As filed with the Securities and Exchange Commission on April 29, 2005

Registration No. 333-          

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Williams Partners L.P.

(Exact name of registrant as specified in its charter)

Delaware	4922	20-2485124
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

One Williams Center

Tulsa, Oklahoma 74172-0172

(918) 573-2000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

James J. Bender

One Williams Center

Tulsa, Oklahoma 74172-0172

(918) 573-2000

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Robert V. Jewell
William J. Cooper
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
(713) 220-4200 Dan A. Fleckman
Vinson & Elkins LLP
First City Tower
1001 Fannin, Suite 2300
Houston, Texas 77002
(713) 758-2222

      Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

      If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.     o

      If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

      If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

      If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o

      If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.     o

CALCULATION OF REGISTRATION FEE

	Proposed
Title of Each Class of	Maximum Aggregate	Amount of
Securities to be Registered	Offering Price(1)(2)	Registration Fee
Common units representing limited partnership interests	$120,750,000	$14,213

(1)	Includes common units issuable upon exercise of the underwriters’ over-allotment option.
(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

      The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated April 29, 2005

PROSPECTUS

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. We expect the initial public offering price to be between $ and $          per common unit. Holders of common units are entitled to receive distributions of available cash of $0.37 per unit per quarter, or $1.48 per unit on an annualized basis, before any distributions are paid to the holders of our subordinated units. We will only make these distributions to the extent we have sufficient available cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. We intend to apply to list the common units on the New York Stock Exchange 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. 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 NGL prices or a change in NGL prices relative to natural gas prices.

•  Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may restrict 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 $5.60 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	$	$
Underwriting discount (1)	$	$
Proceeds to Williams Partners L.P. (before expenses)	$	$

(1)  Excludes structuring fees of $         

We have granted the underwriters a 30-day option to purchase up to an additional 750,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 5,000,000 common units in this offering. The net proceeds from any exercise of the underwriters’ option to purchase additional units will be used to redeem an equal number of common units from an affiliate of our general partner.

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                   , 2005.

Lehman Brothers

Citigroup

RBC Capital Markets

Wachovia Securities

                        , 2005

[PICTURE/ GRAPHICS TO COME]

TABLE OF CONTENTS

PROSPECTUS SUMMARY		1
	Williams Partners L.P.	1
	The Transactions and Partnership Structure	4
	The Offering	7
	Summary Historical and Pro Forma Combined Financial and Operating Data	10
RISK FACTORS		15
	Risks Inherent in Our Business	15
	Risks Inherent in an Investment in Us	24
	Tax Risks	28
USE OF PROCEEDS		31
CAPITALIZATION		32
DILUTION		33
CASH DISTRIBUTION POLICY		34
	Distributions of Available Cash	34
	Operating Surplus and Capital Surplus	34
	Subordination Period	35
	Distributions of Available Cash From Operating Surplus During the Subordination Period	37
	Distributions of Available Cash From Operating Surplus After the Subordination Period	38
	Incentive Distribution Rights	38
	Percentage Allocations of Available Cash from Operating Surplus	38
	Distributions from Capital Surplus	39
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels	39
	Distributions of Cash Upon Liquidation	40
CASH AVAILABLE FOR DISTRIBUTION		43
	General	43
	Estimated Available Cash for Distribution	43
SELECTED HISTORICAL AND PRO FORMA COMBINED FINANCIAL AND OPERATING DATA		46
	Non-GAAP Financial Measure	48
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		51
	Introduction	51
	General	51
	Our Operations	53
	Critical Accounting Policies and Estimates	56
	Results of Operations	58
	Liquidity and Capital Resources	63
	Effects of Inflation	66
	Regulatory Matters	66
	Environmental	67
	Qualitative and Quantitative Disclosures About Market Risk	67
BUSINESS		69
	Our Partnership	69
	Business Strategies	70
	Competitive Strengths	70
	Our Relationship with Williams	70
	Industry Overview	71

i

	The Discovery Assets		77
		General	77
		Discovery Management	79
		Discovery Natural Gas Pipeline System	80
		Larose Gas Processing Plant	81
		Paradis Fractionator	81
		Discovery Customers and Contracts	82
		Competition	82
		Gas Supply	83
	The Carbonate Trend Pipeline		83
		General	83
		Carbonate Trend Customers and Contracts	84
		Competition	85
		Gas Supply	85
	The Conway Assets		85
		General	85
		Conway Storage Assets	86
		The Conway Fractionation Facility	88
	Safety and Maintenance		90
	FERC Regulation		91
	Environmental Regulation		93
	Title to Properties and Rights-of-Way		97
	Employees		97
	Legal Proceedings		97
MANAGEMENT			98
	Management of Williams Partners L.P.		98
	Directors and Executive Officers of Our General Partner		98
	Executive Compensation		99
	Employment Agreements		100
	Compensation of Directors		100
	Long-Term Incentive Plan		900
	Reimbursement of Expenses of Our General Partner		101
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			102
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			103
	Distributions and Payments to Our General Partner and Its Affiliates		103
	Agreements Governing the Transactions		104
	Omnibus Agreement		104
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			107
	Conflicts of Interest		107
	Fiduciary Duties		110
DESCRIPTION OF THE COMMON UNITS			113
	The Units		113
	Transfer Agent and Registrar		113
	Transfer of Common Units		113
DESCRIPTION OF THE SUBORDINATED UNITS			115
	Cash Distribution Policy		115
	Conversion of the Subordinated Units		115
	Distributions Upon Liquidation		115
	Limited Voting Rights		115

ii

THE PARTNERSHIP AGREEMENT		116
	Organization and Duration	116
	Purpose	116
	Power of Attorney	116
	Capital Contributions	116
	Limited Liability	117
	Voting Rights	118
	Issuance of Additional Securities	119
	Amendment of the Partnership Agreement	119
	Merger, Sale or Other Disposition of Assets	122
	Termination and Dissolution	122
	Liquidation and Distribution of Proceeds	122
	Withdrawal or Removal of Our General Partner	123
	Transfer of General Partner Interest	124
	Transfer of Incentive Distribution Rights	124
	Transfer of Ownership Interests in Our General Partner	124
	Change of Management Provisions	124
	Limited Call Right	125
	Meetings; Voting	125
	Status as Limited Partner or Assignee	126
	Non-citizen Assignees; Redemption	126
	Indemnification	127
	Books and Reports	127
	Right to Inspect Our Books and Records	128
	Registration Rights	128
UNITS ELIGIBLE FOR FUTURE SALE		129
MATERIAL TAX CONSEQUENCES		130
	Partnership Status	130
	Limited Partner Status	131
	Tax Consequences of Unit Ownership	132
	Tax Treatment of Operations	137
	Disposition of Common Units	137
	Uniformity of Units	139
	Tax-Exempt Organizations and Other Investors	140
	Administrative Matters	141
	State, Local and Other Tax Considerations	143
INVESTMENT IN WILLIAMS PARTNERS L.P. BY EMPLOYEE BENEFIT PLANS		144
UNDERWRITING		145
	Commissions and Expenses	145
	Option to Purchase Additional Common Units	145
	Lock-Up Agreements	146
	Offering Price Determination	146
	Indemnification	146
	Stabilization, Short Positions and Penalty Bids	146
	Electronic Distribution	147
	New York Stock Exchange	147
	Discretionary Sales	148
	Relationships	148
	NASD Conduct Rules	148

iii

VALIDITY OF THE COMMON UNITS	149
EXPERTS	149
WHERE YOU CAN FIND MORE INFORMATION	149
FORWARD-LOOKING STATEMENTS	151
INDEX TO FINANCIAL STATEMENTS	F-1
Appendix A — Form of First Amended and Restated Agreement of Limited Partnership of Williams Partners L.P.	A-1
Appendix B — Form of Application for Transfer of Common Units	B-1
Appendix C — Glossary of Terms	C-1
Appendix D — Estimated Available Cash for Distribution	D-1
Certificate of Limited Partnership
Certificate of Formation of Williams Partners GP LLC
Consent of Ernst & Young LLP

      You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

      Until                     , 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.

iv

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 notes to those financial statements. The information presented in this prospectus assumes (1) an initial public offering price of $           per common unit and (2) 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 C.

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. We are principally engaged in the business of gathering, transporting and processing natural gas and fractionating and storing natural gas liquids, or 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 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 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. Upon completion of Discovery’s market expansion project, Discovery will have 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 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 facilities at Conway are 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 the Mid-America, or MAPL, and 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.

1

      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, we generated EBITDA of approximately $11.7 million, which does not include Discovery. In addition, our 40% interest in Discovery generated EBITDA of approximately $13.6 million. Please read “— Summary Historical and Pro Forma Combined Financial and Operating Data — Non-GAAP Financial Measure” for an explanation of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures, calculated and presented in accordance with U.S. generally accepted accounting principles, or GAAP. For the same period, on a pro forma basis, our estimated available cash for distribution was approximately $23.8 million. Please read “Appendix D” for an explanation of estimated available cash for distribution and a reconciliation of estimated available cash for distribution 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 our 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.

2

      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 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 61% 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 Williams and its affiliates 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. 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 NGL prices or a change in NGL prices relative to natural gas prices.

•  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 NGLs. The loss of any of these key customers or producers could result in a decline in our revenues and cash available for distribution.

•  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 for distribution 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.

3

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 $5.60 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.

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 for distribution 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 NGL 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 1,621,622 common units and 6,621,622 subordinated units representing an aggregate 61.0% 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 $0.425 per unit per quarter;

4

•  we will issue 5,000,000 common units to the public in this offering, representing a 37.0% 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 Williams and its affiliates 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 its management of our business, 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,” “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.

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 “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.”

5

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		37	%
The Williams Companies, Inc. and Affiliates		61	%
General Partner Interest		2	%
	Total	100	%

6

The Offering

Common units offered to the public	5,000,000 common units.
	5,750,000 common units, if the underwriters exercise their option to purchase additional units in full.
Units outstanding after this offering	6,621,622 common units and 6,621,622 subordinated units, each representing a 49% limited partner interest in us.
Use of proceeds	We intend to use the net proceeds of $93.5 million from this offering to:
	• repay $85.4 million in advances from Williams;
	• provide $3.5 million of additional working capital; and
	• pay $4.6 million of expenses associated with this offering and related formation transactions.
	If the underwriters’ option to purchase additional units is exercised, we will use the net proceeds to redeem a number of common units from affiliates of our general partner, equal to the number of common units issued upon exercise of that option, at a price per common unit equal to the net proceeds per common unit after underwriting discounts and commissions but before other expenses.
Cash distributions	We intend to make minimum quarterly distributions of $0.37 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 $0.37 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 $0.37; and
	• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.425.
	If cash distributions exceed $0.425 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 C. The amount of

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	available cash may be greater than or less than the minimum quarterly distribution to be distributed on all units.
	We believe, based on the assumptions listed on page 44 of this prospectus, that we will have sufficient cash from operations, including working capital borrowings, to enable us to pay the full minimum quarterly distribution of $0.37 on all units for each quarter through June 30, 2006. The amount of estimated cash available from operating surplus generated during 2004 would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and on the subordinated units during this period. Please read “Cash Available for Distribution — Estimated Available Cash for Distribution” and Appendix D to this prospectus.
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, 2010.
	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 conversion of subordinated units	If we meet the financial tests described in the partnership agreement for any three consecutive four-quarter periods ending on or after June 30, 2008, 25% of the subordinated units will convert into common units. If we meet these tests for any three consecutive four-quarter periods ending on or after June 30, 2009, an additional 25% of the subordinated units will convert into common units. The second early conversion of the subordinated units may not occur until at least one year after the first early conversion.
Early termination of subordination period	If we have earned and paid an amount that equals or exceeds $2.22 (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 “Cash Distribution Policy — Subordination Period — Early Termination of 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

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	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 62.2% 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.
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           % 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	We intend to apply to list the common units on the New York Stock Exchange 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 pro forma financial data of Williams Partners L.P. for the year ended December 31, 2004 is 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 December 31, 2004, 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 following table includes EBITDA, a non-GAAP financial measure, for both Williams Partners L.P. and for our interest in Discovery. EBITDA is 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 Measure,” 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 EBITDA separately for both Williams Partners L.P. and for our equity interest in Discovery.

      For Williams Partners L.P., we define EBITDA as net income (loss) plus interest (income) expense and depreciation and accretion less our equity earnings in Discovery. We also adjust for non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003 and the impairment of our investment in Discovery in 2004, which were added back to net income (loss) in the years indicated.

      For Discovery, we define EBITDA as net income plus interest (income) expense, depreciation and accretion. We also adjust for non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003, which was added back to net income (loss) in that year. Our equity share of Discovery’s EBITDA thus calculated is 40%.

      For a reconciliation of EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measure.”

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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 —									Williams
		Historical									Partners L.P.
											Pro Forma
		Year Ended December 31,									Year Ended
											December 31,
		2002			2003			2004			2004
		(In thousands, except per unit data)
Statement of Income Data:
Revenues		$	25,725		$	28,294		$	40,976		$	40,976
Costs and expenses			16,542			21,250			32,935			32,935
Operating income			9,183			7,044			8,041			8,041
Equity earnings — Discovery			2,026			3,447			4,495			4,495
Impairment of investment in Discovery			—			—			(13,484	)(a)		(13,484	)
Interest expense			(3,414	)		(4,176	)		(12,476	)		(778	)
Cumulative effect of change in accounting principle			—			(1,099	)		—			—
Net income (loss) (b)		$	7,795		$	5,216		$	(13,424	)	$	(1,726	)
Pro forma net loss per limited partner unit											$	(0.13	)
Balance Sheet Data (at period end):
Total assets		$	125,069		$	230,150	(c)	$	219,361		$	211,201
Property, plant and equipment, net			72,062			69,695			67,793			67,793
Investment in Discovery			49,323			156,269	(c)		147,281	(a)		126,766
Advances from affiliate			90,996			187,193	(c)		186,024			—
Total owners’ equity/ Partners’ capital			22,914			30,092			16,668			194,532
Other Financial Data:
Williams Partners Predecessor:
	EBITDA	$	12,758		$	10,751		$	11,727		$	11,727
	Maintenance capital expenditures (d)		295			1,176			1,622			1,622
Discovery Producer Services — our 40%:
	EBITDA		15,314			16,614			13,566
	Maintenance capital expenditures		1,131			1,128			338
Operating Information:
Williams Partners Predecessor:
	Carbonate Trend gathered volumes (MMBtu/d)		57,060			67,638			49,981
	Conway fractionation volumes (Bbls/d) — our 50%		38,234			34,989			39,062
	Conway storage revenues	$	10,854		$	11,649		$	15,318
Discovery Producer Services — 100%:
	Gathered volumes (MMBtu/d)		425,388			378,745			348,142
	Gross processing margin (¢/MMBtu) (e)		12¢			17¢			17¢

(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 Measure

      EBITDA is used as a supplemental financial measure 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.

      EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, EBITDA as presented below may not be comparable to similarly titled measures of other companies.

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      The following table presents a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measures of net income (loss) and of cash provided 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 —									Williams
		Historical									Partners L.P.
											Pro Forma
		Year Ended December 31,									Year Ended
											December 31,
		2002			2003			2004			2004
		($ in thousands)
Williams Partners Predecessor
Reconciliation of Non-GAAP “EBITDA” to GAAP
“Net income (loss)”
Net income (loss)		$	7,795		$	5,216		$	(13,424	)	$	(1,726	)
Interest expense			3,414			4,176			12,476			778
Depreciation and accretion			3,575			3,707			3,686			3,686
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	)		(4,495	)
EBITDA		$	12,758		$	10,751		$	11,727		$	11,727
Reconciliation of Non-GAAP “EBITDA” to GAAP
“Net Cash provided by operating activities”
Net cash provided by operating activities		$	8,144		$	6,644		$	2,703
Interest expense			3,414			4,176			12,476
Changes in operating working capital:
	Accounts receivable		958			850			(261	)
	Other current assets		185			187			362
	Accounts payable		(593	)		274			(2,711	)
	Accrued liabilities		1,218			320			417
	Deferred revenue		765			(1,108	)		(775	)
Other, including changes in noncurrent assets and liabilities			(1,333	)		(592	)		(484	)
EBITDA		$	12,758		$	10,751		$	11,727

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

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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 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; and

•  the amount, if any, of cash reserves established by 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.

      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 approximately $20 million. Estimated available cash for distribution generated during 2004 would have been sufficient to allow us to pay the full minimum quarterly distribution on the common units and on the subordinated units during this period. For a calculation of our ability to make distributions to unitholders based on our pro forma results in 2004, please read “Cash Available for Distribution” and Appendix D.

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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. 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 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 and (2) our ability to compete for volumes from successful new wells.

      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 or competition, 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 natural gas prices.

      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 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.

      In addition to reducing throughput on our pipelines, lower natural gas and oil prices could result in a decline in the production of natural gas and NGLs. 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.

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      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 for distribution.

      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, BP Products North America, Inc., SemStream, L.P. and Enterprise Products Partners, all customers of our Conway facilities, accounted for approximately 52.7% of our revenues. Discovery’s largest customer for the year ended December 31, 2004, other than a subsidiary of Williams that markets NGLs for Discovery, was Eni Petroleum Co., Inc., which accounted for 11% of Discovery’s revenues. 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 for distribution could be adversely affected.

      We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities 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 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

17

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 subject to any financial covenants or ratios under Williams’ revolving credit facility, Williams is subject to these tests. Accordingly, any breach of these or other covenants, ratios or tests, could cause the acceleration of any indebtedness we have outstanding under the facility as well as Williams’ and its other subsidiaries’ outstanding indebtedness. In the event of an acceleration, we might not have, or be able to obtain, sufficient funds to make required repayments of debt, finance our operations, make acquisitions or pay distributions to unitholders. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

      Due to our relationship with 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.

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 ChevronTexaco 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

18

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 ChevronTexaco 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 Koch-owned fractionator located in Hutchinson, Kansas, a Koch-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 Koch-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.

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.

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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;

•  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 occurrence 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.

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

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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. It is not clear what impact, if any, the court’s opinion will have on Discovery’s tariffed rates or on the rates of other interstate natural gas pipelines organized as non-corporate entities, including other master limited partnerships, because it is not clear what action FERC will take in response to BP West Coast, whether such action will be challenged, and, if so, whether it will withstand further FERC or judicial review. Nevertheless, a shipper might rely on the court’s decision to challenge Discovery’s rates and claim that its income tax allowance should be eliminated. If FERC were to disallow Discovery’s income tax allowance, it may be more difficult for Discovery to justify its rates. In addition, as discussed above, if Discovery were to file a rate case a shipper could challenge the inclusion of an income tax allowance in Discovery’s cost of service during the rate case proceeding.

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;

•  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. 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

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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 Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions; (2) the Federal Water Pollution Control Act, commonly referred to as the Clean Water Act, 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, 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

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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.

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.

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      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 61% 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

•  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.”

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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 general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

      In order to become a limited partner of our partnership, a common unitholder is required to agree to 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.

      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 of poor management of the business, so the removal of our general partner because of

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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 $5.60 per common unit.

      The assumed initial public offering price of $20.00 per common unit exceeds pro forma net tangible book value of $14.40 per common unit. You will incur immediate and substantial dilution of $5.60 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 for distribution on each unit may decrease;

•  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•  the 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.

      The Omnibus Agreement will not prohibit Williams and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, 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. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”

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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 for distribution 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.

      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.

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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. 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 for distribution 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 for distribution 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.

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      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 for distribution 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.

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 for distribution 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.

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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.

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 and Louisiana. 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 $93.5 million from the sale of 5,000,000 common units offered by this prospectus, after deducting estimated underwriting discounts but before paying estimated offering expenses. We base this amount on an assumed initial public offering price of $20.00 per common unit.

      We intend to use the net proceeds of this offering to:

•  repay $85.4 million in advances from Williams;

•  provide $3.5 million of additional working capital; and

•  pay $4.6 million of expenses associated with the offering and related formation transactions.

      If the underwriters’ option to purchase additional units is exercised, we will use the net proceeds to redeem a number of common units from affiliates of our general partner, equal to the number of common units issued upon exercise of that option, at a price per common unit equal to the net proceeds per common unit after underwriting discounts and commissions but before other expenses.

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CAPITALIZATION

      The following table shows:

•  the historical capitalization of our predecessor as of December 31, 2004; and

•  our pro forma capitalization as of December 31, 2004, 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 December 31, 2004
				Actual		As Adjusted
				($ in thousands)
Cash and cash equivalents				$	—	$	7,000
Long-term debt, including current portion:
	Advances from Williams			$	186,024	$	—
	Our borrowings under Williams’ revolving credit facility				—		—
	Working capital facility with Williams				—		—
			Total long-term debt		186,024		—
Equity:
	Owners’ equity				16,668		—
	Held by public:
		Common units			—		71,977
	Held by the general partner and its affiliates:
		Common units			—		23,344
		Subordinated units			—		95,321
		General partner interest			—		3,890
			Total equity		16,668		194,532
			Total capitalization	$	202,692	$	194,532

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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. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of December 31, 2004, after giving effect to the offering of common units and the related transactions, our net tangible book value was $194.5 million, or $14.40 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				$	20.00
	Pro forma net tangible book value per common unit before the offering (a)	$	12.60
	Increase in net tangible book value per common unit attributable to purchasers in the offering		1.80
Less: Pro forma net tangible book value per common unit after the offering (b)					14.40
Immediate dilution in net tangible book value per common unit to purchasers in the offering				$	5.60

(a)  Determined by dividing the total number of units (1,621,622 common units, 6,621,622 subordinated units, and the 2% general partner interest, which has a dilutive effect equivalent to 270,270 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 and the forgiveness of the remaining balance of an advance from affiliates. 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 (6,621,622 common units, 6,621,622 subordinated units, and the 2% general partner interest, which has a dilutive effect equivalent to 270,270 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)			8,513,514		63.0	%	$	107.3		51.8	%
New investors			5,000,000		37.0			100.0		48.2
	Total		13,513,514		100.0	%	$	207.3		100.0	%

(a)  Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates will own 1,621,622 common units, 6,621,622 subordinated units, and a 2% general partner interest having a dilutive effect equivalent to 270,270 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 December 31, 2004 was $107.3 million.

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CASH DISTRIBUTION POLICY

Distributions of Available Cash

Overview

      Within approximately 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.

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 distributions 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.

Intent to Distribute the Minimum Quarterly Distribution

      We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.37 per unit, or $1.48 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the common units in any quarter, and we will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under Williams’ revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Borrowing Limit Under Williams’ Credit Facility.”

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 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; plus

•  $           million (as described below); plus

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•  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; less

•  the amount of cash reserves established by our general partner for future operating expenditures.

      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 we receive from Williams for general and administrative expenses 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 $           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.

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 $0.37 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.

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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, 2010 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 Conversion of Subordinated Units

      Before the end of the subordination period, 50% of the subordinated units, or up to 3,310,811 subordinated units, may convert into common units on a one-for-one basis immediately after the distribution of available cash to the partners in respect of any quarter ending on or after:

•  June 30, 2008 with respect to 25% of the subordinated units; and

•  June 30, 2009 with respect to 25% of the subordinated units (based on the total amount of subordinated units initially issued).

      The early conversions of the subordinated units will occur if at the end of the applicable quarter each of the following three tests is 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 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.

      However, the second early conversion of the second 25% of the subordinated units may not occur until at least one year following the first early conversion of the first 25% of the subordinated units.

Early Termination of Subordination Period

      In addition to the early conversion of subordinated units described above, 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 $2.22 (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 $2.22 (150% of the

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	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.

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.

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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.

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 $0.4250 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 $0.4625 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 $0.5550 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 include its 2% general partner interest and assume our general partner has not transferred the incentive distribution rights.

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.

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The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has not transferred the incentive distribution rights.

			Marginal Percentage Interest
			in Distributions
	Total Quarterly Distribution
	Target Amount		Unitholders		General Partner
Minimum Quarterly Distribution		$0.3700		98%		2%
First Target Distribution		up to $0.4250		98%		2%
Second Target Distribution		above $0.4250 up to $0.4625		85%		15%
Third Target Distribution		above $0.4625 up to $0.5550		75%		25%
Thereafter		above $0.5550		50%		50%

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.

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 include its 2% general partner interest and assume our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

      In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

•  the minimum quarterly distribution;

•  the target distribution levels;

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•  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 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 for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain

      The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

•  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;

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•  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
(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 include its 2% general partner interest and assume our general partner has not transferred the incentive distribution rights.

      If the liquidation occurs after the end of the subordination period, the distinction between common 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.

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      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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CASH AVAILABLE FOR DISTRIBUTION

General

      We intend to pay each quarter, to the extent we have sufficient available cash from operating surplus, the minimum quarterly distribution of $0.37 per unit, or $1.48 per unit on an annual basis, on all the common units and subordinated units. The amounts of available cash from operating surplus needed to pay the minimum quarterly distribution on the common units, the subordinated units and the 2% general partner interest to be outstanding immediately after this offering for one quarter and for four quarters are approximately:

		One Quarter		Four Quarters
		($ in thousands)
Common units		$	2,450	$	9,800
Subordinated units			2,450		9,800
2% general partner interest			100		400
	Total	$	5,000	$	20,000

Estimated Available Cash for Distribution

Estimated available cash for distribution during 2004 would have been sufficient to pay the minimum quarterly distribution on all of our units.

      If we had completed the transactions contemplated in this prospectus on January 1, 2004, pro forma available cash from operating surplus generated during 2004 would have been approximately $25.4 million. Pro forma available cash from operating surplus excludes incremental general and administrative expenses of approximately $5.5 million per year that we will incur as a result of being a public company. These costs include 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 will be $3.9 million for the first year following the closing of this offering and will decrease by approximately $800,000 in each subsequent year. As a result, in the first year following the closing of this offering, we estimate we will only incur incremental general and administrative expense of approximately $1.6 million, net of the credit provided by Williams.

      Pro forma available cash from operating surplus also excludes any cash from working capital or other borrowings and cash on hand on the closing date of this offering plus $           million that are included in the cumulative calculation of operating surplus under our partnership agreement. As described in “Cash Distribution Policy,” cash from these sources may also be used to pay distributions.

      We derive estimated available cash from operating surplus by subtracting from pro forma available cash for distribution the incremental general and administrative expenses described above. Our estimated available cash for distribution generated during 2004 would have been $23.8 million. This amount would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units and subordinated units for that period.

      We derived the amounts of pro forma available cash from operating surplus shown above from our pro forma financial statements in the manner described in Appendix D. The pro forma adjustments are based upon currently available information and specific estimates and assumptions. The pro forma financial statements 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, available cash for distribution is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should only view the amount of estimated available cash from operating surplus as a general indication of the amount of available cash from operating surplus that we might have generated had we been formed in earlier periods.

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We believe we will have sufficient available cash from operating surplus following the offering to pay the minimum quarterly distribution on all units through June 30, 2006.

      We believe that, following completion of this offering, we will have sufficient available cash from operating surplus to allow us to make the full minimum quarterly distribution on all outstanding common and subordinated units for each quarter through June 30, 2006. Our belief is based on a number of specific assumptions, including the material assumptions set forth below, which relate to the twelve-month period ending June 30, 2006. For a more detailed explanation of the concepts and terms described below, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

•  average gathered volumes of natural gas on Discovery will be no less than 387,400 MMBtu per day, representing an average increase of approximately 11% over the year ended December 31, 2004 due to the receipt of first gas deliveries from three new prospects and higher gathering fees associated with these new volumes;

•  average volumes of natural gas shipped on our Carbonate Trend pipeline will be no less than 44,300 MMBtu per day, representing an average decline of approximately 12% over the year ended December 31, 2004;

•  average gross processing margins at Discovery’s gas processing plant will be no less than $0.14 per MMBtu;

•  average volumes fractionated for our account at the Conway fractionator will be no less than 44,500 barrels per day;

•  storage revenues at our Conway storage facilities will be no less than $16.8 million;

•  our maintenance capital expenditures, including our share of Discovery’s maintenance capital expenditures will be approximately $3.1 million;

•  general and administrative expenses will be approximately $8.0 million and will benefit from a $3.9 million credit from Williams for that period;

•  we will benefit from a gas purchase contract with a subsidiary of Williams for a sufficient quantity of natural gas at a fixed price to satisfy our fuel requirements under a fractionation contract that contains a cap on the per-unit fee we are able to charge;

•  operating and maintenance expenses, including Discovery, will remain stable compared to 2004, other than increases in fuel costs at our Conway fractionator and increased costs of complying with a KDHE regulation;

•  no material accidents, releases, unscheduled downtime or similar unanticipated and material events will occur; and

•  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 the projections 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 from operating surplus that we could generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all units, in which event the market price of the common units may decline materially. Consequently, the statement that we believe that we will have 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 such a distribution. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors,” “Forward-Looking Statements” and elsewhere in this

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prospectus. Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimate.

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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. All other amounts have been prepared from our financial records.

      The selected pro forma financial data of Williams Partners L.P. for the year ended December 31, 2004 is 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 December 31, 2004, 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. All other amounts have been prepared from our financial records.

      The following table includes EBITDA, a non-GAAP financial measure, for both Williams Partners L.P. and for our interest in Discovery. EBITDA is 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 Measure,” 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 EBITDA separately for both Williams Partners L.P. and for our equity interest in Discovery.

      For Williams Partners L.P., we define EBITDA as net income (loss) plus interest (income) expense and depreciation and accretion less our equity earnings in Discovery. We also adjust for non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003 and the impairment of our investment in Discovery in 2004, which were added back to net income (loss) in the years indicated.

      For Discovery, we define EBITDA as net income plus interest (income) expense, depreciation and accretion. We also adjust for non-cash, non-recurring items, including the cumulative effect of a change in accounting principle in 2003, which was added back to net income (loss) in that year. Our equity share of Discovery’s EBITDA thus calculated is 40%.

      For a reconciliation of EBITDA to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measure.”

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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
		Williams Partners Predecessor — Historical															Partners L.P.
																	Pro Forma
		Year Ended December 31,															Year Ended
																	December 31,
		2000			2001			2002			2003			2004			2004
		(In thousands, except per unit data)
Statement of Income Data:
Revenues		$	24,117		$	29,164		$	25,725		$	28,294		$	40,976		$	40,976
Costs and expenses			17,930			23,692			16,542			21,250			32,935			32,935
Operating income			6,187			5,472			9,183			7,044			8,041			8,041
Equity earnings (loss) — Discovery			(10,454	)		(13,401	)		2,026			3,447			4,495			4,495
Impairment of investment in Discovery			—			—			—			—			(13,484	)(a)		(13,484	)
Interest expense			(4,730	)		(4,173	)		(3,414	)		(4,176	)		(12,476	)		(778	)
Cumulative effect of change in accounting principle			—			—			—			(1,099	)		—			—
Net income (loss) (b)		$	(8,997	)	$	(12,102	)	$	7,795		$	5,216		$	(13,424	)	$	(1,726	)
Pro forma net loss per limited partner unit																	$	(0.13	)
Balance Sheet Data (at period end):
Total assets		$	130,170		$	122,239		$	125,069		$	230,150	(c)	$	219,361		$	211,201
Property, plant and equipment, net			69,931			75,269			72,062			69,695			67,793			67,793
Investment in Discovery			58,322			44,499			49,323			156,269	(c)		147,281	(a)		126,766
Advances from affiliate			91,472			95,535			90,996			187,193	(c)		186,024			—
Total owners’ equity/ Partners’ capital			29,183			15,236			22,914			30,092			16,668			194,532
Other Financial Data:
Williams Partners Predecessor:
	EBITDA	$	8,231		$	8,849		$	12,758		$	10,751		$	11,727		$	11,727
	Maintenance capital expenditures		3,853			4,269			295			1,176			1,622			1,622
Discovery Producer Services — our 40%:
	EBITDA		5,331			1,284			15,314			16,614			13,566
	Maintenance capital expenditures (d)		N/A			N/A			1,131			1,128			338
Operating Information:
Williams Partners Predecessor:
	Carbonate Trend gathered volumes (MMBtu/d)		80,458	(e)		55,746			57,060			67,638			49,981
	Conway fractionation volumes (Bbls/d) — our 50%		40,059			40,713			38,234			34,989			39,062
	Conway storage revenues	$	13,022		$	11,134		$	10,854		$	11,649		$	15,318
Discovery Producer Services — 100%:
	Gathered volumes (MMBtu/d)		267,397			226,820			425,388			378,745			348,142
	Gross processing margin (¢/MMbtu) (d)(f)		N/A			N/A			12¢			17¢			17¢

(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 Measure

      EBITDA is used as a supplemental financial measure 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.

      EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA excludes some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, EBITDA as presented below may not be comparable to similarly titled measures of other companies.

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      The following table presents a reconciliation of the non-GAAP financial measure, EBITDA to the GAAP financial measure of net income (loss) and of cash provided 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
		Williams Partners Predecessor — Historical															Partners L.P.
																	Pro Forma
		Year Ended December 31,															Year Ended
																	December 31,
		2000			2001			2002			2003			2004			2004
		($ in thousands)
Williams Partners Predecessor:
Reconciliation of Non-GAAP “EBITDA” to GAAP
“Net income (loss)”
Net income (loss)		$	(8,997	)	$	(12,102	)	$	7,795		$	5,216		$	(13,424	)	$	(1,726	)
Adjustments to derive EBITDA:
	Interest expense		4,730			4,173			3,414			4,176			12,476			778
	Depreciation and accretion		2,044			3,377			3,575			3,707			3,686			3,686
	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	)		(4,495	)
EBITDA		$	8,231		$	8,849		$	12,758		$	10,751		$	11,727		$	11,727
Reconciliation of Non-GAAP “EBITDA” to GAAP
“Net Cash provided by operating activities”
Net cash provided by operating activities								$	8,144		$	6,644		$	2,703
Interest expense									3,414			4,176			12,476
Changes in operating working capital:
	Accounts receivable								958			850			(261	)
	Other current assets								185			187			362
	Accounts payable								(593	)		274			(2,711	)
	Accrued liabilities								1,218			320			417
	Deferred revenue								765			(1,108	)		(775	)
Other, including changes in noncurrent assets and liabilities									(1,333	)		(592	)		(484	)
EBITDA								$	12,758		$	10,751		$	11,727

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

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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 fractionating and storing 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 will typically decline from year to year due to normal production decline curves. These volumes may increase year to year due to new well connections and workovers or recompletions of existing connected wells.

      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. Processing revenue is 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 replacement gas and fuel gas, are deducted from these revenues to determine processing gross margin. 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 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 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 will be $3.9 million for the first year following the closing of this offering and will decrease by approximately $800,000 in each subsequent

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year. As a result, in the first year following the closing of this offering, we expect to incur incremental general and administrative expenses of approximately $1.6 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 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. 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. For 2005 only one of our customers has elected to utilize this capacity.

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      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 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 third 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. 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. 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 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

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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.

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, we will be a party to a gas purchase contract with a subsidiary of Williams for a sufficient quantity of natural gas at a fixed price to satisfy our fuel requirements under this fractionation contract. 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.

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      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.

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.

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.

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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 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 and providing indemnification for others. Please read “— Environmental” and see Note 10 of Notes to Combined Financial Statements for further information.

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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. The results of operations by segment are discussed in further detail following this Combined Overview discussion.

			Years Ended December 31,
			2002			2003			2004
			($ in thousands)
Revenues			$	25,725		$	28,294		$	40,976
Costs and expenses:
	Operating and maintenance expenses			10,382			13,960			19,376
	Product cost			—			1,263			6,635
	Depreciation			3,575			3,574			3,603
	General and administrative expenses			1,956			1,813			2,613
	Taxes other than income			640			640			716
	Other — net			(11	)		—			(8	)
		Total costs and expenses		16,542			21,250			32,935
Operating income				9,183			7,044			8,041
Equity earnings — Discovery				2,026			3,447			4,495
Impairment of investment in Discovery				—			—			(13,484	)
Interest expense				(3,414	)		(4,176	)		(12,476	)
Income (loss) before cumulative effect of change in accounting principle				7,795			6,315			(13,424	)
Cumulative effect of change in accounting principle				—			(1,099	)		—
Net income (loss)			$	7,795		$	5,216		$	(13,424	)

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.

      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. 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.

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      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.

Results of Operations — Gathering and Processing

      This segment includes (1) our 40% ownership interest in Discovery and (2) the Carbonate Trend gathering pipeline.

		Years Ended December 31,
		2002		2003		2004
		($ in thousands)
Revenues		$	3,962	$	5,513	$	4,833
Costs and expenses:
	Operating and maintenance expenses		661		379		572
	Depreciation		1,196		1,200		1,200
Total costs and expenses			1,857		1,579		1,772
Segment operating income			2,105		3,934		3,061
Equity earnings			2,026		3,447		4,495
Impairment of investment			—		—		(13,484	)
Segment profit (loss)		$	4,131	$	7,381	$	(5,928	)

Carbonate Trend

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. In 2004, production declines from connected wells were not offset by new production coming online. We expect gathering volumes to continue to decline in 2005, but at a slower rate.

      Operating and maintenance expenses increased $0.2 million due to additional costs for contractor services.

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.

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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.

			Years Ended December 31,
			2002			2003			2004
			($ in thousands)
Revenues			$	91,422		$	103,178		$	99,876
Costs and expenses, including interest:
	Operating and maintenance expenses:
		Fuel and shrink replacement		35,091			42,914			45,637
		Other operating and maintenance		15,987			17,229			18,996
	Depreciation and accretion			21,935			22,875			22,795
	Interest expense			10,851			9,611			—
	Other expense, net			2,060			1,501			778
				85,924			94,130			88,206
Net income before cumulative effect of change in accounting principle			$	5,498		$	9,048		$	11,670
Membership 40% interest			$	2,199		$	3,619		$	4,668
Capitalized interest amortization				(173	)		(172	)		(173	)
Equity earnings per combined statement of operations			$	2,026		$	3,447		$	4,495

Year Ended December 31, 2004 vs. Year Ended December 31, 2003

      The $3.3 million, or 3%, decrease in revenues resulted primarily due to 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 and generated $5.1 million lower revenue 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 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.

      Discovery’s volumes are expected to increase during 2005 primarily due to the receipt of first gas deliveries from three new prospects — Front Runner, Rock Creek and Tarantula. We also expect incremental revenue in 2005 from Discovery’s market expansion project scheduled to be in service in July 2005. Please read “Business — The Discovery Assets” for a further discussion of the market expansion project.

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      Shrink replacement costs increased by $2.7 million, or 6%, primarily due to higher average gas prices. Other operating and maintenance expenses increased $1.8 million, or 10%, 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.

      Depreciation and accretion expense remained stable in 2004 as compared to 2003, but is expected to increase approximately $2.2 million in 2005 as a result of three new prospects and the market expansion project discussed above.

      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.

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 reflects higher fuel costs at the fractionator, partially offset by 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.

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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.

		Years Ended December 31,
		2002			2003		2004
		($ in thousands)
Revenues		$	21,763		$	22,781	$	36,143
Costs and expenses:
	Product cost		—			1,263		6,635
	Operating and maintenance expenses		9,721			13,581		18,804
	Depreciation		2,379			2,374		2,403
	General and administrative expense — third party		274			421		535
	Taxes other than income taxes		640			640		716
	Other — Net		(11	)		—		(8	)
Total costs and expenses			13,003			18,279		29,085
	Segment profit	$	8,760		$	4,502	$	7,058

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:

•  Increased product sales accounted for $6.9 million of the total increase in revenue. The higher product sales were primarily the result of the sale of surplus propane volumes created through our product optimization activities. These optimization activities also increased our product costs.

•  Storage revenues increased $3.7 million due to higher average per unit storage rates, partially offset by lower contracted storage volumes. The higher average rates primarily reflect 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.

•  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.

      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 increased 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.

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•  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. Williams utilizes a cash management program for most of its subsidiaries, including us, whereby all cash receipts are deposited in Williams’ bank accounts and all cash disbursements are 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 us and Williams. Prospectively, we plan to maintain our own bank accounts but will continue to participate in Williams’ common treasury function in this manner.

      We expect our sources of liquidity to include: the retention of $3.5 million of proceeds from the initial public offering, cash settlement of our outstanding trade accounts receivables of $3.5 million by Williams, 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 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, effective with the consummation of this offering, to provide for quarterly distributions of available cash. Future cash requirements for Discovery relating to working capital and maintenance capital expenditures are expected to be funded by 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.

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Cash Flows and Capital Expenditures

Williams Partners Predecessor

	Years Ended December 31,
	2002			2003			2004
	($ in thousands)
Net cash provided by operating activities	$	8,144		$	6,644		$	2,703
Net cash used by investing activities		(3,532	)		(102,810	)		(1,534	)
Net cash provided (used) by financing activities		(4,612	)		96,166			(1,169	)

      The decrease of $3.9 million in net cash provided by operating activities in 2004 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.

      Net cash provided by financing activities in 2003 includes funding of our $101.6 million share of a Discovery cash call discussed below. The remaining financing cash flows represent the pass through of our net cash flows to Williams under its cash management program as described above.

      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.

      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, 2004, 2003 and 2002.

Discovery Producer Services — 100%

	Years Ended December 31,
	2002			2003			2004
	($ in thousands)
Net cash provided by operating activities	$	19,572		$	44,025		$	35,623
Net cash used by investing activities		(7,183	)		(12,073	)		(39,115	)
Net cash provided by financing activities		7,320			409			—

      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 decreased by $8.4 million.

      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 ongoing operations.

      During 2003, net cash used by 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).

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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 maintenance capital expenditures for Conway and Carbonate Trend assets to be approximately $2.0 million to $2.5 million for 2005. We do not expect to make expansion capital expenditures for these assets in 2005.

      We estimate maintenance capital expenditures for 100% of Discovery to be approximately $2.0 million for 2005. These will be funded by Discovery’s cash flows from operations.

Borrowing Limit Under Williams’ Credit Facility

      In connection with the closing of this offering, Williams will amend 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. 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 December 31, 2004, letters of credit totaling $422 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 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 capitalization 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 capitalization 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.

Working Capital Credit Facility

      At the closing of the offering, we will enter into a $20 million, two-year revolving credit facility with Williams as the lender. The facility will be available exclusively to fund working capital borrowings. Borrowings under the facility will bear interest at the same rate as would be available for borrowings under the 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.

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      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		$	—	$	—	$	—	$	—		$	—
Capital leases			—		—		—		—			—
Operating leases			56		—		—		—			56
Purchase obligations			146		240		240		120	(a)		746
Other long-term liabilities			—		—		—		—			—
	Total	$	202	$	240	$	240	$	120		$	802

(a)  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			1,732	(a)		—		—		—		1,732
Other long-term liabilities			—			—		—		—		—
	Total	$	2,243		$	1,722	$	1,720	$	4,967	$	10,652

(a)  Purchase obligations represents open purchase orders as of December 31, 2004.

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

      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.

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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 in response to the Underground Hydrocarbon and Natural Gas Storage Program. 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 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. Under the Omnibus Agreement, Williams has agreed to indemnify us for the $4.2 million deductible (less amounts expended prior to the closing of this offering). We estimate that the approximate annual cost of this project management and soil and groundwater monitoring for which we will not be indemnified will be approximately $                    . 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. We have posted two letters of credit in an aggregate amount of $17.6 million to guarantee our plugging and abandonment responsibilities for these facilities. In 2004 we incurred interest expense of approximately $496,000 related to these assurances. 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 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

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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.

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; however, $85.4 million will be repaid and Williams has agreed to forgive the remaining balance due it in connection with the consummation of this offering. 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 fractionating and storing 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. Upon completion of Discovery’s market expansion project, Discovery will have 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 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 facilities at Conway are 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, we generated EBITDA of approximately $11.7 million, which does not include Discovery. In addition, our 40% interest in Discovery generated EBITDA of approximately $13.6 million. Please read “Prospectus Summary — Summary Historical and Pro Forma Combined Financial and Operating Data — Non-GAAP Financial Measure” for an explanation of EBITDA and a reconciliation of EBITDA to our most directly comparable financial measures, calculated and presented in accordance with GAAP. For the same period, on a pro forma basis, our estimated available cash for distribution was approximately $23.8 million. Please read “Appendix D” for an explanation of estimated available cash for distribution and a reconciliation of estimated available cash for distribution to our most directly comparable financial measure, calculated and presented in accordance with GAAP.

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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 our 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 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 61% 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

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agreement with Williams and its affiliates 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.

Source: Energy Information Agency Annual Energy Outlook 2005

      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.

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.

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.

      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:

      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. 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.

      Gas processing facilities have some flexibility in the degree to which they separate NGLs from natural gas. The actual volume of NGLs produced is often determined by the extent to which NGL prices exceed the cost of separating the mixed NGLs from the natural gas stream. This in turn is influenced by the cost of the natural gas consumed in the fractionation process. When operating and extraction costs of gas processing and fractionation plants are higher than the incremental value of the NGL products that would be received by NGL extraction, the recovery levels of certain NGL products, particularly ethane, may be reduced. The increase or decrease in NGL recovery levels is a primary factor behind changes in gross fractionation volumes.

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      The following graph shows the total domestic NGL production from 1993 through 2003, the most recent year for which this data is available.

Source: Energy Information Agency U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report.

      NGL Storage. After NGLs are fractionated, the fractionated products are stored for customers when they are unable or do not wish to take immediate delivery. NGL storage customers may include both NGL producers, who sell to end users, and NGL end users, such as retail propane companies. Both the producers and the end users seek to store NGLs to ensure an adequate supply for their respective customers over the course of the year, particularly during periods of increased demand. A significant portion of the U.S. NGL production is brought through pipelines to two market centers: one on the Gulf Coast at Mont Belvieu, Texas and the other in the Mid-Continent area at Conway, Kansas.

      Fractionated NGL products are typically stored underground in salt formations because large capacity above-ground storage would be uneconomical. NGL products must be pressurized or refrigerated for storage or transportation in a liquid state. Salt formations, which are indigenous to the Mont Belvieu and Conway areas, provide a medium that is impervious to the stored products and can contain large quantities of hydrocarbons in a safe manner and at a significantly lower per-unit cost than any above-ground alternative. A salt cavern is formed by drilling and dissolving, through percolation, an underground cavern in a naturally existing salt formation and installing related surface facilities. Water mixed with salt, or brine, is used to displace the stored products and to maintain pressure in the well as product volumes fluctuate. The typical salt cavern storage facility consists of a solution mining plant, which provides fresh water to dissolve cavities within the underlying salt, brine handling and disposal facilities, and the necessary surface equipment to compress the fractionated products into the cavity and allow them to flow back into a pipeline.

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The Discovery Assets

General

      We own a 40% interest in Discovery, which in turn owns:

•  a 273-mile natural gas gathering and transportation pipeline system, located primarily off the coast of Louisiana in the Gulf of Mexico, with a FERC-certified capacity of 600 MMcf/d on its mainline;

•  a cryogenic natural gas processing plant in Larose, Louisiana with a capacity of 600 MMcf/d;

•  a fractionator in Paradis, Louisiana with a current capacity of 32,000 bpd (which can be expanded to 42,000 bpd); and

•  two onshore liquids pipelines, including a 22-mile mixed NGL pipeline connecting the gas processing plant to the fractionator and a 10-mile condensate pipeline connecting the gas processing plant to a third party oil gathering facility.

      Discovery’s customers are primarily offshore natural gas producers. Discovery provides these customers with “wellhead to market” delivery options by offering a full range of services including gathering, transportation, processing and fractionation. Discovery also has the ability to provide its customers with other specialized services, such as offshore production handling, condensate separation and stabilization and dehydration.

      The Discovery pipeline system currently connects to two natural gas pipelines for delivery of natural gas to end-use markets: the Bridgeline and Texas Eastern pipeline systems. Access to these two pipeline systems provides Discovery’s producer customers with market flexibility. In addition, FERC recently approved Discovery’s market expansion project, which will provide additional market flexibility by enabling Discovery to connect to three additional interstate pipeline systems. As a result, Discovery’s customers have access to market from the Gulf of Mexico to the Eastern United States.

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      The following map shows the location of the Discovery offshore gathering and transportation pipelines and the blocks of reserves dedicated to Discovery.

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      The following map shows the locations of Discovery’s onshore Larose natural gas processing plant, the raw make pipeline, the Paradis fractionator and the connecting long-haul natural gas pipeline systems.

      MAPCO, Inc., which Williams acquired in 1998, purchased a 50.0% interest in Discovery from Texaco in February 1997. Construction of the Discovery assets commenced in March 1997, and the system became operational in January 1998. After the consummation of this offering and the related transactions, Discovery will be owned 40% by us, 26.7% by Williams and 33.3% by Duke Energy Field Services. Williams has granted Duke Energy Field Services an option, which expires on October 31, 2005, to acquire an additional 6.7% interest from Williams. Williams is the operator of the Discovery assets.

Discovery Management

      Upon the consummation of this offering, Discovery will be managed by a three member management committee consisting of representation from each of the three owners. The members of the management committee will have voting power that corresponds to the ownership interest of the owner they represent. However, except under limited circumstances, all actions and decisions relating to Discovery require the unanimous approval of the owners. Discovery must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. The management committee, by majority approval, will determine the amount of such distributions. In addition, the owners are required to offer to Discovery all opportunities to construct pipeline laterals within an “area of interest.”

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Discovery Natural Gas Pipeline System

      General. The Discovery natural gas gathering and transportation pipeline system consists of:

•  a 105-mile 30-inch natural gas pipeline, or mainline, that runs from the edge of the Outer Continental Shelf in the Gulf of Mexico north to Discovery’s natural gas processing plant in Larose, Louisiana and continues as a four-mile 20-inch natural gas pipeline that connects to the Texas Eastern pipeline; and

•  approximately 168 miles of gathering laterals, with pipeline diameters ranging from eight inches to 20 inches.

      The mainline and approximately 60 miles of the gathering laterals are under the jurisdiction of FERC.

      Natural Gas Pipeline. The mainline of the Discovery pipeline system consists of a 105-mile, 30-inch diameter natural gas and condensate pipeline, which begins at a platform, owned by a third party, located in the offshore Louisiana Outer Continental Shelf at Ewing Bank 873 and extends northerly to the Larose gas processing plant and a four-mile 20-inch natural gas pipeline that connects the Larose plant to the Texas Eastern Pipeline. Approximately 66 miles of the mainline is located offshore, in water depths ranging from approximately 40 to 800 feet. Producers have dedicated their production from over 50 offshore blocks to Discovery. Each block representing an area of 5,760 square acres. The mainline has a FERC-certificated capacity of approximately 600 MMcf/d.

      The Discovery system currently connects to two natural gas pipelines, which provide 1.3 Bcf/d of takeaway capacity: the Bridgeline system, which serves southern Louisiana and connects to the Henry Hub natural gas market point, and the Texas Eastern pipeline system, which serves markets from Texas to the northeastern United States. Access to these two pipeline systems allows Discovery’s producer customers to sell their gas in a number of markets. In 2004, FERC approved a proposed market expansion project that will connect the Discovery system to three additional pipeline systems: Tennessee Gas Pipeline, Columbia Gulf Transmission and Transco. Together, these pipelines will provide up to an additional 500 MMcf/d of takeaway capacity. Discovery estimates that this market expansion project, consisting of approximately 40 miles of 20-inch diameter pipe extending from the Larose processing plant to Pointe Au Chien, Louisiana and Old Lady Lake, will commence operations by July 2005 and will cost approximately $11.0 million, most of which has been expended. Once completed, the market expansion project will have a FERC-certificated capacity of 150 MMcf/d.

      Shallow Water/ Onshore Gathering. Discovery also owns shallow water and onshore gathering assets that consist of:

•  90 miles of offshore laterals with pipeline diameters ranging from 12 inches to 20 inches with connections to the mainline. These shallow water laterals are located in water depths ranging from approximately 50 to 360 feet. Of the 90 miles of shallow water laterals, 60 miles are regulated by FERC;

•  a fixed-leg shelf production handling facility installed along the mainline at Grand Isle 115. The platform facility allows for the injection of condensate into the pipeline and is equipped with a production handling facility; and

•  a five-mile onshore gathering lateral with 20-inch diameter pipe that extends from a production area north of the Larose gas processing plant directly to the plant. This lateral is not regulated by FERC.

      A ChevronTexaco-owned gathering system also connects to the Larose gas processing plant.

      Deepwater Gathering. Discovery’s deepwater gathering assets, which are located in water depths of greater than 1,000 feet, consist of 73 miles of gathering laterals, with pipeline diameters ranging from eight inches to 16 inches that extend to deepwater producing areas such as the Morpeth prospect, Allegheny prospect and Front Runner prospect. The maximum water depth of these deepwater laterals is approximately 3,200 feet. None of Discovery’s deepwater laterals are regulated by FERC.

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Larose Gas Processing Plant

      General. Discovery’s cryogenic gas processing plant is located near Larose, Louisiana at the onshore terminus of Discovery’s natural gas pipeline and has a design capacity of 600 MMcf/d. The plant was placed in service in January 1998 and is located on land that Discovery leases from a third party. The initial term of the lease is 20 years and is renewable for ten-year intervals thereafter at Discovery’s option for up to a total of 50 years.

      We believe that the Larose plant is one of the most efficient and flexible gas processing plants in South Louisiana. The Larose plant is able to recover over 90% of the ethane contained in the natural gas stream and effectively 100% of the propane and heavier liquids. In addition, the processing plant is able to reject ethane down to effectively 0% when justified by market economics, while retaining a propane recovery rate of over 95% and butanes and heavier liquids recovery rates of effectively 100%. We believe that the Larose plant consumes very low amounts of natural gas as fuel, using only approximately 1.4% of the volume of natural gas processed.

      In addition to its gas processing activities, the Larose plant generates additional revenues by charging separate fees for ancillary services, such as dehydration and condensate separation and stabilization. Producers may also contract with Discovery for transportation of condensate from offshore production handling facilities and upon separation and stabilization, through Discovery’s 10-mile condensate pipeline to a third party’s oil gathering facility. Discovery also provides compression services for a third party’s onshore gathering system that connects to Discovery’s onshore lateral.

      Gas processed at the Larose plant is delivered to the Bridgeline pipeline system with markets throughout Southern Louisiana including the Henry Hub natural gas market point, and to the Texas Eastern pipeline system with markets from Texas to the northeastern United States. As described above, Discovery’s market expansion project will provide connectivity to three additional interstate pipeline systems.

      Through its portfolio of processing contracts, we believe that Discovery is able to mitigate its exposure in its processing operations to commodity price risk. Discovery’s portfolio of contracts includes the following types of contracts:

•  Fee-based. Under fee-based contracts, Discovery receives revenue based on the volume of natural gas processed and the per-unit fee charged.

•  Percent-of-liquids. Under percent-of-liquids gas processing 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 from the sale of these retained NGLs to third parties at market prices. Some of Discovery’s percent-of-liquids contracts have a “bypass” option. Under contracts with a bypass option, if customers elect not to process their natural gas due to unfavorable processing economics, Discovery retains a portion of the customers’ natural gas in lieu of NGLs as a fee. Discovery may choose to process gas that a customer has elected to bypass, but then must deliver natural gas with an equivalent Btu content to the customer.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations — Gathering and Processing Segment — Processing and Fractionation Contracts” for additional information on Discovery’s contracts.

Paradis Fractionator

      General. The fractionator is located onshore near Paradis, Louisiana. The fractionator and mixed NGL pipeline went into service in January 1998. The initial term of the lease is 20 years and is renewable for ten-year intervals thereafter at Discovery’s option for up to a total of 50 years. The Paradis fractionator is designed to fractionate 32,000 bpd of mixed NGLs and is expandable to 42,000 bpd. In 2004, Discovery fractionated an average of approximately 8,900 bpd of mixed NGLs. All products can be delivered through

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the ChevronTexaco TENDS NGL pipeline system and propane and heavier products may be transported by truck or railway.

      Discovery fractionates NGLs for third party customers and for itself, and it receives title to approximately one-half of the mixed NGL volumes leaving the Larose plant. A subsidiary of Williams markets substantially all of the NGLs and natural gas to which Discovery takes title by purchasing them from Discovery and reselling them to end-users. Discovery fractionates third party NGL volumes for a fractionation fee, which typically includes a base fractionation fee per gallon, that is subject to adjustment for changes in certain fractionation expenses, including natural gas fuel costs on a monthly basis and labor costs on an annual basis, which are the principal variable costs in NGL fractionation. As a result, Discovery is generally able to pass through increases in those fractionation expenses to its customers.

Discovery Customers and Contracts

      Customers. Discovery relies on a few large customers for the majority of its revenues. Five offshore producer customers accounted for approximately 36.8% of Discovery’s revenues in 2004. These five customers are: Eni Petroleum (10.9%), El Paso Production (6.6%), Pogo Producing (6.5%), Mariner Energy (6.5%) and ChevronTexaco (6.3%). Additionally, a subsidiary of Williams, which markets substantially all of the NGLs and natural gas to which Discovery takes title, accounted for approximately 57.9% of Discovery’s revenues in 2004 even though it does not produce any of the natural gas that is supplied to Discovery.

      Contracts. Discovery provides a complete range of “wellhead to market” services for its customers who are offshore producers in the Gulf of Mexico. The principal services provided include gathering, transportation, processing and fractionation. Discovery also provides ancillary services such as dehydration and condensate transportation, separation and stabilization. Each of these services is usually supported by a separate customer contract.

      The mainline and the FERC-regulated laterals generate revenues through FERC-regulated tariffs for two types of service — firm transportation service on a commodity basis with reserve dedication, and traditional interruptible transportation service. Discovery also offers a third type of service, traditional firm service with reservation fees, but none of Discovery’s customers currently contracts for this transportation service. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations — Gathering and Processing Segment.”

      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 to alter this scheduled reduction. However, if filed, we cannot assure you that a rate case would be successful in even partially preventing the scheduled rate reduction. Please read “— FERC Regulation.”

Competition

      The Discovery pipeline system competes with other “wellhead to market” delivery options available to offshore producers in the Gulf of Mexico. While Discovery offers integrated gathering, transportation, processing and fractionation services through a single provider, it generally competes with other offshore Gulf of Mexico gathering systems and interconnecting gas processing and fractionation facilities, some of which may have the same owner. On the continental shelf in shallow water, Discovery’s pipeline system competes primarily with the MantaRay/ Nautilus system, the Trunkline system, the Tennessee System and the Venice Gathering System. These competing shallow water gathering systems connect to the following gas processing and fractionation facilities: the MantaRay/ Nautilus System connects to the Neptune gas processing plant, the Trunkline pipeline connects to the Patterson and Calumet gas processing plants, the Tennessee pipeline connects to the Yscloskey gas processing plant, and the Venice Gathering System connects to the Venice gas processing plant. In the deepwater region of the Gulf of Mexico, the Discovery pipeline system competes primarily with the GulfTerra pipeline and the Cleopatra pipeline. The GulfTerra pipeline connects to the

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ANR/ Pelican gas processing plant near Patterson, Louisiana, and the Cleopatra pipeline connects to the Neptune plant in Centerville, Louisiana.

Gas Supply

      Over 50 production blocks are currently dedicated to the Discovery system under life-of-lease contracts. Recently connected blocks include Murphy’s Front Runner discovery, Energy Partner’s Rock Creek discovery and Apache’s Tarantula discovery. In addition, in areas that we believe are accessible to the Discovery pipeline system, approximately 600 deepwater blocks are currently leased and approximately 100 have related exploration plans filed with the MMS or are named prospects. A named prospect is an individual lease or group of adjacent leases that are generally considered by a producer to have some economic potential for production.

The Carbonate Trend Pipeline

General

      Our Carbonate Trend gathering pipeline is a sour gas gathering pipeline consisting of approximately 34 miles of 12-inch diameter pipe that is used to gather sour gas production from the Carbonate Trend area off the coast of Alabama. Our Carbonate Trend pipeline is not regulated under the Natural Gas Act but is regulated under the Outer Continental Shelf Lands Act, which requires us to transport gas supplies on the Outer Continental Shelf on an open and non-discriminatory access basis. “Sour” gas is natural gas that has relatively high concentrations of acidic gases such as hydrogen sulfide and carbon dioxide. Our pipeline is designed to transport gas with a hydrogen sulfide and carbon dioxide content that exceeds normal gas transportation specifications. The pipeline was built and placed in service in 2000 and has a maximum design throughput capacity of approximately 120 MMcf per day. For the year ended December 31, 2004, our average transportation volume was approximately 50 MMcf/d. The pipeline is operated by ChevronTexaco under an operating agreement.

      Gas is shipped through our pipeline to Shell’s offshore sour gas gathering pipeline and Yellowhammer sour gas treatment facility located onshore in Coden, Alabama. From the Yellowhammer facility, treated gas can be delivered to the Williams-owned Mobile Bay gas processing plant, which has multiple pipeline interconnections to Transco, Florida Gas Transmission, Gulfstream, Mobile Gas Services and GulfSouth pipelines. Treated gas may also be delivered directly into the GulfSouth or the Transco pipelines at the tailgate of the Yellowhammer facility without processing.

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      The following map shows the location of our Carbonate Trend gathering pipeline, the Yellowhammer facility and Williams’ Mobile Bay gas processing plant.

      Our pipeline extends from ChevronTexaco’s production platform located at Viosca Knoll Block 251 to an interconnection point with Shell’s offshore sour gas gathering facility located at Mobile Bay Block 113. ChevronTexaco operates the pipeline, and we contract with Williams for the formulation of a corrosion control program to ensure the maintenance and reliability of our pipeline. Due to the corrosive nature of the sour gas, Williams has formulated and ChevronTexaco has implemented a corrosion control program for the Carbonate Trend pipeline. Please read “— Safety and Maintenance.”

      Revenue from the Carbonate Trend pipeline is generated through negotiated fees that we charge our customers to transport gas to the Shell offshore sour gas gathering system. These fees typically depend on the volume of gas we transport.

Carbonate Trend Customers and Contracts

      Customers. Our primary customer on the Carbonate Trend pipeline is ChevronTexaco, which, together with Noble Energy, have large lease positions in the Carbonate Trend area. ChevronTexaco and Noble Energy own an interest in 27 federal leases in the Southeast segment of the Carbonate Trend area and ChevronTexaco is the operator for the majority of these leases. For the year ended December 31, 2004, volumes from these ChevronTexaco leases represented approximately 68% of Carbonate Trend’s total throughput and 72% of Carbonate Trend’s total revenue with volumes from Noble Energy constituting the remainder.

      Contracts. We have long-term transportation agreements with ChevronTexaco and Noble Energy. Pursuant to these agreements, ChevronTexaco and Noble Energy have agreed to transport on our pipeline all

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gas produced on their 27 Carbonate Trend leases for the life of the leases or the economic life of the underlying reserves. There is no minimum volume requirement, and if the leases held by ChevronTexaco and Noble Energy expire or the underlying reserves are depleted, ChevronTexaco and Noble Energy will not be committed to ship any natural gas on our pipeline. In addition, if any lease expires, and is reacquired by the same company within ten years of such expiration, all production from that lease must again be transported via our pipeline. Under these agreements ChevronTexaco and Noble Energy may make an annual election to utilize capacity along a segment of Transco. When ChevronTexaco or Noble Energy utilize this capacity, our per-unit gathering fee is determined by subtracting the FERC tariff-based rate charged by Transco for this capacity from the total negotiated fee. Should these customers elect not to utilize the capacity along this segment of Transco, there is no assurance that this capacity will not be made available to these customers in the future. We have the option to terminate these agreements if expenses exceed certain levels or if revenues fall below certain levels and we are not compensated for these expenses or shortfalls.

Competition

      Other than the producer gathering lines that connect to the Carbonate Trend pipeline, there are no other sour gas gathering and transportation pipelines in the Carbonate Trend area, and we know of no current plans to build competing pipelines. As a result, as other blocks in the Carbonate Trend are developed, we believe that producers will find it more cost effective to connect to our pipeline than to construct or commission new sour gas pipelines of their own.

Gas Supply

      ChevronTexaco developed the Viosca Knoll Carbonate Trend area in the shallow waters of the Mobile and Viosca Knoll areas in the Eastern Gulf of Mexico. ChevronTexaco has filed 12 exploration plans with the MMS that we believe could result in the discovery of additional amounts of natural gas. Other producers may also transport gas on the Carbonate Trend pipeline. If the Yellowhammer facility becomes unavailable for the treatment of our customer’s sour gas, we believe that we can construct pipeline connections to access either of two third party-owned treatment facilities also located in Coden, Alabama.

The Conway Assets

General

      Our Conway assets are strategically located at one of the two major NGL trading hubs in the continental United States, and consist of:

•  three integrated NGL storage facilities; and

•  a 50% interest in an NGL fractionator.

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      The following map shows our Conway storage facilities, the Conway fractionator, connecting NGL and mixed NGL pipelines and competing storage and fractionation facilities.

Conway Storage Assets

      General. We believe we are the largest NGL storage facility, in terms of capacity, in the Mid-Continent Region. We own and operate three integrated underground NGL storage facilities in the Conway, Kansas area with an aggregate capacity of approximately 20 million barrels, which we refer to as the Conway West, Conway East and Mitchell storage facilities. Each facility is comprised of a network of caverns located several hundred feet below ground, and all three facilities are connected by pipeline. The caverns hold large volumes of NGLs and other hydrocarbons, such as propylene and naphtha. We operate these assets as one coordinated facility. Three lines connect the Mitchell facility to the Conway West facility and two lines connect the Conway East facility to the Conway West Facility. As of December 31, 2004, the storage facilities included a total of 158 caverns available for service with 162 well bores. These facilities also include a total of 18 brine basins with a total capacity of approximately 13 million barrels. Ten of the brine basins are located at the Conway West facility, five at the Conway East facility and three at the Mitchell facility.

      Our Conway storage facilities interconnect directly with two end-use interstate NGL pipelines: MAPL and the Kinder Morgan pipeline. We also, through connections of less than a mile, indirectly interconnect to two end-use interstate NGL pipelines: the Kaneb pipeline and the Koch pipeline. Through these pipelines and other storage facilities we can provide our customers interconnectivity to additional interstate NGL pipelines. We believe that the attributes of our storage facilities, such as the number and size of our caverns and well bores and our extensive brine system, coupled with our direct connectivity to MAPL through multiple meters

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allows our customers to inject, withdraw and deliver all of their products stored in our facilities more rapidly than products stored with our competitors.

      Conway West. The Conway West facility located adjacent to the Conway fractionation facility in McPherson County, Kansas is our primary storage facility. This facility consists of 54 caverns available for service and four undeveloped caverns with an aggregate storage capacity of approximately ten million barrels and ten brine ponds.

      Conway East. The Conway East facility is located approximately four miles east of the Conway West facility in McPherson County, Kansas and consists of 81 caverns available for service and five brine ponds. The Conway East facility has an aggregate storage capacity of approximately five million barrels. The Conway East facility also has an active truck loading and unloading facility, each with two spots, and a rail loading and unloading facility with 20 spots.

      Mitchell. The Mitchell facility is located approximately 14 miles west of the Conway West facility in Rice County, Kansas and consists of 23 caverns available for service with an aggregate storage capacity of approximately five million barrels and three brine ponds.

Customers and Contracts

      Customers. Our NGL storage customers include NGL producers, NGL pipeline operators, NGL service providers and NGL end-users. Our three largest customers, which accounted for 67% of our storage revenues for the storage year ended March 2004, are SemStream, Enterprise and Koch. Enterprise is an NGL pipeline operator, Koch is an NGL service provider, while SemStream is principally involved in propane marketing and distribution.

      Contracts. Our storage year for customer contracts runs from April 1 to March 31. We lease capacity on varying terms from less than six months to a year or more and have additional capacity available to contract. Our storage revenues are not generally affected by seasonality because our customers generally pay for storage capacity, not injected or withdrawn volumes.

      We have long-term contracts with SemStream, Enterprise and Koch. These three customers contract for approximately seven million barrels of storage capacity per year for terms that expire between 2009 and 2018. Each of these contracts is based a percentage of our published price of storage in our Conway facilities, which we adjust annually.

      Aside from our long-term contracts, most of our contracts are for a period of one year. In addition, we also enter into contracts for fungible product storage in increments of six months, three months or one month. For contracts of one year or less, our customers are required to remit the full contract price at the time the contract is signed, which makes us less susceptible to credit risks. One of our customers is the beneficiary of an agreement, which terminates 2019, that provides this customer with a yearly $177,000 credit against storage fees that it may incur in excess of the fees that it incurs for its contracted storage.

      We currently offer our customers four types of storage contracts — single product fungible, two product fungible, multi-product fungible and segregated product storage — in various quantities and at varying terms. Single product fungible storage allows customers to store a single product. Two-product fungible storage allows customers to store any combination of two fungible products. Multi-product fungible storage allows customers to store any combination of fungible products. In the case of two-product and multi-product storage, the customer designates the quantity of storage space for each product at the beginning of the lease period. Customers may change their quantity configurations throughout the year based upon our ability to accommodate each change. Segregated storage also is available to customers who desire to store non-fungible products at Conway, such as propylene, refinery grade butane and naphtha. We evaluate pricing, volume and availability for segregated storage on a case-by-case basis. Segregated storage allows a customer to lease an entire storage cavern and have its own product injected and withdrawn without having its product commingled with the products of our other customers. In addition to the fees we charge for fungible product storage and segregated product storage, we also receive fees for overstorage.

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Competition

      We compete with other salt cavern storage facilities. Our most direct competitor is a ONEOK-owned Bushton, Kansas storage facility that is directly connected to a Kinder Morgan pipeline. Other competitors include a ONEOK-owned facility in Conway, Kansas, a NCRA-owned facility in Conway, Kansas, a Koch-owned facility in Hutchinson, Kansas and a Ferrellgas-owned facility in Hutchinson, Kansas. We also compete with storage facilities on the Gulf Coast and in Canada to the extent that NGL product commodity prices differ between the Mid-Continent region and those areas and interstate pipelines to the extent that they offer storage services.

      An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. Many of our competitors have capital and other resources far greater than ours. Other competitive factors include (1) the quantity, location and physical flow characteristics of interconnected pipelines, (2) the ability to offer service from multiple storage locations, (3) the costs of service and rates of our competitors and (4) NGL product commodity prices in the Mid-Continent region as compared to prices in other regions.

NGL Sources and Transportation Options

      We generally receive the NGLs that we inject into our facilities, and our customers generally choose to transport the NGLs that we withdraw from our facilities, through the interstate NGL pipelines that interconnect with our storage facilities, including MAPL, a Kinder Morgan pipeline, a Kaneb pipeline and a Koch pipeline. We also receive substantially all of the separated NGLs from our fractionator for storage and further transportation through these interstate pipelines.

      Additionally, our customers have the option to have NGLs delivered to or transported from our storage facility, through our active truck loading and unloading facility, each with two spots, or our rail loading and unloading facility with 20 spots.

The Conway Fractionation Facility

      General. The Conway fractionation facility is strategically located at the junction of the south, east and west legs of MAPL and has interconnections with the BP Wattenberg pipeline and the ConocoPhillips Chisholm pipeline, each of which transports mixed NGLs to our facility. The Conway fractionation facility began operations in 1973 with single production train. In 1977, a second train was added and the capacity of the first train was upgraded, which brought the total design capacity of the Conway fractionation facility to approximately 107,000 bpd.

      We own a 50% undivided interest in the Conway fractionation facility, representing capacity of approximately 53,500 bpd. ConocoPhillips owns a 40% undivided interest, representing capacity of approximately 42,800 bpd, and Koch owns a 10% undivided interest, representing capacity of approximately 10,700 bpd. Each joint owner markets its own capacity independently. Each owner can also contract with the other owners for additional capacity at the Conway fractionation facility, if necessary. We will be the operator of the facility pursuant to an operating agreement that extends until May 2006. This agreement will automatically renew for an additional five years, until 2011, unless one of the parties gives notice of termination in writing one year prior to the expiration of the initial term.

      We primarily fractionate NGLs for third party customers for a fee based on the volumes of mixed NGLs fractionated. The fee per unit we charge is generally subject to adjustment for changes in certain fractionation 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 fractionation expenses to our customers. However, under one of our long-term fractionation contracts described below, 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, we will be a party to a gas purchase contract with a subsidiary of Williams for a sufficient quantity of natural

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gas at a fixed price to satisfy our fuel requirements under this fractionation contract. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations — NGL Services Segment — Fractionation Contracts.”

      The results of operations of the Conway fractionation facility are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. Overall, the NGL fractionation business exhibits little to no seasonal variation as NGL production is relatively constant throughout the year. We have additional capacity available at our fractionation facility to accommodate additional volumes.

Customers and Contracts

      Customers. We have long-term fractionation agreements with BP and Enterprise, which together accounted for approximately 66% of our NGL fractionation capacity at the Conway facility for the year ended December 31, 2004. Our other fractionation customers include Duke and Coffeyville Resources.

      Contracts. We have a long-term contract with BP which requires BP to deliver all of its proprietary mixed NGLs from its Wattenberg pipeline, which runs from Eastern Colorado to Bushton, Kansas, and its Hugoton, Kansas gas processing plant to the Conway fractionator. There is no minimum volume requirement, however, and if BP’s Hugoton processing plant and the Wattenberg pipeline were to cease operations for any reason, BP would not be required to deliver any mixed NGLs for fractionation under this agreement. Deliveries of mixed NGLs under the BP agreement have averaged approximately 27,200 bpd during the period from April to December 2003 and 25,400 bpd during the full year of 2004. The term of the agreement with respect to deliveries from the Wattenberg pipeline expires on January 1, 2008 but will automatically be renewed on a year-to-year basis unless otherwise terminated by the parties. The term of the agreement with respect to deliveries from Hugoton expires on January 1, 2013 and may be terminated effective January 1, 2008 if either party provides notice of termination before December 31, 2005.

      We have a long-term contract with Enterprise which requires it to deliver all of the mixed NGLs Enterprise purchases from Pioneer’s Texas Panhandle and Oklahoma Panhandle natural gas processing facilities to the Conway fractionator if it chooses to ship its mixed NGLs to the Mid-Continent region, as defined in the agreement. However, if Enterprise chooses to ship its mixed NGLs to another region, it has the right, on a month-to-month basis, to deliver its mixed NGLs elsewhere. Enterprise’s decision on whether to ship its products to the Mid-Continent region or to another region depends on factors including supply and demand in the respective regions and the current price being paid for purity products in each region. Deliveries of mixed NGL products under the Enterprise agreement have averaged approximately 10,000 bpd during the full year of 2004 and 6,100 bpd during the period from April to December 2003. The Enterprise agreement expires in 2009.

      We generally enter into contracts that cover a portion of our remaining capacity at the Conway facility for periods of one year or less.

Competition

      Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products are also important competitive factors and are determined by the existence of the necessary pipeline and storage infrastructure. NGL fractionators connected to extensive storage, transportation and distribution systems such as ours have direct access to larger markets than those with less extensive connections. Our principal competitors are a Koch-owned fractionator located in Medford, Oklahoma, a Koch-owned fractionator located in Hutchinson, Kansas and a ONEOK-owned fractionator located in Bushton, Kansas. We compete with the two other joint owners of the Conway fractionation facility for third party customers. We also compete with fractionation facilities on the Gulf Coast, to the extent that NGL product commodity prices differ between the Mid-Continent region and the Gulf Coast.

      An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. Many of our competitors have capital and other resources far greater than ours. Other

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competitive factors include (1) the quantity and location of interconnected pipelines, (2) the costs and rates of our competitors, (3) whether fractionation providers offer to purchase a customers mixed NGLs instead of providing fee based fractionation services and (4) NGL product commodity prices in the Mid-Continent region as compared to prices in other regions.

Mixed NGL Sources

      Based on EIA projections of relatively stable production levels of natural gas in the Mid-Continent region over the next ten years, we believe that sufficient volumes of mixed NGLs will be available for fractionation in the foreseeable future. In addition, through connections with MAPL and the BP Wattenberg pipeline, the Conway fractionation facility has access to mixed NGLs from additional major supply basins in North America, including additional major supply basins in the Rocky Mountain production area.

NGL Transportation Options

      After the mixed NGLs are separated at the fractionator, the NGL products are typically transported to our storage facilities. At our storage facilities, the NGLs may be stored or transported on one of the interconnected NGL pipelines. Our customers also have the option to have their NGL products transported through our truck loading and rail loading facilities. Additionally, when market conditions dictate, we have the ability to place propane directly into MAPL from our fractionator, providing our customers with expedited access to interstate markets.

Safety and Maintenance

      Discovery’s natural gas pipeline system is subject to regulation by the United States Department of Transportation, referred to as DOT, under the Accountable Pipeline and Safety Partnership Act of 1996, referred to as the Hazardous Liquid Pipeline Safety Act, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management. The Hazardous Liquid Pipeline Safety Act covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations.

      Discovery’s gas pipeline system is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002. The Natural Gas Pipeline Safety Act regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States oil and natural gas transportation pipelines and some gathering lines in high-consequence areas within 10 years. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. We currently estimate we will incur costs of approximately $1.3 million between 2005 and 2009 to implement integrity management program testing along certain segments of Discovery’s 16, 20, and 30-inch diameter natural gas pipelines and its 10, 14, and 18-inch diameter NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program.

      States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we or the entities in which we own an interest operate.

      Our natural gas pipelines have continuous inspection and compliance programs designed to keep its facilities in compliance with pipeline safety and pollution control requirements. In addition, in compliance with applicable permit requirements, offshore portions of our Carbonate Trend pipeline are being surveyed

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following the occurrence of Hurricane Ivan in September 2004 to confirm the extent to which any scour of overburden soils developed along the pipeline right-of-way. This survey is expected to be completed by June 1, 2005 at a cost of approximately $600,000, with additional costs likely to be incurred for restoration activities if any significant scour of the overburden soils is detected. We believe that our natural gas pipelines are in material compliance with the applicable requirements of these safety regulations.

      Our Carbonate Trend pipeline requires a corrosion control program to protect the integrity of the pipeline and prolong its life. The corrosion control program consists of continuous monitoring and injection of corrosion inhibitor into the pipeline, periodic chemical treatments and annual detailed comprehensive inspections. We believe that this is an aggressive and proactive corrosion control program that will reduce metal loss, limit corrosion and possibly extend the service life of the pipe by 15 to 20 years.

      In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with the OSHA regulations.

FERC Regulation

General

      The Carbonate Trend sour gas gathering pipeline and the offshore portion of Discovery’s natural gas pipeline are subject to regulation under the Outer Continental Shelf Lands Act, which calls for nondiscriminatory transportation on pipelines operating in the outer continental shelf region of the Gulf of Mexico.

      Portions of Discovery’s natural gas pipeline are also subject to regulation by FERC, under the Natural Gas Act. The Natural Gas Act requires, among other things, that the rates be “just and reasonable” and nondiscriminatory. Under the Natural Gas Act, the FERC has authority over the construction, operation and expansion of interstate pipeline facilities, as well as the terms and conditions of service provided by the operator of such facilities. In general, Discovery must receive prior FERC approval to construct, operate or expand its FERC-regulated facilities, to initiate new service using such facilities, to alter the terms and conditions of service provided on such facilities, and to abandon service provided by its FERC-regulated facilities. With respect to certain types of construction activities and certain types of service, the FERC has issued rules that allow regulated pipelines to obtain blanket authorizations that obviate the need for prior specific FERC approvals for initiating and abandoning service. Commencing in 1992, the FERC issued a series of orders (“Order No. 636”), which require interstate pipelines to provide transportation service separate or “unbundled” from the pipelines’ sales of gas. Order No. 636 also required interstate pipelines, such as Discovery to provide open access transportation on a non-discriminatory basis that is equal for all similarly situated shippers. The Natural Gas Act also gives FERC the authority to regulate the rates that Discovery charges for service on portions of its natural gas pipeline system. The natural gas pipeline industry has historically been heavily regulated by federal and state governments, and we cannot predict what further actions FERC, state regulators, or federal and state legislators may take in the future.

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      The Discovery 105-mile mainline, approximately 60 miles of laterals and its market expansion project are subject to regulation by FERC, as will be the market expansion project once it begins service. The following table shows the maximum transportation tariffs that Discovery can charge on its regulated transportation pipelines:

Discovery Asset	Maximum FERC Rate
Mainline	$0.1569/MMBtu through January 2008; $0.08 thereafter
FERC-regulated laterals	$0.039/MMBtu
Market expansion project	$0.08/MMBtu

      Under Discovery’s current FERC-approved tariff, the maximum rate that Discovery may charge its customers for the transportation of natural gas along its mainline is $0.1569/ MMBtu. This maximum rate is scheduled to decrease in 2008 to $0.08/ MMBtu. 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 reduction. However, if filed, we cannot assure you that a rate case would be successful in even partially preventing the scheduled rate reduction.

      In connection with a rate case filed by Discovery, all aspects of its cost of service and rate design of its rates could be reviewed, including the following:

•  the overall cost of service, including operating costs and overhead;

•  the allocation of overhead and other administrative and general expenses to the rate;

•  the appropriate capital structure to be utilized in calculating rates;

•  the appropriate rate of return on equity;

•  the cost of debt;

•  the rate base, including the proper starting rate base;

•  the throughput underlying the rate; and

•  the proper allowance for federal and state income taxes.

      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. It is not clear what impact, if any, the court’s opinion will have on Discovery’s tariffed rates or on the rates of other interstate natural gas pipelines organized as non-corporate entities, including other master limited partnerships, because it is not clear what action FERC will take in response to BP West Coast, whether such action will be challenged, and, if so, whether it will withstand further FERC or judicial review. Nevertheless, a shipper might rely on the court’s decision to challenge Discovery’s rates and claim that its income tax allowance should be eliminated. If FERC were to disallow Discovery’s income tax allowance, it may be more difficult for Discovery to justify its rates.

      These aspects of Discovery’s rates also could be reviewed if FERC or a shipper initiated a complaint proceeding. However, we do not believe that it is likely that there will be a challenge to Discovery’s rates by a current shipper that would materially affect its revenues or cash flows.

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      In 2000, FERC issued Order No. 637 which, among other things:

•  required pipelines to implement imbalance management services;

•  restricted the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders; and

•  implemented a number of new pipeline reporting requirements.

      In addition, FERC implemented new regulations governing the procedure for obtaining authorization to construct new pipeline facilities and has issued a policy statement, which it largely affirmed in a recent order on rehearing, establishing a presumption in favor of requiring owners of new pipeline facilities to charge rates based solely on the costs associated with such new pipeline facilities. We cannot predict what further action FERC will take on these matters. However, we do not believe that Discovery will be affected by any action taken previously or in the future on these matters materially differently than other natural gas gatherers and processors with which it competes.

      Commencing in 2003, the FERC issued a series of orders adopting rules for new Standards of Conduct for Transmission Providers (Order No. 2004) which apply to interstate natural gas pipelines such as Discovery. Order No. 2004 became effective last year. Among other matters, Order No. 2004 requires interstate pipelines to operate independently from their energy affiliates, prohibits interstate pipelines from providing non-public transportation or shipper information to their energy affiliates; prohibits interstate pipelines from favoring their energy affiliates in providing service; and obligates interstate pipelines to post on their websites a number of items of information concerning the pipeline, including its organizational structure, facilities share with energy affiliates, discounts given for transportation service, and instances in which the pipeline has agreed to waive discretionary terms of its tariff. Discovery requested and received a partial waiver from certain portions of Order No. 2004. Since the effective date of Order No. 2004, Discovery has determined that additional waivers from compliance with Order No. 2004 are necessary to accommodate the management committee structure under which Discovery operates. Discovery expects to file a request for additional limited waivers from for Order No. 2004 compliance in the near future.

      Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that the less stringent and pro-competition regulatory approach recently pursued by FERC and Congress will continue.

      The Carbonate Trend pipeline is a gathering pipeline, and is not subject to FERC jurisdiction under the Natural Gas Act.

Processing Plant

      The primary function of Discovery’s natural gas processing plant is the extraction of NGLs and the conditioning of natural gas for marketing into the natural gas pipeline grid. FERC has traditionally maintained that a processing plant that primarily extracts NGLs is not a facility for transportation or sale of natural gas for resale in interstate commerce and therefore is not subject to its jurisdiction under the Natural Gas Act. We believe that the natural gas processing plant is primarily involved in removing NGLs and, therefore, is exempt from the jurisdiction of FERC.

Environmental Regulation

General

      Our operation of pipelines, plants and other facilities for gathering, transporting, processing or storing natural gas, NGLs and other products is subject to stringent and complex federal, state, and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. Due to the myriad of complex federal, state and local laws and regulations that may affect us, directly or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.

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      As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that our operations are in material compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent, and often times more stringent, change by regulatory authorities and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Violation of environmental laws, regulations and permits can result in the imposition of significant administrative, civil and criminal penalties, remedial obligations, injunctions and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent the event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and claims made by neighboring landowners and other third parties for personal injury and property damage.

      We or the entities in which we own an interest inspect the pipelines regularly using equipment rented from third party suppliers. Third parties also assist us in interpreting the results of the inspections.

      Williams has agreed to indemnify us in an aggregate amount not to exceed $           million for            years after the closing of this offering for environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before the closing date.

Air Emissions

      Our operations are subject to the Clean Air Act and comparable state and local statutes. Amendments to the Clean Air Act enacted in late 1990 require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the U.S. Environmental Protection Agency, or EPA, and state environmental agencies. As a result of these amendments, our facilities that emit volatile organic compounds or nitrogen oxides are subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the 1990 Clean Air Act Amendments established a new operating permit for major sources. Although we can give no assurances, we believe that the expenditures needed for us to comply with the 1990 Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations.

Hazardous Substances and Waste

      To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste. They also require corrective action, including the investigation and remediation of certain units, at a facility where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses natural gas, we may nonetheless handle “hazardous substances” within the meaning of CERCLA, or similar state statutes, in the course of our ordinary

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operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

      We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal Solid Waste Disposal Act, the federal Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for wastes currently designated as “non-hazardous.” However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements than non-hazardous wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.

      We currently own or lease, and our predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.

Water

      The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act, also referred to as the CWA, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state and federal waters. The CWA imposes substantial potential civil and criminal penalties for non-compliance. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities. In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The EPA has promulgated regulations that require us to have permits in order to discharge certain storm water run-off. The EPA has entered into agreements with certain states in which we operate whereby the permits are issued and administered by the respective states. These permits may require us to monitor and sample the storm water run-off. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

Endangered Species Act

      The Endangered Species Act restricts activities that may affect endangered species or their habitats. Although none of our facilities have been designated as habitat for endangered species, the discovery of previously unidentified endangered species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected area.

Hazardous Materials Transportation Requirements

      The DOT regulations affecting pipeline safety require pipeline operators to implement measures designed to reduce the environmental impact of discharge from onshore pipelines. These regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. In addition, the DOT regulations contain detailed specifications for pipeline operation and maintenance. We believe our operations are in substantial compliance with these regulations. Please read “— Safety and Maintenance.”

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Kansas Department of Health and Environment Obligations

      We currently own and operate underground storage caverns near Conway, Kansas that have been created by solutioning the caverns in the Hutchinson salt formation. These storage caverns are used to store NGLs and other hydrocarbons. These caverns 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. The Underground Hydrocarbon and Natural Gas Storage Program became effective on April 1, 2003 and regulates the storage of liquefied petroleum gas, hydrocarbons and natural gas in bedded salt for the purpose of protecting public health and safety, property and the environment and regulates the construction, operation and closure of brine ponds associated with our storage caverns. Storage facilities subject to these regulations must be in compliance by no later than April 1, 2008 or April 1, 2010, depending on the specific regulations. Failure to comply with the Underground Hydrocarbon and Natural Gas Storage Program may lead to the assessment of administrative, civil or criminal penalties.

      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.

      Furthermore, the KDHE has advised us that a regulation relating to the metering of NGL volumes that are injected and withdrawn from our caverns may be interpreted 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 Conway West and Mitchell would be approximately $3.9 million over three years.

      Additionally, we are currently undergoing remedial activities pursuant to KDHE Consent Orders issued in the early 1990s. The Consent Orders were issued after elevated concentrations of chlorides were discovered in various on-site and off-site shallow groundwater resources at each of our Conway storage facilities. With KDHE approval, we are currently installing and implementing a containment and monitoring system to delineate further the scope of and to arrest the continued migration of the chloride plume at the Mitchell facility. Chlorides have also been detected near the Equus Beds Aquifer, in the vicinity of one of our Conway facilities, although preliminary investigations do not indicate that we are the source of such contamination. Nonetheless, we are currently cooperating with KDHE and other operators in the area to evaluate the situation.

      Furthermore, historical releases of hydrocarbons from our pipelines and from previous operations at our storage facility assets have resulted in localized contamination of the groundwater with hydrocarbon derivatives. It is expected, however, that most of the localized groundwater contamination will be addressed by the chloride containment system discussed above. We have also recently detected NGLs and other hydrocarbons in localized groundwater resources around two abandoned storage caverns. Although the complete extent of the contamination appears to be limited and appears to have been arrested, we are continuing to work to delineate further the scope of the contamination. To date, KDHE has not undertaken any enforcement action related to the releases around the abandoned storage caverns.

      We are continuing to evaluate our assets to prevent future releases. While we maintain an extensive inspection and audit program designed, as appropriate, to prevent and to detect and address such releases promptly, there can be no assurance that future environmental releases from our assets will not have a material effect on us.

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Title to Properties and Rights-of-Way

      Our real property falls into two categories: (1) parcels that we own in fee, such as land at the Conway fractionation and storage facility, and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. The fee sites upon which major facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, right-of-way and licenses.

      Some of the leases, easements, rights-of-way, permits and licenses to be transferred to us require the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner expects to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to closing of this offering, the closing of this offering will not occur unless reasonable bases exist that permit our general partner to conclude that such consents, permits, or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business. With respect to leases and right-of-way interests in federal waters of the Gulf of Mexico, the MMS regulations require MMS approval for assignments of such leases and right-of-way interests and such approval cannot be obtained in advance of the consummation of this offering. Based on Williams’ prior experience with the MMS, we believe that we will obtain the requisite MMS approvals in the ordinary course of business after the closing of the offering.

      Williams or its affiliates initially may continue to hold record title to portions of certain assets until we make the appropriate filings in the jurisdictions in which such assets are located and to obtain any consents and approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions such as the MMS. In some cases, Williams or its affiliates may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from the holding by Williams or its affiliates of title to any part of such assets subject to future conveyance or as our nominee. We have established a legal opinion with regard to the risk, if any, of the holding by Williams or its affiliates of record title to some portion of our assets as our nominee.

Employees

      To carry out our operations, our general partner or its affiliates employ approximately 120 people who provide direct support for our operations. None of these employees are covered by collective bargaining agreements. Our general partner considers its employee relations to be good.

Legal Proceedings

      We are not a party to any legal proceeding but are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “— FERC Regulation” and “— Environmental Regulation.”

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MANAGEMENT

Management of Williams Partners L.P.

      Williams Partners GP LLC, as our general partner, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation.

      Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to incur indebtedness or other obligations that are nonrecourse.

      At least two members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the New York Stock Exchange and the Sarbanes-Oxley Act of 2002 and other federal securities laws. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. In addition, we will have an audit committee of at least three independent directors that will review our external financial reporting, recommend engagement of our independent auditors and review procedures for internal auditing and the adequacy of our internal accounting controls. Our conflicts and compensation committees will consist of two or more independent members that will also serve on our audit committee. The compensation committee will oversee compensation decisions for the officers of our general partner as well as the compensation plans described below.

      In compliance with the corporate governance rules of the New York Stock Exchange, the members of the board of directors of our general partner will appoint an independent member to the board upon listing of the common units on the Exchange, a second independent member within three months of listing and a third independent member within 12 months of listing. The independent members of the board of directors of our general partner will serve as the initial members of the conflicts, audit and compensation committees.

      We are managed and operated by the directors and officers of our general partner. All of our operational personnel will be employees of an affiliate of our general partner.

      All of the senior officers of our general partner are also senior officers of Williams and will spend a sufficient amount of time overseeing the management, operations, corporate development and future acquisition initiatives of our business. Alan Armstrong, the Chief Operating Officer of our general partner will be the principal executive responsible for the oversight of our affairs. Our non-executive directors will devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

Directors and Executive Officers of Our General Partner

      The following table shows information for the directors and executive officers of our general partner. Directors are elected for one-year terms.

Name	Age		Position with Williams Partners GP
Steven J. Malcolm		56	Chairman of the Board and Chief Executive Officer
Donald R. Chappel		53	Chief Financial Officer and Director
Alan S. Armstrong		42	Chief Operating Officer and Director
James J. Bender		48	General Counsel
Phillip D. Wright		49	Director

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

      Steven J. Malcolm is chairman of the board of directors of our general partner and chief executive officer of our general partner. Mr. Malcolm has served as president of Williams since September 2001, chief executive of Williams since January 2002, and chairman of the board of directors of Williams since May 2002. From May 2001 to September 2001, he served as executive vice president of Williams. From December 1998 to May 2001, he served as president and chief executive officer of Williams Energy Services, LLC. From November 1994 to December 1998, Mr. Malcolm served as the senior vice president and general manager of Williams Field Services Company. Mr. Malcolm served as chief executive officer and chairman of the board of directors of the general partner of Williams Energy Partners L.P. from the initial public offering in February 2001 of Williams Energy Partners L.P. (now known as Magellan Midstream Partners, L.P.) to the sale of Williams’ interests therein in June 2003.

      Donald R. Chappel is chief financial officer and a director of our general partner. Mr. Chappel has served as senior vice president and chief financial officer of Williams since April 2003. Prior to joining Williams, Mr. Chappel, from 2000 to April 2003, founded and served as chief executive officer of a development business in Chicago, Illinois. From 1987 though February 2000, Mr. Chappel served in various financial, administrative and operational leadership positions for Waste Management, Inc., including twice serving as chief financial officer, during 1997 and 1998 and most recently during 1999 through February 2000.

      Alan S. Armstrong is chief operating officer and a director of our general partner. Mr. Armstrong has served as senior vice president of Williams’ midstream operations since February 2002. From 1999 to February 2002, Mr. Armstrong was vice president, gathering and processing of Williams’ midstream operations and from 1998 to 1999 was vice president, commercial development for Williams’ midstream operations.

      James J. Bender is the general counsel of our general partner. Mr. Bender has served as senior vice president and general counsel of Williams since December 2002. From June 2000 until joining Williams, Mr. Bender was senior vice president and general counsel with NRG Energy, Inc. Mr. Bender was vice president, general counsel and secretary of NRG Energy from June 1997 to June 2000. NRG Energy filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003.

      Phillip D. Wright is a director of our general partner. Mr. Wright has served as senior vice president of Williams’ gas pipeline operations since January 2005. From October 2002 to January 2005, Mr. Wright served as chief restructuring officer of Williams. From September 2001 to October 2002, Mr. Wright served as president and chief executive officer of Williams Energy Services. From 1996 to September 2001, he was senior vice president, enterprise development and planning for Williams’ energy services group. Mr. Wright, from 1989 to 1996 served in various capacities for Williams. Mr. Wright served as president, chief operating officer and director of the general partner of Williams Energy Partners L.P. from the initial public offering in February 2001 of Williams Energy Partners L.P. (now known as Magellan Midstream Partners, L.P.) to the sale of Williams’ interests therein in June 2003.

Executive Compensation

      Williams Partners L.P. and our general partner were formed in February 2005. We have not accrued any obligations with respect to management incentive or retirement benefits for the directors and officers for the 2005 fiscal year. Officers and employees of our general partner or its affiliates may participate in employee benefit plans and arrangements sponsored by our general partner or its affiliates, including plans that may be established by our general partner or its affiliates in the future.

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Employment Agreements

      The executive officers of our general partner are also executive officers of Williams. These executive officers do not have employment agreements with Williams or our general partner.

Compensation of Directors

      Following the completion of this offering, our officer or employees who also serve as directors will not receive additional compensation. Our general partner anticipates that each independent director will receive compensation for attending meetings of the board of directors, as well as committee meetings. The amount of compensation to be paid to independent directors has not yet been determined. In addition, each non-employee director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law.

Long-Term Incentive Plan

      Our general partner intends to adopt the Williams Partners L.P. Long-Term Incentive Plan for employees, consultants and directors of our general partner and employees and consultants of its affiliates who perform services for our general partner or its affiliates. Our general partner currently has no intention to make any grants or awards under the plan in connection with this offering or afterwards, but reserves the right to implement the plan in the future. The long-term incentive plan consists of four components: restricted units, phantom units, unit options and unit appreciation rights. The long-term incentive plan currently permits the grant of awards covering an aggregate of            units. If the plan is implemented, it will be administered by the compensation committee of the board of directors of our general partner.

      Our general partner’s board of directors, or its compensation committee, in its discretion may initiate, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any award that has not yet been granted. Our general partner’s board of directors, or its compensation committee, also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

Restricted Units and Phantom Units

      Should we choose to implement the long-term incentive plan, a restricted unit will be a common unit subject to forfeiture prior to the vesting of the award. A phantom unit will be a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equivalent to the value of a common unit. The compensation committee may determine to make grants under the plan of restricted units and phantom units to employees, consultants and directors containing such terms as the compensation committee shall determine. The compensation committee will determine the period over which restricted units and phantom units granted to employees, consultants and directors will vest. The committee may base its determination upon the achievement of specified financial objectives. In addition, the restricted units and phantom units will vest upon a change of control of Williams Partners L.P., our general partner or Williams, unless provided otherwise by the compensation committee.

      If a grantee’s employment, service relationship or membership on the board of directors terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the compensation committee provides otherwise. Common units to be delivered in connection with the grant of restricted units or upon the vesting of phantom units may be common units acquired by our general partner on the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. Thus, the cost of the restricted units and delivery of common units upon the vesting of phantom units will be borne by us. If we issue new common units in connection with the grant of restricted units or upon vesting of the

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phantom units, the total number of common units outstanding will increase. The compensation committee, in its discretion, may grant tandem distribution rights with respect to restricted units and tandem distribution equivalent rights with respect to phantom units.

Unit Options and Unit Appreciation Rights

      Should we choose to implement the long-term incentive plan, it will permit the grant of options covering common units and the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess may be paid in common units, cash, or a combination thereof, as determined by the compensation committee in its discretion. The compensation committee will be able to make grants of unit options and unit appreciation rights under the plan to employees, consultants and directors containing such terms as the committee shall determine. Unit options and unit appreciation rights may have an exercise price that is less than, equal to or greater than the fair market value of the common units on the date of grant. In general, unit options and unit appreciation rights granted will become exercisable over a period determined by the compensation committee. In addition, the unit options and unit appreciation rights will become exercisable upon a change in control of Williams Partners L.P., our general partner or Williams, unless provided otherwise by the committee.

      Upon exercise of a unit option (or a unit appreciation right settled in common units), our general partner will acquire common units on the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received from a participant at the time of exercise. Thus, the cost of the unit options (or a unit appreciation right settled in common units) will be borne by us. If we issue new common units upon exercise of the unit options (or a unit appreciation right settled in common units), the total number of common units outstanding will increase, and our general partner will pay us the proceeds it receives from an optionee upon exercise of a unit option. The availability of unit options and unit appreciation rights is intended to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

Reimbursement of Expenses of Our General Partner

      Our general partner will not receive any management fee or other compensation for its management of Williams Partners L.P. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf, including the compensation of employees of an affiliate of our general partner that perform services on our behalf. These expenses include all expenses necessary or appropriate to the conduct of the business of, and allocable to, Williams Partners L.P. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to Williams Partners L.P. There is no cap on the amount that may be paid or reimbursed to our general partner for compensation or expenses incurred on our behalf, except that pursuant to the Omnibus Agreement, Williams will provide a partial credit for general and administrative expenses that we incur for a period of five years following this offering. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

      The following table sets forth the beneficial ownership of units of Williams Partners L.P. that will be owned upon the consummation of this offering and the related transactions by:

•  each person known by us to be a beneficial owner of more than 5% of the units;

•  each of the directors of our general partner;

•  each of the named executive officers of our general partner; and

•  all directors and executive officers of our general partner as a group.

      The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

      Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

      Percentage of beneficial ownership after the transaction is based on 13,243,244 units outstanding. The table assumes that the underwriters’ option to purchase additional units is not exercised and excludes any units purchased in this offering by the respective beneficial owners.

			Percentage of					Percentage of			Percentage of
	Common		Common			Subordinated		Subordinated			Total
	Units to be		Units to be			Units to be		Units to be			Units to be
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner	Owned		Owned			Owned		Owned			Owned
The Williams Companies, Inc.(a)		1,621,622		24.4	%		6,621,622		100	%		62.2	%
Williams Energy Services, LLC
Williams Energy LLC
Williams Discovery Pipeline, LLC
Williams Partners Holdings LLC
Steven J. Malcolm		—		—			—		—			—
Donald R. Chappel		—		—			—		—			—
Alan S. Armstrong		—		—			—		—			—
James J. Bender		—		—			—		—			—
Phillip D. Wright		—		—			—		—			—
All executive officers and directors as a group (5 persons)		—		—			—		—			—

*  Less than 1%.

(a)  The Williams Companies, Inc. is the ultimate parent company of Williams Energy Services, LLC, Williams Energy LLC, Williams Discovery Pipeline, LLC and Williams Partners Holdings LLC and may, therefore, be deemed to beneficially own the units held by Williams Energy Services, LLC, Williams Energy LLC, Williams Discovery Pipeline, LLC and Williams Partners Holdings LLC. The Williams Companies, Inc.’s common stock is listed on the New York Stock Exchange under the symbol “WMB.” The Williams Companies, Inc. files information with or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Securities Exchange Act of 1934.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

      After this offering, our general partner and its affiliates will own 1,621,622 common units and 6,621,622 subordinated units representing a direct 61% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us.

Distributions and Payments to Our General Partner and Its Affiliates

      The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation, and liquidation of Williams Partners L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general partner and its affiliates for the contribution of the assets and liabilities	• 1,621,622 common units;
	• 6,621,622 subordinated units;
	• 2% general partner interest;
	• the incentive distribution rights; and
	• $85.4 million cash distribution of the proceeds of the offering to repay them for certain advances.

Operational Stage

Distributions of available cash to our general partner and its affiliates	We will generally make cash distributions 98% to unitholders, including our general partner and its affiliates, as holders of an aggregate of 1,621,622 common units, all of the subordinated units and the remaining 2% to our general partner.
	In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level. We refer to the rights to the increasing distributions as “incentive distribution rights.” Please read “Cash Distribution Policy — Incentive Distribution Rights” for more information regarding the incentive distribution rights.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units, our general partner would receive an annual distribution of approximately $0.4 million on the 2% general partner interest and the affiliates of our general partner described above would receive an annual distribution of approximately $12.2 million on their common units and subordinated units.
Payments to our general partner and its affiliates	Our general partner will not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates will be reimbursed, however, for all direct

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	and indirect expenses incurred on our behalf. Our general partner will determine the amount of these expenses.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement — Withdrawal or Removal of Our General Partner.”

Liquidation Stage

Liquidation Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements Governing the Transactions

      We, our general partner, our operating company and other parties have entered into or will enter into the various documents and agreements that will effect the transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with vesting assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement

      Upon the closing of this offering, we will enter into the Omnibus Agreement with Williams and its affiliates that will govern our relationship with them regarding the following matters:

•  reimbursement of certain general and administrative expenses;

•  indemnification for certain environmental liabilities, tax liabilities and right-of-way defects; and

•  a license for the use of certain software and intellectual property.

Indemnification

      Under the Omnibus Agreement, Williams will indemnify us after the closing of this offering for a period of three years against certain unknown environmental liabilities in excess of $           per occurrence arising out of or associated with the operation of the assets before the closing date of this offering. Liabilities resulting from a change of law after the closing of this offering are excluded from the environmental indemnity. There is an aggregate cap of $          on the amount of indemnity coverage provide by Williams for the unknown environmental liabilities.

      In addition, Williams will indemnify us for certain known environmental liabilities associated with the operation of the Conway assets before the closing date of this offering. We purchased a $5 million insurance policy with respect to the certain known environmental obligations. There is a $4.2 million deductible under the insurance policy. Williams has agreed to indemnify us for the $4.2 million deductible (less any amounts that are expended prior to closing) of remediation expenditures not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring.

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      Williams will also indemnify us for liabilities related to:

•  certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to us are located and failure to obtain certain consents and permits necessary to conduct our business that arise within            years after the closing of this offering; and

•  certain income tax liabilities attributable to the operation of the assets contributed to us prior to the time they were contributed.

Intellectual Property [and Software] License

      Williams and its affiliates will grant a license to us for the use of the Product Accounting System software system and other intellectual property, including our logo, for as long as Williams controls our general partner, at no charge.

General and Administrative Expenses

      Williams will provide us with a five-year partial credit for general and administrative expenses incurred on our behalf. In the first year, the amount of this credit will be $3.9 million. The amount of this credit will decrease by approximately $800,000 each year. As a result, after five years, we will no longer receive and credit and will be required to reimburse Williams for all of the general and administrative expenses incurred on our behalf.

Amendments

      The Omnibus Agreement may not be amended without the prior approval of the conflicts committee if the proposed amendment will, in the reasonable discretion of our general partner, adversely affect holders of our common units.

Competition

      Williams will not be restricted under the Omnibus Agreement from competing 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 those assets.

Working Capital Credit Facility

      At the closing of the offering, we will enter into a $20 million, two-year revolving credit facility with Williams as the lender. The facility will be available exclusively to fund working capital borrowings. Borrowings under the facility will bear interest at the same rate as would be available for borrowings under the Williams revolving credit facility described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Borrowing Limit Under Williams’ Credit Facility.”

      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.

      In addition we will also have the ability to borrow up to $75 million under the Williams revolving credit facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Borrowing Limit Under Williams’ Credit Facility.”

Discovery Operating and Maintenance Agreement

      Discovery is party to an operating and maintenance agreement with Williams. Under this agreement, Discovery is required to reimburse Williams for direct payroll and employee benefit costs incurred on Discovery’s behalf. Most costs for materials, services and other charges are third-party charges and are invoiced directly to Discovery. Discovery is required to pay Williams a monthly operation and management

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fee to cover the cost of accounting services, computer systems and management services provided to Discovery. Discovery also pays Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

      Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Williams, on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to the unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

      Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. An independent third party is not required to evaluate the fairness of the resolution.

      Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

•  approved by the conflicts committee, although our general partner is not obligated to seek such approval;

•  approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

•  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•  fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

      If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires. Please read “Management — Management of Williams Partners L.P.” for information about the conflicts committee of the board of directors of our general partner.

      Conflicts of interest could arise in the situations described below, among others.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders or accelerate the right to convert subordinated units.

      The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

•  amount and timing of asset purchases and sales;

•  cash expenditures;

•  borrowings;

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•  issuance of additional units; and

•  the creation, reduction or increase of reserves in any quarter.

      In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

•  enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

•  hastening the expiration of the subordination period.

      For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Cash Distribution Policy — Subordination Period.”

      Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company, or its operating subsidiaries.

We do not have any officers or employees and rely solely on officers and employees of our general partner and its affiliates.

      Affiliates of our general partner conduct businesses and activities of their own in which we have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to general partner. The officers of general partner are not required to work full time on our affairs. These officers are required to devote time to the affairs of Williams or its affiliates and are compensated by them for the services rendered to them.

Certain of our officers are not required to devote their full time to our business.

      All of the senior officers of our general partner are also senior officers of Williams and will spend sufficient amounts of their time overseeing the management, operations, corporate development and future acquisition initiatives of our business. Alan Armstrong, the Chief Operating Officer of our general partner will be the principal executive responsible for the oversight of our affairs. Our non-executive directors will devote as much time as is necessary to prepare for and attend board of directors and committee meetings.

We will reimburse our general partner and its affiliates for expenses.

      We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”

Our general partner intends to limit its liability regarding our obligations.

      Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained terms that are more favorable without the limitation on liability.

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Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

      Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

      Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement between us and our general partner and its affiliates, must be:

•  on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•  “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

      Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

      Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner and its affiliates, except as may be provided in contracts entered into specifically dealing with that use. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

Common units are subject to our general partner’s limited call right.

      Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

We may not choose to retain separate counsel for ourselves or for the holders of common units.

      The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner’s affiliates may compete with us.

      Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than those incidental to its ownership of interests in us. However, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to acquire those assets.

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Fiduciary Duties

      Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by a general partner to limited partners and the partnership.

      Our partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has fiduciary duties to manage our general partner in a manner beneficial both to its owner, Williams, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interests would be restricted. The modifications to the fiduciary standards benefit our general partner by enabling it to take into consideration all parties involved in the proposed action. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to the common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of:

•  the fiduciary duties imposed on our general partner by the Delaware Act;

•  material modifications of these duties contained in our partnership agreement; and

•  certain rights and remedies of unitholders contained in the Delaware Act.

State law fiduciary duty standards	Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.
Partnership agreement modified standards	Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, Section 7.9 of our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
	Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee

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	of the board of directors of our general partner’s general partner must be:
	• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
	• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
	If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.
	In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner, its general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.
Rights and remedies of unitholders	The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

      In order to become one of our limited partners, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

      Under the partnership agreement, we must indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. We also must provide this indemnification for

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criminal proceedings when our general partner or these other persons acted with no reasonable cause to believe that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the Securities and Exchange Commission such indemnification is contrary to public policy and therefore unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

      The common units and the subordinated units represent limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section, “Cash Distribution Policy” and “Description of the Subordinated Units.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

      EquiServe Trust Company, N.A. will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:

•  surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

•  special charges for services requested by a holder of a common unit; and

•  other similar fees or charges.

      There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

      The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

      The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer application. By executing and delivering a transfer application, the transferee of common units:

•  becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

•  automatically requests admission as a substituted limited partner in our partnership;

•  agrees to be bound by the terms and conditions of, and executes, our partnership agreement;

•  represents that the transferee has the capacity, power and authority to enter into the partnership agreement;

•  grants powers of attorney to officers of our general partner and any liquidator of us as specified in the partnership agreement; and

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•  gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

      An assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a completed and duly executed transfer application and certification has been received to be recorded on our books and records no less frequently than quarterly.

      A transferee’s broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

      Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a transfer application obtains only:

•  the right to assign the common unit to a purchaser or other transferee; and

•  the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

      Thus, a purchaser or transferee of common units who does not execute and deliver a transfer application:

•  will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application as to itself and any beneficial holders; and

•  may not receive some federal income tax information or reports furnished to record holders of common units.

      The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and forward the transfer application to the transfer agent. Please read “The Partnership Agreement — Status as Limited Partner or Assignee.”

      Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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DESCRIPTION OF THE SUBORDINATED UNITS

      The subordinated units represent a separate class of limited partner interests in our partnership, and the rights of holders of subordinated units to participate in distributions differ from, and are subordinated to, the rights of the holders of common units. Unlike the common units, the subordinated units will not be publicly traded.

Cash Distribution Policy

      During the subordination period, 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 $0.37 per common unit, 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.

      The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordinated units are not entitled to receive any arrearages in the payment of the minimum quarterly distribution from prior quarters. For a more complete description of our cash distribution policy on the subordinated units, please read “Cash Distribution Policy — Distributions of Available Cash from Operating Surplus During the Subordination Period.”

Conversion of the Subordinated Units

      Each subordinated unit will convert into one common unit at the end of the subordination period, which will end once we meet the financial tests in the partnership agreement. For a more complete description of the circumstances under which the subordinated units will convert into common units, please read “Cash Distribution Policy — Subordination Period.”

Distributions Upon Liquidation

      If we liquidate during the subordination period, we will, to the extent possible, allocate gain and loss to entitle the holders of common units a preference over the holders of subordinated units to the extent required to permit the common unitholders to receive their unrecovered initial unit price, plus the minimum quarterly distribution for the quarter during which liquidation occurs, plus any arrearages. For a more complete description of this liquidation preference, please read “Cash Distribution Policy — Distributions of Cash Upon Liquidation.”

Limited Voting Rights

      The subordinated units do not vote as separate classes of units. For a more complete description of the voting rights of holders of subordinated units, please read “The Partnership Agreement — Voting Rights.”

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THE PARTNERSHIP AGREEMENT

      The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. The form of limited liability company agreement of our operating company is included as an exhibit to the registration statement of which this prospectus constitutes a part. We will provide prospective investors with a copy of these agreements upon request at no charge.

      We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

•  with regard to distributions of available cash, please read “Cash Distribution Policy;”

•  with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units;” and

•  with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization and Duration

      We were organized on February 28, 2005 and have a perpetual existence.

Purpose

      Our purpose under the partnership agreement is limited to serving as the sole member of our operating company and engaging in any business activities that may be engaged in by our operating company and its subsidiaries or that are approved by our general partner. The limited liability company agreement of our operating company will provide that it may, directly or indirectly, engage in:

      (1) its operations as conducted immediately before our initial public offering;

      (2) any other activity approved by our general partner but only to the extent that our general partner determines that, as of the date of the acquisition or commencement of the activity, the activity generates “qualifying income” as this term is defined in Section 7704 of the Internal Revenue Code; or

      (3) any activity that enhances the operations of an activity that is described in (1) or (2) above.

      Although our general partner has the ability to cause us, our operating company or its subsidiaries to engage in activities other than gathering, transporting and processing natural gas and fractionating and storing NGLs, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

      Each limited partner and each person who acquires a unit from a unitholder and executes and delivers a transfer application grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement. Please read “— Amendment of the Partnership Agreement” below.

Capital Contributions

      Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

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Limited Liability

Participation in the Control of Our Partnership

      Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

•  to remove or replace our general partner;

•  to approve some amendments to our partnership agreement; or

•  to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Unlawful Partnership Distribution

      Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Failure to Comply with the Limited Liability Provisions of Jurisdictions in Which We Do Business

      Our subsidiaries may be deemed to conduct business in Kansas and Louisiana. Our subsidiaries may conduct business in other states in the future. Maintenance of our limited liability may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our membership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

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Voting Rights

      The following matters require the unitholder vote specified below. Matters requiring the approval of a “unit majority” require:

•  during the subordination period, the approval of: a majority of the common units, excluding those common units held by our general partner and its affiliates; and a majority of the subordinated units, voting as separate classes; and

•  after the subordination period, the approval of a majority of the common units.

      In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us and the limited partners.

Issuance of additional units	No approval right.
Amendment of the partnership agreement	Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets	Unit majority. Please read “— Merger, Sale or