Edgar Filing: Williams Partners L.P.

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As filed with the Securities and Exchange Commission on April 7, 2006

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	(Primary Standard Industrial	(I.R.S. Employer
incorporation or organization)	Classification Code Number)	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		Dan A. Fleckman
William J. Cooper		Vinson & Elkins L.L.P.
Andrews Kurth LLP		First City Tower
600 Travis, Suite 4200		1001 Fannin, Suite 2300
Houston, Texas 77002		Houston, Texas 77002
(713) 220-4200		(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 maximum	Proposed maximum
Title of Each Class of	Amount to	offering price	aggregate offering	Amount of
Securities to be Registered	be registered(1)	per unit(2)	price(2)	Registration Fee

Common units representing limited partnership interests	8,050,000	$32.54	$261,947,000	$28,028.33


(1)	Includes 1,050,000 common units which may be sold upon exercise of the underwriters’ over-allotment option.

(2)	Calculated in accordance with Rule 457(c) on the basis of the average of the high and low sales price of the common units on April 4, 2006.

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 7, 2006

PROSPECTUS

7,000,000 Common Units

Representing Limited Partner Interests

We are offering to sell 7,000,000 common units representing limited partner interests in Williams Partners L.P. Our common units are listed on the New York Stock Exchange under the symbol “WPZ”. The last reported sales price of our common units on the NYSE on April 6, 2006, was $32.75 per common unit.

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 22.

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 and competitive factors, the success of our gathering and transportation businesses depends on our ability to connect 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 the price of natural gas liquids or a change in the price of natural gas liquids relative to the price of natural gas.

	•	Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.

	•	Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.

	•	Even if unitholders are dissatisfied, they cannot currently remove our general partner without its consent.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.


	Per Common Unit	Total

Public offering price	$	$
Underwriting discount	$	$
Proceeds to Williams Partners L.P. (before expenses)	$	$

We have granted the underwriters a 30-day option to purchase up to an additional 1,050,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 7,000,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about , 2006.


Lehman Brothers	Citigroup

, 2006

TABLE OF CONTENTS


PROSPECTUS SUMMARY			1
	Williams Partners L.P.		1
	Partnership Structure and Management		6
	The Offering		9
	Summary Historical and Pro Forma Financial and Operating Data		11
RISK FACTORS			22
	Risks Inherent in Our Business		22
	Risks Inherent in an Investment in Us		34
	Tax Risks		39
ACQUISITION OF INTEREST IN FOUR CORNERS			42
USE OF PROCEEDS			48
CAPITALIZATION			49
PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS			50
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			51
	Non-GAAP Financial Measures		54
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
	OF OPERATIONS		58
	General		58
	Business Overview		58
	Executive Summary of 2005 Results		59
	Recent Events		59
	How We Evaluate Our Operations		60
	Our Operations		62
	Critical Accounting Policies and Estimates		65
	Results of Operations		67
	Four Corners		75
	Financial Condition and Liquidity		80
	Effects of Inflation		87
	Regulatory Matters		87
	Environmental		87
	Qualitative and Quantitative Disclosures About Market Risk		88
BUSINESS			90
	Our Partnership		90
	Business Strategies		91
	Competitive Strengths		91
	Our Relationship with Williams		91
	Industry Overview		92
	Gathering and Processing — The Discovery Assets		97
		General	97
		Discovery Natural Gas Pipeline System	100
		Larose Gas Processing Plant	101
		Paradis Fractionation Facility	102
		Discovery Management	102
		Discovery Customers and Contracts	102


		Competition	103
		Gas Supply	103
	Gathering and Processing — The Carbonate Trend Pipeline		104
		General	104
		Carbonate Trend Customers and Contracts	105
		Competition	106
		Gas Supply	106
	NGL Services — The Conway Assets		107
		General	107
		Conway Storage Assets	107
		The Conway Fractionation Facility	109
	Safety and Maintenance		111
	FERC Regulation		112
	Environmental Regulation		115
	Title to Properties and Rights-of-Way		118
	Employees		118
	Legal Proceedings		118
MANAGEMENT			119
	Management of Williams Partners L.P.		119
	Directors and Executive Officers of Our General Partner		119
	Executive Compensation		121
	Employment Agreements		122
	Compensation of Directors		122
	Long-Term Incentive Plan		122
	Reimbursement of Expenses of Our General Partner		124
HOW WE MAKE CASH DISTRIBUTIONS			125
	General		125
	Operating Surplus and Capital Surplus		126
	Subordination Period		128
	Distributions of Available Cash from Operating Surplus During the Subordination Period		129
	Distributions of Available Cash from Operating Surplus After the Subordination Period		129
	Incentive Distribution Rights		129
	Percentage Allocations of Available Cash from Operating Surplus		130
	Distributions from Capital Surplus		131
	Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		131
	Distributions of Cash Upon Liquidation		132
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			135
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			137
	Distributions and Payments to Our General Partner and Its Affiliates		137
	Agreements Governing the Transactions		137
	Omnibus Agreement		138
	Credit Facilities		139
	Discovery Limited Liability Company Agreement		140
	Discovery Operating and Maintenance Agreements		140
	Gas Purchase Contract		140


	Natural Gas and NGL Marketing Contracts	140
	Purchase and Sale Agreement	141
	Four Corners Limited Liability Company Agreement	141
	Treating and Processing Contracts	141
	Waste Heat Contract	141
	Balancing Services Contract	142
	Summary of Transactions with Williams	142
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES		143
	Conflicts of Interest	143
	Fiduciary Duties	147
DESCRIPTION OF THE COMMON UNITS		150
	The Units	150
	Transfer Agent and Registrar	150
	Transfer of Common Units	150
DESCRIPTION OF THE SUBORDINATED UNITS		152
	Cash Distribution Policy	152
	Conversion of the Subordinated Units	152
	Distributions Upon Liquidation	152
	Limited Voting Rights	152
THE PARTNERSHIP AGREEMENT		153
	Organization and Duration	153
	Purpose	153
	Power of Attorney	153
	Capital Contributions	153
	Limited Liability	154
	Voting Rights	155
	Issuance of Additional Securities	156
	Amendment of the Partnership Agreement	156
	Merger, Sale or Other Disposition of Assets	158
	Termination and Dissolution	159
	Liquidation and Distribution of Proceeds	159
	Withdrawal or Removal of Our General Partner	160
	Transfer of General Partner Interest	161
	Transfer of Incentive Distribution Rights	161
	Transfer of Ownership Interests in Our General Partner	161
	Change of Management Provisions	162
	Limited Call Right	162
	Meetings; Voting	163
	Status as Limited Partner	163
	Non-Citizen Assignees; Redemption	163
	Indemnification	164
	Books and Reports	164
	Right to Inspect Our Books and Records	165
	Registration Rights	165
UNITS ELIGIBLE FOR FUTURE SALE		166

iii


MATERIAL TAX CONSEQUENCES		167
	Partnership Status	167
	Limited Partner Status	168
	Tax Consequences of Unit Ownership	169
	Tax Treatment of Operations	174
	Disposition of Common Units	174
	Uniformity of Units	176
	Tax-Exempt Organizations and Other Investors	177
	Administrative Matters	178
	State, Local and Other Tax Considerations	180
INVESTMENT IN WILLIAMS PARTNERS L.P. BY EMPLOYEE BENEFIT PLANS		181
UNDERWRITING		182
	Commissions and Expenses	182
	Option to Purchase Additional Common Units	182
	Lock-Up Agreements	183
	Indemnification	183
	Stabilization, Short Positions and Penalty Bids	183
	Electronic Distribution	184
	New York Stock Exchange	184
	Relationships	184
	NASD Conduct Rules	185
VALIDITY OF THE COMMON UNITS		186
EXPERTS		186
WHERE YOU CAN FIND MORE INFORMATION		186
FORWARD-LOOKING STATEMENTS		187
INDEX TO FINANCIAL STATEMENTS		F-1
Appendix A — Glossary of Terms		A-1

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.

References in this prospectus to “Williams Partners L.P.,” “we,” “our,” “us” or like terms, when used in the present tense, prospectively or for historical periods since August 23, 2005, refer to Williams Partners L.P. and its subsidiaries. References to “our predecessor,” or to “we,” “our,” “us” or like terms for historical periods prior to August 23, 2005, refer to the assets of The Williams Companies, Inc. and its subsidiaries, which were contributed to us at the closing of our initial public offering on August 23, 2005. In either case, unless the context clearly indicates otherwise, references to “we,” “our” and “us” generally include the operations of Discovery Producer Services LLC, in which we own a 40% interest, but does not include Williams Four Corners LLC, in which we will own a 25.1% interest upon consummation of the transactions discussed in this prospectus. When we refer to Discovery and Four Corners by name, we are referring exclusively to their respective businesses and operations.

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes that the underwriters’ option to purchase additional units is not exercised. You should read “— Williams Partners L.P. — Summary of Risk Factors” and “Risk Factors” for information about important factors to consider before buying the common units. We include a glossary of some of the terms used in this prospectus as Appendix A.

Williams Partners L.P.

We are a Delaware limited partnership formed by The Williams Companies, Inc., or Williams, in February 2005, 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. Fractionation is the process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane. These natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives, among other applications.

On April 6, 2006, we entered into an agreement to acquire a 25.1% membership interest in Williams Four Corners LLC, or Four Corners, from affiliates of Williams. Four Corners owns a 3,500-mile natural gas gathering system, including three natural gas processing plants and two natural gas treating plants, located in the San Juan Basin in Colorado and New Mexico. Please read “— Acquisition of Interest in Four Corners.” This is our first acquisition since our initial public offering in August 2005. We intend to acquire additional assets in the future and have a management team dedicated to a growth strategy.

Our current asset portfolio consists of:


	•	a 40% interest in Discovery Producer Services LLC, or Discovery, which owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and a natural gas liquids fractionator in Louisiana;

	•	the Carbonate Trend natural gas gathering pipeline off the coast of Alabama; and

	•	three integrated natural gas liquids storage facilities and a 50% interest in a natural gas liquids fractionator near Conway, Kansas.

Our Carbonate Trend gathering pipeline is a 34-mile pipeline that gathers sour gas production from the Carbonate Trend area off the coast of Alabama. “Sour” gas is natural gas that has relatively high concentrations of acidic gases, such as hydrogen sulfide and carbon dioxide, that exceed normal gas transportation specifications. The pipeline was built and placed into service in 2000 and has a maximum design capacity of 120 million cubic feet per day.

We are also engaged in the storage and fractionation of natural gas liquids near Conway, Kansas, which is the principal natural gas liquids market hub for the Mid-Continent region of the United States. We believe our integrated natural gas liquids storage facility at Conway is one of the largest in the Mid-Continent region. These storage facilities consist of a network of interconnected underground caverns that hold large volumes of natural gas liquids and other hydrocarbons and have an aggregate capacity of approximately 20 million barrels. Our Conway storage facilities connect directly with the Mid-America, or MAPL, and Kinder Morgan

natural gas liquids pipeline systems and indirectly with three other large interstate natural gas liquids pipelines. We also own a 50% undivided interest in the Conway natural gas liquids fractionation facility, which is strategically located at the junction of the south, east and west legs of MAPL. This fractionation facility also benefits from its proximity to other natural gas liquids pipelines in the Conway area, and from its proximity to our Conway storage facility. Our share of the fractionator’s capacity is approximately 53,500 barrels per day.

We account for our 40% interest in Discovery as an equity investment, and therefore do not consolidate its financial results. Please read “— Summary Historical and Pro Forma Financial and Operating Data” for information regarding our and Discovery’s financial and operating results.

Business Strategies

Our primary business objectives are to generate stable cash flows sufficient to make quarterly cash distributions to our unitholders and to increase quarterly cash distributions over time by executing the following strategies:


	•	grow through accretive acquisitions of complementary energy assets from third parties, Williams or both, such as our proposed acquisition of a 25.1% interest in Four Corners;

	•	capitalize on expected long-term increases in natural gas production in proximity to Discovery’s pipelines in the Gulf of Mexico;

	•	optimize the benefits of our scale, strategic location and pipeline connectivity serving the Mid- Continent natural gas liquids market;

	•	leverage the scale and competitive position of Four Corners’ standing as a leading provider of natural gas gathering, processing and treating services in the San Juan Basin; 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, such as our proposed acquisition of a 25.1% interest in Four Corners;

	•	our assets are strategically located in areas with high demand for our services;

	•	our assets are diversified geographically and encompass important aspects of the midstream natural gas and natural gas liquids businesses;

	•	the senior management team and board of directors of our general partner have extensive industry experience and include the most senior officers of Williams; and

	•	Williams has established a reputation in the midstream natural gas and natural gas liquids industry as a reliable and cost-effective operator, and we believe that we and our customers will benefit from Williams’ scale and operational expertise as well as our access to the broad array of midstream services that Williams offers.

Acquisition of Interest in Four Corners


	*General*

On April 6, 2006, we entered into a purchase and sale agreement with our general partner and certain subsidiaries of Williams, pursuant to which they will contribute to us a 25.1% membership interest in Four Corners in exchange for aggregate consideration of $360 million.

Four Corners owns:


	•	a 3,500-mile natural gas gathering system in the San Juan Basin in New Mexico and Colorado with capacity of two billion cubic feet per day;

	•	the Ignacio natural gas processing plant in Colorado and the Kutz and Lybrook natural gas processing plants in New Mexico, which have a combined processing capacity of 760 million cubic feet per day; and

	•	the Milagro and Esperanza natural gas treating plants in New Mexico, which have a combined carbon dioxide treating capacity of 750 million cubic feet per day.

Four Corners’ customers are primarily natural gas producers in the San Juan Basin. Four Corners provides its customers with a full range of gathering, processing and treating services.

The Four Corners pipeline system gathers approximately 37% of the natural gas produced in the San Juan Basin and connects with the five pipeline systems that transport natural gas to end markets from the basin. Approximately 40% of the supply connected to the Four Corners pipeline system in the San Juan Basin is produced from conventional reservoirs with approximately 60% coming from coal bed reservoirs. Four Corners is currently the only company in the basin that owns and operates both major conventional and coal bed natural gas gathering, processing and treating facilities. Despite the topographically challenging terrain, Four Corners has gathering pipelines throughout most of the San Juan Basin.

Consistent with our growth strategy, our proposed acquisition of the interest in Four Corners will allow us to expand our asset base with an ownership position in an integrated business that complements our existing portfolio of midstream assets. Our interest in Four Corners will expand our customer base and diversify our geographic footprint by providing a presence in the San Juan Basin. We expect that this transaction will be accretive on a per unit basis. For a more detailed discussion of this transaction, please read “Acquisition of Interest in Four Corners.”

The closing of our acquisition of the interest in Four Corners is subject to the satisfaction of a number of conditions, including our ability to obtain financing. We expect closing to occur in the second quarter of 2006.

We will account for the 25.1% interest in Four Corners as an equity investment, and therefore will not consolidate its financial results. For the year ended December 31, 2005, a 25.1% interest in Four Corners generated:


	•	net income plus interest (income) expense and depreciation, referred to as Adjusted EBITDA, of approximately $38.4 million; and

	•	net income plus depreciation and accretion and less maintenance capital expenditures, referred to as Distributable Cash Flow, or DCF, of approximately $35.4 million.

For a reconciliation of each of Adjusted EBITDA and DCF to its most directly comparable financial measure calculated and presented in accordance with United States generally accepted accounting principles, or GAAP, please read “— Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.” Please read “— Summary Historical and Pro Forma Financial and Operating Data — Four Corners” for information regarding Four Corners’ financial and operating results.


	*Conflicts Committee Approval*

The conflicts committee of the board of directors of Williams Partners GP LLC, our general partner, recommended approval of the acquisition of the interest in Four Corners. The committee retained independent legal and financial advisors to assist it in evaluating and negotiating the transaction. In recommending approval of the transaction, the committee based its decision in part on an opinion from the committee’s independent financial advisor that the consideration to be paid by us to Williams is fair, from a financial point of view, to us and our public unitholders.


	*Financing*

We intend to finance our acquisition of the interest in Four Corners with:


	•	the net proceeds of this offering; and

	•	the net proceeds from a private placement of our senior notes to qualified institutional investors and to non-U.S. persons in offshore transactions.

Concurrently with this offering, we are offering $150 million in aggregate principal amount of senior notes in a private placement. The senior notes are being offered only to qualified institutional investors in reliance on Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions in reliance on Regulation S under the Securities Act and initially will not be guaranteed by any of our subsidiaries. In the future in certain instances, some or all of our subsidiaries may be required to guarantee our senior notes. This prospectus shall not be deemed to be an offer to sell or a solicitation of an offer to buy any senior notes offered in the private placement. We cannot assure you that this private placement will be completed or, if it is completed, that it will be completed for the amount contemplated.

This offering is conditioned upon the consummation of the private placement of senior notes, and the private placement of senior notes is conditioned upon the consummation of this offering.

Our Relationship with Williams

One of our principal attributes is our relationship with Williams, an integrated energy company with 2005 revenues in excess of $12.5 billion that trades on the New York Stock Exchange under the symbol “WMB”. Williams operates in a number of segments of the energy industry, including natural gas exploration and production, interstate natural gas transportation and midstream services. Williams has been in the midstream natural gas and natural gas liquids industry for more than 20 years.

Williams has a long history of successfully pursuing and consummating energy acquisitions and intends to use our partnership as a growth vehicle for its midstream, natural gas, natural gas liquids and other complementary energy businesses. Although we expect to have the opportunity to make additional acquisitions directly from Williams in the future, we cannot say with any certainty which, if any, of these acquisition opportunities may be made available to us or if we will choose to pursue any such opportunity. In addition, through our relationship with Williams, we will have access to a significant pool of management talent and strong commercial relationships throughout the energy industry. While our relationship with Williams and its subsidiaries is a significant attribute, it is also a source of potential conflicts. For example, Williams is not restricted from competing with us. Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Following this offering, Williams will have a significant interest in our partnership through its ownership of a 38.5% limited partner interest and all of our 2% general partner interest. Additionally, subsidiaries of Williams market substantially all of the natural gas liquids to which Discovery and Four Corners take title and affiliates of Williams have contracts with Four Corners related to processing natural gas and providing waste heat from the Milagro co-generation plant to assist in the operation of the Milagro treating plant.

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. These 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.


	•	Because of the natural decline in production from existing wells and competitive factors, the success of our gathering and transportation businesses depends on our ability to connect 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.

	•	Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.

	•	Our processing, fractionation and storage businesses could be affected by any decrease in the price of natural gas liquids or a change in the price of natural gas liquids relative to the price of natural gas.

	•	We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and natural gas liquids. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.

	•	If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and natural gas liquids or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

	•	Our future financial and operating flexibility may be adversely affected by restrictions in our indenture and by our leverage.

	•	Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.


	*Risks Inherent in an Investment in Us*


	•	Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.

	•	Our partnership agreement limits our general partner’s fiduciary duties to our 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 currently 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.

	•	We may issue additional common units without your approval, which would dilute your ownership interests.

	•	Williams and its affiliates may compete directly with us and have no obligation to present business opportunities to us.


	*Tax Risks*


	•	Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash available to pay distributions to you would be substantially reduced.

	•	A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

	•	The tax gain or loss on the disposition of our common units could be different than expected.

Partnership Structure and Management

Management of Williams Partners L.P.

Our general partner manages our operations and activities. Some of the executive officers and directors of Williams also serve as executive officers and directors of our general partner. For more information about these individuals, please read “Management — Directors and Executive Officers of Our General Partner.” Our general partner will not receive any management fee or other compensation in connection with the management of our business or this offering, but it is 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 is also entitled to distributions on its general partner interest and, if specified requirements are met, on its incentive distribution rights. Please read “How We Make Cash Distributions,” “Management — Executive Compensation” and “Certain Relationships and Related Transactions.”

Unlike shareholders in a publicly traded corporation, our unitholders are not 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 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

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 wholly owned by Williams, the officers and directors of our general partner have fiduciary duties to manage the business of our general partner in a manner beneficial to Williams. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, on the other hand. For a more detailed description of the conflicts of interest of our general partner, please read “Risk Factors — Risks Inherent in an Investment in Us” and “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.”

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to unitholders. By purchasing a common unit, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.

For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Transactions.”

Organizational Structure After the Transactions

Immediately upon the closing of this common unit offering, and subject to the conditions described above under “— Acquisition of Interest in Four Corners — Financing”:


	•	we will issue $150 million aggregate principal amount of senior notes, which initially will not be guaranteed by any of our subsidiaries, in a private placement to institutional investors and


		non-U.S. persons in offshore transactions. In the future in certain instances, some or all of our subsidiaries may be required to guarantee our senior notes; and

	•	an affiliate of Williams will contribute the interest in Four Corners to us in exchange for aggregate consideration of $360 million.

The following diagram depicts our organizational structure after giving effect to this offering, our private placement of senior notes and our acquisition of a 25.1% interest in Four Corners.

Ownership of Williams Partners L.P.


Public Common Units		59.5	%
The Williams Companies, Inc. and Affiliates Common and Subordinated Units		38.5	%
General Partner Interest		2.0	%

	Total	100.0	%

The Offering


Common units offered by us		7,000,000 common units.

		8,050,000 common units if the underwriters exercise their option to purchase additional units in full.

Units outstanding after this offering		14,006,146 common units and 7,000,000 subordinated units.

		15,056,146 common units and 7,000,000 subordinated units if the underwriters exercise their option to purchase additional units in full.

Use of proceeds		We estimate the net proceeds from this offering will be approximately $216.9 million assuming an offering price of $32.75 per common unit and after deducting underwriting discounts and estimated offering expenses. We intend to use the net proceeds of this offering, together with the net proceeds from our private placement of $150 million aggregate principal amount of senior notes, to pay the aggregate consideration of $360 million in exchange for the 25.1% interest in Four Corners. Please read “Use of Proceeds.”

Cash distributions		We paid a quarterly cash distribution of $0.35 per unit for the fourth quarter of 2005, or $1.40 per unit on an annualized basis, on February 14, 2006 to unitholders of record as of February 7, 2006. In general, we will pay any cash distributions we make each quarter in the following manner:

		• first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.35 plus any arrearages from prior quarters;

		• second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.35; and

		• third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.4025.

		If cash distributions exceed $0.4025 per unit in a quarter, our general partner will receive increasing percentages, up to 50%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.”

		We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner in its discretion to provide for the proper conduct of our business, to comply with any applicable debt instruments or to provide funds for future distributions. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix A. The amount of available cash may be greater than or less than the minimum quarterly distribution to be distributed on all units.

Subordination period		During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. The subordination period will end once we meet the financial tests in the partnership agreement. Except as described below, it generally cannot end before June 30, 2008.


		When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

Early termination of subordination period		If we have earned and paid an amount that equals or exceeds $2.10 (150% of the annualized minimum quarterly distribution) on each outstanding unit for any four-quarter period, the subordination period will automatically terminate and all of the subordinated units will convert into common units. Please read “How We Make Cash Distributions — Subordination Period.”

Issuance of additional units		We can issue an unlimited number of common units without the consent of unitholders, subject to the limitations imposed by the New York Stock Exchange. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”

Voting rights		Our general partner manages and operates us. Unlike the holders of common stock in a corporation, you have only limited voting rights on matters affecting our business. You have no right to elect our general partner or the directors of our general partner. Our general partner may not be removed except by a vote of the holders of at least 66²/3 % of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of 39.3% of our common and subordinated units. This gives 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, 2008, 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.”

New York Stock Exchange symbol		“WPZ”.

Summary Historical and Pro Forma

Financial and Operating Data

Williams Partners L.P.

The following table shows summary historical financial and operating data of Williams Partners L.P., summary pro forma financial data of Williams Partners L.P., summary historical financial and operating data of Discovery Producer Services LLC and summary historical financial and operating data for Williams Four Corners Predecessor for the periods and as of the dates indicated. The summary historical financial data of Williams Partners L.P. as of December 31, 2004 and 2005 and for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Williams Partners L.P. appearing elsewhere in this prospectus.

The summary pro forma financial data of Williams Partners L.P. as of and for the year ended December 31, 2005 are derived from the unaudited pro forma consolidated financial statements of Williams Partners L.P. included elsewhere in this prospectus. These pro forma consolidated financial statements show the pro forma effect of:


	•	this offering, including our use of the anticipated net proceeds;

	•	the proposed private placement of $150 million aggregate principal amount of our senior notes to certain institutional investors and to non-U.S. persons in offshore transactions, including our use of the anticipated net proceeds of that private placement;

	•	our acquisition of a 25.1% interest in Four Corners;

	•	the forgiveness by Williams of advances to our predecessor in connection with our initial public offering; and

	•	the payment of estimated underwriters’ commissions and other offering expenses.

The summary pro forma balance sheet data assumes that the items listed above occurred as of December 31, 2005, and the summary pro forma income statement data assumes that the items listed above occurred on January 1, 2005.

The summary historical financial data of Discovery Producer Services LLC for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Discovery Producer Services LLC appearing elsewhere in this prospectus. The summary historical financial data of Williams Four Corners Predecessor for the years ended December 31, 2003, 2004 and 2005 are derived from the audited financial statements of Williams Four Corners Predecessor appearing elsewhere in this prospectus.

The following table includes these non-GAAP financial measures:


	•	Adjusted EBITDA Excluding Equity Investments for Williams Partners L.P.;

	•	Adjusted EBITDA for both our interest in Discovery and the 25.1% interest in Four Corners that we expect to acquire;

	•	Distributable Cash Flow for Williams Partners L.P. Excluding Equity Investments; and

	•	Distributable Cash Flow for both our interest in Discovery and the 25.1% interest in Four Corners that we expect to acquire.

These measures are presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Our 40% ownership interest in Discovery is not and our 25.1% ownership interest in Four Corners will not be, consolidated in our financial results; rather we account or will account for them using the equity method of accounting. In order to evaluate EBITDA for the impact of our investment in Discovery and Four Corners on our results, we calculate Adjusted EBITDA Excluding Equity Investments and Distributable Cash Flow Excluding Equity Investments separately for Williams Partners L.P.

and Adjusted EBITDA and Distributable Cash Flow for both our interest in Discovery and the interest in Four Corners that we expect to acquire. We expect distributions we receive from Discovery and Four Corners to represent a significant portion of the cash we distribute to our unitholders. Discovery’s limited liability company agreement provides for quarterly distributions of available cash to its members. Four Corners’ limited liability company agreement, as amended to be effective as of the closing of this offering, will provide for distributions of available cash at least quarterly to its members. Please read “How We Make Cash Distributions — General — Discovery’s Cash Distribution Policy” and “— General — Four Corners’ Cash Distribution Policy.”

For Williams Partners L.P., we define Adjusted EBITDA Excluding Equity Investments as net income (loss) plus interest (income) expense, depreciation and accretion and the amortization of a natural gas contract, less our equity earnings in Discovery and Four Corners. We also adjust for certain non-cash, non-recurring items.

For Discovery and Four Corners we define Adjusted EBITDA as net income plus interest (income) expense, depreciation and accretion. We also adjust for certain non-cash, non-recurring items. Our equity share of Discovery’s Adjusted EBITDA is 40%, and our equity share of Four Corners’ Adjusted EBITDA will be 25.1%.

For Williams Partners L.P., we define Distributable Cash Flow Excluding Equity Investments as net income (loss) plus the non-cash affiliate interest expense associated with the advances from affiliate to our predecessor that were forgiven by Williams, depreciation and accretion, the amortization of a natural gas contract, and reimbursements from Williams under our omnibus agreement, less our equity earnings in Discovery and Four Corners and maintenance capital expenditures. We also adjust for certain non-cash, non-recurring items.

For Discovery and Four Corners, we define Distributable Cash Flow as net income (loss) plus depreciation and accretion and less maintenance capital expenditures. Our equity share of Discovery’s Distributable Cash Flow is 40%, and our equity share of Four Corner’s Distributable Cash Flow will be 25.1%.

For a reconciliation of these measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”

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 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 L.P.(a									)

		Historical

											Pro Forma
		Year Ended December 31,									Year Ended
											December 31,
		2003			2004			2005			2005

		($ in thousands, except per unit data)
Statement of Income Data:
Revenues		$	28,294		$	40,976		$	51,769		$	51,769
Costs and expenses			21,250			32,935			46,568			46,568

Operating income			7,044			8,041			5,201			5,201
Equity earnings — Four Corners												28,668
Equity earnings — Discovery			3,447			4,495			8,331			8,331
Impairment of investment in Discovery			—			(13,484	)(b)		—			—
Interest expense — net			(4,176	)		(12,476	)		(8,073	)		(12,472	)

Income before cumulative effect of change in accounting principle			6,315			(13,424	)		5,459		$	29,728

Cumulative effect of change in accounting principle			(1,099	)		—			(628	)

Net income (loss)(c)		$	5,216		$	(13,424	)	$	4,831

Diluted earnings per limited partner unit:
	Income before cumulative effect of change in accounting principle							$	0.49		$	1.45

	Cumulative effect of change in accounting principle								(0.05	)

	Net income							$	0.44

Balance Sheet Data (at period end):
Total assets		$	230,150	(d)	$	219,361		$	240,941		$	404,285
Property, plant and equipment, net			69,695			67,793			67,931			67,931
Investment in Four Corners												152,003
Investment in Discovery			156,269	(d)		147,281	(b)		150,260			150,260
Advances from affiliate			187,193	(d)		186,024			—			—
Total Partners’ capital			30,092			16,668			221,655			234,999
Other Financial Data:
Williams Partners L.P.:
	Adjusted EBITDA Excluding Equity Investments	$	10,751		$	11,727		$	10,853		$	10,853
	Distributable Cash Flow Excluding Equity Investments		9,575			9,609			8,165			(3,673	)
Four Corners — our 25.1%:
	Adjusted EBITDA		32,705			34,445			38,447
	Distributable Cash Flow		30,677			31,900			35,391
Discovery — our 40%:
	Adjusted EBITDA		16,614			13,566			17,575
	Distributable Cash Flow		11,641			13,448			17,235


		Williams Partners L.P.(a)

		Historical

		Year Ended December 31,

		2003			2004			2005

		($ in thousands, except per unit data)
Operating Information:
Williams Partners L.P.:
	Conway storage revenues	$	11,649		$	15,318		$	20,290
	Conway fractionation volumes (bpd) — our 50%		34,989			39,062			39,965
	Carbonate Trend gathered volumes (MMBtu/d)		67,638			49,981			35,605
Four Corners — 100%:
	Gathered volumes (MMBtu/d)		1,577,181			1,559,940			1,521,507
	Processed volumes (MMBtu/d)		900,356			900,194			863,693
	Net liquids margin (cents/gallon)(e)		17	¢		29	¢		37	¢
Discovery — 100%:
	Gathered volumes (MMBtu/d)		378,745			348,142			345,098
	Gross processing margin (¢/ MMBtu)(f)		17	¢		17	¢		19	¢


(a)	Williams Partners L.P. is the successor to Williams Partners Predecessor. Results of operations and balance sheet data prior to August 23, 2005 represent historical results of the Williams Partners Predecessor.


(b)	The $13.5 million impairment of our equity investment in Discovery in 2004 reduced the investment balance. See Note 6 of the Notes to Consolidated Financial Statements.


(c)	Our operations are 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.


(d)	In December 2003, our predecessor made a $101.6 million capital contribution to Discovery, which Discovery subsequently used to repay maturing debt. Our predecessor funded this contribution with an advance from Williams.


(e)	Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Four Corners — How We Evaluate Four Corners — Net Liquids Margin” for a discussion of net liquids margin.


(f)	Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Gross Processing Margins” for a discussion of gross processing margin.

Four Corners

The following table shows summary historical financial and operating data of Williams Four Corners Predecessor for the periods and as of the dates indicated. The summary historical financial data of Williams Four Corners Predecessor as of December 31, 2004 and 2005 and for the years ended December 31, 2003, 2004 and 2005 are derived from the audited financial statements of Williams Four Corners Predecessor appearing elsewhere in this prospectus. The table should be read together with, and is qualified in its entirety by reference to, the historical 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 Four Corners Predecessor

		Year Ended December 31,

		2003			2004			2005

		($ in thousands)
Statement of Income Data:
Revenues		$	354,134		$	428,223		$	463,203
Costs and expenses			265,387			331,667			348,988

Income before cumulative effect of change in accounting principle			88,747			96,556			114,215
Cumulative effect of change in accounting principle			(330	)		—			(694	)

Net income		$	88,417		$	96,556		$	113,521

Balance Sheet Data (at period end):
Total assets		$	666,589		$	645,294		$	635,094
Property, plant and equipment, net			635,905			601,710			591,034
Total owner’s equity			644,441			620,530			605,590
Other Financial Data:
	Adjusted EBITDA		130,299			137,231			153,175
	Distributable Cash Flow		122,220			127,093			141,000
Operating Information:
	Gathered volumes (MMBtu/d)		1,577,181			1,559,940			1,521,507
	Processed volumes (MMBtu/d)		900,356			900,194			863,693
	Net liquids margin (cents/gallon)(a)		17	¢		29	¢		37	¢


(a)	Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Four Corners — How We Evaluate Four Corners — Net Liquids Margin” for a discussion of net liquids margin.

Discovery

The following table shows 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 Discovery Producer Services LLC as of December 31, 2004 and 2005 and for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Discovery Producer Services LLC appearing elsewhere in this prospectus. The table should be read together with, and is qualified in its entirety by reference to, the historical 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.”


		Discovery Producer Services LLC

		Year Ended December 31,

		2003			2004			2005

		($ in thousands)
Statement of Income Data:
Revenues		$	103,178		$	99,876		$	122,745
Costs and expenses			84,519			88,756			102,597

Operating income			18,659			11,120			20,148
Interest (expense) income and other			(9,611	)		550			680

Income before cumulative effect of change in accounting principle			9,048			11,670			20,828
Cumulative effect of change in accounting principle			(267	)		—			(176	)

Net income		$	8,781		$	11,670		$	20,652

Balance Sheet Data (at period end):
Total assets		$	401,525		$	423,919		$	459,827
Property, plant and equipment, net			332,398			356,385			344,743
Total Members’ capital			379,975			391,645			413,636
Other Financial Data:
	Adjusted EBITDA		41,534			33,915			43,937
	Distributable Cash Flow		29,103			33,620			43,088
Operating Information:
	Gathered Volumes (MMBtu/d)		378,745			348,142			345,098
	Gross processing margin (MMBtu)(a)		17	¢		17	¢		19	¢


(a)	Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Gross Processing Margins” for a discussion of gross processing margin.

Non-GAAP Financial Measures

Adjusted EBITDA Excluding Equity Investments and Distributable Cash Flow Excluding Equity Investments, in our case, and Adjusted EBITDA and Distributable Cash Flow, in Discovery’s and Four Corners’ cases, are used as supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and

	•	our operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.

Our Adjusted EBITDA Excluding Equity Investments and Distributable Cash Flow Excluding Equity Investments, Discovery’s Adjusted EBITDA and Distributable Cash Flow and Four Corners’ Adjusted EBITDA and Distributable Cash Flow should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA Excluding Equity Investments and Distributable Cash Flow Excluding Equity Investments, Discovery’s Adjusted EBITDA and Distributable Cash Flow and Four Corners’ Adjusted EBITDA and Distributable Cash Flow exclude some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, our Adjusted EBITDA Excluding Equity Investments and Distributable Cash Flow Excluding Equity Investments, Discovery’s Adjusted EBITDA and Distributable Cash Flow and Four Corners’ Adjusted EBITDA and Distributable Cash Flow as presented may not be comparable to similarly titled measures of other companies.

The following tables present a reconciliation of the non-GAAP financial measures, our Adjusted EBITDA Excluding Equity Investments and Distributable Cash Flow Excluding Equity Investments, Discovery’s Adjusted EBITDA and Distributable Cash Flow and Four Corners’ Adjusted EBITDA and Distributable Cash Flow, to the GAAP financial measures of net income (loss) and of net cash provided (used) by operating activities, on a historical basis and on a pro forma basis, as adjusted for this offering, the proposed private placement of our senior notes, the application of the net proceeds from each offering, our acquisition of the interest in Four Corners, and the forgiveness of advances from affiliate to our predecessor in connection with our initial public offering.


		Williams Partners L.P.									(a)

		Historical

											Pro Forma
		Year Ended December 31,									Year Ended
											December 31,
		2003			2004			2005			2005

		($ in thousands)
Williams Partners L.P.
Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Equity Investments” to GAAP “Net income (loss)”
Net income (loss)		$	5,216		$	(13,424	)	$	4,831		$	28,926
Interest expense, net of interest income			4,176			12,476			8,073			12,472
Depreciation and accretion			3,707			3,686			3,619			3,619
Amortization of natural gas purchase contract			—			—			2,033			2,033
Impairment of investment in Discovery Producer Services			—			13,484			—			—
Equity earnings — Discovery Producer Services			(3,447	)		(4,495	)		(8,331	)		(8,331	)
Equity earnings — Four Corners			—			—			—			(28,668	)
Cumulative effect of change in accounting principle			1,099			—			628			802

Adjusted EBITDA Excluding Equity Investments		$	10,751		$	11,727		$	10,853		$	10,853

Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Equity Investments” to GAAP “Net cash provided (used) by operating activities”
Net cash provided (used) by operating activities		$	6,644		$	2,703		$	1,893		$	(2,506	)
Interest expense, net of interest income			4,176			12,476			8,073			12,472
Distributed earnings from equity investments			—			—			(1,280	)		(1,280	)
Changes in operating working capital:
	Accounts receivable		850			(261	)		3,045			3,045
	Other current assets		187			362			384			384
	Accounts payable		274			(2,711	)		(4,215	)		(4,215	)
	Accrued liabilities		320			417			737			737
	Deferred revenue		(1,108	)		(775	)		(247	)		(247	)
Other, including changes in noncurrent assets and liabilities			(592	)		(484	)		2,463			2,463

Adjusted EBITDA Excluding Equity Investments		$	10,751		$	11,727		$	10,853		$	10,853

Reconciliation of Non-GAAP “Distributable Cash Flow Excluding Equity Investments” to GAAP “Net income (loss)”
Net income (loss)		$	5,216		$	(13,424	)	$	4,831		$	28,926
Affiliate interest expense(b)			4,176			11,980			7,439			—
Depreciation and accretion			3,707			3,686			3,619			3,619
Amortization of natural gas purchase contract			—			—			2,033			2,033
Reimbursements from Williams under an omnibus agreement			—			—			1,610			1,610
Impairment of investment in Discovery Producer Services			—			13,484			—			—
Cumulative effect of change in accounting principle			1,099			—			628			802
Equity earnings — Discovery Producer Services			(3,447	)		(4,495	)		(8,331	)		(8,331	)
Equity earnings — Four Corners			—			—			—			(28,668	)
Maintenance capital expenditures			(1,176	)		(1,622	)		(3,664	)		(3,664	)

Distributable Cash Flow Excluding Equity Investments		$	9,575		$	9,609		$	8,165		$	(3,673	)


		Williams Partners L.P									.(a)

		Historical

											Pro Forma
		Year Ended December 31,									Year Ended
											December 31,
		2003			2004			2005			2005

		($ in thousands)
Williams Partners L.P.
Reconciliation of Non-GAAP “Distributable Cash Flow Excluding Equity Investments” to GAAP “Net cash provided (used) by operating activities”
Net cash provided (used) by operating activities		$	6,644		$	2,703		$	1,893		$	(2,506	)
Affiliate interest expense(b)			4,176			11,980			7,439			—
Distributions from equity investments			—			—			(1,280	)		(1,280	)
Changes in operating working capital:
	Accounts receivable		850			(261	)		3,045			3,045
	Other current assets		187			362			384			384
	Accounts payable		274			(2,711	)		(4,215	)		(4,215	)
	Accrued liabilities		320			417			737			737
	Deferred revenue		(1,108	)		(775	)		(247	)		(247	)
Other, including changes in noncurrent assets and liabilities			(592	)		(484	)		2,463			2,463
Reimbursements from Williams under an omnibus agreement			—			—			1,610			1,610
Maintenance capital expenditures			(1,176	)		(1,622	)		(3,664	)		(3,664	)

Distributable Cash Flow Excluding Equity Investments		$	9,575		$	9,609		$	8,165		$	(3,673	)


(a)		Williams Partners L.P. is the successor to Williams Partners Predecessor. Results of operations data prior to August 23, 2005 represent historical results of the Williams Partners Predecessor.

(b)		Represents affiliate interest expense associated with the advances from affiliate to our predecessor that were forgiven by Williams in connection with our initial public offering.


		Williams Four Corners Predecessor

		Year Ended December 31,

		2003			2004			2005

		($ in thousands)
Williams Four Corners Predecessor
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net income”
Net income		$	88,417		$	96,556		$	113,521
Depreciation			41,552			40,675			38,960
Cumulative effect of change in accounting principle			330			—			694

Adjusted EBITDA — 100%		$	130,299		$	137,231		$	153,175

Adjusted EBITDA — our 25.1% interest		$	32,705		$	34,445		$	38,447

Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities		$	122,266		$	134,387		$	156,039
Provision for loss on property, plant and equipment			(7,598	)		(7,636	)		(917	)
Gain (loss) on sale of property, plant and equipment			1,151			(1,258	)		—
Changes in operating working capital:
	Accounts receivable		279			(1,298	)		1,374
	Prepaid expenses		1,530			—			79
	Accounts payable		3,266			(9,435	)		(4,586	)
	Produce imbalance		4,447			7,983			(10,073	)
	Accrued liabilities		(61	)		5,047			3,271
	Other, including changes in other noncurrent assets and liabilities		5,019			9,441			7,988

Adjusted EBITDA — 100%		$	130,299		$	137,231		$	153,175

Reconciliation of Non-GAAP “Distributable Cash Flow” to GAAP “Net income”
Net income		$	88,417		$	96,556		$	113,521
Depreciation			41,552			40,675			38,960
Cumulative effect of change in accounting principle			330			—			694
Maintenance capital expenditures(a)			(8,079	)		(10,138	)		(12,175	)

Distributable Cash Flow — 100%		$	122,220		$	127,093		$	141,000

Distributable Cash Flow — our 25.1% interest		$	30,677		$	31,900		$	35,391


(a)	Maintenance capital expenditures for Williams Four Corners Predecessor includes well connection capital.


		Discovery Producer Services LLC

		Year Ended December 31,

		2003			2004			2005

		($ in thousands)
Discovery Producer Services
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net income”
Net income		$	8,781		$	11,670		$	20,652
Interest (income) expense, net			9,611			(550	)		(1,685	)
Depreciation and accretion			22,875			22,795			24,794
Cumulative effect of change in accounting principle			267			—			176

Adjusted EBITDA — 100%		$	41,534		$	33,915		$	43,937

Adjusted EBITDA — our 40% interest		$	16,614		$	13,566		$	17,575

Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities		$	44,025		$	35,623		$	30,814
Interest (income) expense, net			9,611			(550	)		(1,685	)
Changes in operating working capital:
	Accounts receivable		(7,860	)		1,658			35,739
	Inventory		229			240			84
	Other current assets		761			1			1,012
	Accounts payable		1,415			(1,256	)		(29,355	)
	Other current liabilities		(2,223	)		668			(664	)
	Accrued liabilities		(4,424	)		(2,469	)		7,992

Adjusted EBITDA — 100%		$	41,534		$	33,915		$	43,937

Reconciliation of Non-GAAP “Distributable Cash Flow” to GAAP “Net income”
Net income		$	8,781		$	11,670		$	20,652
Depreciation and accretion			22,875			22,795			24,794
Cumulative effect of change in accounting principle			267			—			176
Maintenance capital expenditures			(2,820	)		(845	)		(2,534	)

Distributable cash flow — 100%		$	29,103		$	33,620		$	43,088

Distributable cash flow — our 40% interest		$	11,641		$	13,448		$	17,235

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;

	•	the amount, if any, of cash reserves established by our general partner;

	•	the amount of cash that each of Discovery and Four Corners distributes to us; and

	•	reimbursement payments to us by, and credits from, Williams under the omnibus agreement.

You should be aware that 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.

Because of the natural decline in production from existing wells and competitive factors, the success of our gathering and transportation businesses depends on our ability to connect 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 and Discovery’s pipelines receive natural gas directly from offshore producers. The Four Corners gathering system receives natural gas directly from producers in the San Juan Basin. The production from existing wells connected to these pipelines and the Four Corners’ gathering system will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. We do not produce an aggregate reserve report on a regular basis or regularly obtain or update independent reserve evaluations. The amount of natural gas reserves underlying these wells may be less than we anticipate, and the rate at which production will decline from these reserves may be greater than we anticipate. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas processing plant and fractionator and Four Corners’ processing plants and treating plants, we, Discovery and Four Corners must continually connect new supplies of natural gas. The primary factors affecting our ability to connect new supplies of natural gas and attract new customers to our pipelines include: (1) the level of successful drilling activity near these pipelines; (2) our ability to compete for volumes from successful new wells and existing wells connected to third parties; and (3) our, Discovery’s and Four Corners’ ability to successfully complete lateral expansion projects to connect to new wells.

Neither we nor Four Corners has any current significant lateral expansion projects planned and Discovery has only one currently planned significant lateral expansion project. Discovery signed definitive agreements with Chevron, Shell and Statoil to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. Initial production is expected in April 2008.

The level of drilling activity in the fields served by our and Discovery’s pipelines and Four Corners’ gathering system 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 these fields, which would lead to reduced throughput levels on our pipelines and gathering system. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits, the availability of qualified personnel and equipment, the quality of drilling prospects in the area and regulatory changes. Because of these factors, even if new oil or natural gas reserves are discovered in areas served by our pipelines and gathering system, producers may choose not to develop those reserves. If we were not able to connect new supplies of natural gas to replace the natural decline in volumes from existing wells, due to reductions in drilling activity, competition, or difficulties in completing lateral expansion projects to connect to new supplies of natural gas, throughput on our pipelines and gathering system and the utilization rates of Discovery’s natural gas processing plant and fractionator and Four Corners’ processing plants and treating plants 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.

Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.

Lower natural gas and oil prices could result in a decline in the production of natural gas and NGLs resulting in reduced throughput on our pipelines and Four Corners’ gathering system. Any such decline would reduce the amount of NGLs we fractionate and store, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.

In general terms, the prices of natural gas, NGLs and other hydrocarbon products fluctuate in response to changes in supply, changes in demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include:


	•	worldwide economic conditions;

	•	weather conditions and seasonal trends;


	•	the levels of domestic production and consumer demand;

	•	the availability of imported natural gas and NGLs;

	•	the availability of transportation systems with adequate capacity;

	•	the price and availability of alternative fuels;

	•	the effect of energy conservation measures;

	•	the nature and extent of governmental regulation and taxation; and

	•	the anticipated future prices of natural gas, NGLs and other commodities.

Our processing, fractionation and storage businesses could be affected by any decrease in NGL prices or a change in NGL prices relative to the price of natural gas.

Lower NGL prices would reduce the revenues we generate from the sale of NGLs for our own account. Under certain gas processing contracts, referred to as “percent-of-liquids” and “keep whole” contracts, Discovery and Four Corners both receive NGLs removed from the natural gas stream during processing. Discovery and Four Corners can then choose to either fractionate and sell the NGLs or to sell the NGLs directly. 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 may also affect our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for Discovery, Four Corners and their 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 and Four Corners may experience periods in which higher natural gas prices reduce the volumes of NGLs removed at their processing plants, which would reduce their 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.

We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.

We rely on a limited number of customers for a significant portion of our revenues. Our three largest customers for the year ended December 31, 2005, other than a subsidiary of Williams that markets NGLs for Conway, were BP Products North America, Inc., SemStream, L.P. and Enterprise Products Partners, all customers of our Conway facilities. These customers accounted for approximately 45% of our revenues for the year ended December 31, 2005. Four Corner’s three largest customers for the year ended December 31, 2005, other than a subsidiary of Williams that markets NGLs for Four Corners, were ConocoPhillips, Burlington Resources and Williams Production Company, LLC, which accounted for approximately 30% of Four Corners’ revenues for the year ended December 31, 2005.

In addition, although 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. For example, Four Corners is in active negotiations with several customers to renew gathering, processing and treating contracts that are in evergreen status and that represent approximately 14% of Four Corners’ revenues for the year ended December 31, 2005. The negotiations may not result in any extended commitments from these customers. 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 are able to acquire comparable volumes from other sources.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. For example, MAPL delivers its customers’ mixed NGLs to our Conway fractionator and provides access to multiple end markets for NGL products of our storage customers. 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 adverse impact on our ability to enter into short-term storage contracts and our ability to fractionate sufficient volumes of mixed NGLs at Conway.

MAPL also provides the only liquids pipeline access to multiple end markets for NGL products that are recovered from Four Corners’ processing plants. 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, Four Corners would be unable to deliver a substantial portion of the NGLs recovered at its processing plants. This would have an immediate impact on Four Corners’ ability to sell or deliver NGL products recovered at its processing plants. In addition, the five pipeline systems that move natural gas to end markets from the San Juan Basin connect to Four Corners’ treating and processing facilities, including the El Paso Natural Gas, Transwestern, Williams’ Northwest Pipeline, PNM and Southern Trails systems. Some of these natural gas pipeline systems have minimal excess capacity. If any of these pipeline systems 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, Four Corners’ customers would be unable to deliver natural gas to end markets. This would reduce the volumes of natural gas processed or treated at Four Corners’ treating and processing facilities. Either of such events could materially and adversely affect our business results of operations, financial condition and ability to make distributions to you.

As another example, Shell’s Yellowhammer sour gas treating facility in Coden, Alabama is the only sour gas treating 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 treating facility before delivery to end markets. If the Shell-owned pipeline or the Yellowhammer facility were to become unavailable for current or future volumes of natural gas delivered to it through the Carbonate Trend pipeline due to repairs, damages to the facility, lack of capacity or any other reason, our Carbonate Trend customers would be unable to continue shipping natural gas to end markets. Since we generally receive revenues for volumes shipped on the Carbonate Trend pipeline, this would reduce our revenues.

Any temporary or permanent interruption in operations at MAPL, Yellowhammer or any other third party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.

Our future financial and operating flexibility may be adversely affected by restrictions in our indenture and by our leverage.

In connection with the closing of this offering and our acquisition of the interest in Four Corners, we will issue $150 million of senior notes, which will cause our leverage to increase. After giving effect to this offering and the private placement of our senior notes, our total outstanding debt will be approximately $150 million, representing approximately 39% of our total book capitalization. Immediately prior to this offering and the private placement of our senior notes, we had no outstanding debt.

Debt service obligations and restrictive covenants in the indenture governing the senior notes resulting from this leverage may adversely affect our ability to finance future operations, pursue acquisitions, fund

other capital needs and pay cash distributions to unitholders, and may make our results of operations more susceptible to adverse economic or operating conditions. Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control.

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 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. As of December 31, 2005, letters of credit totaling approximately $378 million had been issued on behalf of Williams and its other subsidiaries by the participating institutions under the facility and we did not have any revolving credit loans outstanding. 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 are not individually subject to any financial covenants or ratios under Williams’ revolving credit facility, Williams and its subsidiaries as a whole are subject to these tests. Accordingly, any breach of these or other covenants, ratios or tests, would terminate our and Williams’ and its other subsidiaries’ ability to make additional borrowings under the credit facility and, as a result, could limit our ability to finance our operations, make acquisitions or pay distributions to unitholders. In addition, a breach of these covenants by Williams would cause the acceleration of Williams’ and, in some cases, our outstanding borrowings under the facility. In the event of acceleration of indebtedness, Williams, the other borrowers or we might not have, or be able to obtain, sufficient funds to make required repayments of the accelerated indebtedness. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition and Liquidity.”

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.

Neither Four Corners nor Discovery is prohibited from incurring indebtedness, which may affect our ability to make distributions to you.

Neither Four Corners nor Discovery is prohibited by the terms of their respective limited liability company agreements from incurring indebtedness. If either Four Corners or Discovery were to incur significant amounts of indebtedness, it may inhibit their ability to make distributions to us. An inability by either Four Corners or Discovery to make distributions to us would materially and adversely affect our ability to make distributions to you because we expect distributions we receive from Discovery and Four Corners to represent a significant portion of the cash we distribute to our unitholders.

We do not own all of the interests in the Conway fractionator, in Discovery or in Four Corners, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.

Because we do not wholly own the Conway fractionator, Discovery or Four Corners, we may have limited flexibility to control the operation of, dispose of, encumber or receive cash from these assets. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

Discovery and Four Corners may reduce their cash distributions to us in some situations

Discovery’s limited liability company agreement provides that Discovery will distribute its available cash to its members on a quarterly basis. Four Corners’ limited liability company agreement, as amended to be effective at the closing of our acquisition of the interest in Four Corners, will provide that Four Corners will distribute its available cash to its members at least quarterly. Both Discovery’s and Four Corners’ available cash includes cash on hand less any reserves that may be appropriate for operating its business. As a result, reserves established by Discovery and Four Corners, including those for working capital, will reduce the amount of available cash. The amount of Discovery’s and Four Corners’ quarterly distributions, including the amount of cash reserves not distributed, are to be determined by the members of their respective management committees representing a majority-in-interest in such entity.

We own a 40% interest in Discovery and an affiliate of Williams owns a 20% interest in Discovery. In addition, to the extent Discovery requires working capital in excess of applicable reserves, the Williams member must make working capital advances to Discovery of up to the amount of Discovery’s two most recent prior quarterly distributions of available cash, but Discovery must repay any such advances before it can make future distributions to its members. As a result, the repayment of advances could reduce the amount of cash distributions we would otherwise receive from Discovery. In addition, if the Williams member cannot advance working capital to Discovery as described above, Discovery’s business and financial condition may be adversely affected.

We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.

Williams operates all of our assets, including Four Corners, other than the Carbonate Trend pipeline, which is operated by Chevron, and our Conway fractionator and storage facilities, which we operate. We have a limited ability to control our operations or the associated costs of these 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 operators.

We also rely on Williams for services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams as an operator and on Williams’ outsourcing relationships, our reliance on Chevron and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas and NGLs than we do.

Discovery competes with other natural gas gathering and transportation and processing facilities and other NGL fractionation facilities located in south Louisiana, offshore in the Gulf of Mexico and along the

Gulf Coast, including the Manta Ray/ Nautilus systems, the Trunkline pipeline and the Venice Gathering System and the processing and fractionation facilities that are connected to these pipelines.

Our Conway fractionation facility competes for volumes of mixed NGLs with a ONEOK-owned fractionator located in Hutchinson, Kansas, a ONEOK-owned fractionator located in Medford, Oklahoma, a ONEOK-owned fractionator located in Bushton, Kansas, the other joint owners of the Conway fractionation facility and, to a lesser extent, with fractionation facilities on the Gulf Coast. Our Conway storage facilities compete with ONEOK-owned storage facilities in Bushton, Kansas and in Conway, Kansas, an NCRA-owned facility in Conway, Kansas, a ONEOK-owned facility in Hutchinson, Kansas and an Enterprise Products Partners-owned facility in Hutchinson, Kansas and, to a lesser extent, with storage facilities on the Gulf Coast and in Canada.

Four Corners competes with other natural gas gathering, processing and treating facilities in the San Juan Basin, including Enterprise, Red Cedar and TEPPCO. 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.

Also, 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 NGLs. Conway, Kansas is one of the two major trading hubs for propane and other NGLs in the continental United States. Demand for propane at Conway is principally driven by demand for its use as a heating fuel. However, propane is also used as an engine and industrial fuel and as a petrochemical feedstock in the production of ethylene and propylene. Demand for propane as a heating fuel is significantly affected by weather conditions and the availability of alternative heating fuels such as natural gas. Weather-related demand is subject to normal seasonal fluctuations, but an unusually warm winter could cause demand for propane as a heating fuel to decline significantly. Demand for other NGLs, which include ethane, butane, isobutane and natural gasoline, could be adversely impacted by general economic conditions, a reduction in demand by customers for plastics and other end products made from NGLs, an increase in competition from petroleum-based products, government regulations or other reasons. Any decline in demand for propane or other NGLs could cause a reduction in demand for our Conway storage and fractionation services.

When prices for the future delivery of propane and other NGLs that we store at our Conway facilities fall below current prices, customers are less likely to store these products, which could reduce our storage revenues. This market condition is commonly referred to as “backwardation.” When the market for propane and other NGLs is in backwardation, the demand for storage capacity at our Conway facilities may decrease. While this would not impact our long-term capacity leases, customers could become less likely to enter into short-term storage contracts.

We may not be able to grow or effectively manage our growth.

A principal focus of our strategy is to continue to grow by expanding our business. Our future growth will depend upon a number of factors, some of which we can control and some of which we cannot. These factors include our ability to:


	•	identify businesses engaged in managing, operating or owning pipeline, processing, fractionation and storage assets, or other midstream assets for acquisitions, joint ventures and construction projects;

	•	control costs associated with acquisitions, joint ventures or construction projects;

	•	consummate acquisitions, including the acquisition of the interest in Four Corners, or joint ventures and complete construction projects, including Discovery’s Tahiti lateral expansion project;

	•	integrate any acquired or constructed business or assets successfully with our existing operations and into our operating and financial systems and controls;

	•	hire, train and retain qualified personnel to manage and operate our growing business; and

	•	obtain required financing for our existing and new operations.

A failure to achieve any of these factors would adversely affect our ability to achieve anticipated growth in the level of cash flows or realize anticipated benefits. Furthermore, competition from other buyers could reduce our acquisition opportunities or cause us to pay a higher price than we might otherwise pay. In addition, Williams is not restricted from competing with us. Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

We may acquire new facilities or expand our existing facilities to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, our new or expanded facilities may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into our operations may result in unforeseen operating difficulties, may absorb significant management attention and may require financial resources that would otherwise be available for the ongoing development and expansion of our existing operations. Future acquisitions or construction projects could result in the incurrence of indebtedness and additional liabilities and excessive costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. For example, in connection with our proposed acquisition of the interest in Four Corners, we will issue $150 million aggregate principal amount of senior notes. 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.

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 July 2004, the United States Court of Appeals for the District of Columbia Circuit, or the D.C. Circuit, issued its opinion in BP West Coast Products, LLC v. FERC, which upheld, among other things, FERC’s determination that certain rates of an interstate petroleum products pipeline, SFPP, L.P., or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the portion of FERC’s decision applying the Lakehead policy. In the Lakehead decision, FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which FERC stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. In December 2005, FERC issued its first case-specific oil pipeline review of the income tax allowance issue in the SFPP proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary for the pipeline to determine its income tax allowance. FERC’s BP West Coast remand decision and the new tax allowance policy have been appealed to the D.C. Circuit and rehearing requests have been filed with respect to the December 16 order. As a result, the ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost-of-service. If Discovery were to file a rate case, as discussed above, it would be required to prove pursuant to the new policy’s standard that the inclusion of an income tax allowance in Discovery’s cost-of-service was permitted. If FERC were to disallow a substantial portion of Discovery’s income tax allowance, it may be more difficult for Discovery to justify its rates.

The only pipeline that provides NGL transportation capacity in the San Juan Basin has filed at FERC to increase certain of its tariff rates. If the requested increase is granted, Four Corners’ operating costs would increase, which could have an adverse effect on our business and operating results.

MAPL, the only pipeline in the San Juan Basin that provides NGL transportation capacity, has filed at FERC to increase certain of its tariff rates. If FERC grants this request to increase those tariff rates, we estimate that Four Corners’ cost of transporting NGLs to certain markets would increase by approximately $3.5 million per year, which could have an adverse effect on our business, results of operations, financial condition and ability to make cash distributions to us.

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, in 2004 we experienced a temporary interruption of service on one of our pipelines due to an influx of seawater while connecting a new lateral. In addition, the Carbonate Trend pipeline is scheduled to be temporarily shut down in the second half of 2006 in connection with restoration activities due to the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004. We believe the cost of these restoration activities will be between $3.4 and $4.6 million.

In addition, in anticipation of Hurricane Katrina, the Discovery and Carbonate Trend assets were temporarily shut down on August 27, 2005. The Carbonate Trend assets were off-line for ten days and then experienced a gradual return to pre-hurricane throughput rates by September 19, 2005. In anticipation of Hurricane Rita, the Discovery assets, which were already at reduced throughput from Hurricane Katrina, were temporarily shut down on September 21, 2005. The Discovery assets were off-line for seven days and then continued to experience lower throughput rates through the end of the year and into 2006. We estimate the unfavorable impact of these hurricanes on our 2005 net income was approximately $1.5 million due primarily to the impact of these hurricanes on Discovery’s results. Discovery’s net income was unfavorably impacted by an approximate loss of $2.3 million in revenue and $1.0 million in uninsured expenses. Discovery’s property insurance policy includes a $1.0 million deductible per occurrence. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Events” for additional information.

Insurance may be inadequate, and in some instances, we may be unable to obtain insurance on commercially reasonable terms, if at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to you.

Pipeline integrity programs and repairs may impose significant costs and liabilities on us.

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for gas transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The final rule requires operators to:


	•	perform ongoing assessments of pipeline integrity;

	•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

	•	improve data collection, integration and analysis;

	•	repair and remediate the pipeline as necessary; and

	•	implement preventive and mitigating actions.

The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 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. In 2005, Conway replaced two sections of brine systems at a cost of $0.2 million. This work is in anticipation of integrity testing scheduled to begin in 2006. 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 — Gathering and Processing — The Carbonate Trend Pipeline — General” for additional information on our corrosion control program.

The State of New Mexico recently enacted rule changes that permit the pressure in gathering pipelines to be reduced below atmospheric levels. In response to these rule changes, Four Corners may reduce the pressures in its gathering lines below atmospheric levels. With Four Corners’ concurrence, producers may also reduce pressures below atmospheric levels prior to delivery to Four Corners. All of the gathering lines owned by Four Corners in the San Juan Basin are made of steel. Reduced pressures below atmospheric levels may introduce increasing amounts of oxygen into those pipelines, which could cause an acceleration of the corrosion.

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 and gathering systems on land owned by third parties and governmental agencies for a specific period of time. For example, portions of the Four Corners gathering system are located on Native American right-of-ways. Four Corners is currently in discussions with the Jicarilla Apache Nation regarding rights-of-way that expire at the end of 2006 for a small segment of the gathering system. 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 public and the environment. These laws include, for example:


	•	the Federal Clean Air Act and analogous state laws, which impose obligations related to air emissions;

	•	the Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act, or CWA, and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters;

	•	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

	•	the federal Resource Conservation and Recovery Act, also known as RCRA, and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

Various governmental authorities, including the U.S. Environmental Protection Agency, or EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and

several, strict liability may be incurred without regard to fault under CERCLA, RCRA and analogous state laws for the remediation of contaminated areas.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of the products we gather, transport, process, fractionate and store, air emissions related to our operations, historical industry operations, waste disposal practices, and the prior use of flow meters containing mercury, some of which may be material. Private parties, including the owners of properties through which our pipeline and gathering systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third party hydrocarbon storage and processing operations and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, some of which may be material.

For example, the Kansas Department of Health and Environment, or the KDHE, regulates the storage of NGLs and natural gas in the state of Kansas. This agency also regulates the construction, operation and closure of brine ponds associated with such storage facilities. In response to a significant incident at a third party facility, the KDHE recently promulgated more stringent regulations regarding safety and integrity of brine ponds and storage caverns. These regulations are subject to interpretation and the costs associated with compliance with these regulations could vary significantly depending upon the interpretation of these regulations. 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.

There is increasing pressure in New Mexico from environmental groups and area residents to reduce the noise from midstream operations through regulatory means. If these groups are successful, Four Corners may have to make capital expenditures to muffle noise from its facilities or to ensure adequate barriers or distance to mitigate noise concerns.

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.

The natural gas gathering operations in the San Juan Basin may be subjected to regulation by the state of New Mexico, which could negatively affect Four Corners.

The New Mexico state legislature has called for hearings to take place to examine the regulation of natural gas gathering systems in the state. It is unclear when these hearings will occur, but they could result in gathering regulation that would affect the fees that Four Corners could collect for gathering services. This type of regulation could adversely impact Four Corners’ revenues and cash flow.

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.

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 your detriment.

Following this offering, Williams will own a 2% general partner interest and a 38.5% limited partner interest in us and will own and control our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and executive officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Williams. 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. In resolving 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:


	•	neither our partnership agreement nor any other agreement requires Williams or its affiliates to pursue a business strategy that favors us;

	•	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 you;

	•	Williams and its affiliates may engage in competition with us;

	•	our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

	•	our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;


	•	our general partner determines the amount and timing of any capital expenditures, as well as whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not, which determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

	•	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 to us or entering into additional contractual arrangements with any of these entities on our behalf;

	•	our general partner intends to limit its liability regarding our contractual and other obligations;

	•	our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

	•	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.”

Our partnership agreement limits our general partner’s fiduciary duties to you and restricts the remedies available to you 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. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

	•	provides that 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, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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

By purchasing a common unit, a common unitholder will be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

Even if you are dissatisfied, you cannot currently remove our general partner without its consent.

Unlike the holders of common stock in a corporation, you have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. You will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Williams. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Furthermore, if you are dissatisfied with the performance of our general partner, you 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, our unitholders are currently unable to remove our general partner without its consent because affiliates of our general partner own sufficient units 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 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 members 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.

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, subject to the limitations imposed by the New York Stock Exchange. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:


	•	our unitholders’ proportionate ownership interest in us will decrease;

	•	the amount of cash available to pay distributions on each unit may decrease;

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

	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of the common units may decline.

Williams and its affiliates may compete directly with us and have no obligation to present business opportunities to us.

The omnibus agreement does not prohibit Williams and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. Williams may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to Williams and its affiliates. As a result, neither Williams nor any of its affiliates has any obligation to present business opportunities to us. Please read “Certain Relationships and Related Transactions — Omnibus Agreement” and “Conflicts of Interest and Fiduciary Duties.”

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would not longer be subject to the reporting requirements of the Securities Exchange Act of 1934. For additional information about this call right, please read “The Partnership Agreement — Limited Call Right.”

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.

Cost reimbursements due our general partner and its affiliates will reduce cash available to pay distributions to you.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner. These expenses will include all costs incurred by the general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. Please read “Certain Relationships and Related Transactions” and “Conflicts of Interest and Fiduciary Duties — Conflicts of Interest.” The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates could adversely affect our ability to pay cash distributions to you.

You may not have limited liability if a court finds that unitholder action constitutes control of our business. You may also have liability to repay distributions.

As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, such as its debts and environmental liabilities, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Please read “The Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.

Common units held by affiliates of Williams eligible for future sale may have adverse effects on the price of our common units.

As of April 1, 2006, affiliates of Williams held 1,250,000 common units and 7,000,000 subordinated units, representing a 38.5% limited partnership interest in us after giving effect to this offering. The affiliates of Williams may, from time to time, sell all or a portion of their common units or subordinated units. Sales of substantial amounts of their common units or subordinated units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.

Our common units have a limited trading history and a limited trading volume compared to other units representing limited partner interests.

Our common units are traded publicly on the New York Stock Exchange under the symbol “WPZ”. However, our common units have a limited trading history and daily trading volumes for our common units are, and may continue to be, relatively small compared to many other units representing limited partner interests quoted on the New York Stock Exchange. This offering may not increase the trading volume for our common units, and the price of our common units may, therefore, be volatile.

The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:


	•	our quarterly distributions;

	•	our quarterly or annual earnings or those of other companies in our industry;

	•	loss of a large customer;

	•	announcements by us or our competitors of significant contracts or acquisitions;

	•	changes in accounting standards, policies, guidance, interpretations or principles;


	•	general economic conditions;

	•	the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

	•	future sales of our common units; and

	•	the other factors described in these “Risk Factors.”

Tax Risks

You should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash available to pay distributions to you would be substantially reduced.

The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of the common units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions to you would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contest will be borne by our unitholders and our general partner.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this prospectus. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

The tax 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. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning 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. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with 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.

The sale or exchange of 50% or more of our capital and profits interests during any 12-month period 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.

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 own property and conduct business in Kansas, Louisiana and Alabama. We may own property or conduct business in other states or foreign countries in the future, including Colorado and New Mexico upon the consummation of the acquisition of the interest in Four Corners. 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.

ACQUISITION OF INTEREST IN FOUR CORNERS

Overview of San Juan Basin

The San Juan Basin, measuring approximately 7,500 square miles, is located in southwest Colorado and northwest New Mexico and is one of North America’s largest natural gas fields. In 2002, the U.S. Geological Survey estimated there were 50.6 trillion cubic feet of undiscovered natural gas in the San Juan Basin. The U.S. Bureau of Land Management also estimates that more than 12,500 undrilled locations remain in the New Mexico portion of the San Juan Basin. Lippman Consulting Inc., an independent natural gas consultant for North America with significant experience in the San Juan Basin, believes wellhead production of natural gas in the San Juan Basin will remain stable at four Bcf/d for at least the next ten years. In addition, we anticipate the level of development in the San Juan Basin to continue at current levels in response to approval from the states of Colorado and New Mexico for increased drilling activity in the basin.

Natural gas in the San Juan Basin is produced from two reservoir types — conventional and coal bed. Conventional natural gas generally contains NGLs and comparatively less carbon dioxide while natural gas from coal beds, or coal bed methane, typically contains few, if any, extractable NGLs and has a high concentration of carbon dioxide. As a result, conventional natural gas generally requires processing, and coal bed methane generally requires treating for excess carbon dioxide, before the natural gas can be transported on long-haul interstate pipelines. Five pipeline systems transport natural gas to end markets from the San Juan Basin, allowing producers to benefit from diversified access to a variety of natural gas markets throughout the western United States.

General

Four Corners owns:


	•	a 3,500-mile natural gas gathering system in the San Juan Basin in New Mexico and Colorado with a capacity of two Bcf/d;

	•	the Ignacio natural gas processing plant in Colorado and the Kutz and Lybrook natural gas processing plants in New Mexico, which have a combined processing capacity of 760 MMcf/d; and

	•	the Milagro and Esperanza natural gas treating plants in New Mexico, which have a combined carbon dioxide treating capacity of 750 MMcf/d.

Four Corners’ customers are primarily natural gas producers in the San Juan Basin. Four Corners provides its customers with a full range of gathering, processing and treating services. Approximately 52% of Four Corners’ revenue for the year ended December 31, 2005 was derived from fee-based gathering, processing and treating services. The remaining 48% was derived primarily from the sale of NGLs. These sales include the sale of NGLs on behalf of producers that have Four Corners market their NGLs for a fee in accordance with their contracts.

The Four Corners pipeline system gathers approximately 37% of the natural gas produced in the San Juan Basin and connects with the five pipeline systems that transport natural gas to end markets from the basin. Approximately 40% of the supply connected to the Four Corners pipeline system in the San Juan Basin is produced from conventional reservoirs with approximately 60% coming from coal bed reservoirs. Four Corners is currently the only company in the basin that is the owner and operator of both major conventional natural gas and coal bed methane gathering, processing and treating facilities in the San Juan Basin. Despite the topographically challenging terrain, Four Corners has gathering pipelines throughout most of the San Juan Basin.

The following map shows the locations of Four Corners’ gathering lines, the Ignacio, Kutz and Lybrook natural gas processing plants and the Milagro and Esperanza natural gas treating plants:

We will account for the 25.1% interest in Four Corners as an equity investment, and therefore will not consolidate its financial results. For the year ended December 31, 2005, this 25.1% interest in Four Corners generated Adjusted EBITDA of approximately $38.4 million and DCF of approximately $35.4 million. For a reconciliation of each of Adjusted EBITDA and DCF to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Prospectus Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures” Please read “Prospectus Summary — Summary Historical and Pro Forma Financial and Operating Data — Four Corners” for information regarding Four Corners’ financial and operating results.

Four Corners Management

Upon the consummation of the proposed transactions, Four Corners will be managed by a two-member management committee consisting of representatives of the two owners, Williams and us. The members of the management committee will have voting power that corresponds to the ownership interest of the owner they represent. Except for certain significant matters that are specified in the Four Corners limited liability company agreement, all actions and decisions relating to Four Corners require the approval of the management committee members representing a majority interest. Through Williams’ 74.9% ownership interest in Four Corners, it will have the ability to control Four Corners. Four Corners is required under its limited liability company agreement to make distributions of available cash (generally, cash from operations less required and discretionary reserves) at least quarterly to its owners. The management committee, by majority approval, will determine the amount of such distributions. Williams will operate the natural gas gathering pipeline system in accordance with the Four Corners limited liability company agreement.

Both members of Four Corners will be subject to reciprocal rights of first offer under the Four Corners limited liability company agreement. Accordingly, prior to selling all or a portion of its respective interest in Four Corners, that member will be required to first offer its membership interest to the other member.

Four Corners Natural Gas Gathering System

The Four Corners natural gas gathering pipeline system consists of:


	•	3,500 miles of 2-inch to 30-inch diameter natural gas gathering pipelines with capacity of two Bcf/d and approximately 6,400 receipt points; and

	•	90 field compression units leased from Hanover Compression, Inc. and an additional 108 compression units owned by Four Corners, providing an aggregate of approximately 290,000 horsepower of field compression. Approximately 85% of this field compression is operated by Hanover Compression.

Additionally, Four Corners owns and operates approximately 110,000 horsepower of compression at pipeline stations and plants, giving the Four Corners’ gathering system an aggregate of approximately 400,000 horsepower of total compression deployed.

Four Corners generally charges a fee on the volume of natural gas gathered on its pipeline system. Four Corners does not, however, take title to the natural gas that it gathers other than natural gas it retains for fuel and purchases for shrinkage.

Four Corners Processing and Treating Plants


	*Natural Gas Processing Plants*

Four Corners owns and operates three natural gas processing plants with a combined processing capacity of 760 MMcf/d and combined NGL production capacity of 41,000 bpd.

The Ignacio natural gas processing plant was constructed in 1956 and is located near Durango, Colorado. Williams acquired the plant in 1983 in connection with its acquisition of Northwest Energy. The primary processing components of the Ignacio plant were installed in 1984 and were subsequently upgraded and expanded in 1999. The Ignacio plant has one cryogenic train with 55,000 horsepower of compression and processing capacity of 450 MMcf/d. The Ignacio plant has outlet connections to the El Paso Natural Gas, Transwestern and Williams’ Northwest Pipeline systems. These pipelines serve markets throughout most of the western United States. The plant has an NGL production capacity of 22,000 bpd. Most of the NGLs are shipped via the MAPL pipeline system to Gulf Coast markets, but some NGLs retained by Four Corners are fractionated at Ignacio and distributed locally via trucks. Ignacio also produces liquefied natural gas, which is distributed via truck. The Ignacio plant is able to recover approximately 95% of the ethane contained in the natural gas stream and nearly all of the propane and heavier NGLs.

The Kutz and Lybrook gas processing plants, located in Bloomfield and Lybrook, New Mexico, respectively, have a combined processing capacity of 310 MMcf/d. These plants have an aggregate

67,000 horsepower of compression and have a combined NGL production capacity of 19,000 bpd. The NGLs are shipped via the MAPL pipeline system to Gulf Coast markets, but some liquids retained by Four Corners are fractionated at Lybrook and distributed locally via truck. The Kutz plant has gas outlets to the El Paso Natural Gas, PNM and Transwestern pipeline systems. The Lybrook plant connects to the PNM pipeline. The Kutz and Lybrook plants are able to recover approximately 55% and 80%, respectively, of the ethane contained in the natural gas stream.


	*Contractual Arrangements*

Four Corners has a portfolio of natural gas processing agreements that includes the following types of contracts:


	•	Keep-whole. Under keep-whole contracts, Four Corners (1) processes natural gas produced by customers, (2) retains some or all of the extracted NGLs as compensation for its services, (3) replaces the Btu content of the retained NGLs that were separated during processing with natural gas it purchases, also known as shrink replacement gas, and (4) delivers an equivalent Btu content of natural gas to customers at the plant outlet. Four Corners, in turn, sells the retained NGLs to a subsidiary of Williams, which serves as a marketer for those NGLs at market prices. For the year ended December 31, 2005, 38% of Four Corners’ processing volumes were under keep-whole contracts.

	•	Percent-of-liquids. Under percent-of-liquids processing contracts, Four Corners (1) processes natural gas produced by customers, (2) delivers to customers an agreed-upon percentage of the extracted NGLs, (3) retains a portion of the extracted NGLs as compensation for its services and (4) delivers natural gas to customers at the plant outlet. Under this type of contract, there is no requirement for Four Corners to replace the Btu content of the retained NGLs that were extracted during processing. Four Corners sells the retained NGLs to a subsidiary of Williams, which serves as a marketer for those NGLs at market prices. For the year ended December 31, 2005, 14% of Four Corners’ processing volumes were under percent-of-liquids contracts.

	•	Fee-based. Under fee-based contracts, Four Corners receives revenue based on the volume of natural gas processed and the per-unit fee charged, and Four Corners retains none of the extracted NGLs. For the year ended December 31, 2005, 13% of Four Corners’ processing volumes were under fee-based contracts.

	•	Fee-based and keep-whole. These contracts have both a per-unit fee component and a keep-whole component. The relative proportions of the fee component and the keep-whole component vary from contract to contract, with the keep-whole component never consisting of more than 50% of the total extracted NGLs. For the year ended December 31, 2005, 35% of Four Corners’ processing volumes were under these fee-based and keep-whole contracts.


	*Treating Plants*

Coal bed methane sources typically contain high levels of carbon dioxide and must be treated before it can be transported through pipelines to end markets. Four Corners owns and operates two natural gas treating plants, the Milagro and Esperanza plants, with a combined carbon dioxide treating capacity of 750 MMcf/d. The Milagro treating plant can deliver natural gas to the El Paso Natural Gas, Transwestern, Southern Trails and PNM pipelines.

Four Corners charges a fee for the volume of natural gas treated at its facilities and does not take gas as payment for its treating services, other than for the reimbursement of gas used or lost during the treating of natural gas.

Four Corners Customers and Contracts


	*Customers*

Three producer customers, ConocoPhillips, Burlington Resources and Williams Production Company, LLC, accounted for approximately 30% of Four Corners’ revenues for the year ending December 31, 2005. In addition, on March 31, 2006, ConocoPhillips acquired Burlington Resources. No other customer accounted for over 10% of Four Corners’ revenues for the year ending December 31, 2005. Additionally, a subsidiary of Williams, to which Four Corners sells substantially all of the NGLs Four Corners retains under its keep-whole and percent-of-liquids contracts, accounted for approximately 48% of Four Corners’ revenues for the year ended December 31, 2005.


	*Contracts*

Four Corners provides its customers with a full range of gathering, processing and treating services. These services are usually provided to each customer under a single long-term contract with applicable acreage dedications, reserve dedications, or both, for the life of the contract.

Competition

The Four Corners pipeline system competes with other delivery options available to producers in the San Juan Basin. Four Corners generally competes with other gathering systems and interconnecting gas processing and treating facilities, some of which may have the same owner. The Enterprise system, comprised of 5,500 miles of gathering lines and one processing plant, gathers approximately 27% of the natural gas produced in the San Juan Basin. Enterprise owns and operates primarily conventional natural gas gathering and processing facilities in the San Juan Basin. The Red Cedar system, consisting of 900 miles of gathering lines, is a joint venture between the Southern Ute Indian tribe and Kinder Morgan Energy Partners. The Red Cedar system gathers approximately 12% of the natural gas produced in the San Juan Basin. The TEPPCO system consists of 400 miles of gathering lines and gathers approximately 12% of the natural gas produced in the San Juan Basin. Red Cedar and TEPPCO own and operate primarily coal bed methane gathering and treating facilities in the San Juan Basin.

Gas Supply

All of Four Corners’ contracts with major customers contain certain production dedications whereby natural gas produced from a particular area and/or group of receipt points may only flow to Four Corners’ assets for the life of the contract. Those contracts also contain provisions requiring the connection of newly drilled wells within dedicated areas to Four Corners. From 1999 to 2005, an average of 220 wells were connected each year and, according to tentative customer drilling plans shared with Williams, may grow to as many as 280 wells annually. We anticipate that these additional well connects, together with sustained drilling activity, other expansion opportunities and production enhancement activities by producers, will offset substantially the impact of normal decline in gathered and processed volumes. Four Corners has on occasion successfully pursued customers connected to competing gathering systems when the customer’s contract with the competing gathering system expired.

Litigation


	*Will Price*

In 2001, Four Corners’ predecessor was named, along with other subsidiaries of Williams, as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged

underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held on April 1, 2005. Four Corners is awaiting a decision from the court.


	*Grynberg*

In 1998, the Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries, including Four Corners’ predecessor. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg has also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the Department of Justice announced that it was declining to intervene in any of the Grynberg cases, including the action filed in federal court in Colorado against Four Corners’ predecessor. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against Four Corners’ predecessor, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remain pending against Four Corners’ predecessor and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against certain Williams’ subsidiaries, including Four Corners’ predecessor, be dismissed. The District Court is considering whether to affirm or reject the special master’s recommendations and heard oral arguments in December 2005.

Conflicts Committee Approval

The conflicts committee of the board of directors of our general partner recommended approval of the acquisition of the interest in Four Corners. The committee retained independent legal and financial advisors to assist it in evaluating and negotiating the transaction. In recommending approval of the transaction, the committee based its decision in part on an opinion from the committee’s independent financial advisor that the consideration to be paid by us to Williams is fair, from a financial point of view, to us and our public unitholders.

Financing

We intend to finance our acquisition of the interest in Four Corners with:


	•	the net proceeds of this offering; and

	•	the net proceeds from a private placement of our senior notes to qualified institutional investors and to non-U.S. persons in offshore transactions.

This offering is conditioned upon the consummation of the private placement of senior notes, and the private placement of senior notes is conditioned upon the consummation of this offering.

USE OF PROCEEDS

We expect to receive net proceeds of approximately $216.9 million from the sale of 7,000,000 common units offered by this prospectus, after deducting estimated underwriting discounts and estimated offering expenses. We base this amount on the public offering price of $32.75 per common unit, the last reported sales price of our common units on the NYSE on April 6, 2006.

The aggregate consideration for our 25.1% interest in Four Corners is $360 million ($355.5 million net of our general partner’s capital contribution related to this offering). We intend to use the net proceeds of this offering, together with the net proceeds from our private placement of $150 million of senior notes, to pay the aggregate consideration in exchange for the interest in Four Corners. Please read “Acquisition of Interest in Four Corners” for more information. If the underwriters exercise their option to purchase additional units, we will use the net proceeds for general partnership purposes.

This offering is conditioned upon the consummation of the private placement of senior notes, and the private placement of senior notes is conditioned upon the consummation of this offering.

CAPITALIZATION

The following table shows:


	•	our historical capitalization as of December 31, 2005; and

	•	our pro forma capitalization as of December 31, 2005, as adjusted to reflect:


	•	this common unit offering;

	•	the private placement of our senior notes;

	•	the application of the net proceeds of this common unit offering and the notes offering as described under “Use of Proceeds;” and

	•	our acquisition of the interest in Four Corners.

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, 2005

					Pro Forma
			Actual		As Adjusted

			($ in thousands)
Cash and cash equivalents			$	6,839	$	15,180

Long-term debt, including current portion:
	Our borrowings under Williams’ revolving credit facility		$	—	$	—
	Working capital facility with Williams			—		—
	Senior Notes			—		150,000

		Total long-term debt		—		150,000

Partners capital:
	Held by public:
		Common units		89,163		296,099
	Held by the general partner and its affiliates:
		Common units		19,363		29,284
		Subordinated units		108,491		108,491
		General partner interest		4,638		(198,875	)

		Total partners’ capital		221,655		234,999

		Total capitalization	$	221,655	$	384,999

PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

As of March 1, 2006, there were 7,006,146 common units outstanding, held by approximately 3,494 holders, including common units held in street name and by affiliates of Williams. Our common units are traded on the NYSE under the symbol “WPZ”.

As of April 1, 2006, there were 7,000,000 subordinated units outstanding held by four subsidiaries of Williams. The subordinated units are not publicly traded.

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the NYSE Composite Transactions Tape, and quarterly cash distributions paid to our unitholders. The last reported sales price of common units on the New York Stock Exchange on April 6, 2006 was $32.75 per common unit.


		Price Ranges
						Cash Distribution
		High		Low		Per Unit (1)

2005
	Third Quarter(2)	$	32.75	$	24.89	$	0.1484	(3)
	Fourth Quarter		34.46		29.75	$	0.3500
2006
	First Quarter	$	33.92	$	31.00		N/A
	Second Quarter (through April 6, 2006)		33.15		32.33		N/A


(1)	Represents cash distributions attributable to the quarter and declared and paid or to be paid within 45 days after quarter end. We paid total cash distributions to our general partner with respect to its 2% general partner interest of $184,800 for the period from August 23, 2005 through December 31, 2005.

(2)	For the period from August 23, 2005 through September 30, 2005.

(3)	The distribution for the third quarter of 2005 represents a pro-rated distribution of $0.35 per common and subordinated unit for the period from August 23, 2005, the date of the closing of our initial public offering of common units, through September 30, 2005.

Distributions of Available Cash

Please read “How We Make Cash Distributions” for information on our cash distribution policy.

SELECTED HISTORICAL AND PRO FORMA

FINANCIAL AND OPERATING DATA

The following table shows selected historical financial and operating data of Williams Partners L.P., selected pro forma financial data of Williams Partners L.P., selected historical financial and operating data of Discovery Producer Services LLC and selected historical financial and operating data for Williams Four Corners Predecessor for the periods and as of the dates indicated. The selected historical financial data of Williams Partners L.P. as of December 31, 2004 and 2005 and for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Williams Partners L.P. appearing elsewhere in this prospectus.

The selected pro forma financial data of Williams Partners L.P. as of and for the year ended December 31, 2005 are derived from the unaudited pro forma consolidated financial statements of Williams Partners L.P. included elsewhere in this prospectus. These pro forma consolidated financial statements show the pro forma effect of:


	•	this offering, including our use of the anticipated net proceeds;

	•	the proposed private placement of $150 million aggregate principal amount of our senior notes to certain institutional investors and to non-U.S. persons in offshore transactions, including our use of the anticipated net proceeds of that private placement;

	•	our acquisition of a 25.1% interest in Four Corners;

	•	the forgiveness by Williams of advances to our predecessor in connection with our initial public offering; and

	•	the payment of estimated underwriters’ commission and other offering expenses.

The selected pro forma balance sheet data assumes that the items listed above occurred as of December 31, 2005, and the selected pro forma income statement data assumes that the items listed above occurred on January 1, 2005.

The selected historical financial data of Discovery Producer Services LLC for the years ended December 31, 2003, 2004 and 2005 are derived from the audited consolidated financial statements of Discovery Producer Services LLC appearing elsewhere in this prospectus. The selected historical financial data of Williams Four Corners Predecessor for the years ended December 31, 2003, 2004 and 2005 are derived from the audited financial statements of Williams Four Corners Predecessor appearing elsewhere in this prospectus.

The following table includes Adjusted EBITDA Excluding Equity Investments, a non-GAAP financial measure, for Williams Partners L.P. and Adjusted EBITDA for both our interest in Discovery and the interest in Four Corners that we expect to acquire. These measures are presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Our 40% ownership interest in Discovery is not and our 25.1% ownership interest in Four Corners will not be, consolidated in our financial results; rather we account or will account for them using the equity method of accounting. In order to evaluate EBITDA for the impact of our investment of Discovery and Four Corners on our results, we calculate Adjusted EBITDA Excluding Equity Investments separately for Williams Partners L.P. and Adjusted EBITDA for both our interest in Discovery and our interest in Four Corners that we expect to acquire. We expect distributions we receive from Discovery and Four Corners to represent a significant portion of the cash we distribute to our unitholders. Discovery’s limited liability company agreement provides for quarterly distributions of available cash to its members. Four Corners’ limited liability company agreement, as amended effective as of the closing of this offering, will provide for distributions of available cash at least quarterly to

its members. Please read “How We Make Cash Distributions — General — Discovery’s Cash Distribution Policy” and “— General — Four Corners’ Cash Distribution Policy.”

For Discovery and Four Corners, we define Adjusted EBITDA as net income plus interest (income) expense, depreciation and accretion. We also adjust for certain non-cash, non-recurring items. Our equity share of Discovery’s Adjusted EBITDA is 40%, and our equity share of Four Corners’ Adjusted EBITDA will be 25.1%.

For a reconciliation of these measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”


		Williams Partners L.P.(a)

		Historical

																	Pro Forma
		Year Ended December 31,															Year Ended
																	December 31,
		2001			2002			2003			2004			2005			2005

		($ in thousands, except per unit data)
Statement of Income Data:
Revenues		$	29,164		$	25,725		$	28,294		$	40,976		$	51,769		$	51,769
Costs and expenses			23,692			16,542			21,250			32,935			46,568			46,568

Operating income			5,472			9,183			7,044			8,041			5,201			5,201
Equity earnings — Four Corners																		28,668
Equity earnings (loss) — Discovery			(13,401	)		2,026			3,447			4,495			8,331			8,331
Impairment of investment in Discovery			—			—			—			(13,484	)(b)		—			—
Interest expense			(4,173	)		(3,414	)		(4,176	)		(12,476	)		(8,073	)		(12,472	)

Income (loss) before cumulative effect of change in accounting principle			(12,102	)		7,795			6,315			(13,424	)		5,459		$	29,728

Cumulative effect of change in accounting principle			—			—			(1,099	)		—			(628	)

Net income (loss)(c)		$	(12,102	)	$	7,795		$	5,216		$	(13,424	)	$	4,831

Diluted earnings per limited partner unit:
	Income (loss) before cumulative effect of change in accounting principle													$	0.49		$	1.45
	Cumulative effect of change in accounting principle														(0.05	)

	Net income (loss)													$	0.44

Balance Sheet Data (at period end):
Total assets		$	122,239		$	125,069		$	230,150	(d)	$	219,361		$	240,941		$	404,285
Property, plant and equipment, net			75,269			72,062			69,695			67,793			67,931			67,931
Investment in Four Corners																		152,003
Investment in Discovery			44,499			49,323			156,269	(d)		147,281	(b)		150,260			150,260
Advances from affiliate			95,535			90,996			187,193	(d)		186,024			—			—
Total partners’ capital			15,236			22,914			30,092			16,668			221,655			234,999


		Williams Partners L.P.(a)

		Historical

												Pro Forma
		Year Ended December 31,										Year Ended
												December 31,
		2001		2002		2003		2004		2005		2005

		($ in thousands, except per unit data)
Other Financial Data:
Williams Partners L.P.:
	Adjusted EBITDA Excluding Equity Investments	$	8,849	$	12,758	$	10,751	$	11,727	$	10,853	$	10,853
	Maintenance capital expenditures(e)		4,269		295		1,176		1,622		3,664		3,664
Four Corners — our 25.1%:
	Adjusted EBITDA						32,705		34,445		38,447
	Maintenance capital expenditures(e)						512		286		797
Discovery — our 40%:
	Adjusted EBITDA		1,284		15,314		16,614		13,566		17,575
	Maintenance capital expenditures(e)		N/A		1,131		1,128		338		1,014
Operating Information:
Williams Partners L.P.:
	Conway storage revenues	$	11,134	$	10,854	$	11,649	$	15,318	$	20,290
	Conway fractionation volumes (bpd) — our 50%		40,713		38,234		34,989		39,062		39,965
	Carbonate Trend gathered volumes (MMBtu/d)		55,746		57,060		67,638		49,981		35,605
Four Corners — 100%:
	Gathered volumes (MMBtu/d)						1,577,181		1,559,940		1,521,507
	Processed volumes (MMBtu/d)						900,356		900,194		863,693
	Net liquids margin (cents/gallon)(f)						17¢		29¢		37¢
Discovery — 100%:
	Gathered volumes (MMBtu/d)		226,820		425,388		378,745		348,142		345,098
	Gross processing margin (¢/MMBtu)(g)		N/A		12¢		17¢		17¢		19¢


(a)		Williams Partners L.P. is the successor to Williams Partners Predecessor. Results of operations and balance sheet data prior to August 23, 2005 represent historical results of the Williams Partners Predecessor.

(b)		The $13.5 million impairment of our equity investment in Discovery in 2004 reduced the investment balance. See Note 6 of the Notes to Consolidated Financial Statements.

(c)		Our operations are 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.

(d)		In December 2003, our predecessor made a $101.6 million capital contribution to Discovery, which Discovery subsequently used to repay maturing debt. Our predecessor funded this contribution with an advance from Williams.

(e)		Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition and Liquidity — Capital Requirements” for a definition of maintenance capital expenditures. Information for 2001 is not available as Williams was not the operator of Discovery.

(f)		Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Four Corners — How We Evaluate Four Corners — Net Liquids Margin” for a discussion of net liquids margin.

(g)		Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Gross Processing Margins” for a discussion of gross processing margin. Gross processing margin information for 2001 is not available because Williams was not the operator of Discovery.

Non-GAAP Financial Measures

Adjusted EBITDA Excluding Equity Investments, in our case, and, Adjusted EBITDA in Discovery’s and Four Corners’ cases, are used as a supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess:


	•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest on our indebtedness and to make distributions to our partners; and

	•	our operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.

Our Adjusted EBITDA Excluding Equity Investments, Discovery’s Adjusted EBITDA and Four Corners’ Adjusted EBITDA should not be considered alternatives to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA Excluding Equity Investments, Discovery’s Adjusted EBITDA and Four Corners’ Adjusted EBITDA exclude some, but not all, items that affect net income and operating income, and these measures may vary among other companies. Therefore, our Adjusted EBITDA Excluding Equity Investments, Discovery’s Adjusted EBITDA and Four Corners’ Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

The following tables present a reconciliation of the non-GAAP financial measures, our Adjusted EBITDA Excluding Equity Investments, Discovery’s Adjusted EBITDA and Four Corners’ Adjusted EBITDA, to the GAAP financial measures of net income (loss) and of net cash provided (used) by operating activities, on a historical basis and on a pro forma basis, as adjusted for this offering, the proposed private placement of our senior notes, the application of the net proceeds from each offering, our acquisition of the interest in Four Corners, and the forgiveness of advances from affiliate to our predecessor in connection with our initial public offering.


		Williams Partners L.P.(a)

		Historical

																	Pro Forma
		Year Ended December 31,															Year Ended
																	December 31,
		2001			2002			2003			2004			2005			2005

		($ in thousands)
Williams Partners L.P.:
Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Equity Investments” to GAAP “Net income (loss)”
Net income (loss)		$	(12,102	)	$	7,795		$	5,216		$	(13,424	)	$	4,831		$	28,926
Interest expense, net of interest income			4,173			3,414			4,176			12,476			8,073			12,472
Depreciation and accretion			3,377			3,575			3,707			3,686			3,619			3,619
Amortization of natural gas purchase contract			—			—			—			—			2,033			2,033
Impairment of investment in Discovery Producer Services			—			—			—			13,484			—			—
Equity (earnings) loss — Discovery Producer Services			13,401			(2,026	)		(3,447	)		(4,495	)		(8,331	)		(8,331	)
Equity earnings — Four Corners																		(28,668	)
Cumulative effect of change in accounting principle			—			—			1,099			—			628			802

Adjusted EBITDA Excluding Equity Investments		$	8,849		$	12,758		$	10,751		$	11,727		$	10,853		$	10,853

Reconciliation of Non-GAAP “Adjusted EBITDA Excluding Equity Investments” to GAAP “Net cash provided (used) by operating activities”
Net cash provided (used) by operating activities					$	8,144		$	6,644		$	2,703		$	1,893			(2,506	)
Interest expense, net of interest income						3,414			4,176			12,476			8,073			12,472
Distributed earnings from equity investments									—			—			(1,280	)		(1,280	)
Changes in operating working capital:
	Accounts receivable					958			850			(261	)		3,045			3,045
	Other current assets					185			187			362			384			384
	Accounts payable					(593	)		274			(2,711	)		(4,215	)		(4,215	)
	Accrued liabilities					1,218			320			417			737			737
	Deferred revenue					765			(1,108	)		(775	)		(247	)		(247	)
Other, including changes in noncurrent assets and liabilities						(1,333	)		(592	)		(484	)		2,463			2,463

Adjusted EBITDA Excluding Equity Investments					$	12,758		$	10,751		$	11,727		$	10,853		$	10,853


(a)		Williams Partners L.P. is the successor to Williams Partners Predecessor. Results of operations data prior to August 23, 2005 represent historical results of the Williams Partners Predecessor.


		Williams Four Corners Predecessor

		Year Ended December 31,

		2003			2004			2005

		($ in thousands)
Four Corners:
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net income (loss)”
Net income		$	88,417		$	96,556		$	113,521
Depreciation			41,552			40,675			38,960
Cumulative effect of change in accounting principle			330			—			694

Adjusted EBITDA — 100%		$	130,299		$	137,231		$	153,175

Adjusted EBITDA — our 25.1% interest		$	32,705		$	34,445		$	38,447

Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities		$	122,266		$	134,387		$	156,039
Provision for loss on property, plant and equipment			(7,598	)		(7,636	)		(917	)
Gain (loss) on sale of property, plant and equipment			1,151			(1,258	)		—
Changes in operating working capital:
	Accounts receivable		279			(1,298	)		1,374
	Prepaid expenses		1,530			—			79
	Accounts payable		3,266			(9,435	)		(4,586	)
	Product imbalance		4,447			7,983			(10,073	)
	Accrued liabilities		(61	)		5,047			3,271
	Other, including changes in other noncurrent assets and liabilities		5,019			9,441			7,988

Adjusted EBITDA — 100%		$	130,299		$	137,231		$	153,175


		Discovery Producer Services LLC

		Year Ended December 31,

		2001			2002			2003			2004			2005

		($ in thousands)
Discovery Producer Services:
Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net income (loss)”
Net income (loss)		$	(33,069	)	$	5,498		$	8,781		$	11,670		$	20,652
Interest (income) expense, net			14,283			10,851			9,611			(550	)		(1,685	)
Depreciation and accretion			21,996			21,935			22,875			22,795			24,794
Cumulative effect of change in accounting principle			—			—			267			—			176

Adjusted EBITDA — 100%		$	3,210		$	38,284		$	41,534		$	33,915		$	43,937

Adjusted EBITDA — our 40% interest		$	1,284		$	15,314		$	16,614		$	13,566		$	17,575

Reconciliation of Non-GAAP “Adjusted EBITDA” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities					$	19,572		$	44,025		$	35,623		$	30,814
Interest (income) expense, net						10,851			9,611			(550	)		(1,685	)
Loss on disposal of equipment						(1,913	)		—			—			—
Changes in operating working capital:
	Accounts receivable					6,008			(7,860	)		1,658			35,739
	Inventory					122			229			240			84
	Other current assets					330			761			1			1,012
	Accounts payable					7,538			1,415			(1,256	)		(29,355	)
	Other current liabilities					1,163			(2,223	)		668			(664	)
	Accrued liabilities					(5,387	)		(4,424	)		(2,469	)		7,992

Adjusted EBITDA — 100%					$	38,284		$	41,534		$	33,915		$	43,937

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and notes and our pro forma financial statements included elsewhere in this prospectus.

Because of the significance of our investment in Discovery, we include separate consolidated 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 consolidated financial statements of Discovery and the notes to those financial statements found elsewhere in this prospectus.

We have recently entered into an agreement to acquire a 25.1% membership interest in Four Corners. Because of the significance of this investment to us in the future, we include separate financial statements and notes of Four Corners 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 Four Corners and the notes to those financial statements found elsewhere in this prospectus.

General

We are a Delaware limited partnership formed in February 2005 by Williams to own, operate and acquire a diversified portfolio of complementary energy assets. On August 23, 2005, we completed our initial public offering of 5,000,000 common units at a price of $21.50 per unit. We used net proceeds from the sale of the units totaling $100.2 million to:


	•	distribute $58.8 million to affiliates of Williams, in part to reimburse Williams for capital expenditures relating to the assets, including a gas purchase contract, contributed to us;

	•	provide $24.4 million to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;

	•	provide $12.7 million of additional working capital; and

	•	pay $4.3 million of expenses associated with our initial public offering and related formation transactions.

Additionally, at the closing of our initial public offering, the underwriters fully exercised their option to purchase 750,000 common units at the initial public offering price of $21.50 per unit from certain affiliates of Williams.

We have recently executed an agreement to acquire a 25.1% membership interest in Four Corners from subsidiaries of Williams. Please read “Acquisition of Interest in Four Corners.” Prior to the closing of our initial public offering, our assets were held by wholly owned subsidiaries of Williams. Upon the closing of our initial public offering, these Williams’ subsidiaries transferred the assets and the related liabilities to us. The following discussion includes the historical period prior to the closing of our initial public offering and analyzes the financial condition and results of operations for our assets, excluding the interest in Four Corners. A discussion of Four Corners’ financial condition and the results of operations is presented separately.

Business Overview

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 segment 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 off the coast of Alabama.


		Discovery 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. These assets generate revenues by providing natural gas gathering, transporting and processing services and integrated 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 and is managed as such.

	•	NGL Services. Our NGL Services segment includes three integrated NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas. These assets generate revenues by providing stand-alone NGL fractionation and storage services using various fee-based contractual arrangements where we receive a fee or fees based on actual or contracted volumetric measures.

Executive Summary of 2005 Results

Overall our 2005 results of operations met our expectations for these assets, although we faced unusual operating conditions the last few months of 2005. Discovery and Carbonate Trend were impacted by Hurricanes Dennis, Katrina and Rita, and Conway saw an impact from a delay in the peak usage of retail propane due to an unusually moderate winter. The hurricanes created an unfavorable impact for our traditional natural gas supplies but also provided an opportunity for Discovery to assist other producers and processors with stranded gas by offering available firm transportation capacity to them through two open seasons discussed below in “— Recent Events.” Discovery replaced some of its lost revenue while helping to bring the supply of natural gas back to the nation in advance of winter. We continue to monitor the longer-term effects these hurricanes had on Discovery’s traditional sources of natural gas, which might cause lower than expected gathered volumes from these sources in 2006. Conway experienced an increased demand for propane storage services as a result of warm early-winter temperatures. Our results were negatively impacted by unfavorable commodity price movements on operating supply inventory we held at Conway and by higher general and administrative costs. Our liquidity continues to meet our expectations. We have had no borrowings under our revolving credit facilities and have successfully met our minimum quarterly distributions. Our capitalization and relationship with Williams has us well-positioned to grow our partnership through both internal projects, including Discovery’s Tahiti lateral expansion, and acquisition transactions with Williams and other third parties.

Recent Events

In July 2005, Discovery executed an agreement with three producers to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. The Tahiti pipeline lateral expansion will have a design capacity of approximately 200 MMcf/d, and its anticipated completion date is May 2007 with initial production expected in April 2008. We expect the total construction cost of the Tahiti pipeline lateral expansion project to be approximately $69.5 million, of which our 40% share will be approximately $27.8 million. In September 2005, we made a $24.4 million contribution to Discovery to cover a substantial portion of the total expenditures attributable to our share of these costs. We funded this contribution with proceeds from our initial public offering. The omnibus agreement with Williams, executed in connection with our initial public offering, provides that Williams will reimburse us for up to $3.4 million in additional costs once the initial escrow funds established for this project have been exhausted.

On July 8, 2005, the Discovery and Carbonate Trend assets were temporarily shut down in anticipation of Hurricane Dennis. The Discovery and Carbonate Trend assets were off-line for four and five days, respectively. We estimate the unfavorable impact of this hurricane on our 2005 net income was approximately $150,000 in lost revenue.

On August 29, 2005, Hurricane Katrina struck the Gulf Coast area. In anticipation of this hurricane, the Discovery and Carbonate Trend assets were temporarily shut down on August 27, 2005. The Discovery assets were off-line for six days and then continued to experience lower throughput rates until being temporarily

shut down for Hurricane Rita. The Carbonate Trend assets were off-line for ten days and then experienced a gradual return to pre-hurricane throughput rates by September 19, 2005. On September 24, 2005, Hurricane Rita struck the Gulf Coast area. In anticipation of this hurricane, the Discovery assets, which were already at reduced throughput from Hurricane Katrina, were temporarily shut down on September 21, 2005. The Discovery assets were off-line for seven days and then continued to experience lower throughput rates through the end of the third quarter. Discovery’s net income was unfavorably impacted by an approximate loss of $2.3 million in revenue and $1.0 million in uninsured expenses. Discovery’s property insurance policy includes a $1.0 million deductible per occurrence. We estimate the unfavorable impact of Hurricanes Katrina and Rita on our 2005 net income was approximately $1.5 million due primarily to the impact of these hurricanes on Discovery’s results.

In October 2005, Discovery conducted two expedited FERC open seasons for firm transportation to provide outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita. Both of these open seasons were for up to 250,000 MMBtu/d. The first of these included Discovery’s construction of a new receipt point at Texas Eastern Transmission Company’s, or TETCO’s, Larose compressor station in Lafourche Parish, Louisiana. The second was via an existing interconnection to Tennessee Gas Pipeline’s, or TGP’s, Line 500 in Terrebonne Parish, Louisiana. We began receiving additional incremental volumes from these receipt points in November and December 2005 and anticipate continued throughput through the first quarter of 2006. Shippers reimbursed Discovery for a majority of the capital necessary to establish these connections. We estimate the favorable impact of these open seasons on Discovery’s 2005 net income was approximately $4.6 million in increased revenue, less related expenses.

For January 2006, the average gathering volumes for Discovery were approximately 694,000 MMBtu/d. This volume includes approximately 412,000 MMBtu/d from multiple customers whose gas is normally processed at another plant that was severely damaged by Hurricane Katrina and 282,000 MMBtu/d from Discovery’s traditional sources.

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.

Pipeline Throughput Volumes. We view throughput volumes on Discovery’s pipeline system and our Carbonate Trend pipeline as an important component of maximizing our profitability. We gather and transport natural gas under fee-based contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas processing plant and fractionator, we and Discovery must continually connect new supplies of natural gas. Our ability to maintain existing supplies of natural gas and connect new supplies are impacted by (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines and (2) our ability to compete for volumes from successful new wells in other areas. We routinely monitor producer activity in the areas served by Discovery and Carbonate Trend and pursue opportunities to connect new wells to these pipelines.

Gross Processing Margins. We view total gross processing margins as an important measure of Discovery’s ability to maximize the profitability of its processing operations. Gross processing margins include revenue derived from:


	•	the rates stipulated under fee-based contracts multiplied by the actual MMBtu volumes;

	•	sales of NGL volumes received under percent-of-liquids contracts for Discovery’s account; and

	•	sales of natural gas volumes that are in excess of operational needs.

The associated costs, primarily shrink replacement gas and fuel gas, are deducted from these revenues to determine processing gross margin. Shrink replacement gas refers to natural gas that is required to replace the Btu content lost when NGLs are extracted from the natural gas stream. In certain prior years, such as 2003, we generated significant revenues from the sale of excess natural gas volumes. However, in response to a final rule issued by FERC in 2004, we expect that Discovery will generate only minimal revenues from the sale of excess natural gas in the future.

Discovery’s mix of processing contract types and its operation and contract optimization activities are determinants in processing revenues and gross margins. Please read “— Our Operations — Gathering and Processing Segment.”

Fractionation Volumes. We view the volumes that we fractionate at the Conway fractionator as an important measure of our ability to maximize the profitability of this facility. We provide fractionation services at Conway under fee-based contracts. Revenue from these contracts is derived by applying the rates stipulated to the volumes fractionated.

Storage Revenues. Our storage revenues are derived by applying the average demand charge per barrel to the total volume of storage capacity under contract. Given the nature of our operations, our storage facilities have a relatively higher degree of fixed verses variable costs. Consequently, we view total storage revenues, rather than contracted capacity or average pricing per barrel, as the appropriate measure of our ability to maximize the profitability of our storage assets and contracts. Total storage revenues include the monthly recognition of fees received for the storage contract year and shorter-term storage transactions.

Operating and Maintenance Expenses. Operating and maintenance expenses are costs associated with the operations of a specific asset. Direct labor, fuel, utilities, contract services, materials, supplies and insurance 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 also review our general and administrative expenditures, substantially all of which are incurred through Williams. In an omnibus agreement, executed in connection with our initial public offering, Williams agreed to provide a five-year partial credit for general and administrative expenses incurred on our behalf. The annualized amount of this credit in 2005 was $3.9 million, which was pro rated for the period from the closing of our initial public offering in August 2005 through year end. The pro rated amount totaled $1.4 million. The amount of the credit will be $3.2 million in 2006 and will decrease by approximately $800,000 in each subsequent year.

We record total general and administrative costs, including those costs that are subject to the credit by Williams, as an expense, and we record the credit as a capital contribution by our general partner. Accordingly, our net income does not reflect the benefit of the credit received from Williams. However, the cost subject to this credit is allocated entirely to our general partner. As a result, the net income allocated to limited partners on a per-unit basis reflects 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 and is managed as such. As a result, 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 — Gathering and Processing — The Discovery Assets” and “Business — Gathering and Processing — The Carbonate Trend Pipeline.”


	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 may 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. If a customer elects to use the Transco capacity, our gathering fee is determined by subtracting the Transco tariff from the total negotiated fee and generally results in a rate lower than would be realized if the customer elects not to utilize Transco’s capacity. The rate associated with Transco capacity is based on a FERC tariff that is subject to change. Accordingly, if the Transco rate increases, our gathering fees will be reduced. The customers with these bundled contracts must make an annual election to receive this capacity. Both customers elected to use this capacity during 2004 and only one elected to use this capacity in 2005 and 2006.

The gathering and transportation revenues that we generate under fee-based contracts are not directly affected by changing commodity prices. However, to the extent a sustained decline in commodity prices realized by our customers results in a decline in the producers’ future drilling and development activities, our revenues from these contracts could be reduced in the long term.


	Processing and Fractionation Contracts

Fee-based contracts. Discovery generates fee-based fractionation revenues based on the volumes of mixed NGLs fractionated and the per-unit fee charged, which is subject to adjustment for changes in certain fractionation expenses, including natural gas fuel and labor costs. Some of Discovery’s natural gas processing contracts are also fee-based contracts under which revenues are generated based on the volumes of natural gas processed at its natural gas processing plant. As discussed below, Discovery also processes natural gas under percent-of-liquids contracts.

The processing revenues that Discovery generates under fee-based contracts are not directly affected by changing commodity prices. However, to the extent a sustained decline in commodity prices realized by our customers results in a decline in the producers’ future drilling and development activities, our revenues from these contracts could be reduced due to long-term development declines.

Percent-of-liquids contracts. Under percent-of-liquids contracts, Discovery (1) processes natural gas for customers, (2) delivers to customers an agreed-upon percentage of the NGLs extracted in processing and (3) retains a portion of the extracted NGLs. Discovery generates revenue by selling these retained NGLs to other parties at market prices. Some of Discovery’s percent-of-liquids contracts have a “bypass” option. Under this option, customers may elect not to process, or bypass, their natural gas on a monthly basis, in which case, Discovery retains a portion of the customers’ natural gas in lieu of NGLs as a fee. Discovery uses its retained natural gas to partially offset the amount of natural gas Discovery must purchase in the market for shrink replacement gas and natural gas consumed as fuel. Discovery may choose to process natural gas that a customer has elected to bypass, but it then must deliver natural gas with an equivalent Btu content to the customer. Discovery would not elect to process bypassed gas if market conditions posed the risk of negative processing margins. Please read “— Operation and Contract Optimization.”

Under Discovery’s percent-of-liquids contracts, revenues either increase or decrease as a result of a corresponding change in the market prices of NGLs. For contracts with a bypass option, and depending upon whether the customer elects the bypass election, Discovery’s revenues would either increase or decrease as a result of a corresponding change in the relative market prices of NGLs and natural gas.

Discovery is also a party to a small number of “keep-whole” gas processing arrangements. Under these arrangements, a processor retains NGLs removed from a customer’s natural gas stream but must deliver gas with an equivalent Btu content to the customer, either from the processor’s inventory or through open market purchases. A rise in natural gas prices as compared to NGL prices can cause the processor to suffer negative margins on keep-whole arrangements. The natural gas associated with Discovery’s keep-whole arrangements has a low NGL content. As a result, this gas does not require processing to be shipped on downstream pipelines. Consequently, under unfavorable market conditions, Discovery may earn little or no margin on these arrangements, but is not exposed to negative processing margins. Discovery does not intend to enter into additional keep-whole arrangements in the future that would represent a material amount of processing volumes.

Substantially all of Discovery’s gas gathering, transportation, processing and fractionation contracts have terms that expire at the end of the customer’s natural resource lease. The actual terms of these contracts will vary depending on life of the natural gas reserves underlying these leases. As a result of Discovery’s current contract mix, Discovery takes title to approximately one-half of the mixed NGL volumes leaving its natural gas processing plant. A Williams subsidiary serves as a marketer for these NGLs and, under the terms of its agreement with Discovery, purchases substantially all of Discovery’s NGLs for resale to end users. As a result, a significant portion of Discovery’s revenues are reported as affiliate revenues even though Williams is not a producer that supplies the Discovery pipeline system with any volumes of natural gas. If the arrangement with the Williams subsidiary were terminated, we believe that Discovery could contract with a third party marketer or perform its own marketing services.


	Operation and Contract Optimization

Long-haul natural gas pipelines, generally interstate pipelines that serve end 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 our initial public offering in August 2005, Williams transferred to us a contract for the purchase of a sufficient quantity of natural gas from a wholly owned subsidiary of Williams at a fixed price to satisfy our fuel requirements under this fractionation contract. Williams paid the full costs associated with entering into this contract prior to assigning the contract to us upon closing of our initial public offering. The fair value of this gas purchase contract was recorded as an equity contribution to us by Williams. This gas purchase contract will terminate on December 31, 2007 to correspond with the expected termination of the related fractionation agreement. Pursuant to the terms of this agreement we provided notice of termination to this customer in July 2005. If we are unable to negotiate a new agreement with this customer upon such termination, we believe that we could contract with other potential customers to replace a significant portion of these volumes.

Two contracts with remaining terms of approximately two and four years account for most of our fractionation revenues. The revenues we generate under fractionation contracts at our Conway facility generally are not directly affected by changing commodity prices. However, to the extent a sustained decline in commodity prices received by our customers results in a decline in their production volumes, our revenues from these contracts could be reduced. One of our customers has the contractual right, on a month-to-month basis, to deliver its mixed NGLs elsewhere. Its decision on whether to ship its products to the Mid-Continent region or another region depends on supply and demand in the respective regions and the current price being paid for fractionated products in each region.


	Storage Contracts

Substantially all our storage contracts are on a firm basis, pursuant to which our customers pay a demand charge for a contracted volume of storage capacity, including injection and withdrawal rights. The majority of our storage revenues are from three contracts with remaining terms between three and twelve 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. The selection of these policies has been discussed with the Audit Committee of our general partner. We believe that the following are the more

critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.


	*Impairment of Long-Lived Assets and Investments*

We evaluate our long-lived assets and investments for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of certain long-lived assets or that the decline in value of an investment is other than temporary.

During 2004, an impairment review was performed 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 publicly-traded partnerships. 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. Please read Note 6 of Notes to Consolidated Financial Statements. Our computations were based upon judgments and assumptions in the following areas:


	•	estimated future volumes and rates;

	•	range of expected future cash flows;

	•	potential proceeds from a sale to another publicly-traded partnership 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 and contractual 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, 2005, we have an accrued asset retirement obligation liability of $762,000 for estimated retirement costs associated with the closure of our Conway underground storage caverns and brine ponds in accordance with KDHE regulations. This estimate is based on the assumption that the closure will occur in 50 years. If this assumption were changed to 30 years, the recorded asset retirement obligation would increase by approximately $2.6 million. Our estimate utilizes judgments and assumptions regarding the costs and timing of closure. Please read Note 7 of Notes to Consolidated 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, 2005, we have an accrual for estimated environmental remediation obligations of $5.4 million. This remediation accrual is revised, and our associated income is affected, during periods in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. We base liabilities for environmental remediation upon our assumptions and estimates regarding what remediation work and post-remediation monitoring will be required and the costs of those efforts, which we develop from information obtained from outside consultants and from discussions with the applicable governmental authorities. As new developments occur or more information becomes available, it is possible that our assumptions and estimates in these matters will change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of

operations for any particular quarter or annual period. During 2004, we purchased an insurance policy covering some of our environmental liabilities. Please read “— Environmental” and Note 13 of Notes to Consolidated Financial Statements for further information.

Results of Operations


	*Consolidated Overview*

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2005. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


		Years Ended December 31,

		2003			2004			2005

		($ in thousands)
Revenues		$	28,294		$	40,976		$	51,769
Costs and expenses:
	Operating and maintenance expense		13,960			19,376			25,111
	Product cost		1,263			6,635			11,821
	Depreciation and accretion		3,707			3,686			3,619
	General and administrative expense		1,813			2,613			5,323
	Taxes other than income		640			716			700
	Other, net		(133	)		(91	)		(6	)

Total costs and expenses			21,250			32,935			46,568

Operating income			7,044			8,041			5,201
Equity earnings — Discovery			3,447			4,495			8,331
Impairment of investment in Discovery			—			(13,484	)		—
Interest expense			(4,176	)		(12,476	)		(8,238	)
Interest income			—			—			165

Income (loss) before cumulative effect of change in accounting principle			6,315			(13,424	)		5,459
Cumulative effect of change in accounting principle			(1,099	)		—			(628	)

Net income (loss)		$	5,216		$	(13,424	)	$	4,831


	Year Ended December 31, 2005 vs. Year Ended December 31, 2004

Revenues increased $10.8 million, or 26%, due primarily to higher revenues in our NGL Services segment reflecting increased product sales volumes and higher storage revenues, slightly offset by lower revenue in our Gathering and Processing segment due to Hurricanes Katrina and Rita and the 2004 recognition of a $950,000 settlement of a contractual volume deficiency provision.

Operating and maintenance expense increased $5.7 million, or 30%, due primarily to larger product imbalance valuation adjustments and higher fuel and power costs recognized by our NGL Services segment in 2005 as compared to 2004.

Product cost increased $5.2 million, or 78%, directly related to the increase in product sales volumes in our NGL Services segment.

General and administrative expense increased $2.7 million, or 104%, due primarily to the increased costs of being a publicly traded partnership. These costs included $1.1 million for audit fees, tax return preparation, director fees, and registration and transfer agent fees, $0.7 million for direct and specific charges allocated, by Williams, for accounting, legal, and other support, $0.6 million for business development, and $0.3 million for other various expenses.

Operating income decreased $2.8 million, or 35%, due primarily to higher operating and maintenance expense in our NGL Services segment, higher general and administrative expenses and lower revenues in our Gathering and Processing segment, partially offset by higher storage revenues in our NGL Services segment.

Equity earnings from Discovery increased $3.8 million. This increase is discussed in detail below under “— Results of Operations — Gathering and Processing.”

The impairment of our investment in Discovery is the result of our analysis pursuant to which we concluded that we had experienced an other-than-temporary decline in the value of our investment in Discovery as described above in “— Critical Accounting Policies and Estimates — Impairment of Long-Lived Assets and Investments.”

Interest expense decreased $4.2 million, or 34%, due primarily to the forgiveness of the advances from Williams to our predecessor in conjunction with the closing of our initial public offering on August 23, 2005.

The cumulative effect of change in accounting principle of $0.6 million in 2005 relates to our December 31, 2005 adoption of Financial Accounting Standards Board Interpretation (“FIN”) No. 47. Please read Note 7 of Notes to Consolidated Financial Statements.


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

Revenues increased $12.7 million, or 45%, due mainly to higher revenues in our NGL Services segment, reflecting higher product sales volumes and storage rates.

Operating and maintenance expense increased $5.4 million, or 39%, due primarily to increased costs to comply with KDHE requirements at NGL Services’ Conway facilities. Product costs increased $5.4 million, from $1.3 million, due to the increase in product sales.

General and administrative expense increased $0.8 million, or 44%, due primarily to an increase in allocated general and administrative expenses from Williams reflecting increased corporate overhead costs within the Williams organization. These increased costs related to various corporate initiatives and Sarbanes-Oxley Act compliance efforts within Williams.

Interest expense increased $8.3 million, from $4.2 million, due primarily to the cash advanced by Williams in December 2003 to fund our predecessor’s $101.6 million share of a cash call by Discovery to repay its outstanding debt.

The cumulative effect of change in accounting principle of $1.1 million in 2003 relates to our January 1, 2003 adoption of Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” Please read Note 7 of Notes to Consolidated Financial Statements.


	*Outlook for 2006*

Following the completion of the private placement of our senior notes to partially finance the acquisition of the 25.1% interest in Four Corners, our interest expense will increase by approximately $11.6 million annually.


	*Results of Operations — Gathering and Processing*

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


		Years Ended December 31,

		2003		2004			2005

		($ in thousands)
Segment revenues		$	5,513	$	4,833		$	3,515
Costs and expenses:
	Operating and maintenance expense		379		572			714
	Depreciation		1,200		1,200			1,200
	General and administrative expense — direct		—		—			2

Total costs and expenses			1,579		1,772			1,916

Segment operating income			3,934		3,061			1,599
Equity earnings — Discovery			3,447		4,495			8,331
Impairment of investment in Discovery			—		(13,484	)		—

Segment profit (loss)		$	7,381	$	(5,928	)	$	9,930


	*Carbonate Trend*


	Year Ended December 31, 2005 vs. Year Ended December 31, 2004

Segment revenues decreased $1.3 million, or 27%, due primarily to a 29% decline in average daily gathered volumes between 2005 and 2004 and the absence of $950,000 of revenue resulting from the settlement of a contractual volume deficiency payment recognized in 2004, partially offset by $452,000 of revenue from the settlement of a contractual volume deficiency payment recognized in 2005.

The decline in average daily gathered volumes was caused by normal reservoir depletion, reduced capacity experienced at a third-party onshore treating plant in April 2005 and the temporary shutdowns for Hurricane Dennis in July 2005 and Hurricane Katrina in August 2005. The overall impact of this decline in gathered volumes on gathering revenue was approximately $1.1 million. This decline in gathered volumes was partially offset by a 11% higher average gathering rate causing a $300,000 increase in gathering revenue. The increase in the average gathering rate was due to a customer’s annual election in 2005 under a bundled rate provision within its contract.

Operating and maintenance expense increased $142,000, or 25%, due to $72,000 increased costs for inhibitor chemicals and internal pipeline corrosion inspection, and $70,000 related to insurance costs. These increases were offset partially by increased painting expense in 2004.

Segment operating income decreased $1.5 million, or 48%, due primarily to the lower revenues discussed above.


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

Segment revenues decreased $0.7 million, or 12%, due primarily to a 26% decline in gathering volumes in 2004, largely offset by the recognition in 2004 of a $950,000 settlement of a contractual volume deficiency provision. Gathering volumes declined in 2004 due to lower production from connected wells that was not offset by new production coming online.

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


	*Discovery*

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 our Consolidated 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,

		2003			2004			2005

		($ in thousands)
Revenues		$	103,178		$	99,876		$	122,745
Costs and expenses, including interest:
	Product cost and shrink replacement		42,914			45,355			64,467
	Operating and maintenance expense		15,829			17,854			10,165
	General and administrative expense		1,400			1,424			2,053
	Depreciation and accretion		22,875			22,795			24,794
	Interest expense (income)		9,611			(550	)		(1,685	)
	Other expenses, net		1,501			1,328			2,123

Total costs and expenses			94,130			88,206			101,917

Income before cumulative effect of change in accounting principle		$	9,048		$	11,670		$	20,828

Williams Partners’ 40% interest		$	3,619		$	4,668		$	8,331
Capitalized interest amortization			(172	)		(173	)		—

Equity earnings per our Consolidated Statement of Operations		$	3,447		$	4,495		$	8,331

Year Ended December 31, 2005 vs. Year Ended December 31, 2004

Revenues increased $22.9 million, or 23%, due primarily to higher NGL product sales from marketing of customers’ NGLs, fractionation revenue, processing revenue and average per-unit NGL sales prices, partially offset by lower NGL sales volumes. The significant components of this increase include the following:


	•	Product sales increased $31.6 million for the NGL sales related to third-party processing customers’ election to have Discovery market their NGLs for a fee under an option in their contracts. These sales were offset by higher associated product costs of $31.6 million discussed below.

	•	Processing and fractionation revenues increased $6.8 million including $3.9 million in additional volumes related to the TGP and TETCO open seasons discussed previously, $2.9 million related to an increase in the fractionation rate for increased natural gas fuel cost pass through, and other increases related to new volumes from the Front Runner prospect that came on line in the first quarter of 2005.

	•	Gathering revenues increased $2.1 million due primarily to a $1.4 million deficiency payment received in 2005 related to a volume shortfall under a transportation contract, $0.4 million related to an increase in volumes and $0.3 million related to a 25% higher average gathering rate associated with new volumes from the Front Runner prospect.

Partially offsetting these increases were the following:


	•	Product sales decreased $4.9 million as a result of lower sales of excess fuel and shrink replacement gas in 2005. During the first half of 2004, increased natural gas prices made it more economical for Discovery’s customers to bypass the processing plant rather than process the gas, leaving Discovery with higher levels of excess fuel and shrink replacement gas in 2004 than 2005.

	•	Product sales also decreased approximately $16.0 million as a result of 36% lower NGL sales volumes following Hurricanes Katrina and Rita, partially offset by a $5.0 million increase associated with a 17% higher average sales prices.


	•	Transportation revenues decreased $0.6 million due primarily to lower condensate transportation volumes. Higher average natural gas transportation volumes were partially offset by a lower average natural gas transmission rate.

	•	Other revenues declined $1.1 million due largely to lower platform rental fees.

Product cost and shrink replacement increased $19.1 million, or 42%, due primarily to:


	•	$31.6 million increased purchase costs for the two processing customers who elected to have Discovery market their NGLs; and

	•	$3.4 million resulting from higher average per-unit natural gas prices.

Partially offsetting these increases were the following:


	•	$11.0 million lower costs related to reduced processing activity in 2005; and

	•	$4.9 million lower cost associated with sales of excess fuel and shrink replacement gas.

Operating and maintenance expense decreased $7.7 million, or 43%, due primarily to a $10.7 million credit related to amounts previously deferred for net system gains from 2002 through 2004 that were reversed following the acceptance in 2005 of a filing with FERC, partially offset by $1.2 million higher utility costs, $1.0 million of uninsured damages caused by Hurricane Katrina, and $0.8 million other miscellaneous operational costs.

General and administrative expense increased $0.6 million, or 44%, due primarily to an increase in the management fee paid to Williams related to Discovery’s market expansion project and additions of other facilities. For a discussion of Discovery’s recently completed market expansion project, please read “Business — Gathering and Processing — The Discovery Assets — Discovery Natural Gas Pipeline System.”

Depreciation and accretion expense increased $2.0 million, or 9%, due primarily to the completion of a pipeline connection to the Front Runner prospect in late 2004.

Interest income increased $1.1 million, due primarily to increases in interest-bearing cash balances during early 2005 when cash flows from operations were being retained by Discovery.

Other expenses, net increased $0.8 million, or 60%, due primarily to a non-cash foreign currency transaction loss from the revaluation of restricted cash accounts denominated in Euros. These restricted cash accounts were established from contributions made by Discovery’s members, including us, for the construction of the Tahiti pipeline lateral expansion project.

Net income increased $9.2 million, or 78%, due primarily to the $10.7 million reversal of deferred net system gains, $8.9 million increased revenue from gathering, processing and fractionation services and $1.1 million higher interest income, partially offset by $3.5 million lower product sales margins, $3.0 million higher other operating and maintenance expense, $0.6 million higher general and administrative expense, $2.0 million higher depreciation and accretion, and $0.8 higher other expense including the foreign currency transaction loss.


	Year Ended December 31, 2004 vs. Year Ended December 31, 20/03

The $3.3 million, or 3%, decrease in revenues resulted primarily from lower fuel and shrink replacement gas sales in 2004 and lower NGL sales volumes, partially offset by higher average per-unit NGL sales prices. The significant components of this decrease consisted of the following:


	•	Increasing gas prices during some months of 2003 made it more economical for Discovery’s customers to bypass the processing plant rather than to process the gas, leaving Discovery with higher levels of excess fuel and shrink replacement gas in 2003 than 2004. This excess natural gas was sold in the market in 2003, which resulted in $5.1 million of lower revenues in 2004.

	•	Transportation volumes declined 6% due to production declines and a temporary interruption of service because of an accidental influx of seawater in a lateral while putting in place a subsea


		connection to a wellhead. These lower volumes resulted in a decrease in fee-based revenues, including $2.7 million from gathering and transportation, $2.2 million from fee-based processing and $0.2 million from fractionation, for a total of $5.1 million.

	•	Other revenues decreased $1.5 million due to a $0.9 million decrease in offshore platform production handling fees related to lower natural gas production volumes and $0.8 million received in connection with the resolution of a condensate measurement and ownership allocation issue in 2003.

	•	NGL sales increased $8.5 million due to a 26% increase in average sales prices, which were slightly offset by a 2% decrease in sales volumes.

Product cost and shrink replacement increased by $2.4 million, or 6%, primarily due to higher average natural gas prices. Operating and maintenance expense increased $2.0 million, or 12%, from 2003 due primarily to $1.2 million of costs for a routine compressor overhaul and $1.3 million of costs to correct a non-routine temporary interruption of service due to an accidental influx of seawater in our offshore pipeline. These increases were partially offset by lower miscellaneous operating expenses.

Interest expense decreased $9.6 million due to the repayment of $253.7 million of outstanding debt in December 2003. Other expense, net decreased $0.7 million due primarily to $0.6 million of income earned on the short-term investing of excess cash.

Net income increased $2.6 million, or 29%, due primarily to $9.6 million lower interest expense, $0.7 million lower other expense, partially offset by $3.3 million lower revenue, $2.4 million higher product cost and shrink replacement expense and $2.0 million higher operating and maintenance expense.


	*Outlook for 2006*

Following our acquisition of a 25.1% interest in Four Corners, that investment would become part of the Gathering and Processing segment. Please read “— Four Corners” for a discussion of the results of operations of Four Corners.

We currently estimate that we will incur $3.4 million to $4.6 million of maintenance expenditures for Carbonate Trend during 2006 for restoration activities related to the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004. Under an omnibus agreement, Williams agreed to reimburse us for the cost of these restoration activities. In connection with these restoration activities, the Carbonate Trend pipeline may experience a temporary shut down. We estimate that this shut down could reduce our cash flows from operations, excluding the maintenance expenditures, by approximately $0.2 million to $0.3 million.

Throughput volumes on Discovery’s pipeline system and our Carbonate Trend pipeline are an important component of maximizing our profitability. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas plant and fractionator, we and Discovery must continually connect new supplies of natural gas.


	•	In 2006, recompletions and workovers may not offset production declines from the wells currently connected to the Carbonate Trend pipeline.

	•	Throughput from the TGP and TETCO open season volumes declined through the first quarter of 2006. Discovery is discussing retaining some of this gas on a long-term basis, and will compete with several other plants in the area for this business.

	•	We anticipate lower gathered volumes from Discovery’s pre-hurricane sources throughout 2006. The 2005 hurricanes caused a significant disruption in our customers’ normal operations, including critical recompletion and drilling activity necessary to sustain and improve their production levels.

	•	With the current oil and natural gas price environment, drilling activity across the shelf and the deepwater of the Gulf of Mexico has been robust. However, the availability of specialized rigs necessary to drill in the deepwater areas, such as those in and around Discovery’s gathering areas, limits producers’ ability to bring identified reserves to market quickly. This will prolong the


		timeframe over which these reserves will be developed. We expect Discovery to be successful in competing for a portion of these new volumes.

	•	Discovery connected a new well in ATP’s Gomez prospect in March 2006. Capital to connect this new well was provided by the producers. The initial flow date for this connection was delayed due to hurricane repair activities.


	*Results of Operations — NGL Services*

The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our undivided 50% interest in the Conway fractionator.


		Years Ended December 31,

		2003		2004		2005

		($ in thousands)
Segment revenues		$	22,781	$	36,143	$	48,254
Costs and expenses:
	Operating and maintenance expense		13,581		18,804		24,397
	Product cost		1,263		6,635		11,821
	Depreciation and accretion		2,507		2,486		2,419
	General and administrative expense — direct		421		535		1,068
	Other, net		507		625		694

Total costs and expenses			18,279		29,085		40,399

Segment profit		$	4,502	$	7,058	$	7,855


	Year Ended December 31, 2005 vs. Year Ended December 31, 2004

Segment revenues increased $12.1 million, or 34%, due primarily to higher product sales, storage and fractionation revenues. The significant components of the increase include the following:


	•	Product sales were $5.0 million higher due primarily to the sale of surplus propane volumes created through our product optimization activities. This increase was partially offset by the related increase in product cost.

	•	Storage revenues increased $5.0 million due primarily to higher average per-unit storage rates for 2005 and higher storage volumes from additional short-term storage leases caused by the reduced demand for propane due to unusually warm temperatures in the early winter months of 2005 and an overall increase in butane storage volumes. The published rate for one-year storage contracts increased 67% on April 1, 2004, primarily reflecting the pass through to customers of increased costs to comply with KDHE regulations. The storage volumes in the remaining quarters of 2004 initially declined due to these higher storage rates. During 2005, the volumes returned to more normal levels.

	•	Fractionation revenues increased $1.7 million due primarily to a 17% increase in the average fractionation rate related to the pass through to customers of increased fuel and power costs and 4% higher volumes in 2005.

	•	Other revenues increased $0.4 million due to increased railcar loadings in 2005.

The following table summarizes the major components of operating and maintenance expense that are discussed in detail below.


		Years Ended December 31,

		2003			2004			2005

		($ in thousands)
Operating and maintenance expense:
	Salaries and benefits	$	2,762		$	2,740		$	2,773
	Outside services and other		3,843			8,240			7,458
	Fuel and power		7,608			8,565			12,538
	Product imbalance expense (income)		(632	)		(741	)		1,628

Total operating and maintenance expense		$	13,581		$	18,804		$	24,397


	•	Outside services and other decreased $0.8 million due to fewer storage cavern workovers in 2005 as compared to 2004. Also our estimated asset retirement obligation for the storage caverns was adjusted in 2005, reducing our operating expense by $0.5 million.

	•	Fuel and power costs increased $4.0 million due primarily to a 33% increase in the average per-unit price for natural gas, which we are generally able to pass through to our customers. Fuel and power costs also include $2.0 million for the amortization of a natural gas purchase contract contributed to us by Williams at the closing of our initial public offering. Please read “— Our Operations — NGL Services Segment — Fractionation Contracts.”

	•	Product imbalance expense increased $2.4 million due primarily to $3.0 million of larger product imbalance valuation adjustments, and $0.6 million other product losses, partially offset by a $1.2 million increase in product optimization gains due to a significantly higher spread between propane and ethane prices in 2005.

Product cost increased $5.2 million, or 78%, directly related to increased sales of surplus propane volumes created through our product optimization activities.

General and administrative expense — direct increased $0.5 million, or 100%, due primarily to increased operational and technical support for these assets.

Segment profit increased $0.8 million, or 11%, due primarily to the $6.7 million higher storage and fractionation revenues and $0.4 million higher other revenues for increased railcar loadings in 2005, partially offset by $5.6 million higher operating and maintenance expense, $0.5 million higher general and administrative expense — direct charges, and $0.2 million decrease in product margin.


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

Revenues increased $13.4 million, or 59%, due primarily to increased product sales and storage revenues. The significant components of the increase consisted of the following:


	•	Product sales were $6.9 million higher primarily due to the sale of surplus propane volumes created through our product optimization activities. Prior to 2003, the sale and purchase activities and related inventory associated with product optimization were conducted by another wholly owned subsidiary of Williams that was sold in 2002. We made no sales of surplus propane until 2004 as we transitioned to conducting these activities and accumulated inventory.

	•	Storage revenues increased $3.7 million due to higher average per-unit storage rates, slightly offset by lower contracted storage volumes. The published rate for one-year storage contracts increased 67% on April 1, 2004 and primarily reflects the pass through of increased costs to comply with KDHE regulations.

	•	During 2004 we began offering product upgrading services for normal butane at our fractionator. This service contributed $1.7 million of fee revenues in 2004.

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 other expenses increased $4.4 million due to new storage cavern workover activity related to KDHE requirements.

	•	Fuel expense increased $1.0 million due to an 18% increase in the average price of natural gas.

Segment profit increased $2.6 million, or 57%, due primarily to higher storage and fractionation revenue of $4.5 million, $1.5 million higher product sales margins and $1.7 million higher other fee revenues, partially offset by $5.2 million higher operating and maintenance expense.


	*Outlook for 2006*

We expect volumes fractionated for our customers at the Conway fractionator to continue averaging 40,000 bpd. Currently, commodity prices in the Mid-Continent region remain strong relative to commodity prices at the Mont Belvieu, Texas market hub, which minimizes the potential for volumes to be redirected to the Mont Belvieu market. We also expect to continue to generate revenue from the blending and segregation of various NGLs.

During the third and fourth quarters of 2005 we experienced a significant increase in storage revenues from short-term contracts. We do not expect this increase to continue because the seasonal increase in retail propane sales began in the first quarter of 2006 and we are nearing the end of the storage contract year. We do not plan to increase storage fees in 2006.

We expect outside service costs to increase in 2006 due to the large number of cavern workovers planned for the first quarter of 2006. We expect outside service costs to continue at these increased levels throughout 2006 and 2007 to ensure that we meet the regulatory compliance requirement to complete cavern workovers before the end of 2008.

Four Corners


	*Introduction*

The Four Corners system gathers and processes approximately 37% of the natural gas produced in the San Juan Basin and connects with the five pipeline systems that transport natural gas to end markets from the basin.

Approximately 40% of the supply connected to the Four Corners system in the San Juan Basin is produced from conventional reservoirs with approximately 60% coming from coal bed reservoirs. Four Corners is currently the only company that owns and operates both major conventional natural gas and coal bed methane gathering, processing and treating facilities.


	*How We Evaluate Four Corners*

Our management uses a variety of financial and operational measures to analyze Four Corners’ performance. These measurements include:


	•	gathering volumes;

	•	processing volumes;

	•	net liquids margin; and

	•	operating and maintenance expenses.

Gathering Volumes. The gathering volumes on the Four Corners system are an important component of maximizing Four Corners’ profitability. Four Corners gathers approximately 37% of the San Juan Basin’s natural gas production at approximately 6,400 receipt points under fee-based contracts.

Processing Volumes. The volumes processed at the Ignacio, Kutz and Lybrook natural gas processing plants are an important measure of Four Corners’ ability to maximize the profitability of these facilities. Four Corners’ natural gas processing plants generate revenues using the following types of contracts:


	•	Keep-whole. Under keep-whole contracts, Four Corners (1) processes natural gas produced by customers, (2) retains some or all of the extracted NGLs as compensation for its services, (3) replaces the Btu content of the retained NGLs that were separated during processing with natural gas it purchases, also known as shrink replacement gas, and (4) delivers an equivalent Btu content of natural gas to customers at the plant outlet. Four Corners, in turn, sells the retained NGLs to a subsidiary of Williams, which serves as a marketer for those NGLs at market prices. For the year ended December 31, 2005, 38% of Four Corners’ processing volumes were under keep-whole contracts.

	•	Percent-of-liquids. Under percent-of-liquids processing contracts, Four Corners (1) processes natural gas produced by customers, (2) delivers to customers an agreed-upon percentage of the extracted NGLs, (3) retains a portion of the extracted NGLs as compensation for its services and (4) delivers natural gas to customers at the plant outlet. Under this type of contract, there is no requirement for Four Corners to replace the Btu content of the retained NGLs that were extracted during processing. Four Corners sells the retained NGLs to a subsidiary of Williams, which serves as a marketer for those NGLs at market prices. For the year ended December 31, 2005, 14% of Four Corners’ processing volumes were under percent-of-liquids contracts.

	•	Fee-based. Under fee-based contracts, Four Corners receives revenue based on the volume of natural gas processed and the per-unit fee charged, and Four Corners retains none of the extracted NGLs. For the year ended December 31, 2005, 13% of Four Corners’ processing volumes were under fee-based contracts.

	•	Fee-based and keep-whole. These contracts have both a per-unit fee component and a keep-whole component. The relative proportions of the fee component and the keep-whole component vary from contract to contract, with the keep-whole component never consisting of more than 50% of the total extracted NGLs. For the year ended December 31, 2005, 35% of Four Corners’ processing volumes were under combined these fee-based and keep-whole contracts.

Under Four Corners’ keep-whole and percent-of-liquids contracts, revenues either increase or decrease as a result of a corresponding change in the market prices of NGLs. Four Corners charges a fee for more than 95% of the gathering and treating services it performs, as well as for approximately 48% of the natural gas it processes. As a result, the majority of the revenues generated by these services are not directly affected by changing commodity prices. However, to the extent a sustained decline in commodity prices realized by the customers of Four Corners results in a decline in their future drilling and development activities and the volumes of gas produced, Four Corners’ revenues would be reduced.

Net Liquids Margin. The net liquids margin is an important measure of Four Corners’ ability to maximize the profitability of its processing operations. Liquids margin is derived by deducting the cost of shrink replacement gas and fuel from the revenue Four Corners receives from the sale of its NGLs. The net liquids margin will either increase or decrease as a result of a corresponding change in the relative market prices of NGLs and natural gas.

Operating and Maintenance Expense. Operating and maintenance expenses are costs associated with the operations of a specific asset. Direct labor, contract services, materials, supplies, rentals, leases and insurance comprise the most significant portion of operating and maintenance expenses. 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 periods during which they are performed.

Product Imbalance Gains and Losses. Additionally, in the course of providing gathering, processing and treating services to its customers, Four Corners realizes over- and under-deliveries of its customers’ products that are reflected in operating and maintenance expense as product imbalance gains and losses. Four

Corners monitors these gains and losses to determine whether they are within industry standards and determine the impact of such gains and losses on Four Corners’ results of operations.


	*Results of Operations*

Our interest in Four Corners will be accounted for using the equity method of accounting. As such, our interest in Four Corners’ net operating results will be reflected as equity earnings in our consolidated statements of operations. Due to the significance that Four Corners’ equity earnings will be to our results of operations, the following discussion addresses in greater detail the results of operations for 100% of the Williams Four Corners Predecessor entity.


		Years Ended December 31,

		2003			2004		2005

		($ in thousands)
Revenues		$	354,134		$	428,223	$	463,203
Costs and expenses, including interest:
	Product cost		91,328			146,328		165,706
	Operating and maintenance		89,783			97,070		104,648
	Depreciation		41,552			40,675		38,960
	General and administrative		24,102			29,566		31,292
	Taxes other than income		6,822			6,790		7,746
	Other, net		11,800			11,238		636

Total costs and expenses			265,387			331,667		348,988

Income before cumulative effect of change in accounting principle			88,747			96,556		114,215
Cumulative effect of change in accounting principle			(330	)		—		(694	)

Net income		$	88,417		$	96,556	$	113,521


	Year Ended December 31, 2005 vs. Year Ended December 31, 2004

Revenues increased $35.0 million, or 8%, due primarily to higher product sales and gathering revenue.

Product sales revenues increased $26.4 million, or 13%, due to:


	•	a $21.5 million increase in the sale of liquids on behalf of third parties. These NGL sales were made on behalf of producers who have Four Corners market their NGLs for a fee in accordance with their contracts. This increase was offset by higher associated product costs of $21.5 million discussed below;

	•	$21.1 million related to 21% higher average NGL sales prices realized for the volumes Four Corners received under its processing contracts;

	•	$3.0 million higher LNG sales; and

	•	$2.9 million higher condensate sales.

These increases were partially offset by $22.1 million related to 18% lower NGL volumes received under Four Corners’ processing contracts. In 2005, a customer exercised an annual option to switch from a keep-whole contract to a fee-based contract, which decreased the NGL volumes that Four Corners retained.

Gathering and processing revenues increased $9.8 million due to $17.1 million higher revenue from a 8% increase in the average gathering and processing rates, partially offset by $7.3 million lower revenue from 3% lower gathering volumes. The average gathering and processing rates increased in 2005 largely as a result of contractual escalation clauses. Most of Four Corners’ gathering contracts include escalation clauses that provide for an annual escalation based on an inflation-sensitive index. One significant gathering agreement is

escalated based on changes in the average price of natural gas. The volume decrease was driven by normal reservoir declines, which were partially offset by new well connects. The overall net decline is related primarily to the slightly steeper decline rate associated with coal bed methane production. Four Corners has historically offset substantially the impact of production declines with new well connects.

Products cost, primarily shrink replacement gas, increased $19.4 million, or 13%, due primarily to the $21.5 million increase from third party customers who elected to have Four Corners market their NGLs and $15.1 million from a 30% increase in the average price of natural gas, partially offset by $17.2 million from 26% lower volumetric shrink requirements from Four Corners’ keep-whole processing contracts resulting from a customer exercising an annual option to switch from a keep-whole contract to a fee-based contract.

Operating and maintenance expense increased $7.6 million, or 8%, due primarily to:


	•	$3.4 million higher materials and supplies and outside services expense related to increased repair and maintenance activity;

	•	$2.8 million higher compressor costs from inflation-indexed escalation clauses in operating and maintenance agreements and additional rental units;

	•	$2.7 million higher natural gas cost related to fuel and system gains and losses; and

	•	$2.9 million other various operating and maintenance expense increases.

Depreciation expense decreased $1.7 million, or 4%, due primarily to the absence of depreciation on assets that were fully depreciated in 2004.

General and administrative expense increased $1.7 million, or 6%, due primarily to an increase in allocated general and administrative expense from Williams. Please read Note 4 of Notes to the Williams Four Corners Predecessor Financial Statements for information pertaining to the methodology used to calculate these allocated general and administrative expenses.

Taxes other than income increased $0.9 million, or 14%, due primarily to increased processing taxes. The State of New Mexico’s average processing tax rate increased 39% between 2004 and 2005. Some, but not all, of Four Corners’ contracts allow Four Corners to recoup these taxes.

Other expense decreased $10.6 million, from $11.2 million in 2004, due primarily to the following 2004 charges that were not present in 2005:


	•	$7.6 million impairment charge for the LaMaquina treating facility in 2004. The LaMaquina treating facility shut down in 2002 and was sold in the first quarter of 2006. Please read Note 5 of Notes to the Williams Four Corners Predecessor Financial Statements for information pertaining to this impairment;

	•	$1.2 million loss on asset dispositions; and

	•	$1.0 million for materials and supplies inventory adjustments.

The cumulative effect of change in accounting principle of $0.7 million in 2005 related to Four Corners’ December 31, 2005 adoption of FIN No. 47. Please read Note 6 of Notes to the Williams Four Corners Predecessor Financial Statements.

Net income increased $17.0 million, or 18%, due primarily to higher gathering and processing revenues of $6.5 million and $3.3 million, respectively, $7.0 million in higher product sales margins on lower NGL sales volumes and lower other expenses of $10.6 million, partially offset by $7.6 million in higher operating and maintenance expenses and $1.7 million higher general and administrative expenses.


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

Revenues increased $74.1 million, or 21%, due primarily to higher product sales, partially offset by lower gathering and processing revenues.

Product sales revenues increased $80.5 million, or 65%, due to:


	•	a $41.8 million increase in the sale of NGLs on behalf of third parties. These NGL sales were made on behalf of producers who have Four Corners market their NGLs for a fee in accordance with their contracts. This increase was offset by higher associated product costs of $41.8 million discussed below;

	•	$28.5 million related to 29% higher average NGL sales prices realized for the volumes Four Corners received under its processing contracts;

	•	$4.9 million related to 5% higher NGL volumes received under Four Corners’ processing contracts;

	•	$4.0 million higher LNG sales; and

	•	$1.3 million higher condensate sales.

Gathering and processing revenues decreased $5.9 million due to $5.0 million lower revenue from a 2% decrease in the average gathering and processing rates and $0.9 million lower revenue from a 3% decrease in average gathered and processed volumes. The decrease in the average rate in 2004 was largely the result of a major new contract with a lower contract rate, partially offset by other contractual escalation clauses.

Product cost, primarily shrink replacement gas, increased $55.0 million, or 60%, due primarily to a $41.8 million increase from third party customers who elected to have Four Corners market their NGLs, $10.2 million from an 18% increase in the average price of natural gas and $4.5 million related to increased LNG and condensate sales.

Operating and maintenance expense increased $7.3 million, or 8%, due primarily to:


	•	$4.4 million higher materials and supplies and outside services expense related to increased repair and maintenance activity; and

	•	$2.7 million higher natural gas cost related to fuel and system gains and losses.

Depreciation expense decreased $0.9 million, or 2%, due primarily to the absence of depreciation on assets that were fully depreciated in 2003.

General and administrative expense increased $5.5 million, or 23%, due primarily to an increase in allocated general and administrative expense from Williams reflecting increased corporate overhead costs within the Williams organization. These increased costs related to various corporate initiatives and Sarbanes-Oxley Act compliance efforts within Williams.

Other expense, net in 2004 includes:


	•	$7.6 million impairment charge for the LaMaquina treating facility;

	•	$1.2 million loss on asset dispositions; and

	•	$1.0 million of materials and supplies inventory adjustments.

Other expense, net in 2003 includes:


	•	$4.1 million impairment charge for the LaMaquina treating facility;

	•	$3.5 million of other asset impairment; and

	•	$4.2 million of contractual settlement accruals.

Please read Note 5 of Notes to the Williams Four Corners Predecessor Financial Statements for information pertaining to the asset impairments.

In 2003, the cumulative effect of change in accounting principle of $0.3 million related to Four Corners’ January 1, 2003 adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” Please read Note 6 of Notes to the Williams Four Corners Predecessor Financial Statements.

Net income increased $8.1 million, or 9%, due primarily to a $25.5 million higher average product sales margins on higher average NGL volumes, partially offset by lower gathering revenue of $4.5 million, higher operating and maintenance expense of $7.3 million and higher general and administrative expense of $5.5 million.


	*Outlook for 2006*


	•	We anticipate that sustained drilling activity, expansion opportunities and production enhancement activities by producers should be sufficient to substantially offset the historical decline in gathered and processed volumes.

	•	Four Corners has realized above average margins at its gas processing plants in recent years, despite volatile natural gas and crude oil markets. We expect unit margins in 2006 to trend downward from the 2005 level of unit margins and towards historical averages. Even with a downward trend, we anticipate that Four Corners’ contract mix and commodity management activities will continue to allow it to realize greater margins relative to industry averages.

	•	We anticipate that operating costs, excluding compression, will increase slightly in 2006. Compression cost increases are dependent upon the extent and amount of additional compression needed to meet the needs of Four Corners’ customers.

	•	Four Corners has not planned any major capital projects for 2006. We estimate that capital expenditures will be approximately $26.2 million for 2006 primarily for well connections and maintenance. We expect Four Corners will fund these capital expenditures with cash generated from operations and capital contributions from its members.

	•	We anticipate that the natural gas fuel cost associated with the operation of the Milagro treating plant will increase due to the expiration, in October 2006, of a below-market natural gas purchase contract with Williams. Please read Note 4 of Notes to the Williams Four Corners Predecessor Financial Statements for information pertaining to this contract.

Financial Condition and Liquidity


	*Outlook for 2006*

Prior to our initial public offering in August 2005, our sources of liquidity included cash generated from operations and funding from Williams. Our cash receipts were deposited in Williams’ bank accounts and all cash disbursements were made from these accounts. Thus, historically our financial statements have reflected no cash balances. Cash transactions handled by Williams for us were reflected in intercompany advances between Williams and us. Following our initial public offering, we maintain our own bank accounts but continue to utilize Williams’ personnel to manage our cash and investments.

We believe we have, or have access, to the financial resources and liquidity necessary to meet future requirements for working capital, capital and investment expenditures, and quarterly cash distributions. We anticipate our 2006 sources of liquidity will include:


	•	the issuance of common units contemplated by this offering;

	•	the issuance of senior notes in a private placement concurrently with this offering;

	•	cash generated from operations;

	•	cash distributions from Discovery;

	•	cash distributions from Four Corners following our planned acquisition of the 25.1% interest;

	•	capital contributions from Williams pursuant to the omnibus agreement; and

	•	borrowings under our credit facilities, as needed.

We anticipate our more significant 2006 capital requirements to be:


	•	acquisition of a 25.1% interest in Four Corners;

	•	maintenance capital expenditures for our Conway assets;

	•	capital contributions to Discovery for its capital expenditure program;

	•	working capital attributable to deferred revenues; and

	•	minimum quarterly distributions to our unitholders.


	Discovery

Prior to our initial public offering, cash distributions from Discovery to its members required unanimous consent and no such distributions were made. Discovery’s limited liability company agreement was amended to provide for quarterly distributions of available cash. We expect future cash requirements for Discovery relating to working capital and maintenance capital expenditures to be funded from cash retained by Discovery at the closing of our initial public offering and from its own internally generated cash flows from operations. Growth or expansion capital expenditures for Discovery will be funded by either cash calls to its members, which requires unanimous consent of the members except in limited circumstances, or from internally generated funds.

Prospectively, Discovery expects to make quarterly distributions of available cash to its members instead of retaining all cash from operations. Accordingly, January 31, 2006, pursuant to the terms of its limited liability company agreement, Discovery made an $11.0 million distribution of available cash to its members. Our 40% share of this distribution was $4.4 million.


	Four Corners

Historically, Four Corners’ sources of liquidity included cash generated from operations and advances from Williams. Four Corners’ limited liability company agreement, as amended effective as of the closing of this offering, provides for the distribution of available cash on at least a quarterly basis. We expect future cash requirements for Four Corners relating to working capital, maintenance capital expenditures and quarterly cash distributions to members to be funded from cash flows internally generated from its operations. Growth or expansion capital expenditures for Four Corners 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.


	Capital Contributions from Williams

Capital contributions from Williams required under the omnibus agreement consist of the following:


	•	Indemnification of environmental and related expenditures for a period of three years (for certain of those expenditures) up to $14.0 million, which includes between $3.4 million and $4.6 million for the restoration activities related to the partial erosion of the Carbonate Trend pipeline overburden by Hurricane Ivan, approximately $3.1 million for capital expenditures related to KDHE-related cavern compliance at our Conway storage facilities, and approximately $1.0 million for our 40% share of Discovery’s costs for marshland restoration and repair or replacement of Paradis’ emission-control flare.

	•	An annual credit for general and administrative expenses of $3.9 million in 2005 ($1.4 million pro-rated for the portion of the year from August 23 to December 31), $3.2 million in 2006, $2.4 million in 2007, $1.6 million in 2008 and $0.8 million in 2009.

	•	Up to $3.4 million to fund our 40% share of the expected total cost of Discovery’s Tahiti pipeline lateral expansion project in excess of the $24.4 million we contributed during September 2005.


	Credit Facilities

On May 20, 2005, Williams amended its $1.275 billion revolving credit facility, which is available for borrowings and letters of credit, to allow us to borrow up to $75 million under the Williams facility. Borrowings under this facility mature on May 3, 2007. Our $75 million borrowing limit under Williams’ revolving credit facility is 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, 2005, letters of credit totaling $378 million had been issued on behalf of Williams and its subsidiaries by the participating institutions under this facility and no revolving credit loans were outstanding. Please read Note 11 of the Notes to Consolidated Financial Statements for additional information regarding the commitment fee we are required to pay, the interest rate on borrowings under this credit facility and the significant financial covenants to which Williams is subject.

If any borrower breaches financial or certain other covenants, the lenders may cause the acceleration of the borrower’s indebtedness and may terminate lending to all borrowers under the credit facility. Additionally, if (i) a borrower were to generally not pay its debts as such debts come due, (ii) a borrower were to make a general assignment for the benefit of its creditors or (iii) proceedings relating to the bankruptcy or receivership of any borrower were to remain unstayed or undismissed for 60 days, then all lending under the credit facility would terminate and all indebtedness outstanding under the credit facility would be accelerated. Williams guarantees our indebtedness under this credit facility. Please read “Risk Factors — Risks Inherent in Our Business — Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings” for information regarding the potential impact on us of restrictions in Williams’ revolving credit facility and in Williams’ public indentures.

We also have a $20 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility will mature on May 3, 2007. Please read Note 11 of the Notes to Consolidated Financial Statements for additional information regarding the commitment fee we are required to pay and the interest rate on borrowings under this credit facility. We are required to reduce all borrowings under our working capital credit facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility. As of December 31, 2005, we had no borrowings outstanding under the working capital credit facility.

At the closing of this offering, Four Corners will enter into a $20 million revolving credit facility with Williams as the lender. The facility is available to fund working capital borrowings and for other purposes. Borrowings under the facility will mature on the third anniversary of the closing of our acquisition of the 25.1% interest in Four Corners. Four Corners will pay a commitment fee to Williams on the unused portion of the credit facility of 0.30 percent annually.

Interest on any borrowings under the Four Corners facility will be calculated based on Four Corners’ 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.


	Senior Notes

Concurrently with this offering, we are offering $150 million in aggregate principal amount of senior notes in a private placement. The senior notes are being offered only to qualified institutional investors and to non-U.S. persons in offshore transactions and initially will not be guaranteed by any of our subsidiaries. In the future in certain instances, some or all of our subsidiaries may be required to guarantee our senior notes.


	*Capital Requirements*

Our 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 our 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 businesses, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities.

We estimate that maintenance capital expenditures for the Conway assets will be approximately $9.0 million for 2006, including approximately $2.3 million to be spent in connection with the installation of wellhead control equipment and well meters and KDHE-related cavern compliance. In the omnibus agreement, Williams agreed to reimburse us for the cost of the wellhead control and well meter expenditures subject to a three-year time limitation from August 23, 2005, the closing date of our initial public offering, and a total dollar limitation of $14 million. Additionally, capital expenditures will include $3.7 million related to workovers that include the installation of cavern liners. The remaining amount consists of various smaller maintenance projects.

We estimate that maintenance capital expenditures for 100% of Discovery will be approximately $2.7 million for 2006. We expect Discovery will fund its maintenance capital expenditures through cash flow from operations.

We estimate that expansion capital expenditures for 100% of Discovery will be approximately $37.6 million for 2006. This amount includes $2.0 million for marshland restoration costs related to the initial construction of the Discovery pipeline, $27.4 million for the ongoing construction of the Tahiti pipeline lateral expansion project, $8.0 million related to a cogeneration project that we expect will have a favorable impact on operating expenses of approximately $1.5 to $2.0 million annually, and $0.2 million for other efficiency projects. We expect Discovery will fund the $2.0 million for marshland restoration through retained cash flow from operations or capital contributions from its members. In either case, our 40% share of marshland restoration costs will be reimbursed by Williams pursuant to the omnibus agreement. We expect Discovery will fund the $27.4 million for the Tahiti pipeline lateral expansion project from the amounts escrowed for this project in September 2005 and capital contributions from its members including approximately $4.0 million of cost that cannot, by agreement, be funded from the escrowed funds. Our 40% share of this $4.0 million cost will be reimbursed by Williams pursuant to the omnibus agreement. Total construction costs of this project are expected to be approximately $69.5 million and we anticipate that the assets will be placed in service in May 2007 with initial production expected in April 2008. We expect Discovery will fund the $8.0 million for the cogeneration project with capital contributions from its members, provided it is approved by the members, including us.


	*Working Capital Attributable to Deferred Revenues*

The storage year for customer contracts at our Conway storage facility runs from April 1 of a year to March 31 of the following year. We typically receive payment for these one-year contracts in advance in April after the beginning of the storage year and recognize the associated deferred revenue over the course of the storage year. We reserve cash throughout the storage year to fund the cost of providing these services. As of December 31, 2005, our deferred storage revenue is $3.4 million.


	*Cash Distributions to Unitholders*

We paid a quarterly distribution of $0.35 per unit ($5.0 million) to common and subordinated unitholders and our general partner on February 14, 2006. We intend to continue making minimum quarterly distributions

of $0.35 per unit to all common and subordinated unitholders throughout 2006 to the extent we have sufficient cash from operations after establishment of cash reserves.


	*Cash Flows*


	Williams Partners L.P.


	Years Ended December 31,

	2003			2004			2005

	($ in thousands)
Net cash provided by operating activities	$	6,664		$	2,703		$	1,893
Net cash used by investing activities		(102,810	)		(1,534	)		(28,088	)
Net cash provided (used) by financing activities		96,166			(1,169	)		33,034

The $0.8 million decrease in net cash provided by operating activities in 2005 as compared to 2004 is due primarily to:


	•	$2.8 million related to trade accounts receivable at August 22, 2005 that were not included in the contribution of net assets to us;

	•	$2.3 million related to decreases in the Conway product imbalance liability largely resulting from settlement activity in the fourth quarter of 2005; and

	•	$1.0 million lower operating income, adjusted for non-cash expenses.

These decreases were largely offset by:


	•	$4.2 million in lower interest expense due to the forgiveness by Williams of advances to our predecessor at the closing of our initial public offering; and

	•	a $1.3 million increase in distributed earnings from Discovery.

The decrease of $3.9 million in net cash provided by operating activities in 2004 as compared to 2003 reflects an increase of $8.3 million in interest expense in 2004 related primarily to the funding of our $101.6 million share of a Discovery cash call discussed below. This decrease in net cash provided by operating activities was partially offset by changes in working capital, including a $2.7 million increase in accounts payable. The increase in accounts payable was due to a $1.6 million accrual for spot ethane purchases in December 2004 and a $1.0 million higher accrual for power costs at the end of 2004 as compared to 2003.

Net cash used by investing activities includes maintenance capital expenditures in our NGL Services segment. In addition, 2005 includes our capital contribution of $24.4 million to Discovery for construction of the Tahiti pipeline lateral expansion project. Net cash used by investing activities in 2003 also includes our predecessor’s $101.6 million capital contribution to Discovery for the repayment of Discovery’s outstanding debt in December 2003.

Net cash provided by financing activities in 2005 includes the cash flows related to our initial public offering on August 23, 2005. These consisted of $100.2 million in net proceeds from the sale of the common and subordinated units, a $58.8 million distribution to Williams and the payment of $4.3 million in expenses associated with our initial public offering. Net cash provided (used) by financing activities for 2004 and 2005 also includes the pass through of $1.2 million and $3.7 million, respectively, of net cash flows to Williams prior to August 23, 2005, under its cash management program. Following the closing of our initial public offering on August 23, 2005, we no longer participate in Williams’ cash management program, and our net cash flows no longer pass through to Williams. The 2005 period also includes $2.1 million of distributions paid to unitholders and $1.6 million in indemnifications and reimbursements received from Williams pursuant to the omnibus agreement.

Net cash provided by financing activities in 2003 includes advances from Williams to fund our $101.6 million share of a Discovery cash call discussed below. The remaining 2003 financing cash flows

represent the pass through of our net cash flows to Williams under its cash management program as described above.


	Discovery — 100%


	Years Ended December 31,

	2003			2004			2005

	($ in thousands)
Net cash provided by operating activities	$	44,025		$	35,623		$	30,814
Net cash used by investing activities		(12,073	)		(39,115	)		(65,997	)
Net cash provided by financing activities		409			—			1,339

Net cash provided by operating activities decreased $4.8 million in 2005 as compared to 2004 due primarily to expenditures incurred for repairs following Hurricane Katrina that have not yet been reimbursed by Discovery’s insurance carrier. The 2005 use of cash related to accounts receivable included a $24.6 million outstanding receivable from a subsidiary of Williams for the marketing activities associated with the TGP and TETCO open seasons discussed under “— Recent Events”; this was offset by a similar change in accounts payable for a balance due to the shippers on TGP and TETCO. The 2005 use of cash related to accounts receivable also included other increases in customers’ outstanding balances of $8.6 million. The 2005 source of cash related to accounts payable also included a $7.7 million imbalance with a customer.

Net cash provided by operating activities decreased $8.4 million in 2004 as compared to 2003 due primarily to the favorable impact in 2003 of improved accounts receivable collections. Working capital levels remained more constant in 2004 as compared to 2003. As a result, net cash provided by operating activities in 2004 did not include significant amounts from changes in working capital and reflected the return to more normal levels.

During 2005, net cash used by investing activities included $44.6 million to fund escrow accounts for the Tahiti pipeline lateral project and related interest income and $21.4 million of capital expenditures for (1) the completion of the Front Runner and market expansion projects, (2) the initial expenditures for the Tahiti project, and (3) the purchase of leased compressors at the Larose processing plant. During 2004, net cash used by investing activities was primarily used for the construction of a gathering lateral to connect our pipeline system to the Front Runner prospect. During 2003, net cash used for investing activities included the $3.5 million purchase of a 12-inch gathering pipeline and $4.5 million of initial capital expenditures incurred for the construction of a gathering lateral to connect to Discovery’s pipeline system to the Front Runner prospect.

During 2005, net cash provided by financing activities included capital contributions from members totaling $48.3 million for the construction of the Tahiti pipeline lateral expansion, the distribution of $43.8 million associated with Discovery’s operations prior to our initial public offering and a $3.2 million quarterly distribution to members in the fourth quarter of 2005. 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.


	Four Corners — 100%


	Years Ended December 31,

	2003			2004			2005

	($ in thousands)
Net cash provided by operating activities	$	122,266		$	134,387		$	156,039
Net cash used by investing activities		(6,581	)		(13,920	)		(27,578	)
Net cash used by financing activities		(115,685	)		(120,467	)		(128,461	)

The $21.7 million increase in net cash provided by operating activities in 2005 as compared to 2004 is due primarily to:


	•	$8.0 million increase in operating income, as adjusted for non-cash expenses; and

	•	$13.8 million in cash provided from changes in working capital related primarily to a change in the shrink replacement gas imbalance from 2004 to 2005.

The increase of $12.1 million in net cash provided by operating activities in 2004 as compared to 2003 was due primarily to:


	•	$9.4 million increase in operating income, as adjusted for non-cash expenses; and

	•	$2.7 million in cash provided from changes in working capital related primarily to a change in accounts payable.

Net cash used by investing activities in 2003, 2004 and 2005 included maintenance capital expenditures of $2.0 million, $1.1 million and $3.2 million, respectively. Additionally, other capital expenditures for 2003, 2004 and 2005 were $6.1 million, $13.0 million and $24.4 million, respectively. These expenditures related primarily to the connection of new wells. Net cash used by investing activities in 2003 was favorably impacted by $1.5 million in proceeds from sales of property, plant and equipment.

Net cash used by financing activities for all periods are distributions of Four Corners’ net cash flows to Williams.


	*Contractual Obligations*

A summary of our contractual obligations as of December 31, 2005, is as follows (in thousands):


		2006		2007-2008		2009-2010		2011+			Total

Notes payable/long-term debt		$	—	$	—	$	—	$	—		$	—
Capital leases			—		—		—		—			—
Operating leases			30		55		10		—			95
Purchase obligations			5,135		2,928		240		120	(a)		8,423
Other long-term liabilities			—		—		—		—			—

	Total	$	5,165	$	2,983	$	250	$	120		$	8,518


(a)	Year 2011 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, 2005, is as follows (in thousands):


		2006		2007-2008		2009-2010		2011+		Total

Notes payable/long-term debt		$	—	$	—	$	—	$	—	$	—
Capital leases			—		—		—		—		—
Operating leases			854		1,712		1,716		4,109		8,391
Purchase obligations(a)			30,807		23,488		—		—		54,295
Other long-term liabilities			—		—		—		—		—

	Total	$	31,661	$	25,200	$	1,716	$	4,109	$	62,686


(a)	With the exception of $3.4 million of 2006 outstanding purchase orders, all other amounts are Tahiti-related expenditures that will be funded from the amounts escrowed for this project in September 2005 and capital contributions from members, including us. Please read “— Financial Condition and Liquidity — Outlook for 2006”.

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, 2005. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by specific price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Regulatory Matters

As of December 31, 2005, Discovery had deferred amounts of $6.0 million relating to retained system gas gains and the over-recovery of lost and unaccounted-for gas on the Discovery system. Please read Note 7 — Rate and Regulatory Matters and Contingent Liabilities — Rate and Regulatory Matters to the Discovery Producer Services LLC Consolidated Financial Statements included herein. Certain shippers challenged Discovery’s right to retain these gains. FERC requested and received from Discovery additional information regarding both lost and unaccounted-for volumes and gas gains. Discovery responded to the information request and on October 31, 2005, FERC accepted the filing and no requests for rehearing were filed. As a result, we recognized the portion of this reserve for the period 2002 through 2004 of $10.7 million in 2005.

Discovery’s natural gas pipeline transportation is subject to rate regulation by FERC under the Natural Gas Act. For more information on federal and state regulations affecting our business, please read “Risk Factors” and “Business — FERC Regulation” elsewhere in this prospectus.

Environmental

Our Conway storage facilities are subject to strict environmental regulation by the Underground Storage Unit within the Geology Section of the Bureau of Water 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 expect 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 in 2004 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.

As of December 31, 2005, we had accrued environmental liabilities of $5.4 million related to four remediation projects at the Conway storage facilities. In 2004, we purchased an insurance policy that covers up to $5.0 million of remediation costs until an active remediation system is in place or April 30, 2008, whichever is earlier, excluding operation and maintenance costs and ongoing monitoring costs, for these four projects to the extent such costs exceed a $4.2 million deductible. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25 million. In the omnibus agreement, Williams agreed to indemnify us for these remediation expenditures to the extent not recovered under the insurance policy, excluding costs of project management and soil and groundwater monitoring, and certain other environmental and related obligations arising out of or associated with the operation of the assets before the closing date of our initial public offering. There is an aggregate cap of $14.0 million on the total amount of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under the environmental insurance policy, subject to a three-year limit from the closing date of our initial public

offering. We estimate that the approximate cost of the project management and soil and groundwater monitoring associated with the four remediation projects at the Conway storage facilities and for which we will not be indemnified will be approximately $200,000 to $400,000 per year following the completion of remediation work. The benefit of the indemnification will be accounted for as a capital contribution to us by Williams as the costs are incurred. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”

In connection with our operations at the Conway facilities, we are required by the KDHE regulations to provide assurance of our financial capability to plug and abandon the wells and abandon the brine facilities we operate at Conway. Williams has posted two letters of credit on our behalf in an aggregate amount of $17.8 million to guarantee our plugging and abandonment responsibilities for these facilities. We anticipate providing assurance in the form of letters of credit in future periods until such time as we obtain an investment-grade credit rating.

In connection with the construction of Discovery’s pipeline, approximately 73 acres of marshland was traversed. Discovery is required to restore marshland in other areas to offset the damage caused during the initial construction. 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, began during 2005 and will cost approximately $2.0 million.

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 were also exposed to the risk of interest rate fluctuations on our intercompany balances with Williams prior to the forgiveness of these balances by Williams in connection with our initial public offering.


	*Commodity Price Risk*

Certain of Discovery’s processing contracts are exposed to the impact of price fluctuations in the commodity markets, including the correlation between natural gas and NGL prices. In addition, price fluctuations in commodity markets could impact the demand for Discovery’s services in the future. Carbonate Trend and our fractionation and storage operations are not directly affected by changing commodity prices except for product imbalances, which are exposed to the impact of price fluctuation in NGL markets. Price fluctuations in commodity markets could also impact the demand for storage and fractionation services in the future. In connection with our initial public offering, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. This physical contract is intended to mitigate the fuel price risk under one of our fractionation contracts which contains a cap on the per-unit fee that we can charge, at times limiting our ability to pass through the full amount of increases in variable expenses to that customer. Currently, approximately 52% of Four Corners’ processing volumes are under keep-whole or percent-of-liquids contracts, and an additional 35% of Four Corners’ processing volumes are under combined keep-whole and fee-based contracts. These contracts are exposed to the impact of price fluctuations in the commodity markets, including the correlation between natural gas and NGL prices. In addition, price fluctuations in commodity markets could impact the demand for Four Corners’ services in the future. We, Discovery and Four Corners do not currently use financial derivatives to manage the risks associated with these price fluctuations.


	*Interest Rate Risk*

Historically, our interest rate exposure was related to advances from Williams to our predecessor. The table below provides information as of December 31, 2004 about our interest rate risk. We had no borrowings and no interest rate risk as of December 31, 2005.


	December 31, 2004

	Carrying		Fair
	Value		Value

	($ in thousands)
Advances from Williams	$	186,024	$	186,024

These advances were due on demand. Prior to the closing of our initial public offering, Williams forgave these advances to our predecessor. The variable interest rate was 7.4% at December 31, 2004.

BUSINESS

Our Partnership

We are a Delaware limited partnership formed by Williams in February 2005, to own, operate and acquire a diversified portfolio of complementary 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. Operations of our businesses are located in the United States and are organized into two reporting segments: (1) Gathering and Processing; and (2) NGL Services. Please read Note 14 of our Consolidated Financial Statements for financial information about our segments.

On April 6, 2006, we entered into an agreement to acquire a 25.1% membership interest in Four Corners from affiliates of Williams. Four Corners owns a 3,500-mile natural gas gathering system, including three natural gas processing plants and two natural gas treating plants, located in the San Juan Basin in Colorado and New Mexico. Please read “Acquisition of Interest in Four Corners.” This is our first acquisition since our initial public offering in August 2005. We intend to acquire additional assets in the future and have a management team dedicated to a growth strategy.

Our current asset portfolio consists of:


	•	a 40% interest in Discovery, which owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to a natural gas processing facility and an NGL fractionator in Louisiana;

	•	the Carbonate Trend natural gas gathering pipeline off the coast of Alabama; and

	•	three integrated NGL storage facilities and a 50% interest in an NGL fractionator near Conway, Kansas.

Discovery provides integrated “wellhead to market” services to natural gas producers operating in the shallow and deep waters of the Gulf of Mexico off the coast of Louisiana. Discovery consists of a 105-mile mainline, 168 miles of lateral gathering pipelines, a natural gas processing plant and an NGL fractionation facility. Discovery has interconnections with five natural gas pipeline systems, which allow producers to benefit from flexible and diversified access to a variety of natural gas markets. The Discovery mainline was placed into service in 1998 and has a design capacity of 600 million cubic feet per day. Additionally, Discovery has recently signed definitive agreements with Chevron, Shell, and Statoil to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. The Tahiti pipeline lateral expansion will have a design capacity of approximately 200 million cubic feet per day, and its anticipated completion date is May 2007 with initial production expected in April 2008.

We are also engaged in NGL storage and fractionation near Conway, Kansas, which is the principal NGL market hub for the Mid-Continent region of the United States. We believe our integrated NGL storage facility at Conway is one of the largest in the Mid-Continent region. These storage facilities consist of a network of interconnected underground caverns that hold large volumes of NGLs and other hydrocarbons and have an aggregate capacity of approximately 20 million barrels. Our Conway storage facilities connect directly with MAPL and the Kinder Morgan NGL pipeline systems and indirectly with three other large interstate NGL pipelines. We also own a 50% undivided interest in the Conway NGL fractionation facility, which is strategically located at the junction of the south, east and west legs of MAPL. This fractionation

facility also benefits from its proximity to other NGL pipelines in the Conway area, and from its proximity to our Conway storage facility. Our share of the fractionator’s capacity is approximately 53,500 barrels per day.

We account for our 40% interest in Discovery as an equity investment, and therefore do not consolidate its financial results. For the year ended December 31, 2005, we generated Adjusted EBITDA Excluding Equity Investments of approximately $10.9 million. In addition, our 40% interest in Discovery generated Adjusted EBITDA of approximately $17.6 million for the year ended December 31, 2005. Please read “Prospectus Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures” for an explanation of our Adjusted EBITDA Excluding Equity Investments and an explanation of Discovery’s Adjusted EBITDA as well as a reconciliation of these measures to our and Discovery’s most directly comparable financial measures, calculated and presented in accordance with GAAP.

Business Strategies


	•	grow through accretive acquisitions of complementary energy assets from third parties, Williams or both, such as our proposed acquisition of a 25.1% interest in Four Corners;

	•	capitalize on expected long-term increases in natural gas production in proximity to Discovery’s pipelines in the Gulf of Mexico;

	•	optimize the benefits of our scale, strategic location and pipeline connectivity serving the Mid-Continent NGL market;

	•	leverage the scale and competitive position of Four Corners’ standing as a leading provider of natural gas gathering, processing and treating services in the San Juan Basin; 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, such as our proposed acquisition of a 25.1% interest in Four Corners;

	•	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 that Williams offers.

Our Relationship with Williams

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 additional acquisitions directly from Williams in the future, we cannot say with any certainty which, if any, of these acquisition opportunities may be made available to us or if we will choose to pursue any such opportunity. In addition, through our relationship with Williams, we will have access to a significant pool of management talent and strong commercial relationships throughout the energy industry. While our relationship with Williams and its subsidiaries is a significant attribute, it is also a source of potential conflicts. For example, Williams is not restricted from competing with us. Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Following this offering, Williams will have a significant interest in our partnership through its ownership of a 38.5% limited partner interest and all of our 2% general partner interest. Additionally, subsidiaries of Williams market substantially all of the NGLs to which Discovery and Four Corners take title and affiliates of Williams have contracts with Four Corners related to processing natural gas and providing waste heat from the Milagro co-generation plant to assist in the operation of the Milagro treating plant.

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 20.4 trillion cubic feet, or Tcf, (55.9 Bcf/d) in 2005 to approximately 21.6 Tcf (59.3 Bcf/d) in 2010, representing an average annual growth rate of over 1.2% per year. By 2010, natural gas is expected to represent approximately 22% of all end-user domestic energy requirements. From 2001 to 2005, the United States has on average consumed approximately 20.7 Tcf per year (56.7 Bcf/d) with average annual domestic production of approximately 19.8 Tcf (54.3 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 61% 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 1.4% per year, on average, to 13.3 Tcf (36.5 Bcf/d) in 2010 from an estimated 12.4 Tcf (34.1 Bcf/d) in 2005.


	*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 approximately 10.6 Bcf/d in 2004. 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.

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, Gulf of Mexico Federal Offshore Production, 2004

According to EIA’s Annual Energy Outlook 2006, 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 11.2 Bcf/d in 2005 to approximately 13.9 Bcf/d in 2015 and deepwater natural gas production in the Gulf of Mexico increasing from approximately 4.9 Bcf/d in 2005 to approximately 8.6 Bcf/d in 2015.


Source:	Energy Information Agency Annual Energy Outlook 2006

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 2006, Mid-Continent natural gas production is projected to remain at levels above 6.5 Bcf/d per year through 2015.


Source:	Energy Information Agency Annual Energy Outlook 2006


	*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 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 treating 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 treating 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 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 in 2003. The mixed NGLs delivered from domestic gas processing plants and crude oil refineries to fractionation facilities are typically transported by NGL pipelines and, to a lesser extent, by railcar and truck.

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.

The following graph shows the total domestic NGL production from 1993 through 2004, 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 2004 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.

Gathering and Processing — 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 approximately 600 MMcf/d on its mainline;

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

	•	a fractionator in Paradis, Louisiana with a current capacity of approximately 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.

Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such. Accordingly, this equity investment is considered part of the Gathering and Processing segment.

Additionally, Discovery signed definitive agreements with Chevron, Shell, and Statoil to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. The Tahiti pipeline lateral expansion is expected to have a design capacity of approximately 200 MMcf/d, and its anticipated completion date is May 2007 with initial production expected in April 2008.

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

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.


	*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.

Transportation and Gathering 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 approximately 60 offshore blocks to Discovery. Each block represents an area of 5,760 square acres. The mainline has a FERC-certificated capacity of approximately 600 MMcf/d.

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The Discovery system connects to five natural gas pipeline systems, two of 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. Additionally, Discovery’s recently completed market expansion project connects Discovery to the following pipeline systems: Tennessee Gas Pipeline, Columbia Gulf Transmission and Transco. Together, these three pipeline systems provide up to an additional 500 MMcf/d of takeaway capacity. 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, Louisiana commenced operations in June 2005 and has a FERC-certificated capacity of approximately 150 MMcf/d. Discovery’s interconnections allow producers to benefit from flexible and diversified access to a variety of natural gas markets from the Gulf of Mexico to the eastern United States.

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 Chevron-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 in the Gulf of Mexico such as the Morpeth prospect, Allegheny prospect and Front Runner prospect. The maximum water depth of these deepwater laterals is approximately 3,200 feet. Additionally, Discovery signed definitive agreements to construct a gathering pipeline lateral to connect Discovery’s existing pipeline system to certain producers’ production facilities for the Tahiti prospect described above. None of Discovery’s deepwater laterals are regulated by FERC.


	*Larose Gas Processing Plant*

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 approximately 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

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handling facilities and upon separation and stabilization, through Discovery’s ten-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.


	*Paradis Fractionation Facility*

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 2005, Discovery fractionated an average of approximately 9,600 bpd of mixed NGLs. All products can be delivered through the Chevron 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 typically 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 excess 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 Management*

Discovery is currently owned 40% by us, 20.0% by Williams and 40.0% by Duke Energy Field Services. Williams is the operator of the Discovery assets. Discovery is managed by a three member management committee consisting of representation from each of the three owners. The members of the management committee 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.”


	*Discovery Customers and Contracts*

Customers. 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. Five offshore producer customers accounted for approximately 21% of Discovery’s revenues in 2005. No customer accounted for over 10% of Discovery’s revenues in 2005. Additionally, a subsidiary of Williams, which markets substantially all of the NGLs and excess natural gas to which Discovery takes title, accounted for approximately 57.7% of Discovery’s revenues in 2005 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 FERC-regulated laterals generate revenues through FERC-regulated tariffs for several types of service — firm transportation service on a commodity basis with reserve dedication, firm transportation service on a commodity basis without reserve dedication to accommodate temporary outages due to Hurricane Katrina, and traditional interruptible transportation service. Discovery also offers another

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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 portfolio of processing 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.


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


	*Gas Supply*

Approximately 60 offshore production blocks are currently dedicated to the Discovery system. Recently connected blocks include Murphy’s Front Runner discovery, Energy Partners’ Rock Creek discovery and Apache’s Tarantula discovery. Additionally, Discovery signed definitive agreements with certain producers to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect described above. Furthermore, 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 Minerals Management Service of

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the U.S. Department of the Interior, or 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.

Gathering and Processing — 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/d. For the year ended December 31, 2005, our average transportation volume was approximately 35 MMcf/d.

Gas is shipped through our pipeline to Shell’s offshore sour gas gathering pipeline and Yellowhammer sour gas treating 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 Chevron’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. The pipeline is operated by Chevron under an operating agreement. 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 Chevron 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 Chevron, which, together with Noble Energy, has large lease positions in the Carbonate Trend area. Chevron and Noble Energy own an interest in more than 30 federal leases in the Carbonate Trend area and Chevron is the operator for the majority of these leases. For the year ended December 31, 2005, volumes from these Chevron leases represented approximately 67% of Carbonate Trend’s total throughput and 74% of Carbonate Trend’s total revenue with volumes from Noble Energy constituting the remainder.

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Contracts. We have long-term transportation agreements with Chevron and Noble Energy. Pursuant to these agreements, Chevron and Noble Energy have agreed to transport on our pipeline all 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 Chevron and Noble Energy expire or the underlying reserves are depleted, Chevron 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 Chevron and Noble Energy may make an annual election to utilize capacity along a segment of Transco. When Chevron or Noble Energy utilize this capacity, our per-unit gathering fee is determined by subtracting FERC tariff-based rate charged by Transco for this capacity from the total negotiated fee. If these customers elect not to utilize the capacity along this segment of Transco, we can make no assurance that this capacity will 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*

Chevron developed the Viosca Knoll Carbonate Trend area in the shallow waters of the Mobile and Viosca Knoll areas in the eastern Gulf of Mexico. Chevron has filed several 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 customers’ sour gas, we believe that we can construct pipeline connections to access either of two third party-owned treating facilities also located in Coden, Alabama.

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NGL Services — 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.

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. These facilities have a total brine pond capacity of approximately 13 million barrels.

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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 additional end-use interstate NGL pipelines: the Kaneb pipeline and the ONEOK 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 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 has an aggregate storage capacity of approximately ten million barrels.

Conway East. The Conway East facility is located approximately four miles east of the Conway West facility in McPherson County, Kansas. 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 has an aggregate storage capacity of approximately five million barrels.


	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 65% of our storage revenues in 2005, are SemStream, Enterprise and ONEOK. Enterprise is an NGL pipeline operator, ONEOK 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 ONEOK. 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 on 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 in 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

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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.


	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 ONEOK-owned facility in Hutchinson, Kansas and an Enterprise Products Partners-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. 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 ONEOK 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 Buckeye Partners, L.P. 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 ONEOK 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 are the operator of the facility pursuant to an operating agreement that extends until May 2011.

We primarily fractionate NGLs for third party customers for a fee based on the volumes of mixed NGLs fractionated. The per-unit fee 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 our initial public offering, Williams transferred to us a contract for the purchase of a sufficient quantity of natural gas from a

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wholly owned subsidiary of Williams at a price not to exceed a specified 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 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 64% of our NGL fractionation capacity at the Conway facility for the year ended December 31, 2005. 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 the Buckeye Partners, L.P. 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. BP accounted for approximately 13.5%, 16.1% and 24.6% of our total revenue in 2005, 2004 and 2003, respectively. 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. Pursuant to the terms of this agreement, we provided notice of termination to BP in July 2005.

Another long-term contract requires a customer to deliver all of the mixed NGLs that customer purchases from Pioneer’s Texas Panhandle and southwestern Kansas 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 the customer 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. The customer’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 fractionated products in each region. Deliveries of mixed NGL products under this agreement have remained consistent during the term of this agreement. This 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 ONEOK-owned fractionator located in Medford, Oklahoma, a ONEOK-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.

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An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. Other 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 Buckeye Partners, L.P. 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 ten 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 $1.7 million between 2006 and 2008 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.

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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 compliance with applicable permit requirements, we completed a survey of portions of our Carbonate Trend pipeline. As a result of this survey, we have determined that it will be necessary for us to undertake certain restoration activities to repair the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004. We estimate that the cost of these restoration activities will be between $3.4 and $4.6 million and that they will be completed by the end of 2006. In the omnibus agreement, Williams agreed to reimburse us for the cost of these restoration activities. 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, 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, 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, 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

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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.

The Discovery 105-mile mainline, approximately 60 miles of laterals and its market expansion project are subject to regulation by FERC. 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 may 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 issued in July 2004 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 upheld, among other things, FERC’s determination that certain rates of an interstate petroleum products pipeline, SFPP, L.P., or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the portion of FERC’s decision applying the Lakehead policy. In its Lakehead decision, FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005, FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which it stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. In December 2005, FERC issued its first case-specific oil pipeline review of the income tax allowance issue in the SFPP proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary for

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the pipeline to determine its income allowance. FERC’s BP West Coast remand decision and the new tax allowance policy have been appealed to the D.C. Circuit, and rehearing requests have been filed with respect to the December 2005 order. Therefore, the ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service. If FERC were to disallow a substantial portion of 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.

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, 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 in 2004. 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 shared 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 filed for additional limited waivers from Order No. 2004 compliance on May 6, 2005 requesting a limited waiver to permit three Duke Energy Field Services (“DEFS”) employees to be shared between Discovery and DEFS and to provide information necessary for DEFS to carry out its responsibilities as an owner of Discovery. FERC has not yet acted on this filing.

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.

On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (“EP Act 2005”). Among other matters, EP Act 2005 amends the Natural Gas Act (“NGA”) to add an antimanipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and provides FERC with additional civil penalty authority. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the antimanipulation provision of EP Act 2005, and

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subsequently denied rehearing. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of interstate gas pipelines as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. EP Act 2005 also amends the NGA to give FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. The antimanipulation rule and enhanced civil penalty authority reflect an expansion of the FERC’s NGA enforcement authority. FERC has not yet taken action pursuant to this enhanced authority.


	*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, treating 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.

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.

In the omnibus agreement, Williams agreed to indemnify us in an aggregate amount not to exceed $14.0 million, including any amounts recoverable under our insurance policy covering remediation costs and

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unknown claims at Conway, generally for three years after the closing of our initial public offering in August 2005, for certain environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before the closing date of our initial public offering.


	*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 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

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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.


	*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.”


	*Kansas Department of Health and Environment Obligations*

We currently own and operate underground storage caverns near Conway, Kansas that have been created by solution mining the caverns in the Hutchinson salt formation. These storage caverns are used to store NGLs and other liquid hydrocarbons. These caverns are subject to strict environmental regulation by the Underground Storage Unit within the Bureau of Water, Geology Section of the KDHE under the Underground Hydrocarbon and Natural Gas Storage Program. The current revision of the Underground Hydrocarbon and Natural Gas Storage regulations became effective on April 1, 2003 (temporary) and August 8, 2003 (permanent); these rules regulate 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. The regulations specify several compliance deadlines including the final permit application for existing hydrocarbon storage wells by April 1, 2006, certain equipment requirements no later than April 1, 2008 and mechanical integrity and casing testing requirements by April 1, 2010. 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 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 $1.0 million per year to install a double liner on a brine pond. In response to these increased costs, we raised our storage rates by an amount sufficient to preserve our margins in this

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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.

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. Investigation and delineation of chloride impacts is ongoing at the two Conway area facilities as specified in their respective consent orders. One of these facilities is located near the Groundwater Management District No. 2’s jurisdictional boundary of the Equus Beds aquifer. At the other Conway area facility, remediation of residual hydrocarbon derivatives from a historic pipeline release is included in the consent order required activities.

Although not mandated by any consent order, we are currently cooperating with the KDHE and other area operators in an investigation of fugitive NGLs observed in the subsurface at the Conway Underground East facility. In addition, we have also recently detected fugitive NGLs in groundwater monitoring wells adjacent to two abandoned storage caverns at the Conway West facility. 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, the 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.

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.

Employees

We do not have any employees. We are managed and operated by the directors and officers of our general partner. To carry out our operations, as of December 31, 2005, our general partner or its affiliates employed approximately 36 people who will spend at least a majority of their time operating the Conway and Carbonate Trend facilities and approximately 30 general and administrative full-time equivalent employees in support of these operations. Discovery is operated by Williams pursuant to an operating and maintenance agreement and the employees who operate the Discovery assets are therefore not included in the above numbers. Please read “Management — Management of Williams Partners L.P.” and “Certain Relationships and Related Transactions — Discovery Operating and Maintenance Agreements.”

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, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not 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.

Three members of the board of directors of our general partner 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 have an audit committee of three independent directors that 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. We also have a compensation committee, consisting of three independent members, with the limited function of administering our long-term incentive plan and any future compensation plans. Please read “— Long-Term Incentive Plan.”

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

All of the senior officers of our general partner are also senior officers of Williams and 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, is 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 as of February 28, 2006.


Name	Age		Position with Williams Partners GP LLC

Steven J. Malcolm		57	Chairman of the Board and Chief Executive Officer
Donald R. Chappel		54	Chief Financial Officer and Director
Alan S. Armstrong		43	Chief Operating Officer and Director
James J. Bender		48	General Counsel
Thomas C. Knudson		59	Director and Member of Audit, Conflicts and Compensation Committees
Bill Z. Parker		58	Director and Member of Audit, Conflicts and Compensation Committees
Alice M. Peterson		53	Director and Member of Audit, Conflicts and Compensation Committees
Phillip D. Wright		50	Director

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The directors of our general partner are elected for one-year terms and 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 of our general partner. There are no family relationships among any of the directors or executive officers of our general partner.

Steven J. Malcolm has served as the chairman of the board of directors and chief executive officer of our general partner since February 2005. 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. Mr. Malcolm has served as a member of the board of directors of BOK Financial Corporation since 2002. Mr. Malcolm has been named as a defendant in numerous shareholder class action suits that have been filed against Williams. These class actions include issues related to the spin-off of WilTel Communications, a previously-owned subsidiary of Williams, Williams Power Company, and public offerings in January 2001, August 2001 and January 2002, known as the FELINE PACS offering. Additionally, four class action complaints were filed against Williams, certain committee members and certain members of the Williams board of directors, including Mr. Malcolm, under the Employee Retirement Income Security Act of 1974, or ERISA, by participants in Williams’ Investment Plus Plan. Final court approval of the ERISA litigation and dismissal with prejudice occurred in November 2005.

Donald R. Chappel has served as the chief financial officer and a director of our general partner since February 2005. Mr. Chappel has served as senior vice president and chief financial officer of Williams since April 2003. From 2000 to April 2003, Mr. Chappel 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 has served as the chief operating officer and a director of our general partner since February 2005. Mr. Armstrong has served as a senior vice president of Williams since February 2002 responsible for heading Williams’ midstream business unit. From 1999 to February 2002, Mr. Armstrong was vice president, gathering and processing in Williams’ midstream business unit and from 1998 to 1999 was vice president, commercial development in Williams’ midstream business unit. From 1997 to 1998, Mr. Armstrong was vice president of retail energy in Williams’ energy services business unit. Prior to this, Mr. Armstrong served in various operations, engineering and commercial leadership roles within Williams.

James J. Bender has served as the general counsel of our general partner since February 2005. 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.

Thomas C. Knudson has served as a director of our general partner since November 2005. Mr. Knudson has served as a member of the board of directors of Bristow Group Inc. (formerly Offshore Logistics, Inc.), a leading provider of helicopter transportation services to the oil and gas industry, since January 2004. Mr. Knudson has also served as a director of NATCO Group Inc., a leading provider of wellhead process equipment, systems and services used in the production of oil and gas, since April 2005. From 2000 to 2003, Mr. Knudson was a senior vice president of ConocoPhillips.

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Bill Z. Parker has served as a director of our general partner since August 2005. Mr. Parker has served as a director for Latigo Petroleum, Inc., a privately-held independent oil and gas production company, since January 2003. From April 2000 to November 2002, Mr. Parker served as executive vice president of Phillips Petroleum Company’s worldwide upstream operations. Mr. Parker was executive vice president of Phillips Petroleum Company’s worldwide downstream operations from September 1999 to April 2000.

Alice M. Peterson has served as a director of our general partner since September 2005. Ms. Peterson is the president of Syrus Global, a provider of ethics, compliance and reputation management solutions. Ms. Peterson has served as a director for RIM Finance, LLC, a wholly owned subsidiary of Research In Motion, Ltd., the maker of the BlackBerry^tm handheld device, since 2000. Ms. Peterson served as a director of TBC Corporation, a marketer of private branded replacement tires, from July 2005 to November 2005, when it was acquired by Sumitomo Corporation of America. From 1998 to August 2004, she served as a director of Fleming Companies. From December 2000 to December 2001, Ms. Peterson served as president and general manager of RIM Finance, LLC. From April 2000 to September 2000, Ms. Peterson served as the chief executive officer of Guidance Resources.com, a start-up business focused on providing online behavioral health and concierge services to employer groups and other associations. From 1998 to 2000, Ms. Peterson served as vice president of Sears Online and from 1993 to 1998, as vice president and treasurer of Sears, Roebuck and Co. Following the bankruptcy of Fleming Companies in 2003, Ms. Peterson was named as a defendant, along with each other member of the company’s board of directors, in a securities class action. The case was settled and all claims against Ms. Peterson were released and dismissed after the court’s approval of the settlement which became a final judgment in December 2005. Ms. Peterson has also been named as a defendant, along each other member of the board of directors of Fleming Companies, in connection with a claim by trade creditors of Dunigan Fuels (a subsidiary of the former Fleming Companies) for “conspiracy to breach fiduciary duties.”

Phillip D. Wright has served as a director of our general partner since February 2005. 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, Mr. Wright was senior vice president, enterprise development and planning for Williams’ energy services group. From 1989 to 1996, Mr. Wright 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. Mr. Wright has been named as a defendant in four class action complaints filed under ERISA against Williams, certain members of the benefits and investment committees and certain members of the Williams’ board of directors, by participants in Williams’ Investment Plus Plan. Final court approval of the ERISA litigation and dismissal with prejudice occurred in November 2005.

Executive Compensation

Williams Partners L.P. and our general partner were formed in February 2005. We have no employees. We are managed by the officers of our general partner. We reimburse Williams for direct and indirect general and administrative expenses incurred on our behalf. For the fiscal year ended December 31, 2005, Williams allocated approximately $22,341 of salary and bonus expense to us (and our predecessor for the portion of the year prior to our formation) for Steven J. Malcolm, the chairman of the board and chief executive officer of our general partner, and approximately $27,659 for all other expenses related to his compensation. For the fiscal year ended December 31, 2004, Williams allocated approximately $19,846 of salary and bonus expense to our predecessor for Mr. Malcolm and approximately $14,873 for all other expenses related to his compensation. Allocated expenses related to Mr. Malcolm’s compensation other than salary and bonus included Williams deferred stock awards, matching contributions made under a Williams 401(k) plan and premiums for life insurance. We also allocated a portion of Williams’ expenses related to perquisites which did not exceed $50,000 or 10% of Mr. Malcolm’s salary and bonus from Williams. The foregoing amounts exclude expenses allocated by Williams to Discovery. Total compensation received by Mr. Malcolm, who is

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also the chairman, president and chief executive officer of Williams, will be set forth in the proxy statement for Williams’ 2006 annual meeting of shareholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors — SEC Filings.” No other executive officer of our general partner received salary and bonus compensation allocable to us or our predecessor in excess of $100,000 and no awards were granted to our general partner’s executive officers under the Williams Partners GP LLC Long-Term Incentive Plan in 2004 or 2005.

Employment Agreements

The executive officers of our general partner are also executive officers of Williams. These executive officers do not have employment agreements in their capacity as officers of our general partner.

Compensation of Directors

Members of the board of directors of our general partner who are also officers or employees of our affiliates do not receive additional compensation for serving on the board of directors. Subject to the proration provisions of the policy, members of the board of directors who are not officers or employees of our affiliates (each a “Non-Employee Director”) each receive an annual compensation package consisting of the following: (a) $50,000 cash; (b) restricted units representing limited partnership interests in us valued at $25,000; and (c) $5,000 cash each for service on the conflicts and audit committees of the board. In addition, each Non-Employee Director receives a one-time grant of restricted units valued at $25,000. Restricted units are granted under the Williams Partners GP LLC Long-Term Incentive Plan and vest 180 days after the date of grant. Cash distributions will be paid on the restricted units granted to the Non-Employee Directors. Each Non-Employee Director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. We also reimburse Non-Employee directors for the costs of education programs relevant to their duties as board members.

Long-Term Incentive Plan

In connection with our initial public offering, our general partner adopted the Williams Partners GP LLC 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. To date, the only grants under the plan have been grants of restricted units to Non-Employee Directors. 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 700,000 units. The plan is 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 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*

A restricted unit is a common unit subject to forfeiture prior to the vesting of the award. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of 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 determines the period over which restricted units and phantom units granted to

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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 is 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 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*

The long-term incentive plan permits 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 may 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 not have an exercise price that is less 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. The compensation committee, in its discretion may grant tandem distribution equivalent rights with respect to unit options and unit appreciation rights.

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.

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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 are 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 our initial public offering in August 2005. Please read “Certain Relationships and Related Transactions — Omnibus Agreement.”

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HOW WE MAKE CASH DISTRIBUTIONS

General


	*Rationale for our Cash Distribution Policy*

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it. Our available cash includes cash generated from the operation of our assets and businesses, which include the gathering, transporting and processing of natural gas and the fractionating and storing of NGLs, as described elsewhere in this prospectus. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash on a quarterly basis. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to such tax.


	*Limitations on Our Ability to Make Quarterly Distributions*

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may become subject to limitations and restrictions and may be changed at any time, including:


	•	Our board of directors has broad discretion to establish reserves for the prudent conduct of our business and the establishment of those reserves could result in a reduction in the amount of cash available to pay distributions.

	•	Although our ability to make distributions is not currently restricted under Williams’ revolving credit agreement, Williams’ other debt instruments or our working capital facility with Williams, we or Williams may enter into future debt arrangements that could subject our ability to pay distributions to compliance with certain tests or ratios or otherwise restrict our ability to pay distributions.

	•	Our ability to make distributions of available cash will depend, to a significant extent, on Discovery’s and Four Corners’ ability to make cash distributions to us. In addition, although Discovery’s limited liability company agreement has been, and Four Corners’ limited liability company agreement will be, amended to provide for quarterly distributions of available cash, Discovery and Four Corners have a limited history of making distributions to their respective members. Discovery’s and Four Corners’ management committees, on which we are and will be represented, have broad discretion to establish reserves for the prudent conduct of their respective businesses. The establishment of those reserves could result in a reduction in Discovery’s and Four Corners’ cash available to pay distributions, which could cause a corresponding reduction in the amount of our cash available to pay distributions.

	•	Even if our cash distribution policy is not modified, the amount of distributions we pay and the decision to make any distribution is at the discretion of our general partner, taking into consideration the terms of our partnership agreement.

	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

	•	Although our partnership agreement requires us to distribute our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without approval of nonaffiliated common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units after the subordination period has ended. After this offering, Williams will own approximately 8.9% of the outstanding common units and 100% of the outstanding subordinated units.


	*Our Cash Distribution Policy May Limit Our Ability to Grow*

Because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. We intend generally to rely upon external financing sources, including borrowings and issuances of debt and equity securities, to fund our acquisition and growth

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capital expenditures. However, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.


	*Discovery’s Cash Distribution Policy*

A substantial portion of our cash available to pay distributions is cash we receive as distributions from Discovery. As in our partnership agreement, Discovery’s limited liability company agreement, as amended, provides for the distribution of available cash on a quarterly basis, with available cash defined to mean, for each fiscal quarter, cash generated from Discovery’s business less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law or any debt instrument or other agreement to which it is a party. Under Discovery’s limited liability company agreement, the amount of Discovery’s quarterly distributions, including the amount of cash reserves not distributed, is determined by the members of Discovery’s management committee representing a majority-in-interest in Discovery. We own a 40% interest in Discovery, and an affiliate of Williams owns a 20.0% interest in Discovery. Discovery’s limited liability agreement may only be amended with the unanimous approval of all its members.


	*Four Corners’ Cash Distribution Policy*

A substantial portion of our cash available to pay distributions will be cash we receive as distributions from Four Corners. Four Corners’ limited liability company agreement, as amended effective as of the closing of this offering, provides for the distribution of available cash at least quarterly, with available cash defined to mean, for each fiscal quarter, cash generated from Four Corners’ business less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law or any debt instrument or other agreement to which it is a party. Under Four Corners’ limited liability company agreement, the amount of Four Corners’ quarterly distributions, including the amount of cash reserves not distributed, will be determined by the members of Four Corners’ management committee representing a majority-in-interest in Four Corners. We will own a 25.1% interest in Four Corners, and an affiliate of Williams will own a 74.9% interest in Four Corners. Four Corners’ limited liability agreement may only be amended with the unanimous approval of all its members.

Operating Surplus and Capital Surplus


	*Overview*

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.


	*Definition of Available Cash*

We define available cash in the glossary, and it generally means, for each fiscal quarter all cash on hand at the end of the quarter:


	•	less the amount of cash reserves established by our general partner to:


	—	provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);

	—	comply with applicable law, any of our debt instruments or other agreements; or

	—	provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;


	•	plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our working capital facility with Williams and in all cases are used solely for working capital purposes or to pay distributions to partners.

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	*Definition of Operating Surplus*

We define operating surplus in the glossary, and for any period it generally means:


	•	our cash balance of $12.8 million on the closing date of our initial public offering, excluding amounts retained from the proceeds of our initial public offering to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project; plus

	•	$10.0 million; plus

	•	all of our cash receipts after the closing of our initial public 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 our initial public offering (including the repayment of working capital borrowings, but not the repayment of other borrowings) and maintenance capital expenditures (including capital contributions to Discovery to be used by Discovery for maintenance capital expenditures); less

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

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition and Liquidity.”

Because operating surplus is a cash accounting concept, the benefit that we receive from our gas purchase contract with a subsidiary of Williams and the partial credit for general and administrative expenses and other reimbursements we receive from Williams under the omnibus agreement will be part of our operating surplus.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $10.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus.


	*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.

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Subordination Period


	*Overview*

During the subordination period, which we define below and in the glossary, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.35 per quarter, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.


	*Definition of Subordination Period*

We define the subordination period in the glossary. Except as described below under “— Early Termination of Subordination Period,” the subordination period will extend until the first day of any quarter beginning after June 30, 2008 that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted basis and the related distribution on the 2% general partner interest during those periods; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

If the unitholders remove our general partner without cause, the subordination period may end early.


	*Early Termination of Subordination Period*

The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis if each of the following occurs:


	•	distributions of available cash from operating surplus on each outstanding common unit and subordinated unit equaled or exceeded $2.10 (150% of the annualized minimum quarterly distribution) for any four-quarter period immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) generated during any four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.10 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units on a fully diluted basis; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.


	*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

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	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.


	*Effect of Expiration of the Subordination Period*

Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:


	•	the subordination period will end and each subordinated unit will immediately convert into one common unit;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.

Distributions of Available Cash from Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	first, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “— Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter, in the manner described in “— Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

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,

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but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

If for any quarter:


	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to our general partner, until each unitholder receives a total of $0.4025 per unit for that quarter (the “first target distribution”);

	•	second, 85% to all unitholders, pro rata, and 15% to our general partner, until each unitholder receives a total of $0.4375 per unit for that quarter (the “second target distribution”);

	•	third, 75% to all unitholders, pro rata, and 25% to our general partner, until each unitholder receives a total of $0.5250 per unit for that quarter (the “third target distribution”); and

	•	thereafter, 50% to all unitholders, pro rata, and 50% to our general partner.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The percentage interests set forth above for our general partner assumes that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders and our general partner up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the unitholders and our general partner in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed additional capital to maintain its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.


			Marginal Percentage Interest in
			Distributions
	Total Quarterly Distribution
	Target Amount		Unitholders			General Partner

Minimum Quarterly Distribution		$0.3500		98	%		2	%
First Target Distribution		up to $0.4025		98	%		2	%
Second Target Distribution		above $0.4025 up to $0.4375		85	%		15	%
Third Target Distribution		above $0.4375 up to $0.5250		75	%		25	%
Thereafter		above $0.5250		50	%		50	%

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Distributions from Capital Surplus


	*How Distributions from Capital Surplus Will Be Made*

We will make distributions of available cash from capital surplus, if any, in the following manner:


	•	first, 98% to all unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price;

	•	second, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.


	*Effect of a Distribution from Capital Surplus*

The partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from our 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 in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to our general partner. The percentage interests shown for our general partner assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

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


	•	the minimum quarterly distribution;

	•	the target distribution levels;

	•	the unrecovered initial unit price; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be convertible into two common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

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


	*Manner of Adjustments for Gain*

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


	•	first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of:


	(1) the unrecovered initial unit price for that common unit;

	(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

	(3) any unpaid arrearages in payment of the minimum quarterly distribution;


	•	third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of:


	(1) the unrecovered initial unit price for that subordinated unit; and

	(2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;


	•	fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to:


	(1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

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	(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 assume that our general partner maintains its 2% general partner interest, that our general partner has not transferred the incentive distribution rights and that we do not issue additional classes of equity securities.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.


	*Manner of Adjustments for Losses*

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:


	•	first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

	•	second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter, 100% to our general partner.

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.

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	*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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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 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 total units to be beneficial owned after this offering is based on 21,006,146 units outstanding. The table assumes that the underwriters’ option to purchase additional units is not exercised. The address for the beneficial owners listed below is One Williams Center, Tulsa, Oklahoma 74172-0172.


			Percentage of					Percentage of
	Common		Common			Subordinated		Subordinated			Percentage of
	Units		Units			Units		Units			Total Units
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner	Owned		Owned			Owned		Owned			Owned

The Williams Companies, Inc.(1)		1,250,000		8.9	%		7,000,000		100.0	%		39.3	%
Williams Energy Services, LLC(1)		821,761		5.9			4,601,861		65.7			25.8
Williams Energy, L.L.C.		447,308		3.2			2,504,925		35.8			14.1
Williams Discovery Pipeline LLC		215,980		1.5			1,209,486		17.3			6.8
Williams Partners Holdings LLC		428,239		3.1			2,398,139		34.3			13.5
MAPCO Inc.(1)		447,308		3.2			2,504,925		35.8			14.1
Steven J. Malcolm(2)		25,100		*			—		—			*
Donald R. Chappel		10,000		*			—		—			*
Alan S. Armstrong		10,000		*			—		—			*
James J. Bender		2,000		*			—		—			*
Thomas C. Knudson(3)		1,494		*			—		—			*
Bill Z. Parker(3)		7,326		*			—		—			*
Alice M. Peterson(3)		2,326		*			—		—			*
Phillip D. Wright		2,000		*			—		—			*
All directors and executive officers as a group (8 persons)		60,246		*			—		—			*


	*	Less than 1%.


(1)	As noted in the Schedule 13D filed with the SEC on September 2, 2005, The Williams Companies, Inc. is the ultimate parent company of Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Discovery Pipeline LLC and Williams Partners Holdings LLC and may, therefore, be deemed to

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beneficially own the units held by Williams Energy Services, LLC, Williams Energy, L.L.C., 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, as amended. Williams Energy Services, LLC is the record owner of 158,473 common units and 887,450 subordinated units and, as the sole stockholder of MAPCO Inc. and the sole member of Williams Discovery Pipeline LLC, may, pursuant to Rule 13d-3, be deemed to beneficially own the units beneficially owned by MAPCO Inc. and Williams Discovery Pipeline LLC. MAPCO Inc., as the sole member of Williams Energy, L.L.C., may, pursuant to Rule 13d-3, be deemed to beneficially own the units held by Williams Energy, L.L.C.


(2)	Represents units beneficially owned by Mr. Malcolm that are held by the Steven J. Malcolm Revocable Trust.

(3)	Includes unvested restricted units granted pursuant to the Williams Partners GP LLC Long-Term Incentive Plan which may be voted by the grantees as follows: Mr. Knudson, 1,494; Mr. Parker, 2,326; and Ms. Peterson, 2,326.

The following table sets forth, as of February 28, 2006, the number of shares of common stock of Williams owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.


			Shares				Percentage of
			Underlying		Total Shares of		Total Shares
	Shares of		Options		Common		of Common
	Common Stock		Exercisable		Stock		Stock
	Owned Directly		Within		Beneficially		Beneficially
Name of Beneficial Owner	or Indirectly(1)		60 Days(2)		Owned		Owned

Alan S. Armstrong		88,975		13,333		102,308		*
James J. Bender		126,334		13,333		139,667		*
Donald R. Chappel		223,731		118,333		342,064		*
Steven J. Malcolm		670,210		75,000		745,210		*
Bill Z. Parker		—		—		—		—
Alice M. Peterson		—		—		—		—
Thomas C. Knudson		—		—		—		—
Phillip D. Wright		172,631		13,333		185,964		*
All directors and executive officers as a group (8 persons)		1,281,881		233,332		1,515,213		*


	*	Less than 1%.


(1)	Includes shares held under the terms of incentive and investment plans as follows: (a) Mr. Armstrong — 14 shares in The Williams Companies Investment Plus Plan, 68,660 deferred shares and 20,301 beneficially owned shares; (b) Mr. Bender — 3,000 shares owned by children, 68,600 deferred shares and 54,674 beneficially owned shares; (c) Mr. Chappel — 141,608 deferred shares of which 50,000 vest on April 16, 2006 and 82,123 beneficially owned shares; (d) Mr. Malcolm — 44,623 shares in The Williams Companies Investment Plus Plan, 374,758 deferred shares and 250,829 beneficially owned shares; and (e) Mr. Wright — 14,742 shares in The Williams Investment Plus Plan, 68,660 deferred shares and 89,229 beneficially owned shares.

(2)	The shares indicated represent stock options granted under Williams’ current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 28, 2006. Shares subject to options cannot be voted.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

After this offering, our general partner and its affiliates will own 1,250,000 common units and 7,000,000 subordinated units representing a 38.5% 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 made or to be made by us to our general partner and its affiliates in connection with the 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.

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 1,250,000 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 “How We Make Cash Distributions — Incentive Distribution Rights” for more information regarding the incentive distribution rights.

Payments to our general partner and its affiliates		Our general partner does not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines 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 affiliates of Williams have entered into or will enter into the various documents and agreements that effected our formation transactions and will effect our acquisition of the interest in Four Corners, including the vesting of assets in, and the assumption of liabilities

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by, us and our subsidiaries, and the application of the proceeds of our initial public offering and this offering. These agreements are not and will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, are not and 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 $4.3 million of transaction expenses incurred in connection with our formation transactions, including the expenses associated with vesting assets into our subsidiaries, were paid from the proceeds of our initial public offering. In addition, all of the transaction expenses incurred in connection with our acquisition of the interest in Four Corners will be paid from the proceeds of this offering.

Omnibus Agreement

Upon the closing of our initial public offering, we entered into an omnibus agreement with Williams and its affiliates that governs 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;

	•	reimbursement for certain expenditures; and

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


	*General and Administrative Expenses*

Williams will provide us with a five-year partial credit for general and administrative, or G&A, expenses incurred on our behalf. For 2005, the amount of this credit was $3.9 million on an annualized basis but was pro rated from the closing of our initial public offering in August 2005 through the end of the year. In 2006, the amount of the G&A credit will be $3.2 million, and the amount of the credit will decrease by $800,000 for each subsequent year. As a result, after 2009, we will no longer receive any credit and will be required to reimburse Williams for all of the general and administrative expenses incurred on our behalf.


	*Indemnification for Environmental and Related Liabilities*

Williams agreed to indemnify us after the closing of our initial public offering against certain environmental and related liabilities arising out of or associated with the operation of the assets before the closing date of our initial public offering. These liabilities include both known and unknown environmental and related liabilities, including:


	•	remediation costs associated with the KDHE Consent Orders and certain fugitive NGLs associated with our Conway storage facilities;

	•	the costs associated with the installation of wellhead control equipment and well meters at our Conway storage facility;

	•	KDHE-related cavern compliance at our Conway storage facility; and

	•	the costs relating to the restoration of the overburden along our Carbonate Trend pipeline in connection with erosion caused by Hurricane Ivan in September 2004.

Williams will not be required to indemnify us for any project management or monitoring costs. This indemnification obligation will terminate three years after the closing of our initial public offering, except in the case of the remediation costs associated with the KDHE Consent Orders which will survive for an unlimited period of time. There is an aggregate cap of $14.0 million on the amount of indemnity coverage, including any amounts recoverable under our insurance policy covering those remediation costs and unknown claims at Conway. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental.” In addition, we are not entitled to indemnification until the aggregate amounts of claims exceed $250,000. Liabilities resulting from a change of law after the closing of our initial public offering are excluded from the environmental indemnity by Williams for the unknown environmental liabilities.

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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 in connection with our initial public offering are located and failure to obtain certain consents and permits necessary to conduct our business that arise within three years after the closing of our initial public offering; and

	•	certain income tax liabilities attributable to the operation of the assets contributed to us in connection with our initial public offering prior to the time they were contributed.


	*Reimbursement for Certain Expenditures Attributable to Discovery*

Williams has agreed to reimburse us for certain capital expenditures, subject to limits, including for certain “excess” capital expenditures in connection with Discovery’s Tahiti pipeline lateral expansion project. We expect the cost of the Tahiti pipeline lateral expansion project will be approximately $69.5 million, of which our 40% share will be approximately $27.8 million. Williams will reimburse us for the excess (up to $3.4 million) of our 40% share of the total cost of the Tahiti pipeline lateral expansion project above the amount of the required escrow deposit ($24.4 million) attributable to our 40% interest in Discovery. Williams will reimburse us for these capital expenditures upon the earlier to occur of a capital call from Discovery or Discovery actually incurring the expenditure.


	*Intellectual Property License*

Williams and its affiliates granted a license to us for the use of certain marks, including our logo, for as long as Williams controls our general partner, at no charge.


	*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 is not 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.

Credit Facilities


	*Working Capital Facility*

At the closing of our initial public offering in August 2005, we entered into a $20 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. Borrowings under the facility will mature on May 3, 2007 and 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 — Financial Condition and Liquidity — Credit Facilities.”

We are required to reduce all borrowings under our working capital credit facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility.


	*Williams Revolving Credit Facility*

In addition, we 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 — Financial Condition and Liquidity — Credit Facilities,” and “Risk Factors — Risks Inherent in Our Business — Williams’ revolving credit facility and Williams’ public indentures contain financial and

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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.”


	*Four Corners Credit Facility*

At the closing of this offering, Four Corners will enter into a $20 million revolving credit facility with Williams as the lender. The facility is available to fund working capital borrowings and for other purposes. Borrowings under the facility will mature on the third anniversary of the closing of our acquisition of a 25.1% interest in Four Corners. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition and Liquidity — Credit Facilities” for additional information regarding the commitment fee Four Corners will be required to pay and the rate on the borrowing under this credit facility.

Discovery Limited Liability Company Agreement

We, an affiliate of Williams and Duke Energy Field Services have entered into an amended and restated limited liability company agreement for Discovery Producer Services LLC. This agreement governs the ownership and management of Discovery and provides for quarterly distributions of available cash to the members. The amount of any such distributions is determined by majority approval of Discovery’s management committee, which consists of representatives from each of the three owners. In addition, to the extent Discovery requires working capital in excess of applicable reserves, the Williams affiliate that is a Discovery member (Williams Energy, L.L.C.) must make capital advances to Discovery up to the amount of Discovery’s two most recent prior quarterly distributions of available cash, but Discovery must repay these advances before it makes any future distributions. In addition, the owners are required to offer to Discovery all opportunities to construct pipeline laterals within an “area of interest.”

Discovery Operating and Maintenance Agreements

Discovery is party to three operating and maintenance agreements with Williams: one relating to Discovery Producer Services LLC, one relating to Discovery Gas Transmission LLC and another relating to the Paradis Fractionation Facility and the Larose Gas Processing Plant. Under these agreements, 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 fee to cover the cost of accounting services, computer systems and management services provided to Discovery under each of these agreements. 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.

Gas Purchase Contract

Upon the closing of our initial public offering, an affiliate of Williams transferred to us a contract for the purchase of a sufficient quantity of natural gas from a wholly owned subsidiary of Williams at a price not to exceed a specified price to satisfy our fuel requirements under this fractionation contract. The fair value of this gas purchase contract was an equity contribution to us by Williams. This gas purchase contract terminates on December 31, 2007. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Our Operations — NGL Services Segment — Fractionation Contracts.”

Natural Gas and NGL Marketing Contracts

Certain subsidiaries of Williams markets substantially all of the NGLs and excess natural gas to which Discovery, our Conway fractionation and storage facility and Four Corners take title. Discovery, our Conway fractionation and storage facility and Four Corners conduct the sales of the NGLs and excess natural gas to which they take title pursuant to a base contract for sale and purchase of natural gas and a natural gas liquids master purchase, sale and exchange agreement. These agreements contain the general terms and conditions governing the transactions such as apportionment of taxes, timing and manner of payment, choice of law and

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confidentiality. Historically, the sales of natural gas and NGLs to which Discovery, our Conway fractionation and storage facility and Four Corners take title have been conducted at market prices with certain subsidiaries of Williams as the counter parties. Additionally, Discovery, our Conway fractionation and storage facility and Four Corners may purchase natural gas to meet their fuel and other requirements and our Conway storage facility may purchase NGLs as needed to maintain inventory balances.

Purchase and Sale Agreement

On April 6, 2006, we entered into a Purchase and Sale Agreement with Williams Energy Services, LLC, Williams Field Services Group, LLC, Williams Field Services Company, LLC, our general partner and Williams Partners Operating LLC. Pursuant to the Purchase and Sale Agreement, we will acquire a 25.1% membership interest in Four Corners in exchange for aggregate consideration of $360 million. Four Corners owns gathering, processing and treating assets in the San Juan Basin in New Mexico and Colorado. In connection with the transactions contemplated by the Purchase and Sale Agreement, we will contribute the 25.1% interest in Four Corners to Williams Partners Operating. Please read “Acquisition of Interest in Four Corners” for more information on Four Corners.

Four Corners Limited Liability Company Agreement

In connection with the closing of our acquisition of a 25.1% interest in Four Corners, Williams Field Services Company, LLC and Williams Partners Operating LLC will enter into an amended and restated limited liability company agreement for Four Corners. This agreement will govern the ownership and management of Four Corners and provides for distributions of available cash to the members at least quarterly. The amount of any such distributions will be determined by unanimous approval of Four Corners’ management committee, which consists of representatives from each of the two owners. Williams Field Services Company will be the operator of Four Corners. Under the limited liability company agreement, Four Corners will be required to reimburse Williams Field Services Company for all direct and indirect expenses it incurs or payments it makes on behalf of Four Corners and all other expenses allocable to Four Corners or otherwise incurred by Williams Field Services Company in connection with operating Four Corners’ business. Williams Field Services Company shall determine the expenses that are allocable to Four Corners in good faith.

Treating and Processing Contracts

Four Corners maintains two contracts with an affiliate, a gas gathering and treating contract and a gas gathering and processing contract. Pursuant to the gas gathering and treating contract, Four Corners gathers and treats coal seam gas delivered by the affiliate to Four Corners’ gathering systems. Deliveries of gas under this agreement averaged approximately 34 MMcf/d during 2003, 39 MMcf/d during 2004 and 42 MMcf/d during 2005. The term of this agreement expires on December 31, 2022, but will continue thereafter on a year-to-year basis subject to termination by either party giving at least six months written notice of termination prior to the expiration of each one year period. Pursuant to the gas gathering and processing contract, Four Corners gathers and processes conventional gas delivered by the affiliate to Four Corners’ gathering systems. Deliveries of gas under this agreement averaged approximately 101 MMcf/d during 2003, 92 MMcf/d during 2004 and 93 MMcf/d during 2005. The primary term of the agreement ended on March 1, 2004, but it continues to remain in effect on a year-to-year basis subject to termination by either party giving at least three months written notice of termination prior to the expiration of each one-year period.

Waste Heat Contract

Four Corners maintains a contract with two affiliates whereby Williams Power Company, Inc. sells natural gas to Four Corners. Four Corners provides a portion of the purchased natural gas to the other affiliate, Williams Flexible Generation, LLC, who burns the gas at their co-generation plant that produces waste heat that assists in the operation of the Milagro treating plant. Four Corners uses the remainder of the natural gas in connection with various operations at the Milagro plant. Four Corners purchased $30.0 million, $23.3 million and $33.0 million of natural gas from Williams Power Company in 2003, 2004 and 2005,

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respectively. Four Corners provided $8.4 million, $6.6 million and $8.9 million of the purchased natural gas to Williams Flexible Generation in 2003, 2004 and 2005, respectively. The term of the agreement expires on December 31, 2006, or when Williams Flexible Generation and Four Corners are no longer affiliated with each other, whichever occurs earlier. The affiliates have options to extend the agreement through December 31, 2007 and through December 31, 2008.

Balancing Services Contract

Four Corners maintains a balancing services contract with Williams Power Company, Inc. Pursuant to this agreement, Four Corners and Williams Power Company communicate on a daily basis to determine the volumes of natural gas to be moved between gathering systems at established interconnect points to optimize flow. We refer to this activity as crosshauling. The term of this agreement expires on December 31, 2006 or upon six months or more written notice of termination, whichever occurs later.

Summary of Transactions with Williams

In connection with the closing of our initial public offering in August 2005:


	•	we contributed 2,000,000 common units, 7,000,000 subordinated units, a 2% general partner interest and incentive distribution rights to affiliates of Williams in exchange for the interests in our operating subsidiaries and Discovery;

	•	we distributed $58.8 million to affiliates of Williams to reimburse Williams for certain capital expenditures incurred prior to our formation and for the contribution by an affiliate of Williams to one of our operating subsidiaries of a gas purchase contract that provides for the purchase of a sufficient quantity of natural gas from a wholly-owned subsidiary of Williams at a price not to exceed a specified price to satisfy our fuel requirements under a fractionation contract;

	•	we provided $24.4 million to make a capital contribution to Discovery to fund an escrow account in connection with the Tahiti pipeline lateral expansion project; and

	•	Williams forgave $186.0 million in intercompany advances to our predecessor.

In addition, for the year ended December 31, 2005:


	•	we incurred $17.6 million from Williams for direct and indirect expenses incurred on our behalf pursuant to the partnership agreement;

	•	we distributed $1.3 million to affiliates of Williams as quarterly distributions on their common units, subordinated units and 2% general partner interest;

	•	we received from Williams $1.4 million of general and administrative credits pursuant to the omnibus agreement;

	•	Williams indemnified us $0.5 million, primarily for KDHE-required compliance costs, pursuant to the omnibus agreement;

	•	Discovery reimbursed Williams $3.4 million for direct payroll and employee benefit costs pursuant to the operating and maintenance agreements;

	•	Discovery paid Williams $2.2 million for operation and management fees pursuant to the operating and maintenance agreements;

	•	we purchased a gross amount of $22.4 million of natural gas for the Conway fractionator from an affiliate of Williams;

	•	we purchased $15.7 million of NGLs from a subsidiary of Williams based on market pricing;

	•	we sold $13.4 million to a subsidiary of Williams that markets substantially all of the NGLs and excess natural gas to which our Conway fractionation and storage facility takes title; and

	•	Discovery sold $70.8 million to a subsidiary of Williams that markets substantially all of the NGLs and excess natural gas to which Discovery takes title.

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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 to pay distributions 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 “How We Make Cash Distributions — Subordination Period.”

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


	Neither our partnership agreement nor any other agreement requires Williams to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Williams’ directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Williams, which may be contrary to our interests.

Because the officers and certain of the directors of our general partner are also directors and/or officers of Williams, such directors and officers have fiduciary duties to Williams that may cause them to pursue business strategies that disproportionately benefit Williams or which otherwise are not in our best interests.


	*Our general partner is allowed to take into account the interests of parties other than us, such as Williams, in resolving conflicts of interest.*

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. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.


	Our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:


	•	provides that the general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of our partnership;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner 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, as determined by the general

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		partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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


	*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 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, is the principal executive responsible for the oversight of our affairs. Our non-executive directors devote as much time as is necessary to prepare for and attend board of directors and committee meetings.


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

We 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.


	*Common unitholders 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, are not and 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

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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 determines, in good faith, the terms of any of these transactions.

Our general partner and its affiliates 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.


	*Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.*

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into securities of the partnership, and the incurring of any other obligations;

	•	the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

	•	the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets or the merger or other combination of us with or into another person;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of partnership cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

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Please read “The Partnership Agreement — Voting Rights” for information regarding the voting rights of unitholders.


	*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 and neither our general partner nor its affiliates have any obligation to present business opportunities to us.*

Our partnership agreement provides that our general partner is 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. 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. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to the general partner and its affiliates. As a result, neither the general partner nor any of its affiliates have any obligation to present business opportunities to us.

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 as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise would be prohibited by state-law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because 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 and permit our general partner to take into account the

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interests of third parties in addition to our interests when resolving conflicted interests. 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 of the board of directors of our general partner must be:

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

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

		If our general partner does not seek approval from the 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, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any

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		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 affiliates and their officers and directors will not be liable for monetary damages to us, our limited partners 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. Please read “Description of the Common Units — Transfer of Common Units.” 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 to sign our 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 or willful misconduct. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent 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. If you have questions regarding the fiduciary duties of our general partner please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section, “How We Make Cash Distributions” 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. serves 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 against all claims and losses that may arise out of all actions of the transfer agent or its agents or subcontractors for their activities in that capacity, except for any liability due to any gross negligence or willful misconduct of the transfer agent or its agents or subcontractors.


	*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

By transfer of common units or the issuance of common units in a merger or consolidation in accordance with our partnership agreement, each transferee of common units will be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Additionally, each transferee:


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

	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

	•	gives the consents and approvals contained in our partnership agreement.

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 transfers to be recorded on our books and records no less frequently than quarterly.

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. 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 are not 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 $0.35 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 “How We Make Cash Distributions — 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 “How We Make Cash Distributions — 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 “How We Make Cash Distributions — Distributions of Cash Upon Liquidation.”

Limited Voting Rights

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. Our partnership agreement is incorporated by reference as an exhibit to the registration statement of which this prospectus constitutes a part. We will provide prospective investors with a copy of this agreement 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 “How We Make Cash Distributions;”

	•	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 provides 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 the fractionating and storing of 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, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement. 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 such 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, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.


	*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, Louisiana and Alabama. Upon the consummation of the acquisition of the interest in Four Corners, we may also be deemed to conduct business in Colorado and New Mexico. 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 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 Other Disposition of Assets.”

Amendment of the limited liability company agreement of the operating company and other action taken by us as the sole member of our operating company		Unit majority if such amendment or other action would adversely affect our limited partners (or any particular class of limited partners) in any material respect. Please read “— Amendment of the Partnership Agreement — Action Relating to the Operating Company.”

Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution.”

Continuation of our partnership upon dissolution Withdrawal of our general partner		Unit majority. Please read “— Termination and Dissolution.” Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2015 in a manner which would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner.”

Removal of our general partner		Not less than 66²/3 % of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of the general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common

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		units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2015. Please read “— Transfer of General Partner Interest.”

Transfer of incentive distribution rights		Except for transfers to an affiliate or another person as part of our general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, or sale of all or substantially all of its equity interest to, such person, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to June 30, 2015. Please read “— Transfer of Incentive Distribution Rights.”

Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in Our General Partner.”

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities, subject to the limitations imposed by the New York Stock Exchange, for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to our common units.

Upon issuance of additional partnership securities other than upon exercise of the underwriters’ option to purchase additional units, our general partner will have the right, but not the obligation, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain its and its affiliates’ percentage interest, including its interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement


	*General*

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may

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decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.


	*Prohibited Amendments*

No amendment may be made that would:


	(1) enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

	(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) or (2) above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of this offering, our general partner and its affiliates will own approximately 39.3% of the outstanding units.


	*No Unitholder Approval*

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:


	(1) a change in our name, the location of our principal place of business, our registered agent or our registered office;

	(2) the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

	(3) a change that our general partner determines to be necessary or appropriate for us to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we, the operating company nor its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	(4) an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or “plan asset” regulations adopted under ERISA whether or not substantially similar to plan asset regulations currently applied or proposed;

	(5) subject to the limitations on the issuance of additional partnership securities described above, an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities;

	(6) any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	(7) an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

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	(8) any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

	(9) a change in our fiscal year or taxable year and related changes;

	(10) certain mergers or conveyances as set forth in our partnership agreement; or

	(11) any other amendments substantially similar to any of the matters described in clauses (1) through (10) above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:


	•	do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

	•	are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

	•	are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of the partnership agreement or are otherwise contemplated by our partnership agreement.


	*Opinion of Counsel and Unitholder Approval*

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being taxed as an entity for federal income tax purposes in connection with any of the amendments described above under “— No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.


	*Action Relating to the Operating Company*

Without the approval of the holders of units representing a unit majority, our general partner is prohibited from consenting on our behalf, as the sole member of the operating company, to any amendment to the limited liability company agreement of the operating company or taking any action on our behalf permitted to be taken by a member of the operating company, in each case, that would adversely affect our limited partners (or any particular class of limited partners) in any material respect.

Merger, Sale or Other Disposition of Assets

A merger or consolidation of us requires the consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so

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free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In addition, the partnership agreement generally prohibits our general partner, without the prior approval of the holders of units representing a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger or consolidation without the prior approval of our unitholders if our general partner has received an opinion of counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of to the limited partners or result in our being taxed as an entity for federal income tax purposes, we are the surviving entity in the transaction, the transaction would not result in an amendment to our partnership agreement that the could not otherwise be adopted solely by our general partner, each of our units will be an identical unit of our partnership following the transaction, and the units to be issued do not exceed 20% of our outstanding units immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:


	(1) the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

	(2) the entry of a decree of judicial dissolution of our partnership;

	(3) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor; or

	(4) there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law.

Upon a dissolution under clause (3) above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in the partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	none of our partnership, the limited partnership, our operating company nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are

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necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period at time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as the general partner of our partnership prior to June 30, 2015 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2015, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Interest” and “— Transfer of Incentive Distribution Rights” below.

Upon the withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a majority of the outstanding common units and subordinated units, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66²/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and subordinated units, voting as separate classes. The ownership of more than 33¹/3 % of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent the general partner’s removal. At the closing of this offering, our general partner and its affiliates will own 39.3% of the outstanding units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	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 its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general

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partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for their fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest in us to another person prior to June 30, 2015 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all the ownership interests in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to June 30, 2015, other transfers of the incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units (excluding common units held by our general partner and its affiliates). On or after June 30, 2015, the incentive distribution rights will be freely transferable.

Transfer of Ownership Interests in Our General Partner

At any time, the members of our general partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

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Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Williams Partners GP LLC as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	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 its incentive distribution rights into common units or to receive cash in exchange for those interests.

Limited Call Right

If at any time our general partner and its affiliates hold more than 80% of the then-issued and outstanding partnership securities of any class, our general partner will have the right, but not the obligation, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the remaining partnership securities of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:


	(1) the highest price paid by either of our general partner or any of its affiliates for any partnership securities of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those partnership securities; and

	(2) the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding partnership securities, a holder of partnership securities may have his partnership securities purchased at an undesirable time or price. Our partnership agreement provides that the resolution of any conflict of interest that is fair and reasonable will not be a breach of the partnership agreement. Our general partner may, but it is not obligated to, submit the conflict of interest represented by the exercise of the limited call right to the conflicts committee for approval or seek a fairness opinion from an investment banker. If our general partner exercises its limited call right, it will make a determination at the time, based on the facts and circumstances, and upon the advice of counsel, as to the appropriate method of determining the fairness and reasonableness of the transaction. 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 no longer be subject to the reporting requirements of the Securities Exchange Act of 1934.

The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

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Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. In the case of common units held by our general partner on behalf of non-citizen assignees, our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities” above. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, or a person or group who acquire units with the prior approval of the board of our general partner acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as the partnership agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of any common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer is reflected in our books and records.

Except as described above under “— Limited Liability” above, the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner we may redeem the units held by the limited partner at their current market price, in accordance with the procedures set forth in our partnership agreement. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner or assignee fails to furnish information about his nationality, citizenship or other related status within

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30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	(1) our general partner;

	(2) any departing general partner;

	(3) any person who is or was an affiliate of our general partner (including Williams and its subsidiaries) or any departing general partner;

	(4) any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above;

	(5) any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	(6) any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books are maintained for both tax and financial reporting purposes on an accrual basis. For tax and financial reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent registered public accounting firm or make such reports available on the SEC’s Electronic Data Gathering, Analysis, and Retrieval (EDGAR) System. Except for our fourth quarter, we will also furnish or make available on EDGAR summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

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Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand stating the purpose of such demand and at his own expense, obtain:


	(1) a current list of the name and last known address of each partner;

	(2) a copy of our tax returns;

	(3) information as to the amount of cash, and a description and statement of the net agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

	(4) copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

	(5) information regarding the status of our business and financial condition; and

	(6) any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests, could damage us or our business or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Williams Partners GP LLC as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale” beginning on the following page.

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, our general partner and its affiliates will hold, directly and indirectly, an aggregate of 1,250,000 common units and 7,000,000 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period, and some may convert earlier. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three month period, the greater of:


	•	1% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue equity securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

We, our subsidiaries and our general partner and its affiliates, including the directors and executive officers of our general partner have agreed not to sell any common units for a period of 90 days after the date of this prospectus, subject to certain exceptions. Please read “Underwriting — Lock-Up Agreements” for a description of these lock-up provisions.

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MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to our general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Williams Partners L.P. and our operating company.

The following discussion does not address all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs), employee benefit plans or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of the common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Andrews Kurth LLP and are based on the accuracy of the representations made by us and our general partner.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions and advice of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which the common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues:


	•	the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

	•	whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and

	•	whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 2% of our current income is not qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and the operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Andrews Kurth LLP has relied include:


	(a) Neither we nor our operating company have elected nor will elect to be treated as a corporation; and

	(b) For each taxable year, more than 90% of our gross income will be income that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation would be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Andrews Kurth LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Williams Partners L.P. will be treated as partners of Williams Partners L.P. for federal income tax purposes. Also, unitholders whose common units are held in

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street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Williams Partners L.P. for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Items of our income, gain, loss or deduction are not reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Williams Partners L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis in his common units generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including our general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of the non-pro rata portion of that distribution over the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2008, 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 the unitholder with respect to that period. We anticipate that after the taxable year ending December 31, 2008, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things,

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numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when the unitholder disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net earnings may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

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Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as “Contributed Property.” These allocations are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity.” The effect of these allocations to a unitholder purchasing common units in this offering will be essentially the same as if the tax basis of Contributed Property was equal to its fair market value at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) allocations,” similar to the Section 704(c) allocations described above, will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders.

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Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Andrews Kurth LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election,” “— Uniformity of Units” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for tax purposes with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Andrews Kurth LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest effective United States federal income tax rate for individuals is currently 35% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to

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have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury Regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “— Uniformity of Units.”

Although Andrews Kurth LLP is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a basis reduction or a built-in loss is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

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Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year different than our taxable year and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization. We use the tax basis of our assets for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner, its affiliates and our other unitholders as of the time of the offering. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

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Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that

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gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties.

Constructive Termination. We will be considered to have been terminated for 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. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year different from our taxable year, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as

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if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. Our counsel, Andrews Kurth LLP, is unable to opine on the validity of any of these positions. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, regulated investment companies, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from certain permitted sources. The American Jobs Creation Act of 2004 generally treats net income from the ownership of publicly traded partnerships as derived from such a permitted source. We anticipate that all of our net income will be treated as derived from such a permitted source.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold tax at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

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Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Andrews Kurth LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return.

Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names Williams Partners GP LLC as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

	(b) a statement regarding whether the beneficial owner is:


	1. a person that is not a United States person;

	2. a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

	3. a tax-exempt entity;


	(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

	(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

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Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.


	*Accuracy-Related Penalties*

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	(1) for which there is, or was, “substantial authority;” or

	(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules apply to “tax shelters,” but we believe we are not a tax shelter.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-Related Penalties,”

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

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State, Local and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We own property or do business in Kansas, Louisiana and Alabama. We may also own property or do business in other jurisdictions in the future, including Colorado and New Mexico upon the consummation of the acquisition of the interest in Four Corners. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend on, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Andrews Kurth LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

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INVESTMENT IN WILLIAMS PARTNERS L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	•	whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibits employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be fiduciaries of the plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:


	•	the equity interests acquired by employee benefit plans are publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

	•	the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or

	•	there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first bullet point above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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UNDERWRITING

Lehman Brothers Inc. and Citigroup Global Markets Inc. are acting as joint book-running managers and representatives of the underwriters. Under the terms of an underwriting agreement, which is filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units opposite their names below.


		Number of
Underwriters		Common Units

Lehman Brothers Inc.
Citigroup Global Markets Inc.

	Total		7,000,000

The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:


	•	the obligation to purchase all of the common units offered hereby if any of the common units are purchased;

	•	the representations and warranties made by us to the underwriters are true;

	•	there is no material change in the financial markets; and

	•	we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.


	No Exercise	Full Exercise

Paid by us per unit	$	$
Total	$	$

We have been advised by the underwriters that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per common unit. After the offering, the representative may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be approximately $2.7 million (exclusive of underwriting discounts and commissions).

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of 1,050,000 additional common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 7,000,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

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Lock-Up Agreements

We, our subsidiaries, our general partner and its affiliates, including the directors and executive officers of the general partner, have agreed, without the prior written consent of Lehman Brothers Inc. and Citigroup Global Markets Inc., not to (1) directly or indirectly, offer, pledge, sell, contract to sell, sell an option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any common units or any securities which may be converted into or exchanged for any common units, other than certain permitted transfers, (2) enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, (3) cause to be filed a registration statement (other than a registration statement on Form S-8) with respect to the registration of any common units or securities convertible or exchangeable into common units or (4) publicly disclose the intention to do any of the foregoing for a period of 90 days from the date of this prospectus.

The 90-day restricted period described in the preceding paragraph will be extended if:


	•	during the last 17 days of the 90-day restricted period we issue an earnings release or announce material news or a material event; or

	•	prior to the expiration of the 90-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 90-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

Lehman Brothers Inc. and Citigroup Global Markets Inc., in their discretion, may release the common units subject to these restrictions in whole or in part at anytime with or without notice. When determining whether or not to release common units from these restrictions, the primary factors that Lehman Brothers Inc. and Citigroup Global Markets Inc. will consider include the requesting unitholder’s reasons for requesting the release, the number of common units for which the release is being requested and the prevailing economic and equity market conditions at the time of the request.

Indemnification

We and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The underwriters may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934.


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	A short position involves a sale by the underwriters of the common units in excess of the number of common units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of common units they are obligated to purchase is not greater than the number of common units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of common units involved is greater than the number of common units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to

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		close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make representation that the representative will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

The common units are listed on the New York Stock Exchange under the symbol “WPZ.”

Relationships

Lehman Brothers Inc. is serving as Williams’ financial advisor in connection with our acquisition of the 25.1% interest in Four Corners. Lehman Brothers Inc. was the sole bookrunning manager, and Citigroup Global Markets Inc. was an underwriter, in our initial public offering in August 2005. In addition, Lehman Brothers, Inc. and Citigroup Global Markets Inc. and the other underwriters performed and may in the future perform investment banking, advisory and other banking services for us from time to time for which they received or may receive customary fees and expenses. In addition, some of the underwriters and their affiliates have performed, and may in the future perform, various financial advisory, investment banking and other banking services in the ordinary course of business with Williams for which they received or will receive customary compensation.

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An affiliate of Lehman Brothers Inc. is a lender, and affiliates of Citigroup Global Markets Inc. are agents and lenders, under Williams’ $1.275 billion revolving credit facility under which we have a $75 million borrowing limit, and each such affiliate of Lehman Brothers Inc. and Citigroup Global Markets Inc. has received customary fees for such services.

NASD Conduct Rules

Because the National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

185

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The financial statements of Williams Partners L.P. as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005 appearing in this prospectus and the registration statement of which this prospectus forms a part have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Discovery Producer Services LLC as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005 appearing in this prospectus and the registration statement of which this prospectus forms a part have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Williams Four Corners LLC as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005 appearing in this prospectus and the registration statement of which this prospectus forms a part have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The balance sheet of Williams Partners GP LLC as of December 31, 2005 appearing in this prospectus and the registration statement of which this prospectus forms a part have been audited by Ernst & Young LLP, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330.

The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site and can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person 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

186

prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

We file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at http://www.williamslp.com, and we 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.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. Our annual report will contain a detailed statement of any transactions with our general partner or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to our general partner or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

Williams is subject to the information requirements of the Securities Exchange Act of 1934, and in accordance therewith files reports and other information with the SEC. You may read Williams’ filings on the SEC’s web site and at the public reference room described above. Williams’ common stock trades on the New York Stock Exchange under the symbol “WMB.” Reports that Williams files with the New York Stock Exchange may be inspected and copied at the offices of the New York Stock Exchange described above.

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this prospectus, excluding historical information, include forward-looking statements — statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

Forward-looking statements can be identified by words such as “may,” “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “continues,” “estimates,” “forecasts,” “might,” “potential,” “projects” or similar expressions. Similarly, statements that describe our future plans, objectives or goals are also forward-looking statements.

Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. These risks and uncertainties include, among other things:


	•	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, the success of our gathering and transportation business depends on our ability to connect 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 the price of natural gas liquids or a change in the price of natural gas liquids relative to the price of natural gas.

187


	•	Williams’ revolving credit facility and Williams’ public indentures contain financial and operating restrictions that may limit our access to credit. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.

	•	Our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to the detriment of our unitholders.

	•	Even if unitholders are dissatisfied, they cannot currently remove our general partner without its consent.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

	•	Our operations are subject to operational hazards and unforeseen interruptions for which we may or may not be adequately insured.

	•	Lower natural gas and oil prices could adversely affect our fractionation and storage businesses.

	•	We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and natural gas liquids. The loss of any of these key customers or producers could result in a decline in our revenues and cash available to pay distributions.

	•	If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and natural gas liquids or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement. The forward-looking statements included in this prospectus are only made as of the date of this prospectus and we undertake no obligation to publicly update forward-looking statements to reflect subsequent events or circumstances.

188

INDEX TO FINANCIAL STATEMENTS


			Page

UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL STATEMENTS:
	Introduction			F-2
	Unaudited Pro Forma Balance Sheet as of December 31, 2005			F-3
	Unaudited Pro Forma Statement of Income for the year ended December 31, 2005			F-4
	Notes to Unaudited Pro Forma Financial Statements			F-5
WILLIAMS PARTNERS L.P. CONSOLIDATED FINANCIAL STATEMENTS:
	Report of Independent Registered Public Accounting Firm			F-7
	Consolidated Balance Sheets as of December 31, 2004 and 2005			F-8
	Consolidated Statements of Operations for the years ended December 31, 2003, 2004 and 2005			F-9
	Consolidated Statement of Partners’ Capital for the years ended December 31, 2003, 2004 and 2005			F-10
	Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2004 and 2005			F-11
	Notes to Consolidated Financial Statements			F-12
	Quarterly Financial Data (unaudited)			F-28
DISCOVERY PRODUCER SERVICES LLC CONSOLIDATED FINANCIAL STATEMENTS:
	Report of Independent Auditors			F-29
	Consolidated Balance Sheets as of December 31, 2004 and 2005			F-30
	Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2003, 2004 and 2005			F-31
	Consolidated Statement of Members’ Capital for the years ended December 31, 2003,
		2004 and 2005		F-32
	Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2004 and 2005			F-33
	Notes to Consolidated Financial Statements			F-34
WILLIAMS FOUR CORNERS PREDECESSOR FINANCIAL STATEMENTS:
	Report of Independent Auditors			F-43
	Balance Sheets as of December 31, 2004 and 2005			F-44
	Statements of Income for the years ended December 31, 2003, 2004 and 2005			F-45
	Statement of Owner’s Equity for the years ended December 31, 2003, 2004 and 2005			F-46
	Statements of Cash Flows for the years ended December 31, 2003, 2004 and 2005			F-47
	Notes to Financial Statements			F-48
WILLIAMS PARTNERS GP LLC FINANCIAL STATEMENTS:
	Report of Independent Registered Public Accounting Firm			F-57
	Consolidated Balance Sheet			F-58
	Notes to Consolidated Balance Sheet			F-59

F-1

UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL STATEMENTS

The pro forma financial statements present the impact on our financial position and results of operations of our acquisition of a 25.1% interest in Williams Four Corners LLC financed by the issuance of 7,000,000 common units pursuant to this offering and $150 million of senior notes in a concurrent private placement. The pro forma financial statements as of and for the year ended December 31, 2005 have been derived from our historical consolidated financial statements set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical consolidated financial statements and related notes contained therein. The unaudited pro forma financial statements should be read in conjunction with the notes accompanying such pro forma financial statements and with the historical consolidated financial statements and related notes set forth elsewhere in this prospectus.

The pro forma adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma financial information.

The pro forma financial statements may not be indicative of the results that actually would have occurred if we had owned a 25.1% interest in Four Corners on the dates indicated.

F-2

WILLIAMS PARTNERS L.P.

UNAUDITED PRO FORMA BALANCE SHEET

December 31, 2005


		Historical		Adjustments			Pro Forma

				($ In thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	6,839	$	229,250	(a)	$	15,180
					150,000	(b)
					(9,743	)(c)
					(2,650	)(d)
					(355,516	)(e)
					(3,000	)(f)
	Accounts receivable		3,944		—			3,944
	Other current assets		7,213		375	(f)		7,588

Total current assets			17,996		8,716			26,712
Investment in Discovery Producer Services			150,260		—			150,260
Investment in Williams Four Corners			—		152,003	(e)		152,003
Property, plant and equipment, net			67,931		—			67,931
Other noncurrent assets			4,754		2,625	(f)		7,379

Total assets		$	240,941	$	163,344		$	404,285

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
	Accounts payable	$	8,635	$	—		$	8,635
	Deferred revenue		3,552		—			3,552
	Accrued liabilities		2,373		—			2,373

Total current liabilities			14,560		—			14,560
Long-term debt			—		150,000	(b)		150,000
Other non-current liabilities			4,726		—			4,726
Partners’ capital:
	Common unitholders		108,526		229,250	(a)		325,383
					(9,743	)(c)
					(2,650	)(d)
	Subordinated unitholders		108,491		—			108,491
	General partner		4,638		(203,513	)(e)		(198,875	)

Total partners’ capital			221,655		13,344			234,999

Total liabilities and partners’ capital		$	240,941	$	163,344		$	404,285

See accompanying notes to unaudited pro forma financial statements.

F-3

WILLIAMS PARTNERS L.P.

UNAUDITED PRO FORMA STATEMENT OF INCOME


			Year Ended December 31, 2005

			Historical			Adjustments			Pro Forma

			($ In thousands — except per unit amounts)
Revenues			$	51,769		$	—		$	51,769
Cost and expenses:
	Operating and maintenance expense			25,111			—			25,111
	Product cost			11,821			—			11,821
	Depreciation and accretion			3,619			—			3,619
	General and administrative expense			5,323			—			5,323
	Taxes other than income			700			—			700
	Other — net			(6	)		—			(6	)

		Total costs and expenses		46,568			—			46,568

Operating income				5,201			—			5,201
Equity earnings				8,331			28,668	(h)		36,999
Interest expense — affiliate				(7,461	)		7,401	(i)		(60	)
Interest expense — third party				(777	)		(11,800	)(j)		(12,577	)
Interest income				165			—			165

Income before cumulative effect of change in accounting principle			$	5,459		$	24,269		$	29,728

Allocation of income before cumulative effect of change in accounting principle:
	Income before cumulative effect of change in accounting principle		$	5,459					$	29,728
	Loss before cumulative effect of change in accounting principle applicable to the period through August 22, 2005			(103	)

	Income before cumulative effect of change in accounting principle applicable to the period August 23 through December 31, 2005			5,562
	Allocation of loss before cumulative effect of change in accounting principle to general partner			(1,261	)					(777	)

	Allocation of income before cumulative effect of change in accounting principle to limited partners		$	6,823					$	30,505

Basic and diluted income before cumulative effect of change in accounting principle per limited partner unit:
	Common units		$	0.49					$	1.45
	Subordinated units			0.49						1.45
Weighted average number of limited partner units outstanding:
	Common units			7,001,366						14,006,146
	Subordinated units			7,000,000						7,000,000

See accompanying notes to unaudited pro forma financial statements.

F-4

UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL STATEMENTS


Note 1.	Basis of Presentation — Four Corners Acquisition

Unless the context clearly indicates otherwise, references in this report to “we”, “our”, “us” or like terms refer to Williams Partners L.P. and its subsidiaries. The historical financial information is derived from our historical consolidated financial statements. The pro forma adjustments have been prepared as if we acquired the interest in Williams Four Corners LLC (“Four Corners”) on December 31, 2005 for the balance sheet and on January 1, 2005 in the case of the pro forma statement of income. The pro forma statement of income also includes adjustments to reflect the effects of the forgiveness of advances from affiliate in connection with our August 2005 initial public offering (“IPO”) as if the IPO had taken place on January 1, 2005.

The pro forma financial statements reflect the following transactions:


	•	the issuance of 7,000,000 of our common units to the public,

	•	the issuance of $150 million of Senior Notes at a 7.5% interest rate,

	•	the acquisition of a 25.1% interest in Four Corners from the Williams Companies, Inc. (“Williams”) and the distribution to Williams of the aggregate consideration, and

	•	the payment of estimated underwriters’ commissions and other offering expenses.


Note 2.	Pro Forma Adjustments and Assumptions


	a)	Reflects $229.3 million of proceeds to us from the issuance and sale of 7,000,000 common units at an offering price of $32.75 per unit.

	b)	Reflects $150.0 million of proceeds to us from the issuance of Senior Notes.

	c)	Reflects the payment of estimated underwriters’ commissions and structuring fees of $9.7 million, which will be allocated to the common units.

	d)	Reflects the payment of $2.7 million for the estimated costs associated with the offering of the common units.

	e)	Reflects the acquisition, from Williams, of the 25.1% interest in Four Corners and related distribution to Williams of the aggregate consideration for the interest in Four Corners less the retention of $4.5 million in cash representing a contribution by our general partner sufficient to maintain its two percent ownership interest in the partnership. This acquisition will be recorded at Williams’ historical cost as it is considered a transaction between entities under common control. The recognition of the investment at Williams’ historical cost rather than the aggregate consideration causes a deficit capital balance for the general partner.


Aggregate consideration	$	360.0
General partner contribution		(4.5	)

Distribution to Williams		355.5
Historical cost of Four Corners investment		(152.0	)

Net charge to general partner equity	$	(203.5	)


	f)	Reflects the payment of $3.0 million for the estimated costs associated with the issuance of the Senior Notes. These costs will be amortized to interest expense over the eight-year term of the notes.


	h)	Reflects the increase in equity earnings associated with the acquisition of a 25.1% interest in Four Corners.

F-5

UNAUDITED WILLIAMS PARTNERS L.P. PRO FORMA FINANCIAL STATEMENTS — (Continued)


	i)	Reflects the effect on affiliate interest expense of the forgiveness of the advances from affiliate effective with the closing of the IPO on August 23, 2005 and a full year’s commitment fees under our $20 million working capital credit facility entered into in connection with our IPO.

	j)	Includes the following increases to third-party interest expense:


	•	a $0.2 million increase to reflect a full year’s commitment fees associated with our $75 million borrowing limit under Williams’ revolving credit facility; and

	•	$11.6 million increase for interest on the $150 million of Senior Notes to be issued concurrently with this offering as described in adjustment b. We have assumed a 7.5% interest rate on these borrowings and also included $0.4 million for amortization of debt issuance costs.


Note 3.	Pro Forma Earnings Per Unit

Pro forma earnings per unit is determined by dividing the pro forma earnings that would have been allocated, in accordance with the net income and loss allocation provisions of our limited partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting the general partner’s interest in the pro forma earnings, by the weighted average number of common and subordinated units, assuming each of the following were outstanding since January 1, 2005:


	•	7,000,000 common units and 7,000,000 subordinated units issued in connection with our August 2005 initial public offering;

	•	7,000,000 common units to be issued in connection with this offering; and

	•	6,146 common units granted to non-employee directors of our general partner.

We allocated $777,000 pro forma loss to the general partner, based upon the following assumptions:


	•	$1.4 million specific allocation of costs associated with capital contributions to us from our general partner; and

	•	No incentive distributions to our general partner.

Basic and diluted pro forma earnings per unit are equivalent as there are no dilutive units.

F-6

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Williams Partners GP LLC

General Partner of Williams Partners L.P.

We have audited the accompanying consolidated balance sheets of Williams Partners L.P. as of December 31, 2005 and 2004, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As described in Note 7, effective January 1, 2003, Williams Partners L.P. adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and effective December 31, 2005, adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 27, 2006

F-7

WILLIAMS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS


			December 31,

			2004		2005

			(In thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	—	$	6,839
	Accounts receivable:
		Trade		2,150		1,840
		Other		1,388		2,104
	Product imbalance			—		760
	Gas purchase contract — affiliate			—		5,320
	Prepaid expenses			749		1,133

	Total current assets			4,287		17,996
Investment in Discovery Producer Services				147,281		150,260
Property, plant and equipment, net				67,793		67,931
Gas purchase contract — noncurrent — affiliate				—		4,754

Total assets			$	219,361	$	240,941


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
	Accounts payable:
		Trade	$	2,480	$	3,906
		Affiliate		1,980		4,729
	Product imbalance			1,071		—
	Deferred revenue			3,305		3,552
	Accrued liabilities			3,924		2,373

	Total current liabilities			12,760		14,560
Advances from affiliate				186,024		—
Environmental remediation liabilities				3,909		3,964
Other noncurrent liabilities				—		762
Commitments and contingent liabilities (Note 13)
Partners’ capital:
	Predecessor partners’ equity			16,668		—
	Common unitholders (7,006,146 outstanding at December 31, 2005)			—		108,526
	Subordinated unitholders (7,000,000 outstanding at December 31, 2005)			—		108,491
	General partner			—		4,638

		Total partners’ capital		16,668		221,655

Total liabilities and partners’ capital			$	219,361	$	240,941

See accompanying notes to consolidated financial statements.

F-8

WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS


			Year Ended December 31,

			2003			2004			2005

			(In thousands)
Revenues:
	Storage:
		Affiliate	$	2,426		$	—		$	—
		Third-party		9,223			15,318			20,290
	Fractionation			8,221			9,070			10,770
	Gathering			5,513			3,883			3,063
	Product sales:
		Affiliate		—			506			13,400
		Third-party		1,263			7,947			63
	Other			1,648			4,252			4,183

Total revenues				28,294			40,976			51,769
Costs and expenses:
	Operating and maintenance expense:
		Affiliate		8,789			9,986			13,378
		Third-party		5,171			9,390			11,733
	Product cost			1,263			6,635			11,821
	Depreciation and accretion			3,707			3,686			3,619
	General and administrative expense:
		Affiliate		1,738			2,534			4,186
		Third-party		75			79			1,137
	Taxes other than income			640			716			700
	Other — net			(133	)		(91	)		(6	)

Total costs and expenses				21,250			32,935			46,568

	Operating income			7,044			8,041			5,201
Equity earnings — Discovery Producer Services				3,447			4,495			8,331
Impairment of investment in Discovery Producer Services				—			(13,484	)		—
Interest expense:
	Affiliate			(4,176	)		(11,980	)		(7,461	)
	Third-party			—			(496	)		(777	)
Interest income				—			—			165

Income (loss) before cumulative effect of change in accounting principle				6,315			(13,424	)		5,459
Cumulative effect of change in accounting principle				(1,099	)		—			(628	)

Net income (loss)			$	5,216		$	(13,424	)	$	4,831

Allocation of net income:
	Net income								$	4,831
	Net loss applicable to the period through August 22, 2005									(103	)

	Net income applicable to the period August 23 through December 31, 2005									4,934
	Allocation of net loss to general partner									(1,273	)

	Allocation of net income to limited partners								$	6,207

Basic and diluted net income per limited partner unit:
	Income before cumulative effect of change in accounting principle:
		Common units							$	0.49
		Subordinated units							$	0.49
	Cumulative effect of change in accounting principle:
		Common units							$	(0.05	)
		Subordinated units							$	(0.05	)
	Net income:
		Common units							$	0.44
		Subordinated units							$	0.44
Weighted average number of units outstanding:
	Common units									7,001,366
	Subordinated units									7,000,000

See accompanying notes to consolidated financial statements.

F-9

WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL


															Accumulated
			Pre-IPO			Limited Partners									Other			Total
			Owner’s									General			Comprehensive			Partners’
			Equity			Common			Subordinated			Partner			Income (Loss)			Capital

			(Dollars in thousands)
Balance — January 1, 2003			$	24,876		$	—		$	—		$	—		$	(1,962	)	$	22,914
Comprehensive income:
	Net Income — 2003			5,216			—			—			—			—			5,216
	Other comprehensive income:
		Net unrealized losses		—			—			—			—			(116	)		(116	)
		Net reclassification into earnings of derivative instrument losses		—			—			—			—			2,078			2,078

	Total other comprehensive income																		1,962

Total comprehensive income																			7,178

Balance — December 31, 2003				30,092			—			—			—			—			30,092
	Net loss — 2004			(13,424	)		—			—			—			—			(13,424	)

Balance — December 31, 2004				16,668			—			—			—			—			16,668
Accounts receivable not contributed				(2,640	)		—			—			—						(2,640	)
Net loss attributable to the period through August 22, 2005				(103	)		—			—			—			—			(103	)

				13,925			—			—			—			—			13,925
Contribution of net assets of predecessor companies (2,000,000 common units; 7,000,000 subordinated units)				(13,925	)		10,471			106,427			4,343			—			107,316
Issuance of units to public (5,000,000 common units)				—			100,247			—			—			—			100,247
Offering costs				—			(4,291	)		—			—			—			(4,291	)
Net income (loss) attributable to the period August 23, 2005 through December 31, 2005				—			3,104			3,103			(1,273	)		—			4,934
Cash distributions ($.1484 per unit)							(1,039	)		(1,039	)		(42	)		—			(2,120	)
Issuance of common units (6,146 common units)				—			34			—			—			—			34
Contributions pursuant to the Omnibus Agreement				—			—			—			1,610			—			1,610

Balance — December 31, 2005			$	—		$	108,526		$	108,491		$	4,638		$	—		$	221,655

See accompanying notes to consolidated financial statements.

F-10

WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS


					Year Ended December 31,

					2003			2004			2005

					(In thousands)
OPERATING ACTIVITIES:
	Net income (loss) before cumulative effect of change in accounting principle				$	6,315		$	(13,424	)	$	5,459
	Adjustments to reconcile to cash provided by operations:
		Depreciation and accretion				3,707			3,686			3,619
		Impairment of investment in Discovery Producer Services				—			13,484			—
		Amortization of gas purchase contract — affiliate				—			—			2,033
		Undistributed earnings of Discovery Producer Services				(3,447	)		(4,495	)		(7,051	)
		Cash provided (used) by changes in assets and liabilities:
			Accounts receivable			(850	)		261			(3,045	)
			Other current assets			(187	)		(362	)		(384	)
			Accounts payable			(274	)		2,711			4,215
			Accrued liabilities			(320	)		(417	)		(737	)
			Deferred revenue			1,108			775			247
		Other, including changes in noncurrent assets and liabilities				592			484			(2,463	)

			Net cash provided by operating activities			6,644			2,703			1,893

INVESTING ACTIVITIES:
		Capital expenditures				(1,167	)		(1,534	)		(3,688	)
		Contribution to Discovery Producer Services				(101,643	)		—			(24,400	)

			Net cash used by investing activities			(102,810	)		(1,534	)		(28,088	)

FINANCING ACTIVITIES:
		Proceeds from sale of common units				—			—			100,247
		Payment of offering costs				—			—			(4,291	)
		Distribution to The Williams Companies, Inc.				—			—			(58,756	)
		Changes in advances from affiliates — net				96,166			(1,169	)		(3,656	)
		Distributions to unitholders				—			—			(2,120	)
		Contributions per omnibus agreement				—			—			1,610

				Net cash provided (used) by financing activities		96,166			(1,169	)		33,034

Increase in cash and cash equivalents						—			—			6,839
Cash and cash equivalents at beginning of year						—			—			—

Cash and cash equivalents at end of year					$	—		$	—		$	6,839

See accompanying notes to consolidated financial statements.

F-11

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1.	Organization

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of Discovery Producer Services LLC (“Discovery”), in which we own a 40 percent interest. When we refer to Discovery by name, we are referring exclusively to its businesses and operations.

We are a Delaware limited partnership that was formed in February 2005, to acquire and own (1) a 40 percent interest in Discovery; (2) the Carbonate Trend gathering pipeline off the coast of Alabama; (3) three integrated natural gas liquids (“NGL”) product storage facilities near Conway, Kansas; and (4) a 50 percent undivided ownership interest in a fractionator near Conway, Kansas. Prior to the closing of our initial public offering (the “IPO”) in August 2005, the 40 percent interest in Discovery was held by Williams Energy, L.L.C. (“Energy”) and Williams Discovery Pipeline LLC; the Carbonate Trend gathering pipeline was held in Carbonate Trend Pipeline LLC (“CTP”), which was owned by Williams Mobile Bay Producers Services, L.L.C.; and the NGL product storage facilities and the interest in the fractionator were owned by Mid-Continent Fractionation and Storage, LLC (“MCFS”). All of these are wholly owned indirect subsidiaries of The Williams Companies, Inc. (collectively “Williams”). Williams Partners GP LLC, a Delaware limited liability company, was also formed in February 2005, to serve as our general partner. We also formed Williams Partners Operating LLC, an operating limited liability company (wholly owned by us) through which all our activities are conducted,.


	*Initial Public Offering and Related Transactions*

On August 23, 2005, we completed our IPO of 5,000,000 common units representing limited partner interests in us at a price of $21.50 per unit. The proceeds of $100.2 million, net of the underwriters’ discount and a structuring fee totaling $7.3 million, were used to:


	•	distribute $58.8 million to Williams, in part to reimburse Williams for capital expenditures relating to the assets contributed to us and for a gas purchase contract contributed to us;

	•	provide $24.4 million to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;

	•	provide $12.7 million of additional working capital; and

	•	pay $4.3 million of expenses associated with the IPO and related formation transactions.

Concurrent with the closing of the IPO, the 40 percent interest in Discovery and all of the interests in CTP and MCFS were contributed to us by Williams’ subsidiaries in exchange for an aggregate of 2,000,000 common units and 7,000,000 subordinated units. The public, through the underwriters of the offering, contributed $107.5 million ($100.2 million net of the underwriters’ discount and a structuring fee) to us in exchange for 5,000,000 common units, representing a 35 percent limited partner interest in us. Additionally, at the closing of the IPO, the underwriters fully exercised their option to purchase 750,000 common units from Williams’ subsidiaries at the IPO price of $21.50 per unit, less the underwriters’ discount and a structuring fee.


Note 2.	Description of Business

We are principally engaged in the business of gathering, transporting and processing natural gas and fractionating and storing NGLs. Operations of our businesses are located in the United States and are organized into two reporting segments: (1) Gathering and Processing and (2) NGL Services. Our Gathering and Processing segment includes our equity investment in Discovery and the Carbonate Trend gathering pipeline. Our NGL Services segment includes the Conway fractionation and storage operations.

F-12

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Gathering and Processing. We own a 40 percent interest in Discovery, which includes a wholly owned subsidiary, Discovery Gas Transmission LLC. Discovery owns (1) a 273-mile natural gas gathering and transportation pipeline system, located primarily off the coast of Louisiana in the Gulf of Mexico, (2) a 600 million cubic feet per day cryogenic natural gas processing plant in Larose, Louisiana, (3) a 32,000 barrels per day (“bpd”) natural gas liquids fractionator in Paradis, Louisiana and (4) 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. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it is primarily engaged in gathering and processing and is managed as such. Hence, this equity investment is considered part of the Gathering and Processing segment.

Our Carbonate Trend gathering pipeline is an unregulated sour gas gathering pipeline consisting of approximately 34 miles of pipeline off the coast of Alabama.

NGL Services. Our Conway storage facilities include three underground NGL storage facilities in the Conway, Kansas, area with a storage capacity of approximately 20 million barrels. The facilities are connected via a series of pipelines. The storage facilities receive daily shipments of a variety of products, including mixed NGLs and fractionated products. In addition to pipeline connections, one facility offers truck and rail service.

Our Conway fractionation facility is located near Conway, Kansas, and has a capacity of approximately 107,000 bpd. We own a 50 percent undivided interest in these facilities representing capacity of approximately 53,500 bpd. ConocoPhillips and ONEOK, Inc. are the other owners. Williams operates the facility pursuant to an operating agreement that extends until May 2011. The fractionator separates mixed NGLs into five products: ethane/propane mix, propane, normal butane, isobutane and natural gasoline. Portions of these products are then transported and stored at our Conway storage facilities.


Note 3.	Summary of Significant Accounting Policies

Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the United States and include the accounts of the parent and our wholly owned subsidiaries. Intercompany accounts and transactions have been eliminated.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include:


	•	impairment assessments of investments and long-lived assets;

	•	loss contingencies;

	•	environmental remediation obligations; and

	•	asset retirement obligations.

These estimates are discussed further throughout the accompanying notes.

Proportional Accounting for the Conway Fractionator. No separate legal entity exists for the fractionator. We hold a 50 percent undivided interest in the fractionator property, plant and equipment, and we are responsible for our proportional share of the costs and expenses of the fractionator. As operator of the

F-13

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

facility, we incur the liabilities of the fractionator (except for certain fuel costs purchased directly by one of the co-owners) and are reimbursed by the co-owners for their proportional share of the total costs and expenses. Each co-owner is responsible for the marketing of their proportional share of the fractionator’s capacity. Accordingly, we reflect our proportionate share of the revenues and costs and expenses of the fractionator in the Consolidated Statements of Operations; and we reflect our proportionate share of the fractionator property, plant and equipment in the Consolidated Balance Sheets. Liabilities in the Consolidated Balance Sheets include those incurred on behalf of the co-owners with corresponding receivables from the co-owners. Accounts receivable also includes receivables from our customers for fractionation services.

Cash and Cash Equivalents. Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.

Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue which generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.

Investments. The voting rights under Discovery’s limited liability company agreement are such that our 40 percent interest combined with the additional interest held by Williams do not control Discovery. Hence, we account for our investment in Discovery under the equity method. Prior to 2004, the excess of the carrying value of our investment over the amount of underlying equity in net assets of Discovery represented interest capitalized during construction on the funds advanced to Discovery for construction prior to Discovery’s receipt of external financing. This excess was being amortized on a straight-line basis over the life of the related assets. In 2004, we recognized an other-than-temporary impairment of our investment. As a result, Discovery’s underlying equity exceeds the carrying value of our investment at December 31, 2005.

Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the carrying value of these assets on capitalized costs, useful lives and salvage values. Depreciation of property, plant and equipment is provided on the straight-line basis over estimated useful lives. Expenditures for maintenance and repairs are expensed as incurred. Expenditures that enhance the functionality or extend the useful lives of the assets are capitalized. The cost of property, plant and equipment sold or retired and the related accumulated depreciation is removed from the accounts in the period of sale or disposition. Gains and losses on the disposal of property, plant and equipment are recorded in the Consolidated Statements of Operations.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (“ARO”). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in operating income.

Revenue Recognition. The nature of our businesses result in various forms of revenue recognition. Our Gathering and Processing segment recognizes revenue from gathering services when the services have been performed. Our NGL Services segment recognizes (1) fractionation revenues when services have been performed and product has been delivered, (2) storage revenues under prepaid contracted storage capacity evenly over the life of the contract as services are provided and (3) product sales revenue when the product has been delivered.

Gas Purchase Contract. In connection with the IPO, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to

F-14

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

exceed a specified level. The gas purchase contract is for the purchase of 80,000 MMBtu per month and terminates on December 31, 2007. The initial value of this contract is being amortized to expense over the contract life.

Product Imbalances. In the course of providing fractionation and storage services to our customers, we realize product gains and losses that are reflected as product imbalance receivables or payables on the Consolidated Balance Sheets. These imbalances are valued based on the market price of the products when the imbalance is identified and are evaluated for the impact of a change in market prices at the balance sheet date. Certain of these product gains and losses arise due to the product blending process at the fractionator. Others are realized when storage caverns are emptied. Storage caverns are emptied periodically to determine whether any product gains or losses have occurred, and as these caverns are emptied, it is possible that the resulting product gains or losses could have a material impact to the results of operations for the period during which the cavern drain is performed.

Impairment of Long-Lived Assets and Investments. We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate the carrying value of such assets may not be recoverable. The impairment evaluation of tangible long-lived assets is measured pursuant to the guidelines of Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the carrying value of the assets is recoverable. We apply a probability weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If the carrying value is not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

We evaluate our investments for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Income Taxes. We are not a taxable entity for federal and state income tax purposes. The tax on our net income is borne by the individual partners through the allocation of taxable income. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.

Environmental. Environmental expenditures that relate to current or future revenues are expensed or capitalized based upon the nature of the expenditures. Expenditures that relate to an existing contamination caused by past operations that do not contribute to current or future revenue generation are expensed. Accruals related to environmental matters are generally determined based on site-specific plans for

F-15

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

remediation, taking into account our prior remediation experience. Environmental contingencies are recorded independently of any potential claim for recovery.

Capitalized Interest. We capitalize interest on major projects during construction to the extent we incur interest expense. Historically, Williams provided the financing for capital expenditures; hence, the rates used to calculate the interest were based on Williams’ average interest rate on debt during the applicable period in time.

Earnings Per Unit. In accordance with the Emerging Issues Task Force (“EITF”) Issue 03-6, we use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common and subordinated units outstanding. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.

Recent Accounting Standards. In December 2004, the Financial Accounting Standards Board (“FASB”) issued revised SFAS No. 123, “Share-Based Payment.” The Statement requires that compensation costs for all share-based awards to employees be recognized in the financial statements at fair value. The Statement, as issued by the FASB, was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission (“SEC”) adopted a new rule that delayed the effective date for revised SFAS No. 123 to the beginning of the next fiscal year that begins after June 15, 2005. We intend to adopt the revised Statement as of January 1, 2006. Payroll costs directly charged to us by Williams and general and administrative costs allocated to us by Williams (see Note 5) will include such compensation costs beginning January 1, 2006. Our and Williams’ adoption of this Statement will not have a material impact on our Consolidated Financial Statements.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which will be applied prospectively for inventory costs incurred in fiscal years beginning after June 15, 2005. The Statement amends Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing,” to clarify that abnormal amounts of certain costs should be recognized as current period charges and that the allocation of overhead costs should be based on the normal capacity of the production facility. The impact of this Statement on our Consolidated Financial Statements will not be material.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” which is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, and will be applied prospectively. The Statement amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but includes certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which is effective prospectively for reporting a change in accounting principle for fiscal years beginning after December 15, 2005. The Statement changes the reporting of a change in accounting principle to require retrospective application to prior periods’ financial statements, except for explicit transition provisions provided for in any existing accounting pronouncements, including those in the transition phase when SFAS No. 154 becomes effective.

F-16

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 4.	Allocation of Net Income and Distributions

The allocation of net income between our general partner and limited partners for the period August 23, 2005 through December 31, 2005 is as follows (in thousands):


Allocation of net income to general partner:
	Net income for the period August 23, 2005 through December 31, 2005		$	4,934
	Direct charges to general partner:
		Reimbursable general and administrative costs		1,400

	Income before direct charges to general partner			6,334
	General partner’s share of net income			2.0	%

	General partner’s allocated share of net income before direct charges			127
	Direct charges to general partner			(1,400	)

Net loss allocated to general partner			$	(1,273	)

Net income for the period August 23, 2005 through December 31, 2005			$	4,934
Net loss allocated to general partner				(1,273	)

Net income allocated to limited partners			$	6,207

The reimbursable general and administrative costs represent the general and administrative costs charged against our income that are required to be reimbursed to us by our general partner under the terms of the Omnibus Agreement.

On November 14, 2005, we paid a cash distribution of $0.1484 per unit on our outstanding common and subordinated units to unitholders of record at the close of business on November 7, 2005. The distribution represents the $0.35 per unit minimum quarterly distribution pro-rated for the 39-day period following the IPO closing date (August 23, 2005 through September 30, 2005). The total distribution, including distributions paid to our general partner on its equivalent units, was $2.1 million.

On February 14, 2006, we paid a cash distribution of $0.35 per unit on our outstanding common and subordinated units to unitholders of record on February 7, 2006. The total distribution, including distributions paid to our general partner on its equivalent units, was $5.0 million.


Note 5.	Related Party Transactions

The employees of our operated assets and all of our general and administrative employees are employees of Williams. Williams directly charges us for the payroll costs associated with the operations employees and certain general and administrative employees. Williams carries the obligations for most employee-related benefits in its financial statements, including the liabilities related to the employee retirement and medical plans and paid time off. Certain of these costs are charged back to the other Conway fractionator co-owners. Our share of those costs are charged to us through affiliate billings and reflected in Operating and maintenance expense — Affiliate in the accompanying Consolidated Statements of Operations.

Williams charges its affiliates, including us and its Midstream segment, of which we are a part, for certain corporate administrative expenses that are directly identifiable or allocable to the affiliates. Direct costs charged from Williams represent the direct costs of services provided by Williams on our behalf. Prior to the IPO, a portion of the charges allocated to the Midstream segment were then reallocated to us. These allocated corporate administrative expenses are based on a three-factor formula, which considered revenues; property, plant and equipment; and payroll. Certain of these costs are charged back to the other Conway fractionator co-owners. Our share of these costs is reflected in General and administrative expense — Affiliate

F-17

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

in the accompanying Consolidated Statements of Operations. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. Under the Omnibus Agreement, Williams gives us a quarterly credit for general and administrative expenses. These amounts are reflected as a capital contribution from our general partner. The annual amounts of the credits are as follows: $3.9 million in 2005 ($1.4 million pro-rated for the portion of the year from August 23 to December 31), $3.2 million in 2006, $2.4 million in 2007, $1.6 million in 2008 and $0.8 million in 2009.

At December 31, 2005, we have a contribution receivable from our general partner of $.3 million, which is netted against Partners’ capital on the Consolidated Balance Sheets, for amounts reimbursable to us under the Omnibus Agreement.

We purchase fuel for the Conway fractionator, including fuel on behalf of the co-owners, from Williams Power Company (“Power”), a wholly owned subsidiary of Williams. These purchases are made at market rates at the time of purchase. In connection with the IPO, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. The amortization of this contract is reflected in Operating and maintenance expense — Affiliate in the accompanying Consolidated Statements of Operations. The carrying value of this contract is reflected as Gas purchase contract — affiliate and Gas purchase contract — noncurrent — affiliate on the Consolidated Balance Sheets.

During a portion of 2003, we provided propane storage, fractionation, transportation and terminalling services to subsidiaries of Williams that have subsequently been sold. In December 2004, we began selling surplus propane and other NGLs to Power, which takes title to the product and resells it, for its own account, to end users. Revenues associated with these activities are reflected as Affiliate revenues on the Consolidated Statements of Operations. Correspondingly, we purchase ethane and other NGLs from Power to replenish deficit product positions. The transactions conducted between us and Power are transacted at current market prices for the products.

A summary of the general and administrative expenses directly charged and allocated to us, fuel purchases from Power and NGL purchases from Power for the periods stated is as follows:


		2003		2004		2005

		(In thousands)
General and administrative expenses, including amounts subsequently charged to co-owners:
	Allocated	$	1,392	$	2,078	$	3,494
	Directly charged		346		456		992
Operating and maintenance expenses, including amounts subsequently charged to co-owners:
	Fuel purchases, including amortization of gas contract		12,843		17,053		24,478
	Salaries and benefits		2,105		3,473		3,514
NGL purchases			—		1,271		15,657

The per-unit gathering fee associated with two of our Carbonate Trend gathering contracts was negotiated on a bundled basis that includes transportation along a segment of a pipeline system owned by Transcontinental Gas Pipe Line Company (“Transco”), a wholly owned subsidiary of Williams. The fees we realize 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 the capacity agreement is based on a Federal Energy Regulatory Commission tariff that is subject to change. Accordingly, if the Transco rate increases, our net gathering fees for these two contracts

F-18

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

may be reduced. The customers with these bundled contracts must make an annual election to receive this capacity. For 2005 and 2006, only one of our customers has elected to utilize this capacity.

We historically participated in Williams’ cash management program; thus, we carried no cash balance on our Consolidated Balance Sheet at December 31, 2004. Effective with the IPO, we began maintaining our own bank accounts but continue to utilize Williams’ personnel to manage our cash and investments. As of December 31, 2004, our net Advances from affiliate consisted of an unsecured promissory note agreement with Williams for both advances to and from Williams. The advances were due on demand; however, Williams did not historically require repayment. Therefore, Advances from affiliate at December 31, 2004 were classified as noncurrent. Prior to the closing of the IPO, Williams forgave the advances due to them at the date the net assets were transferred to us. Accordingly, the advances balance was transferred to Partners’ capital at that date.

Affiliate interest expense includes interest on the advances with Williams calculated using Williams’ weighted average cost of debt applied to the outstanding balance of the advances with Williams and commitment fees on the working capital credit facility (see Note 11). The interest rate on the advances with Williams was 7.373 percent at December 31, 2004.


Note 6.	Investment in Discovery Producer Services

Our 40 percent investment in Discovery is accounted for using the equity method of accounting. At December 31, 2005, Williams owned an additional 20 percent ownership interest in Discovery through Energy. Although we and Williams hold a 60 percent interest in Discovery on a combined basis, the voting provisions of Discovery’s limited liability company agreement give the other member of Discovery significant participatory rights such that we and Williams do not control Discovery.

Of the total ownership interest owned by Williams prior to the transfer of 40 percent to us, a portion was acquired by Williams in April 2005 resulting in a revised basis used for the calculation of the 40 percent interest transferred to us in connection with the IPO. As a result, the carrying value of our 40 percent interest in Discovery and Partners’ capital decreased $11.0 million during the second quarter of 2005.

On August 22, 2005, Discovery made a distribution of approximately $43.8 million to Williams and the other member of Discovery at that date. This distribution was associated with Discovery’s operations prior to the IPO; hence, we did not receive any portion of this distribution. The distribution resulted in a revised basis used for the calculation of the 40 percent interest transferred to us in connection with the IPO. As a result, the carrying value of our 40 percent interest in Discovery and Partners’ capital decreased $17.5 million during the third quarter of 2005.

In September 2005, we made a $24.4 million capital contribution to Discovery for a substantial portion of our share of the estimated future capital expenditures for the Tahiti pipeline lateral expansion project.

Williams is the operator of Discovery. Discovery reimburses Williams for actual payroll and employee benefit costs incurred on its behalf. In addition, Discovery pays Williams a monthly operations and management fee to cover the cost of accounting services, computer systems and management services provided to it. Discovery also has an agreement with Williams pursuant to which Williams markets the NGLs and excess natural gas to which Discovery takes title.

During 2004, we performed an impairment review of this investment because of Williams’ planned purchase of an additional interest in Discovery at an amount below its carrying value. As a result, we recorded a $13.5 million impairment of our investment in Discovery based on a probability-weighted estimation of fair value of our investment. In December 2003, each of the owners made an additional investment in Discovery, which was subsequently used by Discovery to repay maturing debt. Our proportionate share of this additional investment was approximately $101.6 million.

F-19

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Due to the significance of Discovery’s equity earnings to our results of operations, the summarized financial position and results of operations for 100 percent of Discovery are presented below (in thousands).


	December 31,

	2004			2005

Current assets	$	67,534		$	70,525
Non-current restricted cash		—			44,559
Property, plant and equipment		356,385			344,743
Current liabilities		(31,572	)		(45,070	)
Non-current liabilities		(702	)		(1,121	)

Members’ capital	$	391,645		$	413,636


	Years Ended December 31,

	2003		2004			2005

Revenues	$	103,178	$	99,876		$	122,745
Costs and expenses		84,519		88,756			102,597
Interest expense		9,611		—			—
Interest income		—		(550	)		(1,685	)
Foreign exchange loss		—		—			1,005

Income before cumulative effect of change in accounting principle	$	9,048	$	11,670		$	20,828

Net income	$	8,781	$	11,670		$	20,652


Note 7.	Property, Plant and Equipment

Property, plant and equipment, at cost, is as follows:


		December 31,				Estimated
						Depreciable
		2004		2005		Lives

		(In thousands)
Land and right of way		$	2,373	$	2,373
Fractionation plant and equipment			16,555		16,646	30 years
Storage plant and equipment			63,632		65,892	30 years
Pipeline plant and equipment			23,684		23,684	20-30 years
Construction work in progress			566		1,886
Other			1,490		1,492	5-45 years

	Total property, plant and equipment		108,300		111,973
Accumulated depreciation			40,507		44,042

	Net property, plant and equipment	$	67,793	$	67,931

We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003. As a result, we recorded a liability of $993,000 representing the present value of expected future asset retirement obligations at January 1, 2003, and a decrease to earnings of $992,000 reflected as a cumulative effect of a change in accounting principle. An additional $107,000 reduction of earnings is reflected as a cumulative effect of a change in accounting principle for our 40 percent interest in Discovery’s cumulative effect of a change in accounting principle related to the adoption of SFAS No. 143.

F-20

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Effective December 31, 2005, we adopted FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $573,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $16,000 increase in property, plant and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $557,000 reduction to earnings is reflected as a cumulative effect of a change in accounting principle for the year ended 2005. An additional $70,000 reduction of earnings is reflected as a cumulative effect of a change in accounting principle for our 40 percent interest in Discovery’s cumulative effect of a change in accounting principle related to the adoption of FIN No. 47. If the Interpretation had been in effect at the beginning of 2003, the impact to our income from continuing operations and net income would have been immaterial.

The obligations relate to underground storage caverns and the associated brine ponds. At the end of the useful life of each respective asset, we are legally obligated to properly abandon the storage caverns, empty the brine ponds and restore the surface, and remove any related surface equipment.

A rollforward of our asset retirement obligation for 2004 and 2005 is presented below.


	2004			2005

	(In thousands)
Balance, January 1	$	801		$	760
Liabilities incurred during the period		79			91
Liabilities settled during the period		(166	)		(204	)
Accretion expense		83			1
Estimate revisions		—			(460	)
FIN No. 47 revisions		—			574
Gain on settlements		(37	)		—

Balance, December 31	$	760		$	762


Note 8.	Accrued Liabilities

Accrued liabilities are as follows:


	December 31,

	2004		2005

	(In thousands)
Environmental remediation — current portion	$	1,633	$	1,424
Customer volume deficiency payment		749		—
Asset retirement obligation — current portion		760		—
Employee costs — affiliate		317		387
Taxes other than income		359		375
Other		106		187

	$	3,924	$	2,373

F-21

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 9.	Long-Term Incentive Plan

In November 2005, our general partner adopted the Williams Partners GP LLC Long-Term Incentive Plan (the “Plan”) for employees, consultants and directors of our general partner and its affiliates who perform services for us. The Plan permits the grant of awards covering an aggregate of 700,000 common units. These awards may be in the form of options, restricted units, phantom units or unit appreciation rights. The compensation committee of our general partner’s board of directors administers the Plan.

During November and December 2005, our general partner granted 6,146 restricted units pursuant to the Plan to members of our general partner’s board of directors who are not officers or employees of our general partner or its affiliates. These restricted units vest six months from grant date. We recognized compensation expense of $34 thousand associated with these awards in 2005.


Note 10.	Major Customers, Concentrations of Credit Risk and Financial Instruments


	*Major Customers*

In 2003, four customers, BP, Enterprise, Chevron and Williams Power Company (an affiliate company), accounted for approximately 24.6 percent, 15.9 percent, 14.7 percent and 11.6 percent, respectively, of our total revenues. In 2004, three customers, SemStream, L.P., BP and Enterprise accounted for approximately 20.6 percent, 16.1 percent and 16.0 percent, respectively, of our total revenues. In 2005, four customers, Williams Power Company, SemStream, L.P., Enterprise and BP Products North America, Inc. (BP) accounted for approximately 25.9 percent, 17.1 percent, 14.1 percent and 13.5 percent, respectively, of our total revenues. SemStream, L.P., BP, Enterprise and Williams Power Company are customers of the NGL Services segment. Chevron is a customer of the Gathering and Processing segment.

Our Carbonate Trend gathering pipeline has only two customers. The loss of either of these customers, unless replaced, would have a significant impact on the Gathering and Processing segment.


	*Concentrations of Credit Risk*

Our cash equivalents consist of high-quality securities placed with various major financial institutions with credit ratings at or above AA by Standard & Poor’s or Aa by Moody’s Investor’s Service.

The following table summarizes the concentration of accounts receivable by service and segment.


		December 31,

		2004		2005

		(In thousands)
Gathering and Processing:
	Natural gas gathering	$	441	$	525
NGL Services:
	Fractionation services		468		532
	Amounts due from fractionator partners		1,381		1,834
	Storage		1,241		793
	Other		7		260

		$	3,538	$	3,944

Our fractionation and storage customers include crude refiners; propane wholesalers and retailers; gas producers; natural gas plant, fractionator and storage operators; and NGL traders and pipeline operators. Our two Carbonate Trend natural gas gathering customers are oil and gas producers. While sales to our customers are unsecured, we routinely evaluate their financial condition and creditworthiness.

F-22

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Financial Instruments*

We used the following methods and assumptions to estimate the fair value of financial instruments.

Cash and cash equivalents. The carrying amounts reported in the balance sheets approximate fair value due to the short-term maturity of these instruments.

Advances from affiliates. At December 31, 2004, our net Advances from affiliate consisted of an unsecured promissory note agreement with Williams for both advances to and from Williams. The carrying amounts reported in the Consolidated Balance Sheet approximate fair value as this instrument had an interest rate approximating market.


	2004				2005

	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value

	(In thousands)
Cash and cash equivalents		—		—	$	6,839	$	6,839
Advances from affiliates	$	186,024	$	186,024		—		—


Note 11.	Credit Facilities and Leasing Activities


	*Credit Facilities*

On May 20, 2005, Williams amended its $1.275 billion revolving credit facility (“Williams facility”), which is available for borrowings and letters of credit, to allow us to borrow up to $75 million under the Williams facility. Borrowings under the Williams facility mature on May 3, 2007. Our $75 million borrowing limit under the Williams facility is 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, 2005, letters of credit totaling $378 million had been issued on behalf of Williams by the participating institutions under the Williams facility and no revolving credit loans were outstanding.

Interest on any borrowings under the Williams facility is calculated based on our 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 are also required to pay or reimburse Williams for a commitment fee based on the unused portion of its $75 million borrowing limit under the Williams facility, currently 0.325 percent annually. The applicable margin, currently 1.75 percent, and the commitment fee are based on Williams’ senior unsecured long-term debt rating. Under the Williams 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 Williams facility to which Williams is subject include the following:


	•	ratio of debt to net worth no greater than (i) 70 percent through December 31, 2005, and (ii) 65 percent for the remaining term of the agreement;

	•	ratio of debt to net worth no greater than 55 percent for Northwest Pipeline Corporation, a wholly owned subsidiary of Williams, and Transco; and

	•	ratio of EBITDA to interest, on a rolling four quarter basis, no less than (i) 2.0 for any period after March 31, 2005 through December 31, 2005, and (ii) 2.5 for the remaining term of the agreement.

In August 2005, we entered into a $20 million revolving credit facility (the “credit facility”) with Williams as the lender. The credit facility is available exclusively to fund working capital requirements. Borrowings under the credit facility mature on May 3, 2007 and bear interest at the same rate as for borrowings under the Williams facility described above. We pay a commitment fee to Williams on the unused portion of the credit facility of 0.30 percent annually. We are required to reduce all borrowings under the

F-23

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

credit facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the credit facility. No amounts have been drawn on this facility.


	*Leasing Activities*

We lease automobiles for use in our NGL Services segment. We account for these leases as operating leases. Future minimum annual rentals under non-cancelable operating leases as of December 31, 2005 are as follows (in thousands):


2006	$	30
2007		29
2008		27
2009		10
2010		—

	$	96

Total rent expense was $116,000, $110,000 and $119,000 for 2003, 2004 and 2005, respectively.


Note 12.	Partners’ Capital

Of the 7,006,146 common units outstanding at December 31, 2005, 5,756,146 are held by the public, with the remaining 1,250,000 held by our affiliates. All of the 7,000,000 subordinated units are held by our affiliates.

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. The subordination period will end on the first day of any quarter beginning after June 30, 2008 or when we meet certain financial tests provided for in our partnership agreement.

Significant information regarding rights of the limited partners include the following:


	•	Right to receive distributions of available cash within 45 days after the end of each quarter.

	•	No limited partner shall have any management power over our business and affairs; the general partner shall conduct, direct and manage our activities.

	•	The general partner may be removed if such removal is approved by the unitholders holding at least 66²/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates.

	•	Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year.

Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:


				General
Quarterly Distribution Target Amount (per unit)	Unitholders			Partner

Minimum quarterly distribution of $0.35		98	%		2	%
Up to $0.4025		98			2
Above $0.4025 up to $0.4375		85			15
Above $0.4375 up to $0.5250		75			25
Above $0.5250		50			50

F-24

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In the event of a liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner, in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.


	*Other Comprehensive Income*

The main component of our accumulated other comprehensive loss is our share of Discovery’s accumulated other comprehensive loss which is related to a cash flow hedge of interest rate risk held by Discovery in 2003.


Note 13.	Commitments and Contingencies

Environmental Matters. We are a participant in certain environmental remediation activities associated with soil and groundwater contamination at our Conway storage facilities. These activities relate to four projects that are in various remediation stages including assessment studies, cleanups and/or remedial operations and monitoring. We continue to coordinate with the Kansas Department of Health and Environment (“KDHE”) to develop screening, sampling, cleanup and monitoring programs. The costs of such activities will depend upon the program scope ultimately agreed to by the KDHE and are expected to be paid over the next two to nine years.

In 2004, we purchased an insurance policy that covers up to $5 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 projects to the extent such costs exceed a $4.2 million deductible. The policy also covers costs incurred as a result of third party claims associated with then existing but unknown contamination related to the storage facilities. The aggregate limit under the policy for all claims is $25 million. In addition, under an omnibus agreement with Williams entered into at the closing of the IPO, Williams has agreed to indemnify us for the $4.2 million deductible (less amounts expended prior to the closing of the IPO) of remediation expenditures not covered by the insurance policy, excluding costs of project management and soil and groundwater monitoring. There is a $14 million cap on the total amount of indemnity coverage under the omnibus agreement, which will be reduced by actual recoveries under the environmental insurance policy. There is also a three-year time limitation from the IPO closing date, August 23, 2005. The benefit of this indemnification will be accounted for as a capital contribution to us by Williams as the costs are reimbursed. We estimate that the approximate cost of this project management and soil and groundwater monitoring associated with the four remediation projects at the Conway storage facilities and for which we will not be indemnified will be approximately $200,000 to $400,000 per year following the completion of the remediation work.

At December 31, 2005, we had accrued liabilities totaling $5.4 million for these costs. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by KDHE and other governmental authorities and other factors.

Other. We are not currently a party to any legal proceedings but are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

F-25

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 14.	Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different industry knowledge, technology and marketing strategies. The accounting policies of the segments are the same as those described in Note 3, Summary of Significant Accounting Policies. Long-lived assets are comprised of property, plant and equipment.


		Gathering &			NGL
		Processing			Services		Total

		(In thousands)
2003
Segment revenues		$	5,513		$	22,781	$	28,294
Operating and maintenance expense			379			13,581		13,960
Product cost			—			1,263		1,263
Depreciation and accretion			1,200			2,507		3,707
Direct general and administrative expenses			—			421		421
Other, net			—			507		507

Segment operating income			3,934			4,502		8,436
Equity earnings			3,447			—		3,447

Segment profit		$	7,381		$	4,502	$	11,883

Reconciliation to the Statement of Operations:
	Segment operating income						$	8,436
	Allocated general and administrative expenses							(1,392	)

	Combined operating income						$	7,044

Other financial information:
Total assets		$	177,769		$	52,381	$	230,150
Equity method investments			156,269			—		156,269
Additions to long-lived assets			—			1,176		1,176
2004
Segment revenues		$	4,833		$	36,143	$	40,976
Operating and maintenance expense			572			18,804		19,376
Product cost			—			6,635		6,635
Depreciation and accretion			1,200			2,486		3,686
Direct general and administrative expenses			—			535		535
Other, net			—			625		625

Segment operating income			3,061			7,058		10,119
Equity earnings			4,495			—		4,495
Impairment of investment			(13,484	)		—		(13,484	)

Segment profit (loss)		$	(5,928	)	$	7,058	$	1,130

F-26

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			Gathering &		NGL
			Processing		Services		Total

			(In thousands)
Reconciliation to the Statement of Operations:
	Segment operating income						$	10,119
	Allocated general and administrative expenses							(2,078	)

	Combined operating income						$	8,041

Other financial information:
Total assets			$	166,985	$	52,376	$	219,361
Equity method investments				147,281		—		147,281
Additions to long-lived assets				—		1,622		1,622
2005
Segment revenues			$	3,515	$	48,254	$	51,769
Operating and maintenance expense				714		24,397		25,111
Product cost				—		11,821		11,821
Depreciation and accretion				1,200		2,419		3,619
Direct general and administrative expenses				2		1,068		1,070
Other, net				—		694		694

Segment operating income				1,599		7,855		9,454
Equity earnings				8,331		—		8,331

Segment profit			$	9,930	$	7,855	$	17,785

Reconciliation to the Statement of Operations:
	Segment operating income						$	9,454
	General and administrative expenses:
		Allocated — affiliate						(3,194	)
		Third-party direct						(1,059	)

	Combined operating income						$	5,201

Other financial information:
Segment assets			$	171,009	$	64,579	$	235,588
Other assets and eliminations								5,353

Total assets							$	240,941

Equity method investments			$	150,260	$	—	$	150,260
Additions to long-lived assets				—		3,688		3,688

F-27

WILLIAMS PARTNERS L.P.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data are as follows (thousands, except per-unit amounts):


	First		Second			Third			Fourth
	Quarter		Quarter			Quarter			Quarter

2004
Revenues	$	7,953	$	9,043		$	10,457		$	13,523
Costs and operating expenses		5,256		8,289			8,956			10,434
Income (loss) before cumulative effect of change in accounting principle		1,569		(1,125	)		(1,684	)		(12,184	)
Net income (loss)		1,569		(1,125	)		(1,684	)		(12,184	)


			First		Second		Third			Fourth
			Quarter		Quarter		Quarter			Quarter

2005
Revenues			$	11,369	$	12,176	$	12,176		$	16,048
Costs and operating expenses				10,266		8,036		13,175			15,091
Income (loss) before cumulative effect of change in accounting principle				311		1,849		(2,871	)		6,170
Net income (loss)				311		1,849		(2,871	)		5,542
Basic and diluted net income (loss) per limited partner unit:
	Income (loss) before cumulative effect of change in accounting principle:
		Common units		NA		NA	$	(0.02	)	$	0.51
		Subordinated units		NA		NA	$	(0.02	)	$	0.51
	Cumulative effect of change in accounting principle:
		Common units		NA		NA	$	—		$	(0.05	)
		Subordinated units		NA		NA	$	—		$	(0.05	)
	Net income (loss):
		Common units		NA		NA	$	(0.02	)	$	0.46
		Subordinated units		NA		NA	$	(0.02	)	$	0.46


	•	Net income for fourth-quarter 2005 includes our 40 percent share of Discovery’s favorable adjustment of $10.7 million related to amounts previously deferred for net system gains from 2002 through 2004 that were reversed following the acceptance in 2005 of a filing with the FERC.

	•	Net loss for third-quarter 2005 includes a $3.4 million unfavorable product imbalance adjustments included in NGL services.

	•	Net loss for fourth-quarter 2004 includes a $13.5 million impairment of our investment in Discovery Producer Services (see Note 6).

F-28

REPORT OF INDEPENDENT AUDITORS

To the Management Committee of

Discovery Producer Services LLC

We have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC as of December 31, 2005 and 2004, and the related consolidated statements of income and comprehensive income, members’ capital, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Discovery Producer Services LLC at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States.

As described in Note 4, effective January 1, 2003, Discovery Producer Services LLC adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 27, 2006

F-29

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED BALANCE SHEETS


			December 31,

			2004		2005

			(In thousands)
ASSETS
Current assets:
	Cash and cash equivalents		$	55,222	$	21,378
	Accounts receivable:
		Affiliate		4,399		31,448
		Other		5,761		14,451
	Inventory			840		924
	Other current assets			1,312		2,324

	Total current assets			67,534		70,525
Restricted cash				—		44,559
Property, plant and equipment, net				356,385		344,743

Total assets			$	423,919	$	459,827


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
	Accounts payable:
		Affiliate	$	682	$	9,334
		Other		14,622		26,796
	Accrued liabilities			14,197		6,205
	Other current liabilities			2,071		2,735

	Total current liabilities			31,572		45,070
Noncurrent accrued liabilities				702		1,121
Commitments and contingent liabilities (Note 7)
Members’ capital				391,645		413,636

Total liabilities and members’ capital			$	423,919	$	459,827

See accompanying notes to consolidated financial statements.

F-30

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME


			Year Ended December 31,

			2003			2004			2005

			(In thousands)
Revenues:
	Product sales:
		Affiliate	$	54,145		$	57,838		$	70,848
		Third-party		1,943			1,611			4,271
	Gas and condensate transportation services:
		Affiliate		4,611			3,966			1,908
		Third-party		13,225			12,052			13,498
	Gathering and processing services:
		Affiliate		7,549			6,962			3,585
		Third-party		16,974			14,168			26,133
	Other revenues			4,731			3,279			2,502

	Total revenues			103,178			99,876			122,745

Costs and expenses:
	Product cost and shrink replacement:
		Affiliate		7,832			423			7,911
		Third-party		35,082			44,932			56,556
	Operating and maintenance expenses:
		Affiliate		3,035			3,098			3,355
		Third-party		12,794			14,756			6,810
	Depreciation and accretion			22,875			22,795			24,794
	General and administrative expenses — affiliate			1,400			1,424			2,053
	Taxes other than income			1,602			1,382			1,151
	Other — net			(101	)		(54	)		(33	)

	Total costs and expenses			84,519			88,756			102,597

	Operating income			18,659			11,120			20,148
Interest expense				9,611			—			—
Interest income				—			(550	)		(1,685	)
Foreign exchange loss				—			—			1,005

Income before cumulative effect of change in accounting principle				9,048			11,670			20,828
Cumulative effect of change in accounting principle				(267	)		—			(176	)

Net income			$	8,781		$	11,670		$	20,652

Other comprehensive income:
	Cash flow hedging activities:
		Losses reclassified to earnings during year	$	5,196		$	—		$	—
		Unrealized losses during year		(291	)		—			—

	Other comprehensive income			4,905			—			—

Comprehensive income			$	13,686		$	11,670		$	20,652

See accompanying notes to consolidated financial statements.

F-31

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL


														Accumulated
					Williams			Duke Energy						Other
		Williams			Operating			Field			Eni BB			Comprehensive
		Energy LLC			Partners LLC			Services, LLC			Pipelines LLC			Income (Loss)			Total

		(In thousands)
Balance, December 31, 2002		$	58,541		$	—		$	39,028		$	19,515		$	(4,905	)	$	112,179
	Contributions		127,055			—			84,695			42,360			—			254,110
	Net income — 2003		4,391			—			2,927			1,463			—			8,781
	Other comprehensive (loss)		—			—			—			—			4,905			4,905

Balance, December 31, 2003			189,987			—			126,650			63,338			—			379,975
	Net income — 2004		5,835			—			3,890			1,945			—			11,670

Balance, December 31, 2004			195,822			—			130,540			65,283			—			391,645
	Contributions		16,269			24,400			7,634			—			—			48,303
	Distributions		(30,030	)		(1,280	)		(15,654	)		—			—			(46,964	)
	Net income — 2005		8,063			4,651			6,909			1,029			—			20,652
	Sale of Eni 16.67% interest to subsidiaries of Williams Energy LLC		66,312			—			—			(66,312	)		—			—
	Sale of Williams Energy LLC and subsidiaries 40% interest to Williams Operating Partners LLC		(142,761	)		142,761			—			—			—			—
	Sale of Williams Energy LLC 6.67% interest to Duke Energy Field Services LLC		(25,869	)		—			25,869			—			—			—

Balance, December 31, 2005		$	87,806		$	170,532		$	155,298		$	—		$	—		$	413,636

See accompanying notes to consolidated financial statements.

F-32

DISCOVERY PRODUCER SERVICES LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS


			Year Ended December 31,

			2003			2004			2005

			(In thousands)
OPERATING ACTIVITIES:
Income before cumulative effect of change in accounting principle			$	9,048		$	11,670		$	20,828
Adjustments to reconcile to cash provided by operations:
	Depreciation and accretion			22,875			22,795			24,794
	Cash provided (used) by changes in assets and liabilities:
		Accounts receivable		7,860			(1,658	)		(35,739	)
		Inventory		(229	)		(240	)		(84	)
		Other current assets		(761	)		(1	)		(1,012	)
		Accounts payable		(1,415	)		1,256			29,355
		Other current liabilities		2,223			(668	)		664
		Accrued liabilities		4,424			2,469			(7,992	)

		Net cash provided by operating activities		44,025			35,623			30,814

INVESTING ACTIVITIES:
Property, plant and equipment:
	Capital expenditures			(14,746	)		(46,701	)		(12,906	)
	Change in accounts payable — capital expenditures			2,673			7,586			(8,532	)
Increase in restricted cash				—			—			(44,559	)

		Net cash used by investing activities		(12,073	)		(39,115	)		(65,997	)

FINANCING ACTIVITIES:
	Payments of long-term debt			(253,701	)		—			—
	Distributions to members			—			—			(46,964	)
	Capital contributions			254,110			—			48,303

		Net cash provided by financing activities		409			—			1,339

Increase (decrease) in cash and cash equivalents				32,361			(3,492	)		(33,844	)
Cash and cash equivalents at beginning of period				26,353			58,714			55,222

Cash and cash equivalents at end of period			$	58,714		$	55,222		$	21,378

Supplemental Disclosure of Cash Flow Information
Cash paid during the year for interest			$	9,855		$	—		$	—

See accompanying notes to consolidated financial statements.

F-33

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1.	Organization and Description of Business

Our company consists of Discovery Producer Services LLC (“DPS”), a Delaware limited liability company formed on June 24, 1996, and its wholly owned subsidiary, Discovery Gas Transmission LLC (“DGT”), a Delaware limited liability company formed on June 24, 1996. DPS was formed for the purpose of constructing and operating a 600 million cubic feet per day (“MMcf/d”) cryogenic natural gas processing plant near Larose, Louisiana and a 32,000 barrel per day (“bpd”) natural gas liquids fractionator plant near Paradis, Louisiana. DGT was formed for the purpose of constructing and operating a natural gas pipeline from offshore deep water in the Gulf of Mexico to DPS’s gas processing plant in Larose, Louisiana. The pipeline has a design capacity of 600 million cubic feet per day and consists of approximately 173 miles of pipe. DPS has since connected several laterals to the DGT pipeline to expand its presence in the Gulf. Herein, DPS and DGT are collectively referred to in the first person as “we,” “us” or “our” and sometimes as “the Company”.

Until April 14, 2005, we were owned 50 percent by Williams Energy, L.L.C. (a wholly owned subsidiary of The Williams Companies, Inc.), 33.33 percent by Duke Energy Field Services, LP (“Duke”) and 16.67 percent by Eni BB Pipeline, LLC (“Eni”) (formerly British-Borneo Pipeline LLC). Williams Energy is our operator. Herein, The Williams Companies, Inc. and its subsidiaries are collectively referred to as “Williams.”

On April 14, 2005, Williams acquired the 16.67 percent ownership interest in us previously held by Eni. As a result we became 66.67 percent owned by Williams and 33.33 percent owned by Duke.

On August 22, 2005, we distributed cash of $44 million to the members based on 66.67 percent ownership by Williams and 33.33 percent ownership by Duke.

On August 23, 2005, Williams Partners Operating LLC (a wholly owned subsidiary of Williams Partners L.P.) (“WPZ”) acquired a 40 percent interest in us previously held by Williams Energy. As a result we became 40 percent owned by WPZ, 26.67 percent owned by Williams and 33.33 percent owned by Duke. In connection with this Williams, Duke and WPZ amended our limited liability company agreement including provisions for (1) quarterly distributions of available cash, as defined in the amended agreement and (2) pursuit of capital projects for the benefit of one or more of our members when there is not unanimous consent.

On December 22, 2005, Duke acquired 6.67 percent interest in us previously held by Williams Energy. As a result we became 40 percent owned by WPZ, 20 percent owned by Williams and 40 percent owned by Duke.


Note 2.	Summary of Significant Accounting Policies

Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally accepted in the United States and include the accounts of DPS and its wholly owned subsidiary, DGT. Intercompany accounts and transactions have been eliminated.

Reclassifications. Certain prior years amounts have been reclassified to conform with the current year presentation. These include the reclassification of certain costs charged by Williams under operation and maintenance agreements. We have reclassified these costs, which relate to accounting services, computer systems and management services, to General and administrative expenses — affiliate on the Consolidated Statements of Income.

Use of Estimates. The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

F-34

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash and Cash Equivalents. Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.

Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue that generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of the customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. There was no allowance for doubtful accounts at December 31, 2005, and 2004.

Gas Imbalances. In the course of providing transportation services to customers, DGT may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. This results in gas transportation imbalance receivables and payables which are recovered or repaid in cash, based on market-based prices, or through the receipt or delivery of gas in the future and are recorded in the balance sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and the timing of delivery of gas based on operational conditions. In accordance with its tariff, DGT is required to account for this imbalance (cash-out) liability/receivable and refund or invoice the excess or deficiency when the cumulative amount exceeds $400,000. To the extent that this difference, at any year end, is less than $400,000 such amount would carry forward and be included in the cumulative computation of the difference evaluated at the following year end.

Inventory. Inventory includes fractionated products at our Paradis facility and is carried at the lower cost of market.

Restricted Cash. Restricted cash within non-current assets relates to escrow funds contributed by our members for the construction of the Tahiti pipeline lateral expansion. The restricted cash is classified as non-current because the funds will be used to construct a long-term asset. The restricted cash is primarily invested in short-term money market accounts with financials institutions.

Property, Plant and Equipment. Property, plant and equipment are carried at cost. We base the carrying value of these assets on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. The natural gas and natural gas liquids maintained in the pipeline facilities necessary for their operation (line fill) are included in property, plant and equipment.

Depreciation for DPS’s facilities and equipment is computed primarily using the straight-line method with 25-year lives. Depreciation for DGT’s facilities and equipment is computed using the straight-line method with 15-year lives.

Revenue Recognition. Revenue for sales of products are recognized in the period of delivery and revenues from the gathering, transportation and processing of gas are recognized in the period the service is provided based on contractual terms and the related natural gas and liquid volumes. DGT is subject to Federal Energy Regulatory Commission (“FERC”) regulations, and accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending cases. DGT records rate refund liabilities considering regulatory proceedings by DGT and other third parties, advice of counsel, and estimated total exposure as

F-35

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

discounted and risk weighted, as well as collection and other risks. There were no rate refund liabilities accrued at December 31, 2005 or 2004.

Derivative Instruments and Hedging Activities. The accounting for changes in the fair value of a derivative depends upon whether we have designated it in a hedging relationship and, further, on the type of hedging relationship. To qualify for designation in a hedging relationship, specific criteria must be met and the appropriate documentation maintained in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. We establish hedging relationships pursuant to our risk management policies. We initially and regularly evaluate the hedging relationships to determine whether they are expected to be, and have been, highly effective hedges. If a derivative ceases to be a highly effective hedge, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized in earnings each period.

We entered into interest rate swap agreements to reduce the impact of changes in interest rates on our floating rate debt. These instruments were designated as cash flow hedges under SFAS No. 133. The effective portion of the change in fair value of the derivatives is reported in other comprehensive income and reclassified into earnings and included in interest expense in the period in which the hedged item affects earnings. There are no amounts excluded from the effectiveness calculation, and there was no ineffective portion of the change in fair value in 2003. The interest rate swap expired on December 31, 2003, and we have no other derivative instruments.

Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment on an individual asset or asset group basis when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether impairment has occurred. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. These judgments and assumptions include such matters as the estimation of additional tie-ins of customers, strategic value, rate adjustments, and capital expenditures. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Accounting for Repair and Maintenance Costs. We expense the cost of maintenance and repairs as incurred; significant improvements are capitalized and depreciated over the remaining useful life of the asset.

Capitalization of Interest. We capitalize interest on major projects during construction. Interest is capitalized on borrowed funds. Rates are based on the average interest rate on debt.

Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. This election, to be treated as a pass-through entity, also applies to our wholly owned subsidiary, DGT. Therefore, no income taxes or deferred income taxes are reflected in the consolidated financial statements.

Foreign Currency Transactions. Transactions denominated in currencies other than the functional currency are recorded based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains or losses which are reflected in the Consolidated Statements of Income.

F-36

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Recent Accounting Standards. In December 2004, the Financial Accounting Standards Board (“FASB”) issued revised SFAS No. 123, “Share-Based Payment.” The Statement requires that compensation costs for all share-based awards to employees be recognized in the financial statements at fair value. The Statement, as issued by the FASB, was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission (“SEC”) adopted a new rule that delayed the effective date for revised SFAS No. 123 to the beginning of the next fiscal year that begins after June 15, 2005. We intend to adopt the revised Statement as of January 1, 2006. Payroll costs directly charged to us by Williams and general and administrative costs allocated to us by Williams (see Note 3) will include such compensation costs beginning January 1, 2006. Our adoption of this Statement will not have a material impact on our Consolidated Financial Statements.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which will be applied prospectively for inventory costs incurred in fiscal years beginning after June 15, 2005. The Statement amends Accounting Research Bulletin (“ARB”) No. 43, Chapter 4, “Inventory Pricing,” to clarify that abnormal amounts of certain costs should be recognized as current period charges and that the allocation of overhead costs should be based on the normal capacity of the production facility. The impact of this Statement on our Consolidated Financial Statements will not be material.


Note 3.	Related Party Transactions

We have no employees. Pipeline and plant operations were performed under operation and maintenance agreements with Williams. Under this agreement, we reimburse Williams for direct payroll and employee benefit costs incurred on our behalf. Most costs for materials, services and other charges are third-party charges and are invoiced directly to us. Additionally, we purchase a portion of the natural gas from Williams to meet our fuel and shrink requirements at our processing plant. These costs are presented as Operating and maintenance expenses — affiliate and Product costs and shrink replacement — affiliate on the Consolidated Statements of Income.

We pay Williams a monthly operation and management fee to cover the cost of accounting services, computer systems and management services provided to us. This fee is presented as General and administrative expenses — affiliate on the Consolidated Statements of Income.

We also pay Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a project by project basis and is capitalized as part of the construction costs.

F-37

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of the payroll costs and project fees charged to us by Williams and capitalized are as follows:


	Years Ended December 31,

	2003		2004		2005

Capitalized labor	$	204	$	288	$	351
Capitalized project fee		147		854		115

	$	351	$	1,142	$	466

We have various business transactions with our members and other subsidiaries and affiliates of our members, including an agreement with Williams pursuant to which Williams markets the NGLs and natural gas to which we take title. Under the terms of this agreement, Williams purchases the NGLs and excess natural gas and resells it, for its own account, to end users. During 2005, we had transactions with Texas Eastern Corporation, a subsidiary of Duke. These transactions primarily included processing and sales of natural gas liquids and transportation of gas and condensate. We have business transactions with Eni that primarily include processing and transportation of gas and condensate. The following table summarizes these related-party revenues during 2003, 2004 and 2005.


		Years Ended December 31,

		2003		2004		2005

		(In thousands)
Eni*		$	12,160	$	10,928	$	2,830
Texas Eastern Corporation			—		—		2,663
Williams			54,145		57,838		70,848

	Total	$	66,305	$	68,766	$	76,341


*	Through April 14, 2005

Note 4. Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2004 and 2005:


		2004		2005

		(In thousands)
Property, plant and equipment:
	Construction work in progress	$	11,739	$	5,444
	Buildings		4,393		4,406
	Land and land rights		1,165		1,530
	Transportation lines		286,661		302,252
	Plant and other equipment		195,429		198,837

			499,387		512,469
Less accumulated depreciation and amortization			143,002		167,726

		$	356,385	$	344,743

Commitments for construction and acquisition of property, plant and equipment for Tahiti are approximately $64 million at December 31, 2005.

We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003. As a result, we recorded a liability of $549,000 representing the present value of expected future asset retirement

F-38

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

obligations at January 1, 2003, and a decrease to earnings of $267,000 reflected as a cumulative effect of a change in accounting principle.

Effective December 31, 2005, we adopted Financial Accounting Standards Board Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $327,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $151,000 increase in property, plant and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $176,000 reduction to earnings is reflected as a cumulative effect of a change in accounting principle for the year ended 2005. If the Interpretation had been in effect at the beginning of 2003, the impact to our income from continuing operations and net income would have been immaterial.

The obligations relate to an offshore platform and our onshore processing and fractionation facilities. At the end of the useful life of each respective asset, we are legally or contractually obligated to dismantle the offshore platform, remove the onshore facilities and related surface equipment and restore the surface of the property.

A rollforward of our asset retirement obligation for 2004 and 2005 is presented below.


	2004		2005

	(In thousands)
Balance, January 1	$	621	$	702
Accretion expense		81		92
FIN No. 47 revisions		—		327

Balance, December 31	$	702	$	1,121


Note 5.	Leasing Activities

We lease the land on which the Paradis fractionator plant and the Larose processing plant are located. The initial terms of the leases are 20 years with renewal options for an additional 30 years. We entered into a 10 year leasing agreement for pipeline capacity from Texas Eastern Transmission, LP, as part of our Market Expansion project which began in June 2005 (see Note 7). The lease includes renewal options and options to increase capacity which would also increase rentals. The future minimum annual rentals under these non-cancelable leases as of December 31, 2005 are payable as follows:


	(In thousands)
2006	$	854
2007		854
2008		858
2009		858
2010		858
Thereafter		4,109

	$	8,391

Total rent expense for 2003, 2004 and 2005, including a cancelable platform space lease and month-to-month leases, was $1,050,000, $866,000 and $994,610, respectively.

F-39

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6.	Financial Instruments and Concentrations of Credit Risk


	*Financial Instruments Fair Value*

We used the following methods and assumptions to estimate the fair value of financial instruments:

Cash and cash equivalents. The carrying amounts reported in the balance sheets approximate fair value due to the short-term maturity of these instruments.

Restricted cash. The carrying amounts reported in the balance sheets approximate fair value as these instruments have interest rates approximating market.


	2004				2005

	Carrying		Fair		Carrying		Fair
Asset	Amount		Value		Amount		Value

	(In thousands)
Cash and cash equivalents	$	55,222	$	55,222	$	21,378	$	21,378
Restricted cash		—		—		44,559		44,559


	*Concentrations of Credit Risk*

Our cash equivalents and restricted cash consist of high-quality securities placed with various major financial institutions with credit ratings at or above AA by Standard & Poor’s or Aa by Moody’s Investor’s Service.

Substantially all of our accounts receivable result from gas transmission services for and natural gas liquids sales to our two largest customers at December 31, 2005 and 2004. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables. We did not incur any credit losses on receivables during 2005 and 2004.

Major Customers. Three customers, Williams, Eni and Pogo Producing Company accounted for approximately $54 million (52 percent), $12.2 million (12 percent) and $12 million (12 percent), respectively, of our total revenues in 2003. Williams and Eni accounted for approximately $57.8 million (58 percent) and $10.9 million (11 percent), respectively, of our total revenues in 2004, and $70.8 million (58 percent) and $8.5 million (7 percent), respectively, of our total revenues in 2005.

F-40

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 7.	Rate and Regulatory Matters and Contingent Liabilities

Rate and Regulatory Matters. In 2002, DGT filed a request with the FERC to change the lost and unaccounted-for gas percentage to be allocated to shippers from 0.5 percent to 0.1 percent to be effective for the period from July 1, 2002 to June 30, 2003. On June 26, 2002, the FERC approved DGT’s request. Additionally, DGT filed to reduce the lost and unaccounted-for gas percentage to zero to be effective for the period from July 1, 2003 to June 30, 2004. On June 19, 2003, the FERC approved this request. On June 1, 2004, DGT filed to maintain a lost and unaccounted-for percentage of zero for the period from July 1, 2004 to June 30, 2005 due to the continued absence of system gas losses. On June 22, 2004, the FERC approved this request. In this filing, DGT explained that management determined the reasons for the gas gains and established new procedures in July 2003 that significantly reduced the amount of gains occurring thereafter. On April 28, 2005, DGT filed to maintain a lost and unaccounted-for gas percentage of zero for the period from July 1, 2005 to June 30, 2006. DGT also filed to retain net system gains that are unrelated to the lost and unaccounted-for gas over-recovered from its shippers. These system gas gains totaled approximately $2.5 million, $2.5 million and $5.5 million respectively in 2005, 2004, and 2003. Certain shippers protested the net system gains filing and the FERC requested additional information in a May 27, 2005 Letter Order. DGT responded to the information request and on October 31, 2005, the FERC accepted the filing and no requests for rehearing were filed. As a result, we recognized system gains for 2002 — 2004 of $10.7 million in 2005. As of December 31, 2005 and 2004, DGT has deferred amounts of $6 million and $14.2 million, respectively, included in current accrued liabilities in the accompanying Consolidated Balance Sheets representing amounts collected from customers pursuant to prior years’ lost and unaccounted for gas percentage and unrecognized net system gains for 2005.

On July 23, 2003, DGT applied to the FERC for a Certificate of Public Convenience and Necessity authorizing DGT’s market expansion to acquire, lease or construct and/or to own and operate certain new delivery points, pipeline, compression services and metering and appurtenant facilities to enable DGT to deliver natural gas to four additional delivery points to new markets in southern Louisiana. This application was amended on December 30, 2003. On the same dates, DPS applied to the FERC and amended its application for a Limited Jurisdiction Certificate authorizing DPS to provide the compression services to DGT to enable DGT to provide service through the Market Expansion facilities. The capital cost of the expansion facilities was approximately $11 million. On May 6, 2004, the FERC granted DGT’s and DPS’s applications. On July 13, 2004, the FERC granted an additional approval on a rate design issue requested by DGT. On January 6, 2005, the FERC granted DGT permission to commence construction of the Market Expansion facilities. The Market Expansion facilities became operational in June 2005.

On November 25, 2003, the FERC issued Order No. 2004 promulgating new standards of conduct applicable to natural gas pipelines. On August 10, 2004, the FERC granted DGT a partial exemption allowing the continuation of DGT’s current ownership structure and management subject to compliance with many of the other standards of conduct. DGT continues to evaluate the effect of the partial exemption and the compliance with the remaining requirements. The effect of complying with the new standards is not expected to have a material effect on the consolidated financial statements.

On October 11, 2005, DGT applied to the FERC for permission to construct and operate facilities to allow temporary re-routing of gas to DGT from other facilities that were impacted by Hurricane Katrina. The FERC granted emergency exemptions and waivers permitting such actions the same day, allowing emergency service for up to one year or until certain third-party processing facilities were restored to service. DGT conducted two open seasons for shippers wishing to take advantage of the new service.

On January 16, 2006, DPS and DGT received notice of a claim by POGO Producing Company (“POGO”) relating to the results of a POGO audit performed in April 2004. POGO claims that DPS and DGT overcharged POGO and its working interest owners of approximately $600,000 relating to condensate

F-41

DISCOVERY PRODUCER SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

transportation and handling during 2000 — 2004. The underlying agreements limit audit claims to a two-year period from the date of the audit, and DPS and DGT dispute the validity of the claim.

Environmental Matters. We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any noncompliance under the various environmental laws and regulations.

Other. We are party to various other claims, legal actions and complaints arising in the ordinary course of business. Litigation, arbitration and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

F-42

REPORT OF INDEPENDENT AUDITORS

The Board of Directors of

The Williams Companies, Inc.

We have audited the accompanying balance sheets of Williams Four Corners Predecessor as of December 31, 2005 and 2004, and the related statements of income, owner’s equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of The Williams Companies, Inc.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Williams Four Corners Predecessor’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Williams Four Corners Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Williams Four Corners Predecessor at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

March 31, 2006

F-43

WILLIAMS FOUR CORNERS PREDECESSOR

BALANCE SHEETS


				December 31,

				2004		2005

				(In thousands)
ASSETS
Current assets:
	Accounts receivable:
		Trade, less allowance of $1,326 in 2004, $0 in 2005		$	15,599	$	15,855
		Other			250		1,368
	Product imbalance				7,548		—
	Prepaid expenses — current				1,530		1,609

			Total current assets		24,927		18,832
Property, plant and equipment, net					601,710		591,034
Prepaid expenses — noncurrent					18,657		25,228

Total assets				$	645,294	$	635,094

LIABILITIES AND OWNER’S EQUITY
Current liabilities:
	Accounts payable — trade			$	17,080	$	21,666
	Product imbalance				—		2,525
	Accrued liabilities				7,058		3,787

			Total current liabilities		24,138		27,978
Other noncurrent liabilities					626		1,526
Commitments and contingent liabilities (Note 10)
Owner’s equity					620,530		605,590

Total liabilities and owner’s equity				$	645,294	$	635,094

See accompanying notes to financial statements.

F-44

WILLIAMS FOUR CORNERS PREDECESSOR

STATEMENTS OF INCOME


			Year Ended December 31,

			2003			2004		2005

			(In thousands)
Revenues:
	Product sales:
		Affiliate	$	122,762		$	199,210	$	222,620
		Third-party		1,611			5,658		8,665
	Gathering and processing services:
		Affiliate		24,839			30,990		36,755
		Third-party		202,993			190,949		194,978
	Other revenues:
		Affiliate		1,488			924		15
		Third-party		441			492		170

Total revenues				354,134			428,223		463,203
Costs and expenses:
	Product cost:
		Affiliate		44,334			58,193		58,780
		Third-party		46,994			88,135		106,926
	Operating and maintenance expense:
		Affiliate		26,569			29,982		32,816
		Third-party		63,214			67,088		71,832
	Depreciation			41,552			40,675		38,960
	General and administrative expense:
		Affiliate		23,105			27,414		29,579
		Third-party		997			2,152		1,713
	Taxes other than income			6,822			6,790		7,746
	Other — net			11,800			11,238		636

Total costs and expenses				265,387			331,667		348,988

Income before cumulative effect of change in accounting principle				88,747			96,556		114,215
Cumulative effect of change in accounting principle				(330	)		—		(694	)

Net income			$	88,417		$	96,556	$	113,521

See accompanying notes to financial statements.

F-45

WILLIAMS FOUR CORNERS PREDECESSOR

STATEMENT OF OWNER’S EQUITY

(In thousands)


Balance, December 31, 2002.		$	671,709
	Net income — 2003.		88,417
	Distributions to The Williams Companies, Inc. — net		(115,685	)


Balance, December 31, 2003.			644,441
	Net income — 2004.		96,556
	Distributions to The Williams Companies, Inc. — net		(120,467	)


Balance, December 31, 2004.			620,530
	Net income — 2005.		113,521
	Distributions to The Williams Companies, Inc. — net		(128,461	)


Balance, December 31, 2005.		$	605,590

See accompanying notes to financial statements.

F-46

WILLIAMS FOUR CORNERS PREDECESSOR

STATEMENTS OF CASH FLOWS


			Year Ended December 31,

			2003			2004			2005

			(In thousands)
OPERATING ACTIVITIES:
Income before cumulative effect of change in accounting principle			$	88,747		$	96,556		$	114,215
Adjustments to reconcile to cash provided by operations:
	Depreciation			41,552			40,675			38,960
	Provision for loss on property, plant and equipment			7,598			7,636			917
	(Gain)/loss on sale of property, plant and equipment			(1,151	)		1,258			—
	Cash provided (used) by changes in current assets and liabilities:
		Accounts receivable		(279	)		1,298			(1,374	)
		Prepaid expenses		(1,530	)		—			(79	)
		Accounts payable		(3,266	)		9,435			4,586
		Product imbalance		(4,447	)		(7,983	)		10,073
		Accrued liabilities		61			(5,047	)		(3,271	)
Other, including changes in other noncurrent assets and liabilities				(5,019	)		(9,441	)		(7,988	)

Net cash provided by operating activities				122,266			134,387			156,039

INVESTING ACTIVITIES:
Property, plant and equipment:
	Capital expenditures			(8,079	)		(14,069	)		(27,578	)
	Proceeds from sales of property, plant and equipment			1,498			149			—

Net cash used by investing activities				(6,581	)		(13,920	)		(27,578	)

FINANCING ACTIVITIES:
Distributions to The Williams Companies, Inc. — net				(115,685	)		(120,467	)		(128,461	)

Net cash used by financing activities				(115,685	)		(120,467	)		(128,461	)

Increase in cash and cash equivalents				—			—			—
Cash and cash equivalents at beginning of year				—			—			—

Cash and cash equivalents at end of year			$	—		$	—		$	—

See accompanying notes to financial statements.

F-47

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS

Note 1. Basis of Presentation

The accompanying financial statements and related notes present the financial position, results of operations, cash flows and owner’s equity of a natural gas gathering and processing system in the Four Corners area of the United States held by Williams Field Services Company (“WFSC”). This system is collectively referred to as the “Four Corners” system. WFSC is a wholly owned subsidiary of The Williams Companies, Inc. (“Williams”). In February 2006, WFSC was converted into a limited liability company and was renamed Williams Field Services Company, LLC (“WFSC LLC”). Also in November 2005, WFSC LLC formed a new entity, Williams Four Corners LLC (“WFC LLC”), and in the second quarter of 2006, WFSC conveyed the Four Corners assets to it. These financial statements are prepared in connection with the proposed acquisition of a 25.1 percent interest in WFC LLC by Williams Partners L.P. (the “Partnership”). All significant intercompany transactions have been eliminated.

Note 2. Description of Business

We operate a natural gas gathering and processing system in New Mexico and Colorado. This gathering and processing system includes natural gas gathering pipelines, treating plants and processing plants. WFC LLC includes 3,500 miles of natural gas gathering pipelines with a capacity of approximately two billion cubic feet per day (“Bcfd”). The system has total compression of approximately 400,000 horsepower. The assets include two natural gas treating plants (Milagro and Esperanza) with a combined carbon dioxide treating capacity of 750 million cubic feet per day (“MMcfd”) and three natural gas processing plants: Ignacio, Kutz, and Lybrook. The Ignacio plant has an inlet capacity of 450 MMcfd and can produce approximately 22,000 barrels per day (“bpd”) of natural gas liquids (“NGLs”). The Kutz and Lybrook plants have a combined capacity of 310 MMcfd and can produce approximately 19,000 bpd of NGLs.

Note 3. Summary of Significant Accounting Policies

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.


	•	impairment assessments of long-lived assets;

	•	loss contingencies;

	•	asset retirement obligations; and

	•	environmental remediation obligations.

These estimates are discussed further throughout the accompanying notes.

Accounts Receivable. Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. No allowance for doubtful accounts is recognized at the time the revenue which generates the accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers and the amount and age of past due accounts. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been unsuccessful.

F-48

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

Product Imbalances. In the course of providing gathering, processing and treating services to our customers, we realize over and under deliveries of our customers’ products, and over and under purchases of shrink replacement gas when our purchases vary from operational requirements. In addition, we realize gains and losses, which we believe are related to inaccuracies inherent in the gas measurement process. These gains and losses impact our results of operations and are included in operating and maintenance expense in the Statement of Operations. The sum of these items is reflected as product imbalance receivables or payables on the Balance Sheets. These product imbalances are valued based on the market value of the products when the imbalance is identified and are evaluated for the impact of changes in market prices at the balance sheet date.

Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the carrying value of these assets on capitalized costs, useful lives and salvage values. Depreciation of property, plant and equipment is provided on a straight-line basis over estimated useful lives. Expenditures for maintenance and repairs are expensed as incurred. Expenditures that extend the useful lives of the assets or increase their functionality are capitalized. The cost of property, plant and equipment sold or retired and the related accumulated depreciation is removed from the accounts in the period of sale or disposition. Gains and losses on the disposal of property, plant and equipment are recorded in net income.

Revenue Recognition. Revenue for sales of products are recognized when the product has been delivered, and revenues from the gathering and processing of gas are recognized in the period the service is provided based on contractual terms and the related natural gas and liquid volumes.

Impairment of Long-Lived Assets. We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. The impairment evaluation of tangible long-lived assets is measured pursuant to the guidelines of Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the carrying value of the asset is recoverable. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes. If the carrying value is not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Prepaid expenses and leasing activities. Prepaid expenses include the unamortized balance of minimum lease payments made to date under a right-of-way renewal agreement. Land and right-of-way lease payments

F-49

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

made at the time of initial construction or placement of plant and equipment on leased land are capitalized as part of the cost of the assets. Lease payments made in connection with subsequent renewals or amendments of these leases are classified as prepaid expenses. The minimum lease payments for the lease term, including any renewal periods where the economic disincentive to not renew provides reasonable assurance of renewal, are expensed on a straight-line basis over the lease term.

Income Taxes. Our operations are currently included in the Williams’ consolidated federal income tax return. However, prospectively for federal tax purposes, we have elected to be treated as a partnership with each member being separately taxed on its ratable share of our taxable income. Therefore, we have excluded income taxes from these financial statements.

Earnings Per Share. During the periods presented, we were wholly owned by Williams. Accordingly, we have not calculated earnings per share.

Recent Accounting Standards. In December 2004, the Financial Accounting Standards Board (“FASB”) issued revised SFAS No. 123, “Share-Based Payment.” The Statement requires that compensation costs for all share-based awards to employees be recognized in the financial statements at fair value. The Statement, as issued by the FASB, was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, in April 2005, the Securities and Exchange Commission (“SEC”) adopted a new rule that delayed the effective date for revised SFAS No. 123 to the beginning of the next fiscal year that begins after June 15, 2005. We intend to adopt the revised Statement as of January 1, 2006. Payroll costs directly charged to us by Williams and general and administrative costs allocated to us by Williams (see Note 3) will include such compensation costs beginning January 1, 2006. Our adoption of this Statement will not have a material impact on our Financial Statements.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4,” which will be applied prospectively for inventory costs incurred in fiscal years beginning after June 15, 2005. The Statement amends Accounting Research Bulletin (“ARB”) No. 43, Chapter 4, “Inventory Pricing,” to clarify that abnormal amounts of certain costs should be recognized as current period charges and that the allocation of overhead costs should be based on the normal capacity of the production facility. The impact of this Statement on our Financial Statements will not be material.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29,” which is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, and will be applied prospectively. The Statement amends Accounting Principles Board (“APB”) Opinion No. 29, “Accounting for Nonmonetary Transactions.” The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but includes certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a replacement of APB Opinion No. 20 and FASB Statement No. 3,” which is effective prospectively for reporting a change in accounting principle for fiscal years beginning after December 15, 2005. The Statement changes the reporting of a change in accounting principle to require retrospective application to prior periods, financial statements, except for explicit transition provisions provided for in any existing accounting pronouncements, including those in the transition phase when SFAS No. 154 becomes effective.

F-50

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

Note 4. Related Party Transactions

The employees supporting our operations are employees of Williams. Their payroll costs are directly charged to us by Williams. Williams carries the accruals for most employee-related liabilities in its financial statements, including the liabilities related to the employee retirement and medical plans and paid time off accruals. Our share of these costs are charged to us through a benefit load factor with the payroll costs and are reflected in Operating and Maintenance Expense — Affiliate in the accompanying Statements of Income.

We are charged for certain administrative expenses by Williams and its Midstream segment of which we are a part. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams and Midstream at our request. Allocated charges are either (1) charges allocated to the Midstream segment by Williams and then reallocated from the Midstream segment to us or (2) Midstream-level administrative costs that are allocated to us. These expenses are allocated based on a three-factor formula, which considers revenues, property, plant and equipment and payroll. These costs are reflected in General and Administrative Expenses — Affiliate in the accompanying Statements of Income. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams and its Midstream segment.

The operation of the Four Corners gathering system includes the routine movement of gas across gathering systems. We refer to this activity as “crosshauling”. Crosshauling typically involves the movement of some natural gas between gathering systems at established interconnect points to optimize flow. As a result, we must purchase gas for delivery to customers at certain plant outlets and we have excess volumes to sell at other plant outlets. These purchase and sales transactions are conducted for us by Williams Power Company (“Power”), a wholly owned indirect subsidiary of Williams, at current market prices and are included in Product Sales — Affiliate and Product Cost — Affiliate on the Statements of Income. Historically, Power has not charged us a fee for providing this service, but has occasionally benefited from price differentials that historically existed from time to time between the plant outlets.

We also purchase natural gas for fuel and shrink replacement from Power. These purchases are made at market rates at the time of purchase. These costs are reflected in Operating and Maintenance Expense — Affiliate in the accompanying Statements of Income.

Prior to April 2003, we purchased steam from Power for use at our Milagro treating plant. The steam was produced from the operation of the Milagro cogeneration facility owned by Power. Beginning in April 2003, we purchased natural gas for steam conversion services. The natural gas cost charged to us by Power has been favorably impacted by Power’s fixed price natural gas fuel contracts. This impact was approximately $9.0 million annually during the periods presented as compared to estimated market prices. These agreements expire in the fourth quarter of 2006. We are evaluating the means by which we will obtain waste heat to generate steam beyond the life of this agreement and expect that our Milagro natural gas fuel costs will increase due to our expectation that future market prices will exceed prices associated with these agreements.

We sell the NGLs to which we take title to Williams Midstream Marketing and Risk Management, LLC (“WMMRM”), a wholly owned indirect subsidiary of Williams. Revenues associated with these activities are reflected as Product Sales — Affiliate revenues on the Statements of Income.

One of our major customers is Williams Production Company (“WPC”), a wholly owned subsidiary of Williams. WPC is one of the largest natural gas producers in the San Juan Basin and we provide natural gas gathering, treating and processing services to WPC under several contracts. Revenues associated with these activities are reflected in the Gathering and Processing Services — Affiliate revenues on the Statements of Income.

F-51

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

A summary of affiliate general and administrative expenses directly charged and allocated to us, steam generation expenses and other operating and maintenance expenses directly charged to us for the periods stated is as follows:


		2003		2004		2005

		(In thousands)
General and administrative expenses:
	Allocated	$	18,578	$	22,215	$	25,964
	Directly charged		4,527		5,199		3,615
Operating and maintenance expenses:
	Other natural gas and steam expenses		9,003		11,798		14,518
	Salaries and benefits and other		17,566		18,184		18,298

Prior to closing, we participated in Williams’ cash management program; hence, we maintained no cash balances. As of December 31, 2004 and December 31, 2005, our net advances to Williams under an unsecured promissory note agreement which allows for both advances to and from Williams have been classified as a component of owner’s equity because, although the advances are due on demand, Williams has not historically required repayment or repaid amounts owed to us. In addition, when our assets are conveyed to WFC LLC in 2006, the outstanding advances are expected to be distributed to Williams. Changes in the advances to Williams are presented as distributions to Williams in the Statement of Owner’s Equity and Statements of Cash Flows.

Note 5. Other Costs and Expenses — Net

Other — Net reflected on the Statements of Income consists of the following items:


	2003		2004		2005

	(In thousands)
Impairment of LaMaquina carbon dioxide treating facility	$	4,128	$	7,636	$	—
Impairment of membrane units		3,470		—		—
Other		4,202		3,602		636

Total	$	11,800	$	11,238	$	636

LaMaquina Carbon Dioxide Treating Facility. This facility consisted of two amine trains and seven gas powered generator sets. The facility was shut down in 2002 due to a reduced need for treating. In 2003, management estimated that only one amine train would be returned to service. As a result, we recognized an impairment of the carrying value of the other train to its estimated fair value based on estimated salvage values and sales prices. Further developments in 2004 led management to conclude that the facility would not return to service. Thus, we recognized an additional impairment of the carrying value to its estimated fair value. The facility was sold in the first quarter of 2006 resulting in the recognition of a gain on the sale in 2006.

Membrane Units. In 2003, management conducted an impairment assessment on several idle carbon dioxide removal (membrane) units. The estimated fair value was based on the proceeds from the sale of two similar units earlier in 2003. An asset impairment was recognized to adjust the carrying value to the estimated fair value.

Other. In 2003, other expense included $4.2 million of bad debt expense and contingency accruals. In 2004, other expense included losses on asset dispositions and materials and supplies inventory adjustments.

F-52

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

Note 6. Property, Plant and Equipment

Property, plant and equipment, at cost, as of December 31, 2004 and 2005 is as follows:


		December 31				Estimated
						Depreciable
		2004		2005		Lives

		(In thousands)
Land and right of way		$	39,367	$	41,990
Gathering pipelines and related equipment			761,837		777,701		30 years
Processing plants and related equipment			163,227		164,257		30 years
Buildings and other equipment			92,694		88,578		3-30 years
Construction work in progress			9,728		18,437

	Total property, plant and equipment		1,066,853		1,090,963
Accumulated depreciation			465,143		499,929

	Net property, plant and equipment	$	601,710	$	591,034

We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003. As a result, we recorded a liability of $330,000 representing the present value of expected future asset retirement obligations at January 1, 2003, and a decrease to earnings of $330,000 reflected as a cumulative effect of a change in accounting principle.

Effective December 31, 2005, we adopted FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $788,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $94,000 increase in property, plant and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred. The net $694,000 reduction to earnings is reflected as a cumulative effect of a change in accounting principle for the year ended 2005. If the Interpretation had been in effect at the beginning of 2003, the impact to our income from continuing operations and net income would have been immaterial.

The ARO at December 31, 2004 and 2005 is $330,000 and $1.1 million, respectively. The increase in the obligation in 2005 is due primarily to the adoption of FIN No. 47. The obligations relate to gas processing and compression facilities located on leased land and wellhead connections on federal land. At the end of the useful life of each respective asset, we are legally or contractually obligated to remove certain surface equipment and cap certain gathering pipelines at the wellhead connection.

F-53

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

Note 7. Accrued Liabilities

Accrued liabilities as of December 31, 2004 and 2005 are as follows:


	December 31

	2004		2005

	(In thousands)
Taxes other than income	$	1,961	$	2,056
Environmental remediation — current portion		1,484		328
Reserve for customer refunds — current portion		2,583		—
Casualty loss accrual		676		435
Other		354		968

	$	7,058	$	3,787

Note 8. Leasing Activities

We lease the land on which a significant portion of our pipeline assets are located. The primary landowners are the Bureau of Land Management (“BLM”) and several Indian tribes. The BLM leases are for thirty years with renewal options. The most significant of the Indian tribal leases will expire at the end of 2022 and will then be subject to renegotiation. We lease compression units under a lease agreement with Hanover Compression, Inc. The initial term of this agreement expires on June 30, 2006. Following the initial term, the agreement can be continued on a month-to-month basis unless terminated by either party upon thirty days advance written notice. We also lease other minor office and warehouse equipment under non-cancelable leases. The future minimum annual rentals under these non-cancelable leases as of December 31, 2005 are payable as follows:


	(Thousands)

2006	$	12,223
2007		1,169
2008		791
2009		421
2010		338
Thereafter		3,120

	$	18,062

Total rent expense for the years ended 2003, 2004 and 2005 was $15.8 million, $14.7 million and $18.8 million, respectively.

Note 9. Major Customers and Concentrations of Credit Risk

For the years ended December 31, 2004 and 2005, substantially all of our accounts receivable result from product sales and gathering and processing services provided to our five largest customers. This concentration of customers may impact our overall credit risk either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required for receivables, but customers’ financial conditions and credit worthiness are evaluated regularly. Our credit policy and the relatively short duration of receivables mitigate the risk of uncollected receivables.

Our largest customer, on a percentage of revenues basis, is WMMRM, which purchases and resells substantially all of the NGLs to which we take title. WMMRM accounted for 35 percent, 47 percent and

F-54

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

48 percent of revenues in 2003, 2004 and 2005, respectively. The percentages for the remaining three largest customers are as follows:


	2003			2004			2005

Customer A		19	%		15	%		15	%
Customer B		12			12			11
Customer C		10			5			4

Note 10. Commitments and Contingent Liabilities

Environmental Matters. We have been aggressively pursuing closure of unlined surface impoundments, or pits, in New Mexico. Current federal regulations require that certain impoundments located near named rivers and catchment areas be taken out of use, and current state regulations required all unlined, earthen pits to be either permitted or closed by December 31, 2005. Our pit inventory is currently being updated to maintain compliance.

We are also a participant in certain environmental activities associated with groundwater contamination at certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at seven and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and sustain closure criteria levels and state regulator approval is received, the sites will be properly abandoned. We expect the remaining sites will be closed within four to eight years.

At December 31, 2005, we have accrued liabilities totaling $735,000 for these environmental activities. It is reasonably possible that we will incur losses in excess of our accrual for these matters. However, a reasonable estimate of such amounts cannot be determined at this time because actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by governmental authorities and other factors.

We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not currently aware of any material noncompliance under the various applicable environmental laws and regulations.

Will Price. In 2001, we were named, along with other subsidiaries of Williams, as defendants in a nationwide class action lawsuit in Kansas state court that had been pending against other defendants, generally pipeline and gathering companies, since 2000. The plaintiffs alleged that the defendants have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs and sought an unspecified amount of damages. The defendants have opposed class certification and a hearing on plaintiffs’ second motion to certify the class was held on April 1, 2005. We are awaiting a decision from the court.

Grynberg. In 1998, the Department of Justice informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly owned subsidiaries, including us. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. Grynberg has also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the Department of Justice announced that it was declining to intervene in any of the Grynberg cases, including the action filed in federal court in Colorado against us. Also in 1999, the Panel on Multi-District Litigation

F-55

WILLIAMS FOUR CORNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. Grynberg’s measurement claims remain pending against us and the other defendants; the court previously dismissed Grynberg’s royalty valuation claims. In May 2005, the court-appointed special master entered a report which recommended that the claims against certain Williams’ subsidiaries, including us, be dismissed. The District Court is considering whether to affirm or reject the special master’s recommendations and heard oral arguments in December 2005.

Other. We are not currently a party to any other legal proceedings but are a party to various administrative and regulatory matters that have arisen in the ordinary course of our business.

Summary. Litigation, arbitration, regulatory matters and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon our future financial position.

F-56

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Williams Partners GP LLC

We have audited the accompanying consolidated balance sheet of Williams Partners GP LLC as of December 31, 2005. The consolidated balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Williams Partners GP LLC, in conformity with U.S. generally accepted accounting principles.


	/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 27, 2006

F-57

WILLIAMS PARTNERS GP LLC

CONSOLIDATED BALANCE SHEET

December 31, 2005

(In thousands)


ASSETS
	Current assets:
		Cash and cash equivalents		$	6,839
		Accounts receivable:
			Trade		1,840
			Other		2,104
	Product imbalance				760
	Gas purchase contract — affiliate				5,320
	Prepaid expenses				1,133

	Total current assets				17,996
Investment in Discovery Producer Services					150,260
Property, plant and equipment, net					67,931
Gas purchase contract — noncurrent — affiliate					4,754

Total assets				$	240,941

LIABILITIES AND OWNERS’ EQUITY
	Current liabilities:
		Accounts payable:
			Trade	$	3,906
			Affiliate		6,562
		Deferred revenue			3,552
		Accrued liabilities			2,373

	Total current liabilities				16,393
Environmental remediation liabilities					3,964
Other noncurrent liabilities					762
Minority interest					112,160
Commitments and contingent liabilities (Note 11)
Owners’ equity					107,662

Total liabilities and owners’ equity				$	240,941

See accompanying notes to the consolidated balance sheet.

F-58

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET


Note 1.	Organization

We are a Delaware limited liability company formed on February 23, 2005, to become the general partner of Williams Partners L.P. (the “Partnership”). We own a 2 percent general partner interest in the Partnership. However, due to the substantive control granted to us by the partnership agreement we consolidate our interest in the Partnership. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of the Partnership. We are a wholly owned subsidiary of The Williams Companies, Inc. (“Williams”).

The Partnership is a Delaware limited partnership formed in February 2005, to acquire and own (1) a 40 percent interest in Discovery; (2) the Carbonate Trend gathering pipeline off the coast of Alabama; (3) three integrated natural gas liquids (“NGL”) product storage facilities near Conway, Kansas; and (4) a 50 percent undivided ownership interest in a fractionator near Conway, Kansas. Prior to the closing of the Partnership’s initial public offering (the “IPO”) in August 2005, the 40 percent interest in Discovery was held by Williams Energy, L.L.C. (“Energy”) and Williams Discovery Pipeline LLC; the Carbonate Trend gathering pipeline was held in Carbonate Trend Pipeline LLC (“CTP”), which was owned by Williams Mobile Bay Producers Services, L.L.C.; and the NGL product storage facilities and the interest in the fractionator were owned by Mid-Continent Fractionation and Storage, LLC (“MCFS”). All of these are wholly owned indirect subsidiaries of The Williams Companies, Inc. (collectively “Williams”). Additionally, Williams Partners Operating LLC, an operating limited liability company (wholly owned by the Partnership) through which all the Partnership’s activities are conducted, was formed.


	*Initial Public Offering and Related Transactions*

On August 23, 2005, the Partnership completed an IPO of 5,000,000 common units representing limited partner interests in us at a price of $21.50 per unit. The proceeds of $100.2 million, net of the underwriters’ discount and a structuring fee totaling $7.3 million, were used to:


	•	distribute $58.8 million to Williams, in part to reimburse Williams for capital expenditures relating to the assets contributed to us and for a gas purchase contract contributed to us;

	•	provide $24.4 million to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;

	•	provide $12.7 million of additional working capital; and

	•	pay $4.3 million of expenses associated with the IPO and related formation transactions.

Concurrent with the closing of the IPO, the 40 percent interest in Discovery and all of the interests in CTP and MCFS were contributed to the Partnership by Williams’ subsidiaries in exchange for an aggregate of 2,000,000 common units and 7,000,000 subordinated units. The public, through the underwriters of the offering, contributed $107.5 million ($100.2 million net of the underwriters’ discount and a structuring fee) to the Partnership in exchange for 5,000,000 common units, representing a 35 percent limited partner interest in the Partnership. Additionally, at the closing of the IPO, the underwriters fully exercised their option to purchase 750,000 common units from Williams’ subsidiaries at the IPO price of $21.50 per unit, less the underwriters’ discount and a structuring fee.


Note 2.	Description of Business

F-59

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

Our Carbonate Trend gathering pipeline is an unregulated sour gas gathering pipeline consisting of approximately 34 miles of pipeline off the coast of Alabama.

Our Conway fractionation facility is located near McPherson, Kansas, and has a capacity of approximately 107,000 bpd. We own a 50 percent undivided interest in these facilities representing capacity of approximately 53,500 bpd. ConocoPhillips and ONEOK, Inc. are the other owners. Williams operates the facility pursuant to an operating agreement that extends until May 2011. The fractionator separates mixed NGLs into five products: ethane, propane, normal butane, isobutane and natural gasoline. Portions of these products are then transported and stored at our Conway storage facilities.


Note 3.	Summary of Significant Accounting Policies

Basis of Presentation. The consolidated balance sheet has been prepared based upon accounting principles generally accepted in the United States and include the accounts of the parent and our controlled subsidiaries. Intercompany accounts and transactions have been eliminated.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated balance sheet and accompanying notes. Actual results could differ from those estimates.

Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the balance sheet and for which it would be reasonably possible that future events or information could change those estimates include:


	•	impairment assessments of investments and long-lived assets;

	•	loss contingencies;

	•	environmental remediation obligations; and

	•	asset retirement obligations.

These estimates are discussed further throughout the accompanying notes.

F-60

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

facility, we incur the liabilities of the fractionator (except for certain fuel costs purchased directly by one of the co-owners) and are reimbursed by the co-owners for their proportional share of the total costs and expenses. Each co-owner is responsible for the marketing of their proportional share of the fractionator’s capacity. Accordingly, we reflect our proportionate share of the fractionator property, plant and equipment in the Consolidated Balance Sheet. Liabilities in the Consolidated Balance Sheet include those incurred on behalf of the co-owners with corresponding receivables from the co-owners. Accounts receivable also includes receivables from our customers for fractionation services.

Cash and Cash Equivalents. Cash and cash equivalents include demand and time deposits, certificates of deposit and other marketable securities with maturities of three months or less when acquired.

Gas purchase contract. In connection with the Partnership’s IPO, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. The gas purchase contract is for the purchase of 80,000 MMBtu per month and terminates on December 31, 2007. The initial value of this contract is being amortized to expense over the contract life.

F-61

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

Product Imbalances. In the course of providing fractionation and storage services to our customers, we realize product gains and losses that are reflected as product imbalance receivables or payables on the Consolidated Balance Sheet. These imbalances are valued based on the market price of the products when the imbalance is identified and are evaluated for the impact of a change in market prices at the balance sheet date. Certain of these product gains and losses arise due to the product blending process at the fractionator. Others are realized when storage caverns are emptied. Storage caverns are emptied periodically to determine whether any product gains or losses have occurred, and as these caverns are emptied, it is possible that the resulting product gains or losses could have a material impact to the results of operations for the period during which the cavern drain is performed.

Income Taxes. We are not a taxable entity for federal and state income tax purposes. The tax on our net income is borne by our owner, The Williams Companies, Inc.

Owners’ Equity. Because we are part of a controlled group that includes other wholly owned subsidiaries of Williams, the ownership interests that the other entities in this controlled group have in the Partnership are classified as Owners’ equity on the Consolidated Balance Sheet.

F-62

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)


Note 4.	Related Party Transactions

Williams charges its affiliates, including us and its Midstream segment, of which we are a part, for certain corporate administrative expenses that are directly identifiable or allocable to the affiliates. Direct costs charged from Williams represent the direct costs of services provided by Williams on our behalf. Prior to the IPO, a portion of the charges allocated to the Midstream segment were then reallocated to us. These allocated corporate administrative expenses are based on a three-factor formula, which considered revenues; property, plant and equipment; and payroll. Certain of these costs are charged back to the other Conway fractionator co-owners. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.

F-63

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

We purchase fuel for the Conway fractionator, including fuel on behalf of the co-owners, from Williams Power Company (“Power”), a wholly owned subsidiary of Williams. These purchases are made at market rates at the time of purchase. In connection with the IPO, Williams transferred to us a gas purchase contract for the purchase of a portion of our fuel requirements at the Conway fractionator at a market price not to exceed a specified level. The initial value of this contract is being amortized to expense over the contract life. The carrying value of this contract is reflected as Gas purchase contract — affiliate and Gas purchase contract — noncurrent — affiliate on the Consolidated Balance Sheet.

We sell surplus propane and other NGLs to Power, which takes title to the product and resells it, for its own account, to end users. Correspondingly, we purchase ethane and other NGLs from Power to replenish deficit product positions. The transactions conducted between us and Power are transacted at current market prices for the products.

Note 5. Investment in Discovery Producer Services

Of the total ownership interest owned by Williams prior to the transfer of 40 percent to us, a portion was acquired by Williams in April 2005 resulting in a revised basis used for the calculation of the 40 percent interest transferred to us in connection with the Partnership’s IPO. As a result, the carrying value of our 40 percent interest in Discovery and Owners’ equity decreased $11.0 million during the second quarter of 2005.

On August 22, 2005, Discovery made a distribution of approximately $43.8 million to Williams and the other member of Discovery at that date. This distribution was associated with Discovery’s operations prior to the Partnership’s IPO; hence, we did not receive any portion of this distribution. The distribution resulted in a revised basis used for the calculation of the 40 percent interest transferred to us in connection with the Partnership’s IPO. As a result, the carrying value of our 40 percent interest in Discovery and Owners’ equity decreased $17.5 million during the third quarter of 2005.

F-64

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

Due to the significance of Discovery’s equity earnings to our financial position, the summarized financial position for 100 percent of Discovery at December 31, 2005 is presented below (in thousands).


	December 31,
	2005

Current assets	$	70,525
Non-current restricted cash		44,559
Property, plant and equipment		344,743
Current liabilities		(45,070	)
Non-current liabilities		(1,121	)

Members’ capital	$	413,636


Note 6.	Property, Plant and Equipment

Property, plant and equipment, at cost, as of December 31, 2005 is as follows (in thousands):


				Estimated
				Depreciable
				Lives

Land and right of way		$	2,373
Fractionation plant and equipment			16,646		30 years
Storage plant and equipment			65,892		30 years
Pipeline plant and equipment			23,684		20-30 years
Construction work in progress			1,886
Other			1,492		5-45 years

	Total property, plant and equipment		111,973
Accumulated depreciation			44,042

	Net property, plant and equipment	$	67,931

Effective December 31, 2005, we adopted FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies that an entity is required to recognize a liability for the fair value of a conditional ARO when incurred if the liability’s fair value can be reasonably estimated. The Interpretation clarifies when an entity would have sufficient information to reasonably estimate the fair value of an ARO. As required by the new standard, we reassessed the estimated remaining life of all our assets with a conditional ARO. We recorded additional liabilities totaling $573,000 equal to the present value of expected future asset retirement obligations at December 31, 2005. The liabilities are slightly offset by a $16,000 increase in property, plant and equipment, net of accumulated depreciation, recorded as if the provisions of the Interpretation had been in effect at the date the obligation was incurred, and the net $557,000 reduced earnings in 2005. If the Interpretation had been in effect at the beginning of 2005, the impact to our balance sheet would have been immaterial.

F-65

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

A rollforward of our asset retirement obligation for 2005 is presented below (in thousands).


Balance, January 1	$	760
Liabilities incurred during the period		91
Liabilities settled during the period		(204	)
Accretion expense		1
Estimate revisions		(460	)
FIN No. 47 revisions		574

Balance, December 31	$	762


Note 7.	Accrued Liabilities

Accrued liabilities as of December 31, 2005 are as follows (in thousands):


Environmental remediation — current portion	$	1,424
Employee costs — affiliate		387
Taxes other than income		375
Other		187

	$	2,373


Note 8.	Long-Term Incentive Plan

In November 2005, we adopted the Williams Partners GP LLC Long-Term Incentive Plan (the “Plan”) for employees, consultants, and directors who perform services for us. The Plan permits the grant of awards covering an aggregate of 700,000 common units. These awards may be in the form of options, restricted units, phantom units or unit appreciation rights. Our Board of Directors Compensation Committee administers the Plan.

During November and December 2005, our we granted 6,146 restricted units pursuant to the Plan to members of our Board of Directors who are not officers or employees. These restricted units vest six months from grant date.


Note 9.	Major Customers, Concentration of Credit Risk and Financial Instruments


	*Major Customers*

In 2005, four customers, Williams Power Company (an affiliate company), SemStream, L.P., Enterprise and BP Products North America, Inc. (BP) accounted for approximately 25.9 percent, 17.1 percent, 14.1 percent and 13.5 percent, respectively, of our total revenues. SemStream, L.P., BP, Enterprise and Williams Power Company are customers of the NGL Services segment. Chevron is a customer of the Gathering and Processing segment.

Our Carbonate Trend gathering pipeline has only two customers. The loss of either of these customers, unless replaced, would have a significant impact on the Gathering and Processing segment.


	*Concentration of Credit Risk*

F-66

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)

The following table summarizes the concentration of accounts receivable by service and segment as of December 31, 2005 (in thousands).


Gathering and Processing:
	Natural gas gathering	$	525
NGL Services:
	Fractionation services		532
	Amounts due from fractionator partners		1,834
	Storage		793
	Other		260

		$	3,944


	*Financial Instruments*

The carrying amount of cash and cash equivalents reported in the balance sheet approximates fair value due to the short-term maturity of these instruments.

The following table summarizes our financial instruments as of December 31, 2005 (in thousands).


	Carrying		Fair
	Amount		Value

Cash and cash equivalents	$	6,839	$	6,839


Note 10.	Credit Facilities


	•	ratio of debt to net worth no greater than (i) 70 percent through December 31, 2005, and (ii) 65 percent for the remaining term of the agreement;

	•	ratio of debt to net worth no greater than 55 percent for Northwest Pipeline Corporation, a wholly owned subsidiary of Williams, and Transco; and

F-67

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)


	•	ratio of EBITDA to interest, on a rolling four quarter basis, no less than (i) 2.0 for any period after March 31, 2005 through December 31, 2005, and (ii) 2.5 for the remaining term of the agreement.


	*Leasing Activities*


2006	$	30
2007		29
2008		27
2009		10
2010		—

	$	96


Note 11.	Commitments and Contingencies

F-68

WILLIAMS PARTNERS GP LLC

NOTES TO CONSOLIDATED BALANCE SHEET — (Continued)


Note 12.	Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. The Segments are managed separately because each segment requires different industry knowledge, technology and marketing strategies. The accounting policies of the segments are the same as those described in Note 3, Summary of Significant Accounting Policies. Long-lived assets are comprised of property, plant and equipment.


	Gathering &		NGL
	Processing		Services		Total

	(In thousands)
2005
Segment Assets	$	171,009	$	64,579	$	235,588
Other assets and eliminations						5,353

Total assets					$	240,941

Equity method investments	$	150,260	$	—	$	150,260
Additions to long-lived assets		—		3,688		3,688

F-69

APPENDIX A

GLOSSARY OF TERMS

Adjusted EBITDA: For Discovery and Four Corners, net income plus interest (income) expense, depreciation and accretion, further adjusted for certain non-cash, non-recurring items.

Adjusted EBITDA Excluding Equity Investments: For Williams Partners L.P., net income (loss) plus interest (income) expense, depreciation and accretion and the amortization of a natural gas contract, less our equity earnings in Discovery and Four Corners, further adjusted for certain non-cash, non-recurring items.

Adjusted operating surplus: For any period, operating surplus generated during that period is adjusted to:

(a) decrease operating surplus by:


	(1) any net increase in working capital borrowings with respect to that period; and

	(2) any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; and

(b) increase operating surplus by:


	(1) any net decrease in working capital borrowings with respect to that period; and

	(2) 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 does not include that portion of operating surplus included in clauses (a)(1) and (a)(2) of the definition of operating surplus.

Available cash: For any quarter ending prior to liquidation:

(a) the sum of:


	(1) all cash and cash equivalents of Williams Partners L.P. and its subsidiaries on hand at the end of that quarter; and

	(2) all additional cash and cash equivalents of Williams Partners L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter resulting from working capital borrowings made after the end of that quarter;

(b) less the amount of cash reserves established by our general partner to:


	(1) provide for the proper conduct of the business of Williams Partners L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Williams Partners L.P. and its subsidiaries) after that quarter;

	(2) comply with applicable law or any debt instrument or other agreement or obligation to which Williams Partners L.P. or any of its subsidiaries is a party or its assets are subject; and

	(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however, that our general partner may not establish cash reserves for distributions on the subordinated units unless our general partner has determined that the establishment of reserves will not prevent Williams Partners L.P. from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon with respect to that quarter; and

provided, further, that disbursements made by Williams Partners L.P. or any of its subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of

A-1

determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.

Barrel: One barrel of petroleum products equals 42 U.S. gallons.

Bcf/d: One billion cubic feet of natural gas per day.

bpd: Barrels per day.

Btu: When used in terms of volumes, Btu is used to refer to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.

Capital account: The capital account maintained for a partner under the partnership agreement. The capital account in respect of a general partner interest, a common unit, a subordinated unit, an incentive distribution right or other partnership interest will be the amount which that capital account would be if that general partner interest, common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Williams Partners L.P. held by a partner.

Capital surplus: All available cash distributed by us from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus as of the end of the quarter before that distribution. Any excess available cash will be deemed to be capital surplus.

¢/ MMBtu: Cents per one million British Thermal Units.

Current market price: For any class of units listed on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

Distributable Cash Flow: For Discovery and Four Corners, net income (loss) plus depreciation and accretion and less maintenance capital expenditures.

Distributable Cash Flow Excluding Equity Investments: For Williams Partners L.P., net income (loss) plus the non-cash affiliate interest expense associated with the advances from affiliate to our predecessor that were forgiven by Williams, depreciation and accretion, the amortization of a natural gas contract, and reimbursements from Williams under our omnibus agreement, less our equity earnings in Discovery and Four Corners and maintenance capital expenditures, further adjusted for certain non-cash, non-recurring items.

Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products.

GAAP: Generally accepted accounting principles in the United States.

General and administrative expenses: General and administrative expenses consist of employment costs, cost of facilities, as well as legal, information technology, audit and other administrative costs.

Incentive distribution right: A non-voting limited partner partnership interest issued to our general partner. The partnership interest will confer upon its holder only the rights and obligations specifically provided in the partnership agreement for incentive distribution rights.

Incentive distributions: The distributions of available cash from operating surplus initially made to our general partner that are in excess of our general partner’s aggregate 2% general partner interest.

(a) borrowings, refinancings or refundings of indebtedness (other than for working capital borrowings and other than for items purchased on open account in the ordinary course of business) by Williams Partners L.P. or any of its subsidiaries and sales of any debt securities of Williams Partners L.P. or any of its subsidiaries;

(b) sales of equity interests by Williams Partners L.P. or any of its subsidiaries; or

(c) sales or other voluntary or involuntary dispositions of any assets of Williams Partners L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the

A-2

ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements).

Long-haul natural gas pipelines: Generally, interstate natural gas pipelines that serve end markets.

LNG: Liquefied natural gas.

MMBtu: One million British Thermal Units.

MMBtu/d: One million British Thermal Units per day.

MMcf: One million cubic feet of natural gas.

MMcf/d: One million cubic feet of natural gas per day.

NGLs: Natural gas liquids.

Operating expenditures: All expenditures of Williams Partners L.P. and its subsidiaries, including, but not limited to, taxes, reimbursements of our general partner, repayment of working capital borrowings, debt service payments and capital expenditures, subject to the following:

(a) Payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings will not constitute operating expenditures.

(b) Operating expenditures will not include:


	(1) capital expenditures made for acquisitions or for capital improvements;

	(2) payment of transaction expenses relating to interim capital transactions; or

	(3) distributions to partners.

Where capital expenditures are made in part for acquisitions or for capital improvements and in part for other purposes, our general partner, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each and, with respect to the part of such capital expenditures made for other purposes, the period over which the capital expenditures made for other purposes will be deducted as an operating expenditure in calculating operating surplus.

Operating surplus: For any period prior to liquidation, on a cumulative basis and without duplication:

(a) the sum of


	(1) $10.0 million;

	(2) all the cash of Williams Partners L.P. and its subsidiaries on hand as of the closing date of its initial public offering, excluding amounts retained from the proceeds of its initial public offering to make a capital contribution to Discovery to fund an escrow account required in connection with the Tahiti pipeline lateral expansion project;

	(3) all cash receipts of Williams Partners L.P. and its subsidiaries for the period beginning on the closing date of the initial public offering and ending with the last day of that period, other than cash receipts from interim capital transactions; and

	(4) all cash receipts of Williams Partners L.P. and its subsidiaries after the end of that period but on or before the date of determination of operating surplus for the period resulting from working capital borrowings; less

(b) the sum of:


	(1) operating expenditures for the period beginning on the closing date of the initial public offering and ending with the last day of that period (other than operating expenditures funded with cash reserves established pursuant to clause (2) below); and

A-3

(2) the amount of cash reserves established by our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to a member of Williams Partners L.P. and its subsidiaries or disbursements on behalf of a member of Williams Partners L.P. and its subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of available cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.

Recompletions: After the initial completion of a well, the action and techniques of reentering the well and redoing or repairing the original completion to restore the well’s productivity.

Subordination period: The subordination period will generally extend from the closing of the initial public offering until the first to occur of:

(a) the first day of any quarter beginning after June 30, 2008 for which:


	(1) distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	(2) 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 common units and subordinated units that were outstanding during those periods on a fully diluted basis, and the related distribution on the general partner interest in Williams Partners L.P.; and

	(3) there are no outstanding cumulative common units arrearages.

(b) the date on which our general partner is removed as general partner of Williams Partners L.P. upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal

provided, however, subordinated units may convert into common units as described in “How We Make Cash Distributions — Subordination Period — Early Termination of Subordinated Units.”

Throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.

Units: Refers to both common units and subordinated units.

Working capital borrowings: Borrowings used exclusively for working capital purposes or to pay distributions to partners made pursuant to a credit facility or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year for an economically meaningful period of time.

Workover: Operations on a completed production well to clean, repair and maintain the well for the purposes of increasing or restoring production.

A-4

7,000,000 Common Units

Representing Limited Partner Interests

PROSPECTUS

, 2006

Joint Book-Running Managers

Lehman Brothers

Citigroup

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE filing fee, the amounts set forth below are estimates.


SEC registration fee		$	28,028
NASD filing fee			28,816
NYSE listing fee			38,640
Printing and engraving expenses			500,000
Accounting fees and expenses			1,050,000
Legal fees and expenses			775,000
Transfer agent and registrar fees			5,000
Miscellaneous			224,516

	Total	$	2,650,000


Item 14.	*Indemnification of Directors and Officers.*

The section of the prospectus entitled “The Partnership Agreement — Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is also made to Section 8 of the form of Underwriting Agreement to be filed as an exhibit to this registration statement in which we and our affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.


Item 15.	*Recent Sales of Unregistered Securities.*

On February 28, 2005, in connection with the formation of the partnership, Williams Partners L.P. issued to Williams Energy Services, LLC the 98% limited partner interest in the partnership for $980 in an offering exempt from registration under Section 4(2) of the Securities Act.

On August 23, 2005, in connection with the consummation of the transactions contemplated by a Contribution Agreement entered into at the closing of the initial public offering, Williams Partners L.P. issued (i) an aggregate 2,000,000 Common Units and 7,000,000 Subordinated Units to Williams Energy, L.L.C., Williams Energy Services, LLC, Williams Partners Holdings LLC and Williams Discovery Pipeline LLC in exchange for certain member interests and (ii) the continuation of a 2.0% general partner interest in Williams Partners L.P. and incentive distribution rights (which represent the right to receive increasing percentages of quarterly distributions in excess of specified amounts) to Williams Partners GP LLC in exchange for certain member interests. Each subordinated unit will convert into one common unit at the end of the subordination period. Unless earlier terminated pursuant to the terms of the partnership agreement of Williams Partners L.P., the subordination period will extend until the first day of any quarter beginning after June 30, 2008 that Williams Partners L.P. meets the financial tests set forth in its partnership agreement. The foregoing transactions were undertaken in reliance upon the exemption from the registration requirements of the

II-1

Securities Act afforded by Section 4(2). Williams Partners L.P. believes that exemptions other than the foregoing exemption may exist for these transactions.

There have been no other sales of unregistered securities within the past three years.


Item 16.	*Exhibits and Financial Statement Schedules.*

(a) The following documents are filed as exhibits to this registration statement:


Exhibit
Number				Description

	1	.1*	—	Form of Underwriting Agreement.
	2	.1+	—	Purchase and Sale Agreement, dated April 6, 2006, by and among Williams Energy Services, LLC, Williams Field Services Group, LLC, Williams Field Services Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams Partners Operating LLC (including the forms of Contribution, Conveyance and Assumption Agreements, Amended and Restated Limited Liability Company Agreement for Williams Four Corners LLC and Loan Agreement between The Williams Companies, Inc. and Williams Four Corners LLC) (incorporated by reference to Exhibit 2.1 to Williams Partners L.P.’s current report on Form 8-K filed on April 7, 2006 (File No. 001-32599)).
	3	.1+	—	Certificate of Limited Partnership of Williams Partners L.P. (incorporated by reference to Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 filed on May 2, 2005 (File No. 333-124517)).
	3	.2+	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate) (incorporated by reference to Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	3	.3+	—	Certificate of Formation of Williams Partners GP LLC (incorporated by reference to Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 filed on May 2, 2005 (File No. 333-124517)).
	3	.4+	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (incorporated by reference to Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	5	.1**	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered.
	8	.1*	—	Opinion of Andrews Kurth LLP relating to tax matters.
	10	.1+	—	Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and the Banks, Citibank, N.A. and Bank of America, N.A. (each, an “Issuing Bank”), and Citicorp USA, INC. as administrative agent (incorporated by reference to Exhibit 1.1 to The Williams Companies, Inc.’s current report on Form 8-K filed May 26, 2005 (File No. 001-04174)).
	10	.2+	—	Contribution, Conveyance and Assumption Agreement, dated August 23, 2005, by and among Williams Partners L.P., Williams Energy, L.L.C., Williams Partners GP LLC, Williams Partners Operating LLC, Williams Energy Services, LLC, Williams Discovery Pipeline LLC, Williams Partners Holdings LLC and Williams Natural Gas Liquids, Inc. (incorporated by reference to Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	10	.3+	—	Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (incorporated by reference to Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	10	.4+	—	Williams Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).

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Exhibit
Number				Description

	10	.5+	—	Working Capital Loan Agreement, dated August 23, 2005, between The Williams Companies, Inc. and Williams Partners L.P. (incorporated by reference to Exhibit 10.4 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	10	.6+†	—	Fractionation Agreement, dated as of July 18, 1997, by and between MAPCO Natural Gas Liquids Inc. and Amoco Oil Company (incorporated by reference to Exhibit 10.6 to Amendment No. 3 to Williams Partners L.P.’s registration statement on Form S-1 filed on August 3, 2005 (File No. 333-124517)).
	10	.7+	—	Third Amended and Restated Limited Liability Company Agreement for Discovery Producer Services LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to Williams Partners L.P.’s registration statement on Form S-1 filed on June 24, 2005 (File No. 333-124517)).
	10	.8+	—	Director Compensation Policy (incorporated by reference to Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K filed December 1, 2005 (File No. 001-32599)).
	10	.9+	—	Form of Grant Agreement for Restricted Units under Williams Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K filed December 1, 2005 (File No. 001-32599)).
	10	.10+	—	Base Contract for Sale and Purchase of Natural Gas between Williams Natural Gas Liquids, Inc. and Williams Power Company, Inc., dated August 15, 2005 (incorporated by reference to Exhibit 10.7 to Williams Partners L.P.’s quarterly report on Form 10-Q filed on September 22, 2005 (File No. 001-32599)).
	21	.1+	—	List of subsidiaries of Williams Partners L.P. (incorporated by reference to Exhibit 21.1 to Amendment No. 1 to Williams Partners L.P.’s registration statement on Form S-1 filed on June 24, 2005 (File No. 333-124517)).
	23	.1**	—	Consent of Ernst & Young LLP.
	23	.2**	—	Consent of Ernst & Young LLP.
	23	.3**	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1).
	23	.4*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1).
	24	.1**	—	Powers of Attorney (included on the signature page).
	99	.1+	—	Pre-approval Policy with respect to audit and non-audit services of the audit committee of the board of directors of Williams Partners GP LLC (incorporated by reference to Exhibit 99.1 to Williams Partners L.P.’s annual report on Form 10-K filed on March 3, 2006 (File No. 001-32599)).


	*	To be filed by amendment.


**	Filed herewith.

+ Incorporated by reference.


	†	Confidential treatment granted for omitted portions.


Item 17.	*Undertakings.*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the

II-3

matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:


	(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

	(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Williams Partners GP LLC, our general partner, or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Williams Partners GP LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Tulsa, State of Oklahoma, on April 6, 2006.


	Williams Partners L.P.


	By:	Williams Partners GP LLC, its General Partner


	By:	/s/ Steven J. Malcolm



	Steven J. Malcolm
	Chairman of the Board and
	Chief Executive Officer

POWER OF ATTORNEY

The undersigned directors and officers of Williams Partners GP LLC hereby constitute and appoint James J. Bender, Brian Shore, and Richard Carson, each with full power to act and with full power of substitution and resubstitution, our true and lawful attorneys-in-fact and agents with full power to execute in our name and behalf in the capacities indicated below any and all amendments (including post-effective amendments and amendments thereto) to this registration statement and to file the same, with all exhibits and other documents relating thereto and any registration statement relating to any offering made pursuant to this registration statement that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act with the Securities and Exchange Commission and hereby ratify and confirm all that such attorney-in-fact or his substitute shall lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.


Name	Title	Date


/s/ Steven J. Malcolm Steven J. Malcolm	Chairman of the Board and Chief Executive Officer (Principal Executive Officer)	April 6, 2006

/s/ Donald R. Chappel Donald R. Chappel	Chief Financial Officer and Director (Principal Financial Officer)	April 6, 2006

/s/ Ted T. Timmermans Ted T. Timmermans	Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)	April 6, 2006

/s/ Alan S. Armstrong Alan S. Armstrong	Chief Operating Officer and Director	April 6, 2006

/s/ Thomas C. Knudson Thomas C. Knudson	Director	April 6, 2006

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Name	Title	Date


/s/ Bill Z. Parker Bill Z. Parker	Director	April 6, 2006

/s/ Alice M. Peterson Alice M. Peterson	Director	April 6, 2006

/s/ Phillip D. Wright Phillip D. Wright	Director	April 6, 2006

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EXHIBIT INDEX


Exhibit
Number				Description

	1	.1*	—	Form of Underwriting Agreement.
	2	.1+	—	Purchase and Sale Agreement, dated April 6, 2006, by and among Williams Energy Services, LLC, Williams Field Services Group, LLC, Williams Field Services Company, LLC, Williams Partners GP LLC, Williams Partners L.P. and Williams Partners Operating LLC (including the forms of Contribution, Conveyance and Assumption Agreements, Amended and Restated Limited Liability Company Agreement for Williams Four Corners LLC and Loan Agreement between The Williams Companies, Inc. and Williams Four Corners LLC) (incorporated by reference to Exhibit 2.1 to Williams Partners L.P.’s current report on Form 8-K filed on April 7, 2006 (File No. 001-32599)).
	3	.1+	—	Certificate of Limited Partnership of Williams Partners L.P. (incorporated by reference to Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 filed on May 2, 2005 (File No. 333-124517)).
	3	.2+	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate) (incorporated by reference to Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	3	.3+	—	Certificate of Formation of Williams Partners GP LLC (incorporated by reference to Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 filed on May 2, 2005 (File No. 333-124517)).
	3	.4+	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (incorporated by reference to Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	5	.1**	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered.
	8	.1*	—	Opinion of Andrews Kurth LLP relating to tax matters.
	10	.1+	—	Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and the Banks, Citibank, N.A. and Bank of America, N.A. (each, an “Issuing Bank”), and Citicorp USA, INC. as administrative agent (incorporated by reference to Exhibit 1.1 to The Williams Companies, Inc.’s current report on Form 8-K filed May 26, 2005 (File No. 001-04174)).
	10	.2+	—	Contribution, Conveyance and Assumption Agreement, dated August 23, 2005, by and among Williams Partners L.P., Williams Energy, L.L.C., Williams Partners GP LLC, Williams Partners Operating LLC, Williams Energy Services, LLC, Williams Discovery Pipeline LLC, Williams Partners Holdings LLC and Williams Natural Gas Liquids, Inc. (incorporated by reference to Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	10	.3+	—	Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (incorporated by reference to Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	10	.4+	—	Williams Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	10	.5+	—	Working Capital Loan Agreement, dated August 23, 2005, between The Williams Companies, Inc. and Williams Partners L.P. (incorporated by reference to Exhibit 10.4 to Williams Partners L.P.’s current report on Form 8-K filed on August 26, 2005 (File No. 001-32599)).
	10	.6+†	—	Fractionation Agreement, dated as of July 18, 1997, by and between MAPCO Natural Gas Liquids Inc. and Amoco Oil Company (incorporated by reference to Exhibit 10.6 to Amendment No. 3 to Williams Partners L.P.’s registration statement on Form S-1 filed on August 3, 2005 (File No. 333-124517)).


Exhibit
Number				Description

	10	.7+	—	Third Amended and Restated Limited Liability Company Agreement for Discovery Producer Services LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 1 to Williams Partners L.P.’s registration statement on Form S-1 filed on June 24, 2005 (File No. 333-124517)).
	10	.8+	—	Director Compensation Policy (incorporated by reference to Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K filed December 1, 2005 (File No. 001-32599)).
	10	.9+	—	Form of Grant Agreement for Restricted Units under Williams Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K filed December 1, 2005 (File No. 001-32599)).
	10	.10+	—	Base Contract for Sale and Purchase of Natural Gas between Williams Natural Gas Liquids, Inc. and Williams Power Company, Inc., dated August 15, 2005 (incorporated by reference to Exhibit 10.7 to Williams Partners L.P.’s quarterly report on Form 10-Q filed on September 22, 2005 (File No. 001-32599)).
	21	.1+	—	List of subsidiaries of Williams Partners L.P. (incorporated by reference to Exhibit 21.1 to Amendment No. 1 to Williams Partners L.P.’s registration statement on Form S-1 filed on June 24, 2005 (File No. 333-124517)).
	23	.1**	—	Consent of Ernst & Young LLP.
	23	.2**	—	Consent of Ernst & Young LLP.
	23	.3**	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1).
	23	.4*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1).
	24	.1**	—	Powers of Attorney (included on the signature page).
	99	.1+	—	Pre-approval Policy with respect to audit and non-audit services of the audit committee of the board of directors of Williams Partners GP LLC (incorporated by reference to Exhibit 99.1 to Williams Partners L.P.’s annual report on Form 10-K filed on March 3, 2006 (File No. 001-32599)).


	*	To be filed by amendment.


**	Filed herewith.

+ Incorporated by reference.


	†	Confidential treatment granted for omitted portions.