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery and Discovery’s ability to generate the amount of its Estimated Adjusted EBITDA that we disclose. If these estimates prove to be materially incorrect, we may not be able to pay the full minimum quarterly distribution or any amount on our outstanding common and subordinated units.
      Our Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Estimated Adjusted EBITDA for the twelve-month period ending June 30, 2006 have been prepared by our management. Our independent auditors have not examined, compiled, or otherwise applied procedures to our Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery or Discovery’s Estimated Adjusted EBITDA for the twelve-month period ending June 30, 2006 and, accordingly, do not express an opinion or any other form of assurance on these estimates.
      When considering our Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Estimated Adjusted EBITDA for the twelve-month period ending June 30, 2006, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” beginning on page 15, and elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our and Discovery’s financial condition and consolidated results of operations to vary significantly from those set forth in the table below. In addition, we do not undertake any obligation to release publicly the results of any future revisions we may make to these estimates or to update these estimates to reflect events or circumstances after the date of this prospectus. Therefore, we caution you not to place undue reliance on this information.

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Williams Partners L.P.
Minimum Estimated Adjusted EBITDA
Excluding Investment in Discovery
      The following table illustrates our estimate of the minimum amount of Estimated Adjusted EBITDA Excluding Investment in Discovery we must generate to have $20.0 million of cash available to pay distributions. This is the amount required to pay the minimum quarterly distribution to our unitholders and our general partner for the twelve-month period ending June 30, 2006, assuming that the offering had been consummated at the beginning of such period. We explain each of the adjustments presented below in the footnotes to the table. All of the amounts for the twelve-month period ending June 30, 2006 in the table and footnotes below are estimates.
           
    Twelve-Month
    Period Ending
    June 30, 2006
     
    (In thousands,
    except per
    unit amounts)
Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery(a)
  $ 61  
Less:
       
 
Cash interest expense(b)
    (934)  
 
Maintenance capital expenditures(c)
    (6,418)  
 
Expansion capital expenditures(d)
    0  
 
Capital contributions to Discovery(e)
    (25,400)  
Add:
       
 
Estimated adjusted available cash from Discovery(f)
    14,080  
 
Capital expenditure and other reimbursements from Williams under the omnibus agreement(g)
    10,200  
 
Net proceeds from this offering retained to fund capital contributions to Discovery related to the Tahiti pipeline lateral expansion project(h)
    24,400  
 
Cash benefit from natural gas purchase contract(i)
    4,011  
       
Minimum cash available to pay distributions at Williams Partners L.P. 
  $ 20,000  
       
Estimated Cash Distributions
       
 
Annualized minimum quarterly distribution per unit
  $ 1.400  
       
 
Distributions to public common unitholders(j)
  $ 7,000  
 
Distributions to The Williams Companies, Inc. and Affiliates(j)
    13,000  
       
 
Total Distributions Paid
  $ 20,000  
       
 
(a) Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery for the twelve-month period ending June 30, 2006 represents the minimum amount of Estimated Adjusted EBITDA Excluding Investment in Discovery necessary to generate $20.0 million of cash available to pay distributions. If we generate $20.0 million of estimated cash available to pay distributions for the twelve-month period ended June 30, 2006, we will be able to pay the minimum quarterly distribution on all of our outstanding common and subordinated units. For the years ended December 31, 2003 and 2004 and the twelve-month period ended March 31, 2005 we generated pro forma Adjusted EBITDA Excluding Investment in Discovery of approximately $9.2 million, $10.1 million and $8.5 million, respectively (which amounts reflect the $1.6 million of net incremental general and administrative expenses that we would have incurred as a result of becoming a separate public entity). Please read “—Pro Forma Cash Available to Pay Distributions for the Year Ended December 31, 2004 and the Twelve-Month Period Ended March 31, 2005.”
 
(b) Reflects estimated cash interest expense for two outstanding letters of credit and for interest expense associated with commitment fees for our $75 million borrowing limit under Williams’ revolving credit facility and our $20 million working capital facility with Williams. This amount is comparable to the pro forma cash interest expense for these commitment fees for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005. The advances from affiliate reflected in our historical balance sheet will be forgiven by Williams prior to the closing of this offering. As a result, the estimated cash interest expense does not include any amount for interest on these balances.
 
(c) Reflects estimated maintenance capital expenditures for the twelve-month period ending June 30, 2006 of $6.4 million, including $3.1 million in KDHE-related cavern compliance expenditures at our Conway storage facility, $1.9 million in connection with the installation of double liners on two brine ponds at our Conway

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storage facility and $1.4 million of other items. We expect that the $3.1 million of KDHE-related cavern compliance expenditures will be reimbursed by Williams under the omnibus agreement, as described in item (2) of Note (g) below. As a result, we estimate that the net amount to us of these maintenance capital expenditures will be $3.3 million. In the omnibus agreement, Williams will agree to reimburse us for a total of $14.0 million of environmental and related liabilities for a period of three years, subject to certain exceptions. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.” We expect to fund maintenance capital expenditures that are not reimbursed under the omnibus agreement with cash from operations. For the years ended December 31, 2003 and December 31, 2004 and the twelve-month period ended March 31, 2005 our maintenance capital expenditures were $1.2 million, $1.6 million and $1.7 million, respectively. The estimated increase in maintenance capital expenditures for the twelve-month period ending June 30, 2006 is primarily attributable to one-time costs associated with KDHE-related cavern compliance expenditures.
 
(d) In our estimate for the twelve-month period ending June 30, 2006, as in 2004 and 2003, all of our expansion capital expenditures have been and will be made by Discovery. Other than Discovery’s Tahiti pipeline lateral expansion project, we do not have any additional expansion capital expenditures planned.
 
(e) Reflects estimated capital contributions to be made to Discovery for the twelve-month period ending June 30, 2006 to fund the following:

  •  Our share ($24.4 million) of funds to be deposited in a Discovery escrow account that will be used for funding costs associated with Discovery’s construction of the Tahiti pipeline lateral expansion project (we expect $10.0 million to be drawn from the Discovery escrow account during the twelve month-period ending June 30, 2006 to cover our 40% share of the estimated $25.0 million of expenditures by Discovery for the Tahiti pipeline lateral expansion project during that period). We expect our share of the total construction cost of Discovery’s Tahiti pipeline lateral expansion project to be $27.8 million, with the balance above $24.4 million to be contributed to Discovery by June 30, 2008. In the omnibus agreement Williams will agree to reimburse us for the excess (up to $3.4 million) of our 40% share of the expected total cost of the Tahiti pipeline lateral expansion project above the amount of the required escrow deposit attributable to our 40% interest in Discovery.
 
  •  Our 40% share ($0.8 million) of marshland restoration costs relating to the construction of Discovery’s pipeline.
 
  •  Our 40% share ($0.2 million) of the cost of the repair or replacement of an emission-control flare at the Paradis fractionation facility.
The costs described in the second and third bullet points above will count against the $14.0 million of total environmental and related costs for which Williams will agree to reimburse us under the omnibus agreement. No significant additional expansion projects are currently planned at Discovery other than the Tahiti pipeline lateral expansion project. As other future opportunities for expansion develop and cash calls are made by Discovery, we expect to fund capital contributions to Discovery necessary to fund its expansion capital expenditures through borrowings or the issuance of debt or equity securities or a combination of both. Pro forma capital contributions to Discovery for the years ended December 31, 2003 and December 31, 2004 and the twelve-month period ended March 31, 2005 were $3.7 million, $15.3 million and $15.2 million, respectively. These pro forma capital contributions were used by Discovery to fund expansion capital expenditures for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005 related to the construction of gathering laterals to the Front Runner, Rock Creek and Tarantula prospects completed in 2004 and the market expansion project completed in 2005.
 
(f) Estimated available cash from Discovery is derived from Discovery’s Estimated Adjusted EBITDA for the twelve-month period ending June 30, 2006. For Discovery, we define Adjusted EBITDA as net income plus interest (income) expense, depreciation and accretion, and we also adjust for certain non-cash, non-recurring items. Although Discovery’s limited liability company agreement has been amended to provide for quarterly distributions of available cash, Discovery has historically retained all of its cash generated from operations to fund its expansion capital expenditures and has not made any cash distributions to its members. Under Discovery’s limited liability company agreement, the amount of Discovery’s quarterly distributions, including the amount of cash reserves not distributed, will be determined by the members of Discovery’s management committee representing a majority-in-interest in Discovery. The amount of Discovery’s estimated cash available to pay distributions assumes that no general cash reserves will be established by Discovery’s management committee during the twelve-month period ending June 30, 2006.

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Discovery Producer Services LLC
           
    Twelve Months
    Ended
    June 30, 2006
     
Estimated Adjusted EBITDA(1)
  $ 37,229  
Less:
       
 
Maintenance capital expenditures(2)
    (3,530 )
 
Expansion capital expenditures(3)
    (27,046 )
Add:
       
 
Capital contribution from members(4)
    27,546  
 
Cash retained for certain maintenance capital expenditures(5)
    1,000  
       
Estimated cash available to pay distributions to members
  $ 35,199  
       
Williams Partners L.P. 40% Interest
  $ 14,080  
       
     
 
  (1)  We estimate that Discovery will generate Estimated Adjusted EBITDA for the twelve-month period ending June 30, 2006 of approximately $37.2 million. This amount is approximately $3.3 million more than Discovery’s Adjusted EBITDA for the year ended December 31, 2004 and $2.6 million more than Discovery’s Adjusted EBITDA for the twelve-month period ended March 31, 2005. The estimated increase from Discovery’s Adjusted EBITDA for the year ended December 31, 2004 is primarily attributable to (i) an anticipated $6.7 million in increased gathering revenues resulting from an estimated 8.1% increase in average gathered volumes of natural gas on Discovery compared to 2004 attributable to new production from the Front Runner, Rock Creek and Tarantula prospects connected in late 2004, offset by declines in production from existing connected wells, (ii) an anticipated $1.8 million increase in revenues attributable to the market expansion project which went into service in June 2005 and established connections to three additional interstate pipeline systems providing new market alternatives to Discovery’s customers and incremental fees to Discovery, (iii) a $2.8 million decrease in revenues attributable to a decline in estimated processing margins, and (iv) a $2.0 million increase in operating expenses related to increased volumes and higher fuel costs.
 
  (2)  Reflects estimated maintenance capital expenditures of $3.5 million in the twelve-month period ending June 30, 2006, including (i) $1.0 million for compressor modification expenditures at Discovery’s Larose gas processing plant and (ii) $0.5 million for the repair or replacement of an emission-control flare at the Paradis fractionation facility. We believe that the specific maintenance capital expenditures described above are one-time costs and that Discovery’s maintenance capital expenditures will return to historical levels in subsequent future periods. For the years ended December 31, 2003 and December 31, 2004 and the twelve-month period ended March 31, 2005, Discovery’s maintenance capital expenditures were $2.8 million, $0.8 million and $2.5 million, respectively.
 
  (3)  Reflects estimated expansion capital expenditures in the twelve-month period ending June 30, 2006 of (i) $25.0 million to fund the construction of the Tahiti pipeline lateral expansion project and (ii) $2.0 million to fund marshland restoration costs relating to the construction of the Discovery pipeline. Discovery, in 2005, will be required to create an escrow account to cover a substantial portion of the total expenditures for the construction of the Tahiti pipeline lateral expansion project attributable to Williams’ and our share of those costs. Our 40% share of funds to be deposited in a Discovery escrow account that will be used for funding costs associated with Discovery’s construction of the Tahiti pipeline lateral expansion project will be $24.4 million (we expect $10.0 million to be drawn from the Discovery escrow account during the twelve month-period ending June 30, 2006 to cover our 40% share of the estimated $25.0 million of expenditures by Discovery for the Tahiti pipeline lateral expansion project during that period). We will retain net proceeds from this offering to make a capital contribution to fund our share ($24.4 million) of this escrow deposit. We do not expect these expansion capital expenditures to generate any earnings or cash flow from operations during the twelve-month period ending June 30, 2006. We expect the total construction cost of the Tahiti pipeline lateral expansion project to be $69.5 million, with the remaining amount to be expended by June 30, 2008. In the omnibus agreement, Williams will agree to reimburse us for up to $3.4 million, which represents the excess of our 40% share ($27.8 million) of the expected total construction cost of the Tahiti pipeline lateral expansion project above the amount of the escrow deposit, and our 40% share ($0.8 million) of the expected marshland restoration costs. Discovery will continue to pursue expansion opportunities, however no significant expansion projects other than the Tahiti pipeline lateral expansion project are currently planned and Williams will not reimburse us for any

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  other expansion capital expenditures. As opportunities for expansion develop and cash calls are made by Discovery, we expect to fund capital contributions to Discovery necessary to fund its expansion capital expenditures through borrowings or the issuance of debt or equity securities or a combination of both. Discovery’s expansion capital expenditures for the years ended December 31, 2003 and December 31, 2004 and the twelve-month period ended March 31, 2005 were $9.3 million, $38.3 million and $38.0 million, respectively. The expansion capital expenditures for the year ended December 31, 2004 and the twelve month period ended March 31, 2005 were related to the construction of gathering laterals to the Front Runner, Rock Creek and Tarantula prospects completed in 2004 and the market expansion project completed in 2005.
 
  (4)  The $27.5 million in capital contributions from Discovery members includes (i) $25.0 million and $2.0 million, respectively, to fund the expansion capital expenditures referred to in Note (f)(3) above and (ii) $0.5 million to fund the repair or replacement of an emission-control flare at the Paradis fractionation facility. The $25.0 million of capital contribution to fund the Tahiti pipeline lateral expansion project includes only the amounts expected to be expended by Discovery in the twelve-month period ending June 30, 2006. We expect our and Williams’ share of this $25.0 million amount to be deposited by Discovery in an escrow account that will be drawn down as the expenditures are incurred. The $25.0 million amount does not include additional capital contributions during that period that will also be deposited in this escrow account and that will be used to fund Williams’ and our share of construction costs expected to be expended after June 30, 2006. We expect that Discovery will fund its expansion capital expenditures by making cash calls upon its members and, with the exception of the cost of the repair or replacement of an emission-control flare at its Paradis fractionation facility, we expect that Discovery will fund its maintenance capital expenditures with cash flow from operations.
 
  (5)  Historically, Discovery has retained all of its cash generated from operations. All of this retained cash is associated with Discovery’s operations prior to this offering. Discovery will make a one-time distribution to its members of a portion of this retained cash, representing approximately 75% of its cash on hand, for the benefit of its existing members prior to the closing of this offering. We will not receive any portion of this one-time distribution. After this one-time distribution, Discovery will have approximately $15.3 million of cash on hand which it will use to fund certain expected or potential expenses (we will not receive any part of this distribution because it will occur prior to our becoming a member of Discovery). The amount retained by Discovery will fund $1.0 million of the $3.5 million of estimated maintenance capital expenditures to pay for compressor modifications at Discovery’s Larose gas processing plant. The amount retained by Discovery will also fund $4.0 million to pay for potential shipper refunds that may be required by FERC for retained system gas gains and the over-recovery of lost and unaccounted-for gas at Discovery, $2.0 million to cover outstanding accounts payable and $8.3 million for working capital. After this offering, Discovery will make quarterly distributions of available cash to its members instead of retaining all cash from operations. (See Note (f) above)

(g) In the omnibus agreement, Williams will agree to reimburse us for, among other things, up to $14.0 million of environmental and related costs for a period of three years following the offering. We estimate that we will receive reimbursement of $6.6 million of these environmental and related costs in the twelve-month period ended June 30, 2006. These reimbursements include (1) restoration activities due to the partial erosion of the Carbonate Trend pipeline overburden, which we currently estimate at $2.5 million, and which we will record as an expense, (2) $3.1 million for capital expenditures related to KDHE-related cavern compliance at our Conway storage facility (see Note (c) above), (3) our 40% share of marshland restoration costs associated with the construction of Discovery’s pipeline, which we estimate will be $0.8 million (see Note (e) above), and (4) our 40% share of the cost of the repair or replacement of an emission-control flare at our Paradis fractionation facility, which we estimate will be $0.2 million (see Note (e) above). In addition, Williams will agree in the omnibus agreement to provide a five-year partial credit for general and administrative expenses incurred on our behalf, which we estimate will be $3.6 million for this period (the amount of this credit in 2005 will be $3.9 million pro rated for the period from the closing of this offering through year end, the amount of the credit will be $3.2 million in 2006 and will decrease by approximately $800,000 in each subsequent year). The total of $10.2 million of capital expenditure and other reimbursements from Williams under the omnibus agreement described above does not include $1.2 million for expected payments of accrued environmental liabilities during the twelve-month period ending June 30, 2006 relating to the environmental remediation activities at Conway that Williams will agree to reimburse us for under the omnibus agreement. This $1.2 million for expected payments of accrued environmental liabilities is not recorded as an adjustment to Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery because the payments were expensed in a prior period. As a result, the corresponding indemnification payment from Williams in respect of

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such liability is also not included as an adjustment to Minimum Adjusted EBITDA Excluding Investment in Discovery. This $1.2 million of additional reimbursement payments, as well as the estimated $6.6 million of reimbursement payments described above, will be applied toward the $14.0 million “cap” for total environmental and related costs that Williams will agree to reimburse us for under the omnibus agreement. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.” There were no such reimbursements from Williams for the years ended December 31, 2003 and December 31, 2004 and the twelve-month period ended March 31, 2005. We generally expect to fund future maintenance capital expenditures, other than those reimbursed under the omnibus agreement, with cash from operations.
 
(h) Discovery will be required to deposit funds in an escrow account that will be used to fund the costs of the Tahiti pipeline lateral expansion project. We will retain net proceeds from this offering to make a capital contribution to fund our share ($24.4 million) of this escrow deposit.
 
(i) Upon the closing of this offering, Williams will transfer to us a contract for the purchase of natural gas from a wholly owned subsidiary of Williams through December 31, 2007 at a price not to exceed a specified price. This natural gas purchase contract will mitigate fuel price risk under a fractionation contract at our Conway fractionation facility that also will terminate on December 31, 2007. Our fuel expense will not reflect the cash benefit of this gas purchase contract due to the non-cash amortization of this contract to operating and maintenance expense. As a result, our Minimum Estimated Adjusted EBITDA Excluding Investment in Discovery for the twelve-months ending June 30, 2006 does not reflect the $4.0 million cash benefit of this natural gas purchase contract. The amount of the cash benefit of this gas purchase contract on a pro forma basis was approximately $2.8 million for the year ended December 31, 2004 and approximately $2.9 million for the twelve-month period ended March 31, 2005 due to lower natural gas prices during those periods. For the twelve-months ending June 30, 2006 the estimated cash benefit of this contract was calculated as the sum of the monthly differences between the forward curve for the NYMEX Henry Hub natural gas price, adjusted for Conway delivery (the average of which was $6.98 per MMBtu for the twelve-month period ending June 30, 2006) and the maximum price specified in this gas purchase contract, multiplied by the monthly purchase quantity of 80,000 MMBtu. For the year ended December 31, 2004 and the twelve-month period ended March 31, 2005 the pro forma cash benefit of this contract was calculated as the sum of the monthly differences between the actual amounts paid for fuel gas purchases (the average of which was $5.72 per MMBtu and $5.87 per MMBtu, respectively) and the pro forma cash settlement amounts for fuel gas purchases calculated using the maximum price specified in this gas purchase contract, multiplied by the actual monthly purchase quantity of 80,000 MMBtu. This natural gas purchase contract meets the definition of a derivative and is subject to the accounting requirements of Statement of Financial Accounting Standards (SFAS) No.133 “Accounting for Derivative Instruments and Hedging Activities”. However, this gas purchase contract also meets the criteria for the normal purchases and normal sales exemption of SFAS No. 133 and, accordingly, will not be subject to “mark-to-market” adjustments. The initial expenditure required to enter into the contract contributed to us by Williams will be amortized to operating and maintenance expense over its contract term, based on the fair value by contract month. The termination of this gas purchase contract on December 31, 2007 coincides with the termination of the underlying fractionation customer contract. As a result we do not anticipate that the termination of this natural gas purchase contract will have a material adverse effect on our financial condition or results of operations.
 
(j) The table below sets forth the assumed number of outstanding common units and subordinated units upon the closing of this offering, the full minimum quarterly distributions payable on the outstanding common units and subordinated units and the amount payable on the 2% general partner interest for the twelve-month period ending June 30, 2006.

                           
    Distributions
     
    Number of   Per    
    Units   Unit   Aggregate
             
Estimated distributions on publicly held common units
    5,000,000     $ 1.40     $ 7,000,000  
Estimated distributions on common units held by Williams and its affiliates
    2,000,000       1.40       2,800,000  
Estimated distributions on subordinated units held by Williams and its affiliates
    7,000,000       1.40       9,800,000  
                   
 
Total distributions on units
    14,000,000       1.40       19,600,000  
                   
Estimated distribution on 2% general partner interest
                    400,000  
                   
 
Total
                  $ 20,000,000  
                   

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Pro Forma Cash Available to Pay Distributions for the Year Ended December 31, 2004 and the Twelve-Month Period Ended March 31, 2005
      The following table illustrates, on a pro forma basis, for the year ended December 31, 2004 and for the twelve-month period ended March 31, 2005, the amount of cash available to pay distributions to our unitholders, assuming, in each case, that the offering and the related transactions had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to those adjustments.
      We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available to pay distributions 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.
Williams Partners L.P.
Unaudited Pro Forma Cash Available to Pay Distributions
                   
        Twelve Months
    Year Ended   Ended
    December 31,   March 31,
    2004   2005
         
    (In thousands)
Net Cash Provided (Used) by Operating Activities
  $ 2,703     $ (691 )
 
Interest expense(a)
    12,476       12,370  
 
Net changes in working capital accounts including net changes in noncurrent assets & liabilities(b)
    (3,452 )     (1,531 )
             
Pro Forma Adjusted EBITDA Excluding Investment in Discovery
    11,727       10,148  
Less:
               
 
Pro forma additional expense of being a public company, net of credit(c)
    (1,600 )     (1,600 )
 
Pro forma cash interest expense(d)
    (1,342 )     (1,537 )
 
Maintenance capital expenditures(e)
    (1,622 )     (1,739 )
 
Expansion capital expenditures(f)
    0       0  
 
Pro forma capital contributions to Discovery(g)
    (15,308 )     (15,209 )
Add:
               
 
Pro forma cash benefit from natural gas purchase contract(h)
    2,800       2,946  
 
Pro forma cash available from Discovery(i)
    13,228       12,844  
 
Pro forma borrowings to fund capital contributions to Discovery(j)
    15,308       15,209  
             
Pro forma cash available to pay distributions at Williams Partners L.P. 
  $ 23,191     $ 21,062  
             
Pro Forma Cash Distributions
               
 
Annualized minimum quarterly distribution per unit
  $ 1.400     $ 1.400  
             
 
Distributions to public common unitholders(k)
  $ 7,000     $ 7,000  
 
Distributions to Williams and its affiliates(k)
    13,000       13,000  
             
 
Total Distributions
  $ 20,000     $ 20,000  
             
Excess(l)
  $ 3,191     $ 1,062  
             
 
(a) The interest expense included in the historical financial statements of the Williams Partners Predecessor is comprised primarily of interest associated with advances from an affiliate. Because these advances will be forgiven prior to the closing of this offering, we have adjusted pro forma cash available to pay distributions to reflect the elimination of this interest expense.
 
(b) We will fund working capital requirements through cash flow from operations, proceeds from this offering and borrowings under our $20 million working capital facility with Williams.
 
(c) Upon completion of this offering, we anticipate incurring incremental general and administrative costs related to becoming a separate public entity, such as costs associated with business development, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees and incremental insurance costs of approximately $5.5 million per year. In the omnibus agreement, Williams will agree to provide a five-year partial credit for general and administrative expenses incurred on our behalf. In 2005, the amount of this credit will be $3.9 million, which will be pro rated for the period from the closing of this offering through year end. The amount of the credit will be $3.2 million in 2006 and will decrease

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by $800,000 in each subsequent year. As a result, for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005, we would have incurred incremental general and administrative expenses of $1.6 million, net of the $3.9 million credit provided by Williams.
 
(d) Reflects (1) actual cash interest expenses of $0.5 million for the year ended December 31, 2004 and $0.7 million for the twelve-month period ended March 31, 2005 for two letters of credit, (2) additional pro forma interest expense associated with commitment fees for our $75 million borrowing limit under Williams’ revolving credit facility and under our $20 million working capital facility with Williams of $0.3 million for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005 and (3) additional pro forma interest expense of $0.6 million for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005 associated with the pro forma borrowings described in Note (j) below. The additional pro forma interest expense was calculated using the interest rate associated with borrowings under Williams’ revolving credit facility at December 31, 2004 of 7.373%. The interest rate associated with these borrowings at June 30, 2005 would have been 5.46% and the pro forma interest expense amount related to these borrowings, calculated using this rate, would have been approximately $0.4 million for both periods.
 
(e) Reflects actual maintenance capital expenditures of $1.6 million for the year ended December 31, 2004 and $1.7 million for the twelve-month period ended March 31, 2005. Approximately half of each such amount was associated with relining a brine pond at our Conway storage facility.
 
(f) The partnership had no expansion capital expenditures for the year ended December 31, 2004 and the twelve-months ended March 31, 2005.
 
(g) Reflects pro forma capital contributions to Discovery to pay for our 40% share of Discovery’s actual expansion capital expenditures for the periods presented. Discovery historically funded its expansion capital expenditures with cash from operations.
 
(h) Upon the closing of this offering, Williams will transfer to us a contract for the purchase of natural gas through December 31, 2007 at a price not to exceed a specified price from a wholly owned subsidiary of Williams. This natural gas purchase contract will mitigate the fuel price risk under a fractionation contract at our Conway fractionation facility that also will terminate on December 31, 2007. Our fuel expense will not reflect the cash benefit of this gas purchase contract due to the non-cash amortization of this contract to operating and maintenance expense. As a result, our pro forma Adjusted EBITDA Excluding Investment in Discovery for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005 does not reflect the cash benefit of this natural gas purchase contract for these periods of $2.8 million and $2.9 million, respectively. For the twelve-months ending June 30, 2006 the estimated cash benefit of this contract was calculated as the sum of the monthly differences between the forward curve for the NYMEX Henry Hub natural gas price, adjusted for Conway delivery (the average of which was $6.98 per MMBtu for the twelve-month period ending June 30, 2006) and the maximum price specified in this gas purchase contract, multiplied by the monthly purchase quantity of 80,000 MMBtu. For the year ended December 31, 2004 and the twelve-month period ended March 31, 2005 the pro forma cash benefit of this contract was calculated as the sum of the monthly differences between the actual amounts paid for fuel gas purchases (the average of which was $5.72 per MMBtu and $5.87 per MMBtu, respectively) and the pro forma cash settlement amounts for fuel gas purchases calculated using the maximum price specified in this gas purchase contract, multiplied by the actual monthly purchase quantity of 80,000 MMBtu. This natural gas purchase contract meets the definition of a derivative and is subject to the accounting requirements of SFAS No. 133. However, this gas purchase contract also meets the criteria for the normal purchases and normal sales exemption of SFAS No. 133 and, accordingly, will not be subject to “mark-to-market” adjustments. The initial expenditure required to enter into the contract contributed to us by Williams will be amortized to operating and maintenance expense over its contract term, based on the fair value by contract month. The termination of this gas purchase contract on December 31, 2007 coincides with the termination of the underlying fractionation customer contract. As a result we do not anticipate that the termination of this natural gas purchase contract will have a material adverse effect on our financial condition or results of operations.
 
(i) Discovery’s pro forma cash available to pay distributions to members for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005 is derived from Discovery’s Adjusted EBITDA for those respective periods. For Discovery, we define Adjusted EBITDA as net income plus interest (income) expense, depreciation and accretion, and we also adjust for certain non-cash, non-recurring items. Although Discovery’s limited liability company agreement has been amended to provide for quarterly distributions of available cash, Discovery has historically retained all of its cash generated from operations to fund its expansion capital expenditures and has not made any cash distributions to its members.

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Discovery Producer Services LLC
                   
        Twelve Months
    Year Ended   Ended
    December 31,   March 31,
    2004   2005
         
    (In thousands)
Net Cash Provided by Operating Activities
  $ 35,623     $ 32,511  
 
Interest (income)
    (550 )     (782 )
 
Net changes in working capital accounts including net changes in noncurrent assets & liabilities(1)
    (1,158 )     2,878  
             
Adjusted EBITDA
    33,915       34,607  
Less:
               
 
Maintenance capital expenditures(2)
    (845 )     (2,497 )
 
Expansion capital expenditures(3)
    (38,270 )     (38,023 )
Add:
               
 
Pro forma capital contribution from members(4)
    38,270       38,023  
             
Pro forma cash available to pay distributions to members
  $ 33,070     $ 32,110  
             
Williams Partners L.P. 40% Interest
  $ 13,228     $ 12,844  
             
     
 
  (1)  Discovery will fund its working capital requirements from cash retained at the closing of this offering and cash flow from operations.
 
  (2)  Reflects actual maintenance capital expenditures for the periods presented. For the twelve-month period ended March 31, 2005, $1.7 million of this amount represents the purchase of three residue compressors that were previously leased.
 
  (3)  Reflects Discovery’s actual expansion capital expenditures related primarily to the construction of gathering laterals to the Front Runner, Rock Creek and Tarantula prospects completed in 2004 and the market expansion project completed in 2005.
 
  (4)  Reflects assumed pro forma capital contributions from members to fund expansion capital expenditures.
(j) Assumes pro forma capital contributions to Discovery were funded entirely through borrowings. The pro forma interest associated with these pro forma borrowings are described in Note (d) above. In the future, we expect to fund expansion capital expenditures through borrowings, the issuance of debt or equity securities or a combination thereof.
 
(k) The table below sets forth the assumed number of outstanding common units and subordinated units upon the closing of this offering and the minimum quarterly distribution per unit and aggregate distribution amounts payable on the outstanding common and subordinated units and the 2% general partner interest on a pro forma basis for the year ended December 31, 2004 and the twelve-month period ended March 31, 2005.
                           
    Distributions
     
    Number of    
    Units   Per Unit   Aggregate
             
Pro forma distributions on publicly held common units
    5,000,000     $ 1.40     $ 7,000,000  
Pro forma distributions on common units held by Williams and its affiliates
    2,000,000       1.40       2,800,000  
Pro forma distributions on subordinated units held by Williams and its affiliates
    7,000,000       1.40       9,800,000  
                   
 
Total distributions on units
    14,000,000       1.40       19,600,000  
                   
Pro forma distribution on 2% general partner interest
                    400,000  
                   
 
Total
                  $ 20,000,000  
                   
(l) Our pro forma available cash for the year ended December 31, 2004 and for the twelve-month period ended March 31, 2005 would have been sufficient to allow us to pay the full minimum quarterly distributions on all of the common and subordinated units and the 2% general partner interest.

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Assumptions and Considerations
      We believe that we will generate sufficient cash flow to enable us to pay the minimum quarterly distributions on all common and subordinated units for each quarter in the twelve-month period ending June 30, 2006. Our belief is based on the following specific assumptions with respect to the twelve-month period ending June 30, 2006, which we believe to be reasonable:
Revenue and Operations
  •  Average gathered volumes of natural gas on Discovery will be at least 376,200 MMBtu/d, compared to 348,142 MMBtu/d and 378,745 MMBtu/d for the years ended December 31, 2004 and December 31, 2003, respectively. The 8.1% increase in volumes compared to 2004 and 0.7% decrease in volumes compared to 2003 are attributable to new production from the Front Runner, Rock Creek and Tarantula prospects connected in late 2004, offset by declines in production from existing connected wells.
 
  •  Discovery will receive incremental revenues of approximately $1.8 million from the market expansion project which was placed in service in June 2005.
 
  •  Average gross processing margins at Discovery’s Larose gas processing plant will be at least $0.14 per MMBtu, compared to $0.17 MMBtu for each of the years ended December 31, 2004 and December 31, 2003, respectively. The 17% decrease from 2004 and 2003 margins is attributable to lower projected spreads between NGL prices and natural gas prices and lower processing fees for recently connected volumes.
 
  •  Average volumes fractionated for our account at the Conway fractionator will be at least 40,700 bpd, compared to 39,062 bpd and 34,989 bpd for the years ended December 31, 2004 and December 31, 2003, respectively. The 4% increase compared to 2004 and 16% increase compared to 2003 are attributable to increased volumes due to the election by one of our long-term customers to deliver its mixed NGLs to the Mid-Continent region versus the Gulf Coast region due to favorable market conditions in the Mid-Continent region. For a description of this contractual arrangement please read “Business — The Conway Assets.”
 
  •  Storage revenues at our Conway storage facilities will be at least $18.7 million, compared to $15.3 million and $11.6 million for the years ended December 31, 2004 and December 31, 2003, respectively. The 22% increase compared to 2004 is attributable to a rate increase under a long-term contract and a significant increase in short-term storage rates. The 61% increase compared to 2003 is attributable to higher average per-unit storage rates reflecting the pass through of increased costs to comply with KDHE regulations.
 
  •  Average volumes of natural gas shipped on our Carbonate Trend pipeline will be at least 40,000 MMBtu/d, compared to 49,981 MMBtu/d and 67,638 MMBtu/d for the years ended December 31, 2004 and 2003 respectively. The 20% decrease compared to 2004 and 41% decrease compared to 2003 are attributable to production declines from existing connected wells, partially offset by anticipated recompletions and workovers at existing connected wells.
 
  •  We will not incur any negative margins from managing product imbalances at our Conway fractionator and our Conway storage facilities. We realized a positive margin related to our management of product imbalances at our Conway facilities of $1.8 million for 2004 and we did not realize any such margin in 2003. Margins related to our management of product imbalances cannot be reliably estimated due to uncertainty related to the timing and amounts of the underlying volumes. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations” for a discussion of these activities.
Expenses and Capital Expenditures
  •  Our maintenance capital expenditures will be approximately $6.4 million, compared to $1.6 million and $1.2 million for the years ended December 31, 2004 and December 31, 2003, respectively. Maintenance capital expenditures for the twelve-month period ended June 30, 2006 include approximately $3.1 million in connection with KDHE-related cavern compliance costs, approximately $1.9 million in connection with the installation of double-liners for two brine ponds both at our Conway storage facilities and $1.4 million of other items. We expect that the $3.1 million of KDHE-related cavern compliance expenditures will be reimbursed by Williams under the omnibus agreement. As a result, the net amount to us of these maintenance capital expenditures will be $3.3 million.
 
  •  Operating and maintenance expenses will be approximately $28.2 million, compared to $19.4 million and $14.0 million for the years ended December 31, 2004 and December 31, 2003, respectively. Our estimate of an increase in operating and maintenance expenses compared to prior periods is attributable primarily to

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  (1) the cost of restoration activities in connection with partial erosion of the overburden along our Carbonate Trend pipeline, which we estimate will be approximately $2.5 million, (2) expenses attributable to increased fuel costs at our Conway fractionator and (3) increased costs of complying with a KDHE regulation.

  •  Discovery’s maintenance capital expenditures will be approximately $3.5 million, which includes (1) $1.0 million for compressor modification expenditures and (3) $0.5 million for the repair or replacement of an emission-control flare at the Paradis fractionation facility. Discovery’s maintenance capital expenditures were $0.8 million and $2.8 million for the years ended December 31, 2004 and December 31, 2003. Our 40% share of these maintenance capital expenditures will be $1.4 million, compared to a 40% share of $0.3 million and $1.1 million for the years ended December 31, 2004 and 2003, respectively.
 
  •  Discovery’s expansion capital expenditures will be approximately $27.0 million, which includes $25.0 million for the construction of the Tahiti pipeline lateral expansion project and $2.0 million for marshland restoration costs relating to the construction of the Discovery pipeline. Discovery, in 2005, will be required to create an escrow account to cover a substantial portion of the total expenditures for the construction of the Tahiti pipeline lateral expansion project attributable to Williams’ and our share of those costs. Our 40% share of funds to be deposited in a Discovery escrow account that will be used for funding costs associated with Discovery’s construction of the Tahiti pipeline lateral expansion project will be $24.4 million (we expect $10.0 million to be drawn from the Discovery escrow account during the twelve month-period ending June 30, 2006 to cover our 40% share of the estimated $25.0 million of expenditures by Discovery for the Tahiti pipeline lateral expansion project during that period). We expect the total construction costs of the Tahiti pipeline lateral expansion project to be approximately $69.5 million, with the balance to be expended by June 30, 2008. Our 40% share of the expansion capital expenditures for marshland restoration costs will be $0.8 million. For the year ended December 31, 2004 and the twelve-month period ended March 31, 2005, Discovery expended $38.3 million and $38.0 million, respectively, in expansion capital expenditures related to the construction of the gathering laterals to the Front Runner, Rock Creek and Tarantula prospects, which were completed in 2004, and the market expansion project, which was completed in 2005.
 
  •  Discovery’s operating and maintenance expense, excluding fuel and shrink replacement, will be approximately $21.3 million, compared to $19.3 million and $17.2 million for the years ended December 31, 2004 and December 31, 2003, respectively. Discovery’s fuel and shrink replacement expense will be approximately $46.4 million, compared to $45.4 million and $42.9 million for the years ended December 31, 2004 and December 31, 2003, respectively. The estimated increase in fuel and shrink replacement expenses compared to prior periods is caused by our expectation of higher average natural gas prices.
 
  •  Our general and administrative expenses will be approximately $8.0 million, excluding the credit from Williams provided for under the omnibus agreement, compared to $2.6 million and $1.8 million for the years ended December 31, 2004 and December 31, 2003 respectively. Including this credit, we expect the cash expenditures for the twelve-month period ending June 30, 2006 associated with general and administrative expenses will be approximately $4.5 million. The increase in the net amount over the next twelve months of $4.5 million from the $2.6 million for the year ended December 31, 2004 relates to our incurrence of various incremental general and administrative costs related to becoming a separate public entity, such as costs associated with business development, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, and registrar and transfer agent fees.
 
  •  We will not have any borrowings or interest expense, other than interest expense of approximately $0.6 million associated with two outstanding letters of credit and $0.3 million in commitment fees related to our borrowing limit under Williams’ revolving credit agreement and our working capital facility with Williams. The advances from affiliates reflected in the historical balance sheet of Williams Partners Predecessor will be forgiven by Williams prior to this offering.
Other
  •  We will benefit from a gas purchase contract with a subsidiary of Williams for a sufficient quantity of natural gas at a price not to exceed a specified price to satisfy our fuel requirements under a fractionation contract that contains a cap on the per-unit fee we receive. Upon the closing of this offering, Williams will transfer to us a contract for the purchase of natural gas from a wholly owned subsidiary of Williams through December 31, 2007 at a price not to exceed a specified price. This natural gas purchase contract

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  will mitigate the fuel price risk under a fractionation contract at our Conway fractionation facility that also will terminate on December 31, 2007.
 
  •  Pursuant to the omnibus agreement, Williams will (1) reimburse us for the estimated $2.5 million cost of restoration activities in connection with the partial erosion of the overburden along our Carbonate Trend pipeline, (2) reimburse us for approximately $3.1 million of maintenance capital expenditures at our Conway storage facility in connection with KDHE-related cavern compliance, (3) reimburse us for up to $3.4 million, which represents the excess of our 40% share ($27.8 million) of expected total construction cost of the Tahiti pipeline lateral expansion project above the amount of our share ($24.4 million) of the escrow deposit, (4) reimburse us for our 40% share ($0.8 million) of the estimated marshland restoration costs associated with the construction of Discovery’s pipeline, (5) reimburse us for our 40% share ($0.2 million) of the estimated cost of the repair or replacement of an emission-control flare at Discovery’s Paradis fractionation facility, (6) provide a credit of approximately $3.5 million for general and administrative expenses and (7) reimburse us for our 40% pro rata share of any liability to Discovery for potential shipper refunds that may be required by FERC for retained system gas gains and the over-recovery of lost and unaccounted-for gas at Discovery in excess of $4.0 million.
 
  •  Discovery will be able to finance its expansion capital expenditures through capital calls to its members, including us.
 
  •  The $15.3 million of cash on hand at Discovery at the closing of this offering will be sufficient to fund (1) $1.0 million of the $3.5 million of estimated maintenance capital expenditures for the twelve-month period ending June 30, 2006 to pay for compressor modifications at Discovery’s Larose gas processing plant, (2) $4.0 million to pay for potential shipper refunds that may be required by FERC for retained system gas gains and the over-recovery of lost and unaccounted-for gas at Discovery, (3) $2.0 million to cover outstanding accounts payable, and (4) $8.3 million of working capital.
 
  •  Williams will not default under its revolving credit agreement, which would preclude us from borrowing under our borrowing limit under the agreement, or otherwise experience a material adverse effect on its business, financial condition or results of operations.
 
  •  No material nonperformance or credit-related defaults by suppliers, customers or vendors will occur.
 
  •  No material accidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated and material events will occur.
 
  •  Market, regulatory, and overall economic conditions will not change substantially.

      While we believe that these assumptions are reasonable in light of management’s current beliefs concerning future events, the assumptions underlying these estimates are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the actual available cash to pay distributions that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution or any amount on all the common and subordinated units, in which event the market price of the common units may decline materially. Consequently, the statement that we believe that we will generate sufficient available cash from operating surplus to pay the full minimum quarterly distribution on all units for each quarter through June 30, 2006 should not be regarded as a representation by us or the underwriters or any other person that we will make these distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings “Risk Factors,” “Forward-Looking Statements” and elsewhere in this prospectus. Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimate.

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HOW WE MAKE CASH DISTRIBUTIONS
Operating Surplus and Capital Surplus
Overview
      All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.
Definition of Available Cash
      We define available cash in the glossary, and it generally means, for each fiscal quarter all cash on hand at the end of the quarter:
  •  less the amount of cash reserves established by our general partner to:
  —  provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);
 
  —  comply with applicable law, any of our debt instruments or other agreements; or
 
  —  provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;
  •  plus all 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 for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our working capital facility with Williams and in all cases are used solely for working capital purposes or to pay distributions to partners.
Definition of Operating Surplus
      We define operating surplus in the glossary, and for any period it generally means:
  •  our cash balance on the closing date of this offering, excluding amounts retained from the proceeds of this offering to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project; plus
 
  •  $10.0 million (as described below); plus
 
  •  all of our cash receipts after the closing of this offering, excluding (1) cash from borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus
 
  •  working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less
 
  •  all of our operating expenditures after the closing of this offering (including the repayment of working capital borrowings, but not the repayment of other borrowings) and maintenance capital expenditures (including capital contributions to Discovery to be used by Discovery for maintenance capital expenditures); less
 
  •  the amount of cash reserves established by our general partner for future operating expenditures.
Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”
      Because operating surplus is a cash accounting concept, the benefit that we receive from our gas purchase contract with a subsidiary of Williams and the partial credit for general and administrative expenses and other reimbursements we receive from Williams under the omnibus agreement will be part of our operating surplus.
      As described above, operating surplus does not reflect actual cash on hand at closing 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 $10.0 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 distributed as capital surplus.

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Definition of Capital Surplus
      We also define capital surplus in the glossary, and it will generally be generated only by:
  •  borrowings other than working capital borrowings;
 
  •  sales of debt and equity securities; and
 
  •  sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or non-current assets sold as part of normal retirements or replacements of assets.
Characterization of Cash Distributions
      We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will 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.
Subordination Period
Overview
      During the subordination period, which we define below and in the glossary, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.35 per quarter, 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. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.
Definition of Subordination Period
      We define the subordination period in the glossary. Except as described below under “— Early Termination of Subordination Period,” the subordination period will extend until the first day of any quarter beginning after June 30, 2008 that each of the following tests are met:
  •  distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
 
  •  the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.
      If the unitholders remove our general partner without cause, the subordination period may end early.
Early Termination of Subordination Period
      The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs:
  •  distributions of available cash from operating surplus on each outstanding common unit and subordinated unit equaled or exceeded $2.10 (150% of the annualized minimum quarterly distribution) for any four-quarter period immediately preceding that date;
 
  •  the “adjusted operating surplus” (as defined below) generated during any four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.10 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units on a fully diluted basis; and
 
  •  there are no arrearages in payment of the minimum quarterly distribution on the common units.

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Definition of Adjusted Operating Surplus
      We define adjusted operating surplus in the glossary, and for any period it generally means:
  •  operating surplus generated with respect to that period; less
 
  •  any net increase in working capital borrowings with respect to that period; less
 
  •  any net reduction in cash reserves for operating expenditures made with respect to that period not relating to an operating expenditure made with respect to that period; plus
 
  •  any net decrease in working capital borrowings with respect to that period; plus
 
  •  any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
      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.
Effect of Expiration of the Subordination Period
      Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:
  •  the subordination period will end and each subordinated unit will immediately convert into one common unit;
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.
Distributions of Available Cash from Operating Surplus During the Subordination Period
      We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
  •  first, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
 
  •  second, 98% to the common unitholders, pro rata, and 2% to 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;
 
  •  third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— Incentive Distribution Rights” below.
      The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
Distributions of Available Cash from Operating Surplus After the Subordination Period
      We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
  •  first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
 
  •  thereafter, in the manner described in “— Incentive Distribution Rights” below.
      The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

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Incentive Distribution Rights
      Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. 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.
      If for any quarter:
  •  we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
 
  •  we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;
then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:
  •  first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.4025 per unit for that quarter (the “first target distribution”);
 
  •  second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.4375 per unit for that quarter (the “second target distribution”);
 
  •  third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.5250 per unit for that quarter (the “third target distribution”); and
 
  •  thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
      In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The percentage interests set forth above for our general partner assumes that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights 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 the additional available cash from operating surplus among the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the 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% general partner interest and assume our general partner has contributed additional capital to maintain its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.
                     
        Marginal Percentage Interest
        in Distributions
    Total Quarterly Distribution    
    Target Amount   Unitholders   General Partner
             
Minimum Quarterly Distribution
  $0.3500     98%       2%  
First Target Distribution
  up to $0.4025     98%       2%  
Second Target Distribution
  above $0.4025 up to $0.4375     85%       15%  
Third Target Distribution
  above $0.4375 up to $0.5250     75%       25%  
Thereafter
  above $0.5250     50%       50%  

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Distributions from Capital Surplus
How Distributions from Capital Surplus Will Be Made
      We will make distributions of available cash from capital surplus, if any, in the following manner:
  •  first, 98% to all unitholders, pro rata, and 2% 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;
 
  •  second, 98% to the common unitholders, pro rata, and 2% 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
 
  •  thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.
      The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
Effect of a Distribution from Capital Surplus
      The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding 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, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to our general partner. The percentage interests shown for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.
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, we will proportionately adjust:
  •  the minimum quarterly distribution;
 
  •  the target distribution levels;
 
  •  the unrecovered initial unit price; and
 
  •  the number of common units into which a subordinated unit is convertible.
      For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be convertible into two common units. We will 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, we will reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s

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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
Overview
      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 our general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
      The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available to pay distributions 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:
  •  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;
 
  •  second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of:
  (1)  the unrecovered initial unit price for that common unit;
 
  (2)  the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and
 
  (3)  any unpaid arrearages in payment of the minimum quarterly distribution;
  •  third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of:
  (1)  the unrecovered initial unit price for that subordinated unit; and
 
  (2)  the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
  •  fourth, 98% to all unitholders, pro rata, and 2% to 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% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;
  •  fifth, 85% to all unitholders, pro rata, and 15% 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

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  (2)  the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence;
  •  sixth, 75% to all unitholders, pro rata, and 25% 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% to the unitholders, pro rata, and 25% to our general partner for each quarter of our existence; and
  •  thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.
      The percentage interests set forth above for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.
      If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.
Manner of Adjustments for Losses
      If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:
  •  first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
 
  •  second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and
 
  •  thereafter, 100% to our general partner.
      The percentage interests set forth above for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.
      If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
Adjustments to Capital Accounts
      We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our 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, we will 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 our 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
COMBINED FINANCIAL AND OPERATING DATA
      The following table shows selected historical financial and operating data of Williams Partners Predecessor, pro forma financial data of Williams Partners L.P. and selected historical financial and operating data of Discovery Producer Services LLC for the periods and as of the dates indicated. The selected historical financial data of Williams Partners Predecessor for the years ended December 31, 2002, 2003 and 2004 are derived from the audited combined financial statements of Williams Partners Predecessor appearing elsewhere in this prospectus. The selected historical financial data of Williams Partners Predecessor for the three months ended March 31, 2004 and 2005 are derived from the unaudited combined financial statements of Williams Partners Predecessor appearing elsewhere in this prospectus and from our financial records. All other amounts have been prepared from our financial records. The results of operations for the interim period are not necessarily indicative of the operating results for the entire year or any future period.
      The selected pro forma financial data of Williams Partners L.P. as of March 31, 2005 and for the year ended December 31, 2004 and three months ended March 31, 2005 are derived from the unaudited pro forma financial statements of Williams Partners L.P. included elsewhere in this prospectus. These pro forma financial statements show the pro forma effect of this offering, including our use of the anticipated net proceeds. The pro forma balance sheet assumes this offering and the application of the net proceeds occurred as of March 31, 2005, and the pro forma statement of operations assumes this offering and the application of the net proceeds occurred on January 1, 2004.
      The selected historical financial data of Discovery Producer Services LLC for the years ended December 31, 2002, 2003 and 2004 are derived from the audited consolidated financial statements of Discovery Producer Services LLC appearing elsewhere in this prospectus. The selected historical financial data of Discovery Producer Services LLC for the three months ended March 31, 2004 and 2005 are derived from the unaudited consolidated financial statements of Discovery Producer Services LLC appearing elsewhere in this prospectus and from our financial records. All other amounts have been prepared from our financial records. The results of operations for the interim period are not necessarily indicative of the operating results for the entire year or any future period.
      The following table includes Adjusted EBITDA Excluding Investment in Discovery, a non-GAAP financial measure, for Williams Partners L.P. and Adjusted EBITDA for our interest in Discovery. These measures are presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. As described further below in “— Non-GAAP Financial Measures,” management believes that the presentation of EBITDA is useful to lenders and investors because of its use in the natural gas industry and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Our 40% ownership interest in Discovery is not consolidated in our financial results; rather we account for it using the equity method of accounting. In order to evaluate EBITDA for the impact of our investment of Discovery on our results, we calculate Adjusted EBITDA Excluding Investment in Discovery separately for Williams Partners L.P. and Adjusted EBITDA for our equity interest in Discovery. We expect distributions we receive from Discovery to represent a significant portion of the cash we distribute to our unitholders. Discovery’s limited liability company agreement provides for quarterly distributions of available cash to its members. Please read “Cash Distribution Policy and Restrictions on Distributions — General — Discovery’s Cash Distribution Policy.”
      For Williams Partners L.P., we define Adjusted EBITDA Excluding Investment in Discovery as net income (loss) plus interest (income) expense and depreciation and accretion less our equity earnings in Discovery plus the impairment of our investment in Discovery in 2004. We also adjust for certain non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003, which we added back to net income in that year.
      For Discovery, we define Adjusted EBITDA as net income plus interest (income) expense, depreciation and accretion. We also adjust for certain non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003, which we added back to net income in that year. Our equity share of Discovery’s Adjusted EBITDA is 40%.
      For a reconciliation of these measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”

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      We derived the information in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the historical combined and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
                                                                           
    Williams Partners Predecessor — Historical        
             
        Three Months   Williams Partners L.P. Pro Forma
        Ended    
    Year Ended December 31,   March 31,   Year Ended   Three Months Ended
            December 31,   March 31,
    2000   2001   2002   2003   2004   2004   2005   2004   2005
                                     
    (In thousands, except per unit data)
Statement of Income Data:
                                                                       
Revenues
  $ 24,117     $ 29,164     $ 25,725     $ 28,294     $ 40,976     $ 7,953     $ 11,369     $ 40,976     $ 11,369  
Costs and expenses
    17,930       23,692       16,542       21,250       32,935       5,256       10,266       32,935       10,266  
                                                       
Operating income
    6,187       5,472       9,183       7,044       8,041       2,697       1,103       8,041       1,103  
Equity earnings (loss) — Discovery
    (10,454 )     (13,401 )     2,026       3,447       4,495       1,982       2,212       4,495       2,212  
Impairment of investment in Discovery
                            (13,484 )(a)                 (13,484 )      
Interest expense
    (4,730 )     (4,173 )     (3,414 )     (4,176 )     (12,476 )     (3,110 )     (3,004 )     (778 )     (270 )
Cumulative effect of change in accounting principle
                      (1,099 )                              
                                                       
Net income (loss) (b)
  $ (8,997 )   $ (12,102 )   $ 7,795     $ 5,216     $ (13,424 )   $ 1,569     $ 311     $ (1,726 )   $ 3,045  
                                                       
Pro forma net income (loss) per limited partner unit:
                                                                       
 
Common unit
                                                          $ (0.12 )   $ 0.21  
 
Subordinated unit
                                                            (0.12 )     0.21  
Balance Sheet Data (at period end):
                                                                       
Total assets
  $ 130,170     $ 122,239     $ 125,069     $ 230,150 (c)   $ 219,361     $ 229,628     $ 220,293             $ 233,447  
Property, plant and equipment, net
    69,931       75,269       72,062       69,695       67,793       69,000       67,146               67,146  
Investment in Discovery
    58,322       44,499       49,323       156,269 (c)     147,281 (a)     158,251       149,493               120,897  
Advances from affiliate
    91,472       95,535       90,996       187,193 (c)     186,024       187,949       190,291                
Total owners’ equity/ Partners’ capital
    29,183       15,236       22,914       30,092       16,668       31,661       16,979               220,424  
Other Financial Data:
                                                                       
Williams Partners Predecessor:
                                                                       
 
Adjusted EBITDA Excluding Investment in Discovery
  $ 8,231     $ 8,849     $ 12,758     $ 10,751     $ 11,727     $ 3,587     $ 2,008     $ 11,727     $ 2,008  
 
Maintenance capital expenditures
    3,853       4,269       295       1,176       1,622       95       212       1,622       212  
Discovery Producer Services — our 40%:
                                                                       
 
Adjusted EBITDA
    5,331       1,284       15,314       16,614       13,566       4,267       4,544                  
 
Maintenance capital expenditures (d)
    N/A       N/A       1,131       1,128       338       86       746                  
Operating Information:
                                                                       
Williams Partners Predecessor:
                                                                       
 
Conway storage revenues
  $ 13,022     $ 11,134     $ 10,854     $ 11,649     $ 15,318     $ 3,109     $ 4,388                  
 
Conway fractionation volumes (bpd) — our 50%
    40,059       40,713       38,234       34,989       39,062       34,314       41,296                  
 
Carbonate Trend gathered volumes (MMBtu/d)
    80,458 (e)     55,746       57,060       67,638       49,981       59,815       41,567                  
Discovery Producer Services — 100%:
                                                                       
 
Gathered volumes (MMBtu/d)
    267,397       226,820       425,388       378,745       348,142       430,466       335,727                  
 
Gross processing margin (¢/MMbtu) (d)(f)
    N/A       N/A       12¢       17¢       17¢       14¢       21¢                  
 
(a) The $13.5 million impairment of our equity investment in Discovery in 2004 reduced the investment balance. See Note 5 of the Notes to Combined Financial Statements.
 
(b) Following the completion of the initial public offering, our operations will be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. Therefore, we have excluded income tax expense from this financial information.
 
(c) In December 2003, Williams Partners Predecessor made a $101.6 million capital contribution to Discovery, which Discovery subsequently used to repay maturing debt. Williams Partners Predecessor funded this contribution with an advance from Williams.
 
(d) Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Requirements” for a definition of maintenance capital expenditures. Information for 2000 and 2001 is not available as Williams was not the operator of Discovery.
 
(e) Gas began flowing on the Carbonate Trend gathering system during November 2000. This represents the average daily throughput for the period from initial operations through the end of the year.
 
(f) Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General — How We Evaluate Our Operations — Gross Processing Margins” for a discussion of gross processing margin.

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Non-GAAP Financial Measures
      Adjusted EBITDA Excluding Investment in Discovery, in our case, and, Adjusted EBITDA in Discovery’s case, are used as a supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess:
  •  the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 
  •  the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and
 
  •  our operating performance and return on invested capital as compared to those of other publicly traded master limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.
      Our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA exclude some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

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      The following tables present a reconciliation of the non-GAAP financial measures, our Adjusted EBITDA Excluding Investment in Discovery and Discovery’s Adjusted EBITDA, to the GAAP financial measures of net income (loss) and of net cash provided (used) by operating activities, on a historical basis and on a pro forma basis, as adjusted for this offering and the application of the net proceeds, as applicable.
                                                                             
    Williams Partners Predecessor — Historical        
         
            Williams Partners L.P. Pro
        Three Months   Forma
        Ended    
    Year Ended December 31,   March 31,   Year Ended   Three Months
            December 31,   Ended
    2000   2001   2002   2003   2004   2004   2005   2004   March 31, 2005
                                     
    ($ in thousands)
Williams Partners Predecessor:
                                                                       
Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Investment in Discovery” to GAAP “Net income (loss)”
                                                                       
Net income (loss)
  $ (8,997 )   $ (12,102 )   $ 7,795     $ 5,216     $ (13,424 )   $ 1,569     $ 311     $ (1,726 )   $ 3,045  
Adjustments to derive Adjusted EBITDA
                                                                       
    Excluding Investment in Discovery:                                                                        
 
Interest expense
    4,730       4,173       3,414       4,176       12,476       3,110       3,004       778       270  
 
Depreciation and accretion
    2,044       3,377       3,575       3,707       3,686       890       905       3,686       905  
 
Impairment of investment in Discovery Producer Services
                            13,484                   13,484        
 
Cumulative effect of change in accounting principle
                      1,099                                
 
Equity (earnings) loss — Discovery Producer Services
    10,454       13,401       (2,026 )     (3,447 )     (4,495 )     (1,982 )     (2,212 )     (4,495 )     (2,212 )
                                                       
Adjusted EBITDA Excluding Investment in Discovery
  $ 8,231     $ 8,849     $ 12,758     $ 10,751     $ 11,727     $ 3,587     $ 2,008     $ 11,727     $ 2,008  
                                                       
Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Investment in Discovery” to GAAP “Net cash provided (used) by operating activities”
                                                                       
Net cash provided (used) by operating activities
                  $ 8,144     $ 6,644     $ 2,703     $ (661 )   $ (4,055 )                
Interest expense
                    3,414       4,176       12,476       3,110       3,004                  
Changes in operating working capital:
                                                                       
 
Accounts receivable
                    958       850       (261 )     (1,760 )     (678 )                
 
Other current assets
                    185       187       362       (49 )     45                  
 
Accounts payable
                    (593 )     274       (2,711 )     (616 )     1,495                  
 
Accrued liabilities
                    1,218       320       417       (41 )     209                  
 
Deferred revenue
                    765       (1,108 )     (775 )     2,474       3,200                  
Other, including changes in noncurrent assets and liabilities
                    (1,333 )     (592 )     (484 )     1,130       (1,212 )                
                                                       
Adjusted EBITDA Excluding Investment in Discovery
                  $ 12,758     $ 10,751     $ 11,727     $ 3,587     $ 2,008                  
                                                       

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    Discovery Producer Services — Historical
     
        Three Months Ended
    Year Ended December 31,   March 31,
         
    2000   2001   2002   2003   2004   2004   2005
                             
    ($ in thousands)
Discovery Producer Services
                                                       
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net income (loss)”
                                                       
Net income (loss)
  $ (25,701 )   $ (33,069 )   $ 5,498     $ 8,781     $ 11,670     $ 5,062     $ 5,531  
Interest (income) expense
    17,191       14,283       10,851       9,611       (550 )     (52 )     (284 )
Depreciation and accretion
    21,838       21,996       21,935       22,875       22,795       5,658       6,113  
Cumulative effect of change in accounting principle
                      267                    
                                           
Adjusted EBITDA — 100%
  $ 13,328     $ 3,210     $ 38,284     $ 41,534     $ 33,915     $ 10,668     $ 11,360  
                                           
Adjusted EBITDA — our 40% interest
  $ 5,331     $ 1,284     $ 15,314     $ 16,614     $ 13,566     $ 4,267     $ 4,544  
                                           
 
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net cash provided by operating activities”
                                                       
Net cash provided by operating activities
                  $ 19,572     $ 44,025     $ 35,623     $ 11,093     $ 7,981  
Interest (income) expense
                    10,851       9,611       (550 )     (52 )     (284 )
Loss on disposal of equipment
                    (1,913 )                        
Changes in operating working capital:
                                                       
 
Accounts receivable
                    6,008       (7,860 )     1,658       (961 )     4,057  
 
Inventory
                    122       229       240       (368 )     138  
 
Other current assets
                    330       761       1       (436 )     (218 )
 
Accounts payable
                    7,538       1,415       (1,256 )     2,630       713  
 
Other current liabilities
                    1,163       (2,223 )     668       (564 )     (443 )
 
Accrued liabilities
                    (5,387 )     (4,424 )     (2,469 )     (674 )     (584 )
                                           
Adjusted EBITDA — 100%
                  $ 38,284     $ 41,534     $ 33,915     $ 10,668     $ 11,360  
                                           

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
      You should read the following discussion of the financial condition and results of operations for Williams Partners Predecessor in conjunction with the historical combined financial statements and notes of Williams Partners Predecessor and the pro forma financial statements for Williams Partners L.P. included elsewhere in this prospectus.
      We also include a discussion of the consolidated financial condition and results of operations for Discovery. Williams acquired an ownership interest in Discovery in 1998 as a result of its acquisition of MAPCO, Inc. Because of the significance of this investment, we include separate financial statements and notes of Discovery in this prospectus as well as an analysis of its financial condition and results of operations presented below. You should read this analysis in conjunction with the historical financial statements of Discovery and the notes to those financial statements found elsewhere in this prospectus.
Introduction
      We are a Delaware limited partnership recently formed by Williams to own, operate and acquire a diversified portfolio of complementary energy assets. Our initial asset portfolio will consist of:
  •  a 40% interest in Discovery, which owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and an NGL fractionator in Louisiana;
 
  •  the Carbonate Trend natural gas gathering pipeline off the coast of Alabama; and
 
  •  three integrated NGL storage facilities and a 50% interest in an NGL fractionator near Conway, Kansas.
      These assets are owned by various wholly owned subsidiaries of Williams, which will contribute these assets, including the related liabilities, to us upon the closing of this offering. The following discussion analyzes the financial condition and results of operations for these assets on a combined basis.
General
      We are principally engaged in the business of gathering, transporting and processing natural gas and the fractionating and storing of NGLs. For an overview of these industries, please read “Business — Industry Overview.” We manage our business and analyze our results of operations on a segmented basis. Our operations are divided into two business segments:
  •  Gathering and Processing. Our Gathering and Processing Segment includes (1) our 40% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline; and
 
  •  NGL Services. Our NGL Services Segment includes three NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas.
How We Evaluate Our Operations
      Our management uses a variety of financial and operational measures to analyze our segment performance, including the performance of Discovery. These measurements include:
  •  pipeline throughput volumes;
 
  •  gross processing margins;
 
  •  fractionation volumes;
 
  •  storage revenues; and
 
  •  operating and maintenance expenses.

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      Pipeline Throughput Volumes. We view throughput volumes on Discovery’s pipeline system and our Carbonate Trend pipeline as an important component of maximizing our profitability. We gather and transport natural gas under fee-based contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas processing plant and fractionator, we and Discovery must continually obtain new supplies of natural gas. Our ability to maintain existing supplies of natural gas and obtain new supplies are impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines and (2) our ability to compete for volumes from successful new wells in other areas. We routinely monitor producer activity in the areas served by Discovery and Carbonate Trend and pursue opportunities to connect new wells to these pipelines.
      In July 2005, Discovery reached an agreement, subject to “project sanctioning”, with Chevron U.S.A. Inc., Shell Gulf of Mexico Inc., and Statoil Gulf of Mexico LLC to construct an approximate 35–mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. Project sanctioning means that the Tahiti producers must still formally decide to proceed with the project. The Tahiti pipeline lateral expansion is expected to have a design capacity of approximately 200 million cubic feet per day, and its anticipated completion date is May 1, 2007.
      Gross Processing Margins. We view total gross processing margins as an important measure of Discovery’s ability to maximize the profitability of its processing operations. Gross processing margins include revenue derived from:
  •  the rates stipulated under fee-based contracts multiplied by the actual MMBtu volumes;
 
  •  sales of NGL volumes received under percent-of-liquids contracts for Discovery’s account; and
 
  •  sales of natural gas volumes that are in excess of operational needs.
      The associated costs, primarily shrink replacement gas and fuel gas, are deducted from these revenues to determine processing gross margin. Shrink replacement gas refers to natural gas that is required to replace the Btu content lost when NGLs are extracted from the natural gas stream. In certain prior years, such as 2003, we generated significant revenues from the sale of excess natural gas volumes. However, in response to a final rule issued by FERC in 2004, we expect that Discovery will generate only minimal revenues from the sale of excess natural gas in the future.
      Discovery’s mix of processing contract types and its operation and contract optimization activities are determinants in processing revenues and gross margins. Please read “— Our Operations — Gathering and Processing Segment.”
      Fractionation Volumes. We view the volumes that we fractionate at the Conway fractionator as an important measure of our ability to maximize the profitability of this facility. We provide fractionation services at Conway under fee-based contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes fractionated.
      Storage Revenues. Our storage revenues are derived by applying the average demand charge per barrel to the total volume of storage capacity under contract. Given the nature of our operations, our storage facilities have a relatively higher degree of fixed verses variable costs. Consequently, we view total storage revenues, rather than contracted capacity or average pricing per barrel, as the appropriate measure of our ability to maximize the profitability of our storage assets and contracts. Total storage revenues include the monthly recognition of fees received for the storage contract year and shorter-term storage transactions.
      Operating and Maintenance Expenses. Operating and maintenance expenses are costs associated with the operations of a specific asset. Direct labor, fuel, utilities, contract services, materials, supplies, insurance and ad valorem taxes comprise the most significant portion of operating and maintenance expenses. Other than fuel, these expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate depending on the activities performed during a specific period. For example, plant overhauls and turnarounds result in increased expenses in the periods during which they are performed. We include fuel cost

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in our operating and maintenance expense, although it is generally recoverable from our customers in our NGL Services Segment. As noted above, fuel costs in our Gathering and Processing Segment are a component in assessing our gross processing margins.
      In addition to the foregoing measures, we will also review our general and administrative expenditures, substantially all of which are incurred through Williams. We estimate that we will incur incremental general and administrative expenses of approximately $5.5 million per year as a result of being a public company. These costs include business development, annual and quarterly reports to unitholders, audit, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees and incremental insurance costs. In the omnibus agreement, Williams will agree to provide a five-year partial credit for general and administrative expenses incurred on our behalf. The amount of this credit in 2005 will be $3.9 million pro rated for the period from the closing of this offering through year end. The amount of the credit will be $3.2 million in 2006 and will decrease by approximately $800,000 in each subsequent year. As a result, for the twelve-month period ending June 30, 2006, we expect to incur incremental general and administrative expenses of approximately $2.0 million, net of the credit provided by Williams.
      We will record total general and administrative costs, including those costs that are subject to the credit by Williams, as an expense, and we will record the credit as a capital contribution by our general partner. Accordingly, our net income will not reflect the benefit of the credit received from Williams. However, the cost subject to this credit will be allocated entirely to our general partner. As a result, the net income allocated to limited partners on a per-unit basis will reflect the benefit of this credit.
Our Operations
Gathering and Processing Segment
      Our Gathering and Processing Segment consists of our interest in Discovery and our Carbonate Trend Pipeline. These assets generate revenues by providing natural gas gathering, transporting and processing services and NGL fractionating services to customers under a range of contractual arrangements. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing. Hence this equity investment, which can only be presented in one segment, is considered part of the Gathering and Processing segment. For additional information on these activities, and the assets and activities described below, please read “Business — Industry Overview.”
Gathering and Transportation Contracts
      We generate gathering and transportation revenues by applying the set tariff or contracted rate to the contractually-defined volumes of gas gathered or transported. Discovery’s mainline and its FERC-regulated laterals generate revenues through two types of arrangements — firm transportation service and traditional interruptible transportation service. Under the firm transportation arrangement, producers are required to dedicate reserves for the life of the lease, but pay no reservation fees for firm capacity. Under the interruptible transportation arrangement, no reserve dedication is required. Customers with firm transportation arrangements are entitled to a higher priority of service, in the case of a full pipeline, than customers who contract for interruptible transportation service. Firm transportation services represent the majority of the revenues from Discovery’s FERC-regulated business. Discovery also offers a third type of arrangement, traditional firm service with reservation fees, but none of Discovery’s customers currently contract for this type of transportation service.
      Discovery’s maximum regulated rate for mainline transportation is scheduled to decrease in 2008. At that time, Discovery will be required to reduce its mainline transportation rate on all of its contracts that have rates above the new reduced rate. This could reduce the revenues generated by Discovery. Discovery may elect to file a rate case with FERC seeking to alter this scheduled reduction. However, if filed, we cannot assure you that a rate case would be successful in even partially preventing the rate reduction. Please read “Risk Factors — Risks Inherent in Our Business — Discovery’s interstate tariff rates are subject to review and possible adjustment by federal regulators, which could have a material adverse effect on our business and

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operating results. Moreover, because Discovery is a non-corporate entity, it may be disadvantaged in calculating its cost of service for rate-making purposes” and “Business — FERC Regulation.”
      Carbonate Trend’s three contracts have terms tied to the life of the customer’s lease. The actual terms of these contracts will vary depending on the productive life of the natural gas reserves underlying these leases. However, the per-unit gathering fee associated with two of our three Carbonate Trend gathering contracts was negotiated on a bundled basis that includes transportation along a segment of Transcontinental Gas Pipe Line Company, or Transco, a wholly owned subsidiary of Williams. The gathering fees we receive are dependent upon whether our customer elects to utilize this Transco capacity. When they make this election, our gathering fee is determined by subtracting the Transco tariff from the total negotiated fee and generally results in a rate lower than would be realized if the customer elects not to utilize Transco’s capacity. The rate associated with Transco capacity is based on a FERC tariff that is subject to change. Accordingly, if the Transco rate increases, our gathering fees will be reduced. The customers with these bundled contracts must make an annual election to receive this capacity. Both customers elected to use this capacity during 2004 while only one has elected to use this capacity in 2005.
      The gathering and transportation revenues that we generate under fee-based contracts are not directly affected by changing commodity prices. However, to the extent a sustained decline in commodity prices realized by our customers results in a decline in the producers’ future drilling and development activities, our revenues from these contracts could be reduced in the long term.
Processing and Fractionation Contracts
      Fee-based contracts. Discovery generates fee-based fractionation revenues based on the volumes of mixed NGLs fractionated and the per-unit fee charged, which is subject to adjustment for changes in certain fractionation expenses, including natural gas fuel and labor costs. Some of Discovery’s natural gas processing contracts are also fee-based contracts under which revenues are generated based on the volumes of natural gas processed at its natural gas processing plant. As discussed below, Discovery also processes natural gas under percent-of-liquids contracts.
      The processing revenues that Discovery generates under fee-based contracts are not directly affected by changing commodity prices. However, to the extent a sustained decline in commodity prices realized by our customers results in a decline in the producers’ future drilling and development activities, our revenues from these contracts could be reduced due to long-term development declines.
      Percent-of-liquids contracts. Under percent-of-liquids contracts, Discovery (1) processes natural gas for customers, (2) delivers to customers an agreed-upon percentage of the NGLs extracted in processing and (3) retains a portion of the extracted NGLs. Discovery generates revenue by selling these retained NGLs to other parties at market prices. Some of Discovery’s percent-of-liquids contracts have a “bypass” option. Under this option, customers may elect not to process, or bypass, their natural gas on a monthly basis, in which case, Discovery retains a portion of the customers’ natural gas in lieu of NGLs as a fee. Discovery uses its retained natural gas to partially offset the amount of natural gas Discovery must purchase in the market for shrink replacement gas and natural gas consumed as fuel. Discovery may choose to process natural gas that a customer has elected to bypass, but it then must deliver natural gas with an equivalent Btu content to the customer. Discovery would not elect to process bypassed gas if market conditions posed the risk of negative processing margins. Please read “— Operation and Contract Optimization.”
      Under Discovery’s percent-of-liquids contracts, revenues either increase or decrease as a result of a corresponding change in the market prices of NGLs. For contracts with a bypass option, and depending upon whether the customer elects the bypass election, Discovery’s revenues would either increase or decrease as a result of a corresponding change in the relative market prices of NGLs and natural gas.
      Discovery is also a party to a small number of “keep-whole” gas processing arrangements. Under these arrangements, a processor retains NGLs removed from a customer’s natural gas stream but must deliver gas with an equivalent Btu content to the customer, either from the processor’s inventory or through open market purchases. A rise in natural gas prices as compared to NGL prices can cause the processor to suffer negative

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margins on keep-whole arrangements. The natural gas associated with Discovery’s keep-whole arrangements has very little NGL content. As a result, this gas does not require processing to be shipped on downstream pipelines. Consequently, under unfavorable market conditions, Discovery may earn little or no margin on these arrangements, but is not exposed to negative processing margins. Discovery does not intend to enter into additional keep-whole arrangements in the future that would represent a material amount of processing volumes.
      Substantially all of Discovery’s gas gathering, transportation, processing and fractionation contracts have terms that expire at the end of the customer’s natural resource lease. The actual terms of these contracts will vary depending on life of the natural gas reserves underlying these leases. As a result of Discovery’s current contract mix, Discovery takes title to approximately one-half of the mixed NGL volumes leaving its natural gas processing plant. A Williams subsidiary serves as a marketer for these NGLs and, under the terms of its agreement with Discovery, purchases substantially all of Discovery’s NGLs for resale to end users. As a result, a significant portion of Discovery’s revenues are reported as affiliate revenues even though Williams is not a producer that supplies the Discovery pipeline system with any volumes of natural gas. If the arrangement with the Williams subsidiary were terminated, we believe that Discovery could contract with a third party marketer or perform its own marketing services.
Operation and Contract Optimization
      Long-haul natural gas pipelines, generally interstate pipelines that serve end use markets, publish specifications for the maximum NGL content of the natural gas that they will transport. Normally, NGLs must be removed from the natural gas stream at a gas processing facility in order to meet these pipeline specifications. Please read “Business — Industry Overview — Midstream Industry.” It is common industry practice, however, to blend some unprocessed gas with processed gas to the extent that the combined gas stream is still able to meet the pipeline specifications at the point of injection into the long-haul pipeline.
      Although it is typically profitable for producers to separate NGLs from their natural gas streams, there can be periods of time in which the relative value of NGL market prices to natural gas market prices may result in negative processing margins and, as a result, lack of profit from NGL extraction. Because of this margin risk, producers are often willing to pay for the right to bypass the gas processing facility if the circumstances permit. Owners of gas processing facilities may often allow producers to bypass their facilities if they are paid a “bypass fee.” The bypass fee helps to compensate the gas processing facility for the loss of processing volumes.
      Under Discovery’s contracts that include a bypass option, Discovery’s customers may exercise their option to bypass the gas processing plant. Producers with these contracts notify Discovery of their decision to bypass prior to the beginning of each month. For the natural gas volumes that producers have chosen to bypass, Discovery evaluates current commodity prices and then decides whether it will process the gas for its own account and retain the separated NGLs for sale to third parties. The customer pays a bypass fee regardless of whether or not Discovery decides to process the gas for its own account. Discovery’s decision is determined by the value of the NGLs it will separate during the month compared to the cost of the replacement volume of natural gas it must purchase to keep the producer whole.
      By providing flexibility to both producers and gas processors, bypass options can enhance both parties’ profitability. Discovery manages its operations given its contract portfolio, which contains a proportion of contracts with this option that is appropriate given current and expected future commodity market conditions.
NGL Services Segment
      We generate revenues by providing NGL fractionation and storage services at our facilities near Conway, Kansas, using various fee based contractual arrangements where we receive a fee or fees based on actual or contracted volumetric measures.

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Fractionation Contracts
      The fee-based fractionation contracts at our Conway facility generate revenues based on the volumes of mixed NGLs fractionated and the per-unit fee charged. The per-unit fee is generally subject to adjustment for changes in certain operating expenses, including natural gas, electricity and labor costs, which are the principal variable costs in NGL fractionation. As a result, we are generally able to pass through increases in those operating expenses to our customers. However, under one of our fractionation contracts, there is a cap on the per-unit fee and, under current natural gas market conditions, we are not able to pass through the full amount of increases in variable expenses to this customer. In order to mitigate the fuel price risk with respect to our purchases of natural gas needed to perform under this contract, upon the closing of this offering, Williams will transfer to us a contract for the purchase of a sufficient quantity of natural gas from a wholly owned subsidiary of Williams at a price not to exceed a specified price to satisfy our fuel requirements under this fractionation contract. Williams will pay the full costs associated with entering into this contract prior to assigning the contract to us upon closing of this offering. The fair value of this gas purchase contract will be an equity contribution to us by Williams. This gas purchase contract will terminate on December 31, 2007 to correspond with the expected termination of the related fractionation agreement. Pursuant to the terms of this agreement we provided notice of termination to this customer in July 2005. If we are unable to negotiate a new agreement with this customer upon such termination, we believe that we could contract with other potential customers to replace a significant portion of these volumes.
      Two contracts with remaining terms of approximately three and five years account for most of our fractionation revenues. The revenues we generate under fractionation contracts at our Conway facility generally are not directly affected by changing commodity prices. However, to the extent a sustained decline in commodity prices received by our customers results in a decline in their production volumes, our revenues from these contracts could be reduced. One of our customers has the contractual right, on a month-to-month basis, to deliver its mixed NGLs elsewhere. Its decision on whether to ship its products to the Mid-Continent region or another region depends on supply and demand in the respective regions and the current price being paid for fractionated products in each region.
Storage Contracts
      Substantially all our storage contracts are on a firm basis, pursuant to which our customers pay a demand charge for a contracted volume of storage capacity, including injection and withdrawal rights. The majority of our storage revenues are from three contracts with remaining terms between four and fourteen years. The terms of our remaining storage contracts are typically one year or less. In addition, we also enter into contracts for fungible product storage in increments of six months, three months and one month.
      For storage contracts of one year or less, we require our customers to remit the full contract price at the time the contract is signed, which reduces our overall credit risk. Most of our contracts of one year or less are on a fixed price basis. We base our longer-term contracts on a percentage of our published price of storage in our Conway facilities and adjust these prices annually.
      We offer our customers four types of storage contracts: single product fungible, two product fungible, multi-product fungible and segregated product storage. In addition to the fees we charge for contracted storage, we also receive fees for overstorage. Overstorage is all barrels held in a customer’s inventory in excess of that customer’s contractual storage rights, calculated on a daily basis.
      Because we typically contract for periods of one year or longer, our business is less susceptible to seasonal variations. However, spot and future NGL market prices can influence demand for storage. When the market for propane and other NGLs is in backwardation, the demand for storage capacity of our Conway facilities may decrease. While this would not impact our long-term leases of storage capacity, our customers could become less likely to enter into short-term storage contracts.

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Operating Supply Management
      We also generate revenues by managing product imbalances at our Conway facilities. In response to market conditions, we actively manage the fractionation process to optimize the resulting mix of products. Generally, this process leaves us with a surplus of propane volumes and a deficit of ethane volumes. We sell the surplus propane and make up the ethane deficit through open-market purchases. We refer to these transactions as product sales and product purchases. In addition, product imbalances may arise due to measurement variances that occur during the routine operation of a storage cavern. These imbalances are realized when storage caverns are emptied. We are able to sell any excess product volumes for our own account, but must make up product deficits. The flexibility we enjoy as operator of the storage facility allows us to manage the economic impact of deficit volumes by settling deficit volumes either from our storage inventory or through opportunistic open-market purchases.
      Historically, we effected these product sales and purchases with third parties. However, in December of 2004, we began to effect these purchases and sales with a subsidiary of Williams. If this arrangement with the Williams subsidiary were terminated, we believe we could once again transact with third parties.
Critical Accounting Policies and Estimates
      Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.
Impairment of Long-Lived Assets and Investments
      We evaluate our long-lived assets and investments for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of certain long-lived assets or that the decline in value of an investment is other-than-temporary.
      During 2004, we performed an impairment review of our 40% equity investment in Discovery because of Williams’ planned purchase of an additional interest in Discovery at an amount below our current carrying value. We estimated the fair value of our investment based on a probability-weighted analysis that considered a range of expected future cash flows and earnings, EBITDA multiples and the distribution yields for MLPs. Based upon our analysis we concluded that our investment in Discovery experienced an other-than-temporary decline in value. As a result, we recorded an 8%, or $13.5 million, impairment of this investment to its estimated fair value at December 31, 2004 (see Note 5 of Notes to Combined Financial Statements). Our computations utilized judgments and assumptions in the following areas:
  •  estimated future volumes and rates;
 
  •  range of expected future cash flows;
 
  •  potential proceeds from a sale to an existing MLP based on an acquirer’s estimated distribution and earnings impact; and
 
  •  expected proceeds from our planned initial public offering.
      Our projections are highly sensitive to changes in the above assumptions. The estimated cash flows from the various scenarios ranged from approximately $28.0 million above to approximately $20.0 million below our estimated fair value at December 31, 2004.
Accounting for Asset Retirement Obligations
      We record asset retirement obligations for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset in the period in which it is incurred if a reasonable estimate of fair value can be made. At December 31, 2004, we have an accrued asset retirement obligation liability of $760,000 for estimated retirement costs associated with the abandonment of certain of our Conway underground storage caverns. This retirement liability obligation

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relates to 18 of our well bores which we are no longer using and expect to retire during the next year. Due to the nature of our underground storage caverns, we generally cannot reasonably estimate the expected timing of their abandonment until circumstances indicate that abandonment will be required soon. Our estimate utilizes judgments and assumptions regarding the costs to abandon a well bore and the timing of abandonment. Please read Note 6 of Notes to Combined Financial Statements.
Environmental Remediation Liabilities
      We record liabilities for estimated environmental remediation liabilities when we assess that a loss is probable and the amount of the loss can be reasonably estimated. At December 31, 2004, we have an accrual for estimated environmental remediation obligations of $5.5 million. This remediation accrual is revised, and our associated income is affected, during periods in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. We base liabilities for environmental remediation upon our assumptions and estimates regarding what remediation work and post-remediation monitoring will be required and the costs of those efforts, which we develop from information obtained from outside consultants and from discussions with the applicable governmental authorities. As new developments occur or more information becomes available, it is possible that our assumptions and estimates in these matters will change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarter or annual period. During 2004, we purchased an insurance policy covering some of our environmental liabilities. Please read “— Environmental” and see Note 10 of Notes to Combined Financial Statements for further information.
Results of Operations
Combined Overview
      The following table and discussion is a summary of our combined results of operations for the three years ended December 31, 2004 and the three months ended March 31, 2004 and 2005. The results of operations by segment are discussed in further detail following this Combined Overview discussion.
                                             
        Three Months Ended
    Years Ended December 31,   March 31,
         
    2002   2003   2004   2004   2005
                     
    ($ in thousands)
Revenues
  $ 25,725     $ 28,294     $ 40,976     $ 7,953     $ 11,369  
Costs and expenses:
                                       
 
Operating and maintenance expenses
    10,382       13,960       19,376       2,610       5,728  
 
Product cost
          1,263       6,635       1,037       2,735  
 
Depreciation
    3,575       3,574       3,603       869       905  
 
General and administrative expenses
    1,956       1,813       2,613       561       706  
 
Taxes other than income
    640       640       716       179       192  
 
Other — net
    (11 )           (8 )            
                               
   
Total costs and expenses
    16,542       21,250       32,935       5,256       10,266  
                               
Operating income
    9,183       7,044       8,041       2,697       1,103  
Equity earnings — Discovery
    2,026       3,447       4,495       1,982       2,212  
Impairment of investment in Discovery
                (13,484 )            
Interest expense
    (3,414 )     (4,176 )     (12,476 )     (3,110 )     (3,004 )
                               
Income (loss) before cumulative effect of change in accounting principle
    7,795       6,315       (13,424 )     1,569       311  
Cumulative effect of change in accounting principle
          (1,099 )                  
                               
Net income (loss)
  $ 7,795     $ 5,216     $ (13,424 )   $ 1,569     $ 311  
                               

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Three Months Ended March 31, 2005 vs. Three Months Ended March 31, 2004
      Revenues increased $3.4 million, or 43%, due mainly to higher revenues in our NGL Services Segment, reflecting increased product sales volumes and higher storage rates.
      Operating and maintenance expenses increased $3.1 million, from $2.6 million, due primarily to increased costs in our NGL Services Segment reflecting the absence of a gain recognized in 2004 related to the draining of a storage cavern and higher fuel costs.
      Interest expense will decrease significantly following the closing of the initial public offering as the advances from Williams will be forgiven prior to closing (see Note 4 of Notes to Combined Financial Statements).
Year Ended December 31, 2004 vs. Year Ended December 31, 2003
      Revenues increased $12.7 million, or 45%, due mainly to higher revenues in our NGL Services Segment, reflecting higher product sales volumes and storage rates.
      Operating and maintenance expenses increased $5.4 million, or 39%, due primarily to increased costs to comply with recent KDHE requirements at NGL Services’ Conway facilities. Product costs increased $5.4 million, from $1.3 million, due to the increase in product sales.
      General and administrative expenses increased $0.8 million, or 44%, due primarily to an increase in allocated general and administrative expenses from Williams reflecting increased corporate overhead costs within the Williams organization. These increased costs related to various corporate initiatives and Sarbanes-Oxley Act compliance efforts within Williams. Please read Note 4 of Notes to Combined Financial Statements for information pertaining to the methodology used to calculate these allocated general and administrative expenses.
      The impairment of our investment in Discovery is the result of our analysis pursuant to which we concluded that we had experienced an other than temporary decline in the value of our investment in Discovery as described above in “— Critical Accounting Policies and Estimates — Impairment of Long-Lived Assets and Investments.” Please read the discussion of Discovery’s results of operations below for an understanding of the change in equity earnings.
      Interest expense increased $8.3 million, from $4.2 million, due primarily to the cash advanced by Williams in December 2003 to fund our $101.6 million share of a cash call by Discovery to repay its outstanding debt.
Year Ended December 31, 2003 vs. Year Ended December 31, 2002
      Revenues increased $2.6 million, or 10%, due to higher gathering revenues in our Gathering and Processing Segment and new product sales revenues in our NGL Services Segment.
      Operating and maintenance expenses increased $3.6 million, or 34%, primarily from NGL Services’ higher fuel costs and lower product gains. Product costs increased $1.3 million directly related to the new product sales activity in 2003.
      Please read the discussion of Discovery’s results of operations below for an understanding of the change in equity earnings. Adoption of Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations in 2003 related to NGL Services’ storage caverns and Discovery’s offshore platform resulted in a charge of $1.1 million classified as a cumulative effect of change in accounting principle. Please read Note 3 of Notes to Combined Financial Statements for further information.
      We currently manage our business in two segments: Gathering and Processing and NGL Services. The following discussion relates to the results of operations of our business segments.

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Results of Operations — Gathering and Processing
      This segment includes (1) our 40% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline.
                                           
        Three Months Ended
    Years Ended December 31,   March 31,
         
    2002   2003   2004   2004   2005
                     
    ($ in thousands)
Revenues
  $ 3,962     $ 5,513     $ 4,833     $ 1,166     $ 880  
Costs and expenses:
                                       
 
Operating and maintenance expenses
    661       379       572       113       107  
 
Depreciation
    1,196       1,200       1,200       300       300  
                               
Total costs and expenses
    1,857       1,579       1,772       413       407  
                               
Segment operating income
    2,105       3,934       3,061       753       473  
Equity earnings
    2,026       3,447       4,495       1,982       2,212  
Impairment of investment
                (13,484 )            
                               
Segment profit (loss)
  $ 4,131     $ 7,381     $ (5,928 )   $ 2,735     $ 2,685  
                               
Carbonate Trend
Three Months Ended March 31, 2005 vs. Three Months Ended March 31, 2004
      Revenues decreased $0.3 million, or 25%, due primarily to a 31% decline in gathering volumes, offset slightly by a higher overall gathering rate due to a customer’s election not to utilize Transco’s capacity under the bundled rate within its contract. Please read “ — Our Operations — Gathering and Processing Segment — Gathering and Transportation Contracts” above for additional information. The volume decline is due primarily to normal reservoir depletion. There have been no new well completions or workovers since early 2004 to offset this decline.
      The daily average volume for the fourth quarter of 2004 was 43,316 MMBtu/d, which is slightly higher than the daily average of 41,567 MMBtu/d for the first quarter of 2005. In the second quarter of 2005, a rig was on location working over one of the existing wells. If the workover is successful, then gathering volumes could increase.
      We currently estimate that we will incur $2.5 million of incremental maintenance expenditures over the next twelve months in connection with restoration activities related to the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004. In the omnibus agreement, Williams will agree to reimburse us for the cost of these restoration activities. That reimbursement will be reflected as a capital contribution. In connection with these restoration activities, the Carbonate Trend pipeline may experience a temporary shut down. We do not believe that this shut down will have a material adverse effect on our operations.
Year Ended December 31, 2004 vs. Year Ended December 31, 2003
      Revenues decreased $0.7 million, or 12%, due primarily to a 26% decline in gathering volumes in 2004, largely offset by the recognition in 2004 of a $950,000 settlement of a contractual volume deficiency provision. Gathering volumes declined in 2004 due to lower production from connected wells that was not offset by new production coming online.
      Operating and maintenance expenses increased $0.2 million due to additional costs for contractor services.

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Year Ended December 31, 2003 vs. Year Ended December 31, 2002
      The $1.6 million, or 39%, increase in revenues was due to a higher average gathering rate and increased gathering volumes. The higher average gathering rate contributed $0.8 million and was the result of a new contract in 2003. Revenues increased $0.8 million due to 19% higher gathering volumes from the connection of three new wells in late 2002 and 2003.
      The $0.3 million decrease in operating and maintenance expenses relates to additional work done in 2002 for our internal corrosion program and pipeline inspections, which is performed about every third year.
Discovery Producer Services
      Discovery is accounted for using the equity method of accounting. As such, our interest in Discovery’s net operating results is reflected as equity earnings in the combined statement of operations. Due to the significance of Discovery’s equity earnings to our results of operations, the following discussion addresses in greater detail, the results of operations for 100% of Discovery.
                                             
        Three Months Ended
    Years Ended December 31,   March 31,
         
    2002   2003   2004   2004   2005
                     
    ($ in thousands)
Revenues
  $ 91,422     $ 103,178     $ 99,876     $ 27,823     $ 27,289  
Costs and expenses, including interest:
                                       
 
Operating and maintenance expenses:
                                       
   
Fuel and shrink replacement
    35,091       42,914       45,355       12,648       11,124  
   
Other operating and maintenance
    15,987       17,229       19,278       4,076       4,493  
 
Depreciation and accretion
    21,935       22,875       22,795       5,658       6,113  
 
Interest expense (income)
    10,851       9,611             (52 )     (284 )
 
Other expense, net
    2,060       1,501       778       431       312  
                               
      85,924       94,130       88,206       22,761       21,758  
                               
Net income before cumulative effect of change in accounting principle
  $ 5,498     $ 9,048     $ 11,670     $ 5,062     $ 5,531  
                               
Membership 40% interest
  $ 2,199     $ 3,619     $ 4,668     $ 2,025     $ 2,212  
Capitalized interest amortization
    (173 )     (172 )     (173 )     (43 )      
                               
Equity earnings per combined statement of operations
  $ 2,026     $ 3,447     $ 4,495     $ 1,982     $ 2,212  
                               
Three Months Ended March 31, 2005 vs. Three Months Ended March 31, 2004
      The $0.5 million, or 2%, decrease in revenues is primarily due to lower fuel and shrink replacement gas sales and transportation volumes in the first quarter of 2005, substantially offset by higher average per-unit NGL sales prices and the receipt of a volume deficit payment. The significant components of this increase consisted of the following:
  •  Increasing gas prices during the first quarter of 2004 made it more economical for Discovery’s customers to bypass the processing plant rather than to process the gas, leaving Discovery with higher levels of excess fuel and replacement gas in the first quarter of 2004 than 2005. This excess natural gas was sold in the market and generated $3.0 million higher revenue in the first quarter of 2004.
 
  •  Fee-based revenues from gathering and transportation decreased $1.1 million due primarily to a 23% decline in the overall transportation volumes from the first quarter of 2004 to the first quarter of 2005. This decline resulted mainly from the high initial decline rate experienced by one of the larger newly

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  connected fields. This was offset somewhat by new volumes from the recently connected Front Runner, Rock Creek and Tarantula prospects.
 
  •  In the first quarter of 2005, Discovery received a $1.4 million volume threshold deficit payment. The deficit payment related to a volume shortfall under its transportation contracts.
 
  •  NGL sales increased $2.0 million due to 18% higher average sales prices, which were slightly offset by a 1% decrease in sales volumes.

      Discovery’s gathered volumes for the fourth quarter of 2004 averaged 291,931 MMBtu/d as compared to 335,727 MMBtu/d for the first quarter of 2005. Although Discovery’s 2005 gathered volumes have declined since the first quarter of 2004, they have increased 15% since the fourth quarter of 2004 following the receipt of first gas deliveries from three new prospects — Front Runner, Rock Creek and Tarantula. We expect annual 2005 gathered volumes to approximate the 2004 level. We also expect incremental revenue in 2005 from Discovery’s market expansion project. Please read “Business — The Discovery Assets” for a further discussion of the market expansion project.
      Shrink replacement costs decreased by $1.5 million, or 12%, primarily due to lower replacement gas sales volumes discussed above in the first quarter of 2005, partially offset by higher average gas prices. Depreciation expense increased $0.5 million, or 8%, from the first quarter of 2004 due to the completion of pipeline connections to the Front Runner and Tarantula prospects in late 2004. Depreciation expense will continue at this level for the second quarter of 2005 and then will increase by approximately $0.2 million per quarter for the remainder of 2005 related to the market expansion project.
Year Ended December 31, 2004 vs. Year Ended December 31, 2003
      The $3.3 million, or 3%, decrease in revenues resulted primarily from lower fuel and shrink replacement gas sales in 2004 and lower NGL sales volumes, partially offset by higher average per-unit NGL sales prices. The significant components of this decrease consisted of the following:
  •  Increasing gas prices during some months of 2003 made it more economical for Discovery’s customers to bypass the processing plant rather than to process the gas, leaving Discovery with higher levels of excess fuel and replacement gas in 2003 than 2004. This excess natural gas was sold in the market in 2003, which resulted in $5.1 million of lower revenues in 2004.
 
  •  Transportation volumes declined 6% due to production declines and a temporary interruption of service because of an accidental influx of seawater in a lateral while putting in place a subsea connection to a wellhead. These lower volumes resulted in a decrease in fee-based revenues, including $2.7 million from gathering and transportation, $2.2 million from fee-based processing and $0.2 million from fractionation, for a total of $5.1 million.
 
  •  Other revenues decreased $1.5 million due to a $0.9 million decrease in offshore platform production handling fees related to lower natural gas production volumes and $0.8 million received in connection with the resolution of a condensate measurement and ownership allocation issue in 2003.
 
  •  NGL sales increased $8.5 million due to a 26% increase in average sales prices, which were slightly offset by a 2% decrease in sales volumes.
      Shrink replacement costs increased by $2.4 million, or 6%, primarily due to higher average gas prices. Other operating and maintenance expenses increased $2.0 million, or 12%, from 2003 due primarily to $1.2 million of costs for a routine compressor overhaul and $1.3 million of costs to correct a non-routine temporary interruption of service due to an accidental influx of seawater in our offshore pipeline. These increases were partially offset by lower miscellaneous operating expenses.
      Interest expense decreased $9.6 million due to the repayment of $253.7 million of outstanding debt in December 2003. Other expense, net decreased $0.7 million due primarily to $0.6 million of income earned on the short term investing of excess cash.

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Year Ended December 31, 2003 vs. Year Ended December 31, 2002
      The increase of $11.8 million, or 13%, in revenues resulted primarily from the sale of excess fuel and shrink replacement gas in 2003, higher fee-based processing revenue and higher NGL sales prices, partially offset by lower gas transportation and processing volumes. The significant components of this increase consisted of the following:
  •  As discussed above, increasing gas prices during some months of 2003 made it more economical for Discovery’s customers to bypass the processing plant. As a result, Discovery’s revenues increased $15.6 million in 2003 from the sale of excess fuel and shrink replacement gas.
 
  •  Fee-based processing and fractionation revenues increased $1.9 million and $0.8 million, respectively, due to increased enforcement of merchantability requirements of the long-haul pipelines that required volumes to be processed before entering the pipelines even though the relationship between natural gas and NGL prices would otherwise not justify processing.
 
  •  Fee-based revenues from gathering and transportation decreased $2.1 million due primarily to 14% lower transportation volumes resulting from production declines.
 
  •  Natural gas liquids sales decreased $5.1 million due to a 38% decline in volumes sold, partially offset by 41% higher average NGL sales prices. The decline in NGL volumes sold was due primarily to Discovery and its customers’ decisions to bypass the processing plant when it was not economical to extract the NGLs due to the relationship between natural gas and NGL prices. Prior to 2003, bypassing the processing plant was not operationally possible.
 
  •  Other revenues increased $0.4 million due primarily to the receipt of $0.8 million in payments in connection with the resolution of a condensate measurement and ownership allocation issue.
      Shrink replacement costs increased $7.8 million, or 22%, due to higher average gas prices, partially offset by the impact of lower processing volumes. The increase of $1.2 million, or 8%, in other operating and maintenance expenses is primarily due to $1.8 million higher fuel costs at the fractionator due to the increase in volumes fractionated partially offset by $0.9 million lower outside services costs. Depreciation expense increased by $0.9 million due to new gathering lines completed in 2003.
      The decrease in interest expense of $1.2 million resulted primarily from lower average interest rates in 2003 and the repayment of Discovery’s outstanding debt of $253.7 million in mid-December 2003.
Results of Operations — NGL Services
      This segment includes our three NGL storage facilities near Conway, Kansas and our undivided 50% interest in the Conway fractionator.
                                           
        Three Months Ended
    Years Ended December 31,   March 31,
         
    2002   2003   2004   2004   2005
                     
    ($ in thousands)
Revenues
  $ 21,763     $ 22,781     $ 36,143     $ 6,787     $ 10,489  
Costs and expenses:
                                       
 
Product cost
          1,263       6,635       1,037       2,735  
 
Operating and maintenance expenses
    9,721       13,581       18,804       2,497       5,621  
 
Depreciation
    2,379       2,374       2,403       569       605  
 
General and administrative expense — direct
    274       421       535       136       203  
 
Taxes other than income taxes
    640       640       716       179       192  
 
Other — Net
    (11 )           (8 )            
                               
Total costs and expenses
    13,003       18,279       29,085       4,418       9,356  
                               
 
Segment profit
  $ 8,760     $ 4,502     $ 7,058     $ 2,369     $ 1,133  
                               

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Three Months Ended March 31, 2005 vs. Three Months Ended March 31, 2004
      Revenues increased $3.7 million, or 55%, due primarily to higher product sales and storage revenues. The significant components of the increase consisted of the following:
  •  Product sales were $1.8 million higher primarily due to the sale of surplus propane volumes created through our product optimization activities. This increase was offset by the related product cost of sales discussed below.
 
  •  Storage revenues increased $1.3 million due to higher average per-unit storage rates, partially offset by lower contracted storage volumes. The published rate for one-year storage contracts increased 67% and primarily reflects the pass through of increased costs to comply with KDHE regulations. Please read “Business — Environmental Regulation” for a further discussion of KDHE regulation of our Conway storage facilities.
 
  •  Fractionation revenues increased $0.5 million due to a 19% increase in fractionated volumes and a 10% increase in the average fractionation rate in the first quarter of 2005.
 
  •  During the second quarter of 2004 we began offering product upgrading services for normal butane at our fractionator. This service contributed an additional $0.3 million of fee revenues in the first quarter of 2005.
      Product costs increased $1.7 million, from $1.0 million, directly related to increased product sales volumes. Operating and maintenance expenses increased $3.1 million, from $2.5 million, primarily due to a gain recognized in 2004 related to the draining of a storage cavern and higher fuel costs. The significant components consisted of the following:
  •  Fuel expense increased $0.4 million due to a 19% increase in the daily average volumes fractionated and an 11% increase in the average price of natural gas.
 
  •  Other operating expenses increased by $2.3 million from a credit balance of $1.4 million in the first quarter of 2004 due primarily to a gain of $1.5 million related to the draining of a storage cavern during the first quarter of 2004 and a lower of cost or market inventory adjustment during the first quarter of 2005 that was $0.6 million higher than the 2004 adjustment.
Year Ended December 31, 2004 vs. Year Ended December 31, 2003
      Revenues increased $13.4 million, or 59%, due primarily to increased product sales and storage revenues. The significant components of the increase consisted of the following:
  •  Product sales were $6.9 million higher primarily due to the sale of surplus propane volumes created through our product optimization activities. Prior to 2003, the sale and purchase activities and related inventory associated with product optimization were conducted by another wholly owned subsidiary of Williams that was sold in 2002. We made no sales of surplus propane until 2004 as we transitioned to conducting these activities and accumulated inventory.
 
  •  Storage revenues increased $3.7 million due to higher average per-unit storage rates, slightly offset by lower contracted storage volumes. The published rate for one-year storage contracts increased 67% and primarily reflects the pass through of increased costs to comply with KDHE regulations.
 
  •  During 2004 we began offering product upgrading services for normal butane at our fractionator. This service contributed $1.7 million of fee revenues in 2004.

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      Product costs increased $5.4 million, from $1.3 million, directly related to increased product sales. Operating and maintenance expenses increased by $5.2 million, or 38%, primarily from higher maintenance expenses and fuel costs. The significant components consisted of the following:
  •  Outside services and materials and supplies expenses increased $3.6 million due to new storage cavern workover activity related to KDHE requirements.
 
  •  Fuel expense increased $1.0 million due to an 18% increase in the average price of natural gas.
Year Ended December 31, 2003 vs. Year Ended December 31, 2002
      Revenues increased $1.0 million, or 5%, mainly from product sales and an increase in per-unit storage fees charged. The significant components of this increase consisted of the following:
  •  During 2003, we recognized $1.3 million from the sale of excess propane/propylene mix attributable to product gains realized during the unloading of railcars. As is customary in the industry, when we are able to unload from a railcar more than 97.5% of the products originally loaded, we are entitled to retain such excess amounts. Prior to 2003, risks and benefits associated with this activity belonged to another wholly owned subsidiary of Williams that was sold in 2002.
 
  •  Storage revenues increased $0.8 million due to a $1.2 million increase from higher storage fees charged offset by $0.4 million lower overstorage revenues.
 
  •  Fractionation volumes declined 8%, resulting in a decrease of $0.9 million in fractionation revenues primarily because of customers’ elections to have their mixed NGLs fractionated at facilities in other regions. Please read “Business — The Conway Assets — The Conway Fractionation Facility — Customers and Contracts.”
      Product costs increased $1.3 million related to the sale of propane/propylene mix discussed above. Operating and maintenance expenses increased $3.9 million, or 40%. The significant components of this increase consisted of the following:
  •  Fuel costs increased by $2.3 million due primarily to a 48% increase in the price of natural gas and an 8% increase in fuel volumes.
 
  •  The product gain from 2002 to 2003 decreased by approximately $0.5 million, or 46%, due primarily to the lower of cost or market adjustment made to value the product inventory at year end 2003.
 
  •  Other expense increased by $0.4 million due to higher fees paid to KDHE and consulting fees related to environmental monitoring of the storage caverns.
 
  •  Materials and supplies increased by $0.5 million due to commencement of cavern workovers required by KDHE in 2003.
Liquidity and Capital Resources
      Historically, our sources of liquidity included cash generated from operations and funding from Williams. Our cash receipts were deposited in Williams’ bank accounts and all cash disbursements were made from these accounts. Thus, historically our financial statements have reflected no cash balances. Cash transactions handled by Williams for us were reflected in intercompany advances between Williams and us. Following this offering, we plan to maintain our own bank accounts but will continue to allow Williams’ personnel to manage our cash and investments.
      In addition to the retention of a portion of the proceeds from the initial public offering for working capital needs, we expect our ongoing sources of liquidity to include cash generated from operations, cash distributions from Discovery, borrowings under Williams’ credit facility up to the amount of our borrowing limit, borrowings under our working capital facility, issuance of additional partnership units, debt offerings and capital contributions from Williams. We believe that cash generated from these sources will be sufficient

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to meet our short-term working capital requirements, long-term capital expenditure requirements, capital contribution obligations to Discovery and quarterly cash distributions.
      Historically, cash distributions from Discovery to its members required unanimous consent and no such distributions were made. Discovery’s limited liability company agreement has been amended, to be effective at the closing of this offering, to provide for quarterly distributions of available cash. We expect future cash requirements for Discovery relating to working capital and maintenance capital expenditures to be funded from cash retained by Discovery at the closing of this offering and from its own internally generated cash flows from operations. Growth or expansion capital expenditures for Discovery will be funded by either cash calls to its members, which requires unanimous consent of the members except in limited circumstances, or from internally generated funds.
Cash Flows and Capital Expenditures
Williams Partners Predecessor
                                         
                Three Months
        Ended
    Years Ended December 31,   March 31,
         
    2002   2003   2004   2004   2005
                     
    ($ in thousands)   (unaudited)
Net cash provided (used) by operating activities
  $ 8,144     $ 6,644     $ 2,703     $ (661 )   $ (4,055 )
Net cash used by investing activities
    (3,532 )     (102,810 )     (1,534 )     (95 )     (212 )
Net cash provided (used) by financing activities
    (4,612 )     96,166       (1,169 )     756       4,267  
      The increase of $3.4 million in net cash used by operating activities in the first quarter of 2005 as compared to the first quarter of 2004 is primarily related to a $1.9 million reduction in cash flows from changes in working capital and lower operating income in the first quarter of 2005. Cash flows from changes in accounts payable decreased $2.1 million related mainly to the payment of the December 2004 spot ethane purchases in the first quarter of 2005.
      The decrease of $3.9 million in net cash provided by operating activities in 2004 as compared to 2003 reflects an increase of $8.3 million in interest expense in 2004 related primarily to the funding of our $101.6 million share of a Discovery cash call discussed below. This decrease in net cash provided by operating activities was partially offset by changes in working capital, including a $2.7 million increase in accounts payable. The increase in accounts payable was due to a $1.6 million accrual for spot ethane purchases in December 2004 and a $1.0 million higher accrual for power costs at the end of 2004 as compared to 2003.
      Net cash used by investing activities in 2003 includes our $101.6 million capital contribution to Discovery for the repayment of Discovery’s outstanding debt in December 2003. The remaining investing cash flows were for NGL Services’ maintenance capital expenditures.
      Net cash provided by financing activities in 2003 includes funding of our $101.6 million share of a Discovery cash call discussed above. The remaining financing cash flows represent the pass through of our net cash flows to Williams under its cash management program as described above.
      As mentioned previously, cash distributions from Discovery will be a source of our liquidity. Summarized below are 100% of Discovery’s cash flow activities for years ended December 31, 2002, 2003 and 2004 and three months ended March 31, 2004 and 2005.

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Discovery Producer Services — 100%
                                         
                Three Months
        Ended
    Years Ended December 31,   March 31,
         
    2002   2003   2004   2004   2005
                     
    ($ in thousands)   (unaudited)
Net cash provided by operating activities
  $ 19,572     $ 44,025     $ 35,623     $ 11,093     $ 7,981  
Net cash used by investing activities
    (7,183 )     (12,073 )     (39,115 )     (5,692 )     (7,097 )
Net cash provided by financing activities
    7,320       409                    
      The decrease of $3.1 million in net cash provided by operating activities in the first quarter of 2005 as compared to the first quarter of 2004 reflects an increase in intercompany accounts receivable relating to an extra month of liquid sales invoices outstanding.
      The increase of $24.5 million in net cash provided by operating activities in 2003 as compared to 2002 reflects our efforts to improve account receivable collections and manage working capital requirements. This resulted in $12.1 million of additional cash generated from working capital in 2003. Working capital levels remained more constant in 2004 as compared to 2003. As a result, net cash provided by operating activities did not include significant amounts from changes in working capital and reflects the return to more normal levels.
      During 2003, net cash used for investing activities was primarily for the purchase of a 12” gathering pipeline ($3.5 million) and initial capital expenditures incurred for the construction of a gathering lateral to connect to Discovery’s pipeline system to the Front Runner prospect ($4.5 million). During 2004, cash used by investing activities was primarily for capital expenditures related to the construction of this gathering lateral ($41.2 million). During 2005, cash used by investing activities was primarily for capital expenditures related to Discovery’s market expansion project and $1.7 million for the purchase of leased compressors at the Larose processing plant.
      During 2003, Discovery’s members made capital contributions of $254.1 million in response to a cash call by Discovery. Discovery used these contributions to retire its outstanding debt of $253.7 million. During 2002, Discovery’s members made capital contributions of $7.3 million, which were used to fund capital projects.
Capital Requirements
      The natural gas gathering, processing and transportation, and NGL fractionation and storage businesses are capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of:
  •  Maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives; and
 
  •  Expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities.
      We estimate that maintenance capital expenditures for the Conway assets will be approximately $4.0 million for 2005, of which approximately $212,000 has been spent through March 31, 2005. The amount of estimated maintenance capital expenditures for the Conway assets includes approximately $1.9 million to be spent in connection with the installation of wellhead control equipment and well meters and KDHE-related cavern compliance. In the omnibus agreement, Williams will agree to reimburse us for the cost of these expenditures.
      We estimate that maintenance capital expenditures for 100% of Discovery will be approximately $3.4 million for 2005, of which approximately $1.9 million has been spent through March 31, 2005. We

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expect Discovery will fund its maintenance capital expenditures through cash retained at the closing of this offering and cash flow from operations.
      We estimate that expansion capital expenditures for 100% of Discovery will be approximately $10.4 million for 2005, $1.7 million of which has been spent through March 31, 2005. Of this estimated amount of total expansion capital expenditures for 2005, $2.7 million is related to the Tahiti pipeline lateral expansion project, none of which has been spent through March 31, 2005.
      We expect the total cost to Discovery of the Tahiti pipeline lateral expansion project will be approximately $69.5 million. Our 40% share of the expected total cost of the Tahiti pipeline lateral expansion project will be approximately $27.8 million. Discovery will be required to create an escrow account in 2005 to cover a substantial portion of the total expenditures attributable to Williams’ and our share of those costs. We expect that the portion of this escrow account attributable to our interest in Discovery will be approximately $24.4 million. We will retain proceeds from this offering to make a capital contribution to Discovery to fund our share of this $24.4 million that will be deposited into escrow. Once these funds are placed in escrow, our share of Discovery’s subsequent capital expenditures on the Tahiti pipeline lateral expansion project will be paid out of the escrow fund until exhausted. We expect that construction of the Tahiti lateral expansion project will be completed by May 2007.
Working Capital Attributable to Deferred Revenues
      The storage year for customer contracts at our Conway storage facility runs from April 1 of a year to March 31 of the following year. We typically receive payment for these one-year contracts in April after the beginning of the storage year and recognize the associated revenues over the course of the storage year. We estimate that we will have a deferred revenue balance of approximately $7.4 million as of June 30, 2005 attributable to payments received in April 2005. Accordingly, we will retain approximately $7.4 million of the proceeds in this offering for working capital purposes associated with this deferred revenue.
Borrowing Limit Under Williams’ Credit Facility
      On May 20, 2005, Williams amended its $1.275 billion revolving credit facility, which is available for borrowings and letters of credit, to allow us to borrow up to $75 million under the Williams facility. Borrowings under this facility mature on May 3, 2007. Our $75 million borrowing limit under Williams’ revolving credit facility will be available for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. At March 31, 2005, letters of credit totaling $455 million had been issued on behalf of Williams by the participating institutions under this facility and no revolving credit loans were outstanding.
      Interest on borrowings under this credit facility is calculated based on a choice of two methods: (i) a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or (ii) a periodic fixed rate equal to LIBOR plus an applicable margin. We will also be required to pay or reimburse Williams for a commitment fee based on the unused portion of our $75 million borrowing limit under the facility, currently 0.375% annually. The applicable margins, currently 2%, and the commitment fee are based on Williams’ senior unsecured long-term debt rating. Under the credit facility, Williams and certain of its subsidiaries, other than us, are required to comply with certain financial and other covenants. Significant financial covenants under the credit facility to which Williams is subject include the following:
  •  ratio of debt to net worth no greater than (i) 70% for the period after December 31, 2004 through December 31, 2005, and (ii) 65% for the remaining term of the agreement;
 
  •  ratio of debt to net worth no greater than 55% for Northwest Pipeline and Transco; and
 
  •  ratio of EBITDA to Interest, on a rolling four quarter basis (or, in the first year, building up to a rolling four-quarter basis), no less than (i) 1.5 for the periods ending September 30, 2004 through March 31, 2005, (ii) 2.0 for any period after March 31, 2005 through December 31, 2005, and (iii) 2.5 for the remaining term of the agreement.

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      If any borrower breaches financial or certain other covenants, the lenders may cause the acceleration of the borrower’s indebtedness and may terminate lending to all borrowers under the credit facility. Additionally, if (i) a borrower were to generally not pay its debts as such debts come due, (ii) a borrower were to make a general assignment for the benefit of its creditors or (iii) proceedings relating to the bankruptcy or receivership of any borrower were to remain unstayed or undismissed for 60 days, then all lending under the credit facility would terminate and all indebtedness outstanding under the credit facility would be accelerated. Williams guarantees our indebtedness under this credit facility. Please read “Risk Factors — Risks Inherent in Our Business — Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings” for information regarding the potential impact on us of restrictions in Williams’ revolving credit facility and in Williams’ public indentures.
Working Capital Credit Facility
      At the closing of the offering, we will enter into a $20 million revolving credit facility with Williams as the lender. The facility will be available exclusively to fund working capital borrowings. Borrowings under the facility will mature on May 3, 2007 and will bear interest at the same rate as would be available for borrowings under Williams’ revolving credit facility described above. We will pay a commitment fee to Williams on the unused portion of the working capital facility of 0.30% annually.
      We will be required to reduce all borrowings under our working capital credit facility to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the facility.
Contractual Cash Obligations and Contingencies
      A summary of our contractual obligations as of December 31, 2004, is as follows (in thousands):
                                           
    2005   2006-2007   2008-2009   2010+   Total
                     
Notes payable/long-term debt
  $     $     $     $     $  
Advances from affiliate
    186,024 (a)                       186,024  
Capital leases
                             
Operating leases
    56                         56  
Purchase obligations
    146       240       240       120 (b)     746  
Other long-term liabilities
                             
                               
 
Total
  $ 186,226     $ 240     $ 240     $ 120     $ 186,826  
                               
 
(a)  Prior to the closing of this offering, Williams will forgive these advances.
(b)  Year 2010+ represents one year of payments associated with an operating agreement whose term is tied to the life of the underlying gas reserves.
      Our equity investee, Discovery, also has contractual obligations for which we are not contractually liable. These contractual obligations, however, will impact Discovery’s ability to make cash distributions to us. A summary of Discovery’s total contractual obligations as of December 31, 2004, is as follows (in thousands):
                                           
    2005   2006-2007   2008-2009   2010+   Total
                     
Notes payable/long-term debt
  $     $     $     $     $  
Capital leases
                             
Operating leases
    511       1,722       1,720       4,967       8,920  
Purchase obligations
                             
Other long-term liabilities
                             
                               
 
Total
  $ 511     $ 1,722     $ 1,720     $ 4,967     $ 8,920  
                               

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Effects of Inflation
      Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three-year period ended December 31, 2004. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by specific price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.
Regulatory Matters
      As of March 31, 2005, Discovery had deferred amounts of $14.7 million relating to retained system gas gains and the over-recovery of lost and unaccounted-for gas on the Discovery system. Please read Note 7 — Rate and Regulatory Matters and Contingent Liabilities — Rate and Regulatory Matters to the Discovery Producer Services LLC Consolidated Financial Statements included herein. A group of shippers has challenged Discovery’s right to retain these gains. Discovery believes the system gains should be retained by the company and recognized as income while the over-recovery of lost and unaccounted-for gas should be made up by Discovery in the future. FERC has requested and received from Discovery additional information regarding both lost and unaccounted-for volumes and gas gains, but has not issued an order resolving these issues. At the closing of this offering, Discovery will retain an amount of cash reserves to apply toward payments to shippers for lost and unaccounted-for gas that might be required by FERC. In the event that payments to shippers are required for both the over-recovered lost and unaccounted-for volumes and system gas gains and such payments were to be calculated based on a June 1, 2005 spot natural gas price instead of gas prices existing at the time such gains or over-recoveries occurred, the amount potentially subject to refund would be approximately $6.1 million for the lost and unaccounted-for volumes and $21.2 million for the system gains. To the extent that Discovery does not have sufficient cash on hand to satisfy any payments required by FERC, it may be required to make a capital call to its members, including us. Pursuant to the omnibus agreement, Williams will reimburse us for our 40% share of any liability to Discovery for potential shipper refunds that may be required by FERC for retained system gas gains and the over-recovery of lost and unaccounted-for gas at Discovery in excess of $4.0 million.
      Discovery’s natural gas pipeline transportation is subject to rate regulation by FERC under the Natural Gas Act. For more information on federal and state regulations affecting our business, please read “Risk Factors” and “Business — FERC Regulation” elsewhere in this prospectus.
Environmental
      Our Conway storage facilities are subject to strict environmental regulation by the Underground Storage Unit within the Geology Section of the KDHE under the Underground Hydrocarbon and Natural Gas Storage Program, which became effective on April 1, 2003.
      We are in the process of modifying our Conway storage facilities, including the caverns and brine ponds, and we believe that our storage operations will be in compliance with the Underground Hydrocarbon and Natural Gas Storage Program regulations by the applicable required compliance dates. In 2003 we began to complete workovers on approximately 30 to 35 salt caverns per year and install, on average, a double liner on one brine pond per year. The incremental costs of these activities is approximately $5.5 million per year to complete the workovers and approximately $900,000 per year to install a double liner on a brine bond. In response to these increased costs, we raised our storage rates by an amount sufficient to preserve our margins in this business. Accordingly, we do not believe that these increased costs have had a material effect on our business or results of operations. We expect on average to complete workovers on each of our caverns every five to ten years and install double liners on each of our brine ponds every 18 years. The KDHE has also advised us that a regulation relating to the metering of NGL volumes that are injected and withdrawn from our caverns may be interpreted and enforced to require the installation of meters at each of our well bores. We have informed the KDHE that we disagree with this interpretation, and the KDHE has asked us to

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provide it with additional information. We estimate that the cost of installing a meter at each of our well bores at Conway West and Mitchell would be approximately $3.9 million over three years.
      We have accrued liabilities for estimated site remediation costs to be incurred in the future at our facilities and properties. We record liabilities when site restoration and environmental remediation and cleanup obligations are known or considered probable and can be reasonably estimated. As of December 31, 2004, we had accrued environmental liabilities of $5.5 million related to four remediation projects at the Conway storage facilities. In 2004, we purchased an insurance policy that covers up to $5.0 million of remediation costs until an active remediation system is in place or April 30, 2008, whichever is earlier, excluding operation and maintenance costs and ongoing monitoring costs, for these four projects to the extent such costs exceed a $4.2 million deductible. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25 million. In the omnibus agreement, Williams will agree to indemnify us for these remediation expenditures to the extent not recovered under the insurance policy, excluding costs of project management and soil and groundwater monitoring, and certain other environmental and related obligations arising out of or associated with the operation of the assets before the closing date of the offering. There will be an aggregate cap of $14.0 million on the total amount of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under the environmental insurance policy. We estimate that the approximate cost of the project management and soil and groundwater monitoring associated with the four remediation projects at the Conway storage facilities and for which we will not be indemnified will be approximately $200,000 to $400,000 per year following the completion of remediation work. The benefit of the indemnification will be accounted for as a capital contribution to us by Williams as the costs are incurred. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”
      In connection with our operations at the Conway facilities, we are required by the KDHE regulations to provide assurance of our financial capability to plug and abandon the wells and abandon the brine facilities we operate at Conway. Williams has posted two letters of credit on our behalf in an aggregate amount of $17.6 million to guarantee our plugging and abandonment responsibilities for these facilities. We anticipate providing assurance in the form of letters of credit in future periods until such time as we obtain an investment-grade credit rating.
      In connection with the construction of Discovery’s pipeline, approximately 73 acres of marshland was traversed and is required to be restored. In Phase I of this project, Discovery created new marshlands to replace about half of the traversed acreage. Phase II, which will complete the project, will begin during 2005 and will cost approximately $2.0 million. For a further discussion of the environmental laws and regulations affecting our business, please read “Business — Environmental Regulation” elsewhere in this prospectus.
Qualitative and Quantitative Disclosures About Market Risk
      Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risk to which we are exposed is commodity price risk for natural gas and NGLs. We are also exposed to the risk of interest rate fluctuations. Our existing intercompany balances with Williams and future borrowings bear interest at variable market based rates.
Commodity Price Risk
      Please read “— Our Operations — Gathering and Processing Segment” and “— Our Operations — NGL Services Segment” for a discussion of our exposure to commodity price risk.

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Interest Rate Risk
      Our current interest rate exposure is related to our advances from Williams. The table below provides information as of December 31, 2003 and 2004 about our interest rate risk.
                                 
    December 31, 2003   December 31, 2004
         
    Carrying   Fair   Carrying   Fair
    Value   Value   Value   Value
                 
    ($ in thousands)
Advances from Williams
  $ 187,193     $ 187,193     $ 186,024     $ 186,024  
      These advances are due on demand. Prior to the closing of this offering, Williams will forgive these advances. The variable interest rate was 7.4% at December 31, 2003 and December 31, 2004. Please read Note 4 of Notes to Combined Financial Statements.

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BUSINESS
Our Partnership
      We are a Delaware limited partnership recently formed by Williams to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the business of gathering, transporting and processing natural gas and the fractionating and storing of NGLs. NGLs, such as ethane, propane and butane, result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives, among other applications. We intend to acquire additional assets in the future and have a management team dedicated to a growth strategy.
      Our initial asset portfolio consists of:
  •  a 40% interest in Discovery, which owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and an NGL fractionator in Louisiana;
 
  •  the Carbonate Trend natural gas gathering pipeline off the coast of Alabama; and
 
  •  three integrated NGL storage facilities and a 50% interest in an NGL fractionator near Conway, Kansas.
      Discovery provides integrated “wellhead to market” services to natural gas producers operating in the shallow and deep waters of the Gulf of Mexico off the coast of Louisiana. Discovery consists of a 105-mile mainline, 168 miles of lateral gathering pipelines, a natural gas processing plant and an NGL fractionation facility. Discovery has interconnections with five natural gas pipeline systems, which allow producers to benefit from flexible and diversified access to a variety of natural gas markets. The Discovery mainline was placed into service in 1998 and has a design capacity of 600 million cubic feet per day. Additionally, Discovery has recently reached an agreement, subject to “project sanctioning”, with Chevron, Shell, and Statoil to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. Project sanctioning means that the Tahiti producers must still formally decide to proceed with the project. The Tahiti pipeline lateral expansion is expected to have a design capacity of approximately 200 million cubic feet per day, and its anticipated completion date is May 1, 2007.
      Our Carbonate Trend gathering pipeline is a 34-mile pipeline that gathers sour gas production from the Carbonate Trend area off the coast of Alabama. “Sour” gas is natural gas that has relatively high concentrations of acidic gases, such as hydrogen sulfide and carbon dioxide, that exceed normal gas transportation specifications. The pipeline was built and placed into service in 2000 and has a maximum design capacity of 120 million cubic feet per day.
      We are also engaged in NGL storage and fractionation near Conway, Kansas, which is the principal NGL market hub for the Mid-Continent region of the United States. We believe our integrated NGL storage facility at Conway is one of the largest in the Mid-Continent region. These storage facilities consist of a network of interconnected underground caverns that hold large volumes of NGLs and other hydrocarbons and have an aggregate capacity of approximately 20 million barrels. Our Conway storage facilities connect directly with MAPL and the Kinder Morgan NGL pipeline systems and indirectly with three other large interstate NGL pipelines. We also own a 50% undivided interest in the Conway NGL fractionation facility, which is strategically located at the junction of the south, east and west legs of MAPL. This fractionation facility also benefits from its proximity to other NGL pipelines in the Conway area, and from its proximity to our Conway storage facility. Our share of the fractionator’s capacity is approximately 53,500 barrels per day.
      We account for our 40% interest in Discovery as an equity investment, and therefore do not consolidate its financial results. For the year ended December 31, 2004 and the three months ended March 31, 2005, we generated Adjusted EBITDA Excluding Investment in Discovery of approximately $11.7 million and $2.0 million, respectively. In addition, our 40% interest in Discovery generated Adjusted EBITDA of approximately $13.6 million and $4.5 million for the year ended December 31, 2004 and the three months

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ended March 31, 2005, respectively. Please read “Prospectus Summary — Summary Historical and Pro Forma Combined Financial and Operating Data — Non-GAAP Financial Measures” for an explanation of our Adjusted EBITDA Excluding Investment in Discovery and an explanation of Discovery’s Adjusted EBITDA as well as a reconciliation of these measures to our and Discovery’s most directly comparable financial measures, calculated and presented in accordance with GAAP. On a pro forma basis, our cash available to pay distributions was approximately $23.2 million for the year ended December 31, 2004 and approximately $21.1 million for the twelve-month period ended March 31, 2005. Please read “Cash Distribution Policy and Restrictions on Distributions” for an explanation of cash available to pay distributions and a reconciliation of pro forma cash available to pay distributions to our most directly comparable financial measure, calculated and presented in accordance with GAAP.
Business Strategies
      Our primary business objectives are to generate stable cash flows sufficient to make quarterly cash distributions to our unitholders and to increase quarterly cash distributions over time by executing the following strategies:
  •  grow through accretive acquisitions of complementary energy assets from third parties, Williams or both;
 
  •  capitalize on expected long-term increases in natural gas production in proximity to Discovery’s pipelines in the Gulf of Mexico;
 
  •  optimize the benefits of our scale, strategic location and pipeline connectivity serving the Mid- Continent NGL market; and
 
  •  manage our existing and future asset portfolio to minimize the volatility of our cash flows.
Competitive Strengths
      We believe we are well positioned to execute our business strategies successfully because of the following competitive strengths:
  •  our ability to grow through acquisitions is enhanced by our affiliation with Williams, and we expect this relationship to provide us access to attractive acquisition opportunities;
 
  •  our assets are strategically located in areas with high demand for our services;
 
  •  our assets are diversified geographically and encompass important aspects of the midstream natural gas and NGL businesses;
 
  •  the senior management team and board of directors of our general partner have extensive industry experience and include the most senior officers of Williams; and
 
  •  Williams has established a reputation in the midstream natural gas and NGL industry as a reliable and cost-effective operator, and we believe that we and our customers will benefit from Williams’ scale and operational expertise as well as our access to the broad array of midstream services Williams offers.
Our Relationship with Williams
      One of our principal attributes is our relationship with Williams, an integrated energy company with 2004 revenues in excess of $12.4 billion that trades on the New York Stock Exchange under the symbol “WMB”. Williams is engaged in numerous aspects of the energy industry, including natural gas exploration and production, interstate natural gas transportation and midstream services. Williams has been in the midstream natural gas and NGL industry for more than 20 years.
      Williams has a long history of successfully pursuing and consummating energy acquisitions and intends to use our partnership as a growth vehicle for its midstream, natural gas, NGL and other complementary energy businesses. Although we expect to have the opportunity to make acquisitions directly from Williams in

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the future, although we cannot say with any certainty which, if any, of these acquisition opportunities may be made available to us or if we will choose to pursue any such opportunity. In addition, through our relationship with Williams, we will have access to a significant pool of management talent and strong commercial relationships throughout the energy industry. While our relationship with Williams and its subsidiaries is a significant attribute, it is also a source of potential conflicts. For example, Williams is not restricted from competing with us. Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”
      Williams will have a significant interest in our partnership through its indirect ownership of a 63% limited partner interest and all of our 2% general partner interest. Additionally, a subsidiary of Williams markets substantially all of the NGLs to which Discovery takes title. We will enter into an omnibus agreement with certain affiliates of Williams that will govern our relationship with them regarding certain reimbursement, indemnification and licensing matters. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”
Industry Overview
      We are engaged in important aspects of the midstream natural gas and NGL businesses along the Gulf Coast and in the Mid-Continent region of the United States. Offshore of and onshore in Louisiana, we gather, transport and process natural gas produced in the Gulf of Mexico, including natural gas that is associated with crude oil production. Near Conway, Kansas, we fractionate and store NGLs. As such, our business is directly impacted by changes in domestic demand for and production of natural gas.
Demand for Natural Gas
      Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.1 trillion cubic feet, or Tcf, (60.7 Bcf/d) in 2004 to approximately 25.4 Tcf (69.7 Bcf/d) in 2010, representing an average annual growth rate of over 2.3% per year. By 2010, natural gas is expected to represent approximately 24% of all end-user domestic energy requirements. During the last five years, the United States has on average consumed approximately 22.6 Tcf per year (62.0 Bcf/d) with average annual domestic production of approximately 19.1 Tcf (52.3 Bcf/d) during the same period.
      The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the last three years, these sectors accounted for approximately 56% of the total natural gas consumed in the United States. According to the EIA, annual consumption in the industrial and electricity generation sectors is expected to increase by over 2.9% per year, on average, to 14.6 Tcf (40.0 Bcf/d) in 2010 from an estimated 12.3 Tcf (33.7 Bcf/d) in 2004.
Natural Gas Production
      Gulf of Mexico. The Gulf of Mexico is a significant producing area for natural gas consumed in the U.S. Many long-haul natural gas pipelines depend on the Gulf of Mexico as a significant source of natural gas. According to the EIA, historic natural gas production rates in the Gulf of Mexico since 1992 have fluctuated from a peak of approximately 14.1 Bcf/d in 1997 to an estimate of approximately 11.8 Bcf/d in 2003. Over that same period, natural gas produced from deepwater wells (greater than 200 meters), as opposed to shallow water wells (less than 200 meters), has constituted an increasingly greater component of total Gulf of Mexico natural gas production.

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      The following graph shows total natural gas production in the Gulf of Mexico since 1992 and the portions attributable to both shallow water and deepwater production. A significant portion of this Gulf of Mexico production includes natural gas associated with crude oil production.
(GRAPH)
Source: Energy Information Agency, Gulf of Mexico Federal Offshore Production, 2004
      According to EIA’s Annual Energy Outlook 2005, both total and deepwater natural gas production levels in the Gulf of Mexico are projected to increase over the next decade. The following graph shows the EIA’s projection of total natural gas production in the Gulf of Mexico increasing from approximately 12.0 Bcf/d in 2004 to approximately 14.0 Bcf/d in 2015 and deepwater natural gas production in the Gulf of Mexico increasing from approximately 5.8 Bcf/d in 2004 to approximately 8.3 Bcf/d in 2015.
(GRAPH)
Source: Energy Information Agency Annual Energy Outlook 2005

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      Mid-Continent. The following graph shows the EIA’s estimates of Mid-Continent natural gas production through the year 2015. The EIA defines the Mid-Continent to include Minnesota, Iowa, Missouri, Nebraska, Kansas, Arkansas, Oklahoma, and the Texas panhandle. According to EIA’s Annual Energy Outlook 2005, Mid-Continent natural gas production is projected to remain at levels above 6.0 Bcf per year through 2015.
(GRAPH)
Source: Energy Information Agency Annual Energy Outlook 2005
Midstream Industry
      General. Once natural gas is produced from wells in areas such as the Gulf of Mexico, producers then seek to deliver the natural gas and its components to end-use markets. The midstream natural gas industry is the link between upstream exploration and production activities and downstream end-use markets. The midstream natural gas industry generally consists of natural gas gathering, transportation, processing, storage and fractionation activities. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.
      The following diagram illustrates the natural gas gathering, processing, fractionation, storage and transportation process. We supply our customers with all of these services from our processing, fractionation and storage facilities, except for natural gas and NGL transportation to end users and natural gas storage.
(GRAPH)
      Offshore Natural Gas Gathering. An offshore gathering system typically consists of multiple gathering laterals of smaller diameter pipe that collect natural gas directly from production platforms or, in some cases, subsea connections to the wellhead. Production platforms provide production handling services, which in the

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case of a well producing a mixture of oil and gas involves the separation of natural gas from the oil and water before the natural gas enters the gathering lateral. Gathering laterals then connect to a main or trunk line of larger diameter pipe. The mainline then transports the natural gas collected from the various laterals to an onshore location, typically a treatment facility or gas processing plant. As new natural gas discoveries are made within the vicinity of the mainline or the existing laterals, new “step out” laterals or extensions of existing laterals are built to connect the gathering system to the newly producing wells. Gathering contracts with offshore natural gas producers are typically executed in conjunction with a reserve dedication. A reserve dedication commits the producer to utilize the midstream service provider’s gathering and transportation system for all current and future production, often for the life of the producer’s reservoir lease.
      Natural Gas Processing and Transportation. The principal component of natural gas is methane, but most natural gas also contains varying amounts of NGLs including ethane, propane, normal butane, isobutane and natural gasoline. NGLs have economic value and are utilized as a feedstock in the petrochemical and oil refining industries or directly as a heating, engine or industrial fuel. Long-haul natural gas pipelines have specifications as to the maximum NGL content of the gas to be shipped. Because of the presence of NGLs, natural gas collected through a gathering system is typically unsuitable for long-haul pipeline transportation. In order to meet quality standards for pipelines, unsuitable natural gas must be processed to separate hydrocarbon liquids that can have higher values as mixed NGLs from the natural gas. NGLs are typically recovered by cooling the natural gas until the mixed NGLs become separated through condensation. Cryogenic recovery methods are processes where this is accomplished at temperatures lower than -150°F, and which provide higher NGL recovery yields. After being extracted from natural gas, the mixed NGLs are typically transported to a fractionator for separation of the NGLs into their component parts.
      In addition to NGLs, natural gas collected through a gathering system may also contain impurities, such as water, sulfur compounds, nitrogen or helium. As a result, a natural gas processing plant will typically provide ancillary services such as dehydration and condensate separation prior to processing. Dehydration removes water from the natural gas stream which can form ice when combined with natural gas and cause corrosion when combined with carbon dioxide or hydrogen sulfide. Condensate separation involves the removal of crude oil-like hydrocarbons from the natural gas stream. Once the condensate has been removed, it may be stabilized for transportation away from the processing plant via truck, rail or pipeline. Natural gas with a carbon dioxide or hydrogen sulfide content higher than permitted by pipeline quality standards requires treatment with chemicals called amines at a separate treatment plant prior to processing.
      Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline.
  •  Ethane. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks used in a wide range of plastics and other chemical products;
 
  •  Propane. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel;
 
  •  Normal Butane. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient in synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization;
 
  •  Isobutane. Isobutane is fractionated from mixed butane (a stream of normal butane and isobutane in solution) or refined from normal butane through the process of isomerization, principally for use in refinery alkylation to enhance the octane content of motor gasoline; and
 
  •  Natural Gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blendstock or petrochemical feedstock.
      NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers. Fractionation takes advantage of the differing boiling points of the various NGL products. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off to the top of the tower where it is condensed and routed to storage. The mixture from the bottom of the first tower

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is then moved into the next tower where the process is repeated, and a heavier NGL product is separated and stored. This process is repeated until the NGLs have been separated into their components. Since the fractionation process requires large quantities of heat, energy costs are a major component of the total cost of fractionation.
      The following diagram illustrates the NGL fractionation process:
(GRAPH)
      NGLs are produced domestically in the United States from two sources — gas processing plants and crude oil refineries. We believe, based on industry data, NGLs produced from domestic gas processing operations accounted for approximately 70% of the total NGL supplies in the United States in 2003. The mixed NGLs delivered from domestic gas processing plants and crude oil refineries to fractionation facilities are typically transported by NGL pipelines and, to a lesser extent, by railcar and truck.
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