UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-K

 

 

Commission file number 1-32599

Williams Partners L.P.

(Exact name of Registrant as Specified in Its Charter)

 

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ

 

The aggregate market value of the registrant’s common units held by non-affiliates based on the closing sale price of such units as reported on the New York Stock Exchange, as of the last business day of the registrant’s most recently completed second quarter was approximately $1,498,921,254. This figure excludes common units beneficially owned by the directors and executive officers of Williams Partners GP LLC, our general partner.

 

The registrant had 52,774,728 common units outstanding as of February 26, 2008.

 

DOCUMENTS INCORPORATED BY REFERENCE
None

 

 

WILLIAMS PARTNERS L.P.
FORM 10-K

TABLE OF CONTENTS

 

DEFINITIONS

 

We use the following oil and gas measurements and industry terms in this report:

 

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.

 

British Thermal Units (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.

 

BBtu/d:  One billion Btus per day.

 

Dth:  One dekatherm.

 

¢/MMBtu: Cents per one million Btus.

 

MMBtu:  One million Btus.

 

MMBtu/d:  One million Btus per day.

 

MMcf:  One million cubic feet. (Volumes of natural gas are generally reported in terms of cubic feet).

 

MMcf/d:  One million cubic feet per day.

 

NGLs:  Natural gas liquids.

 

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.

 

Throughput:  The volume of product transported or passing through a pipeline, plant, terminal or other facility.

 

Workover:  Operations on a completed production well to clean, repair and maintain the well for the purposes of increasing or restoring production.

WILLIAMS PARTNERS L.P.
FORM 10-K

 

PART I

 

 

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 Wamsutter LLC (Wamsutter) and Discovery Producer Services LLC (Discovery) in which we own interests accounted for as equity investments that are not consolidated in our financial statements. When we refer to Wamsutter or Discovery by name, we are referring exclusively to their businesses and operations.

 

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents electronically with the U.S. Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act). From time-to-time, we may also file registration and related statements and/or prospectuses or prospectus supplements pertaining to equity or debt offerings. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at http://www.sec.gov.

 

Our Internet website is http://www.williamslp.com. We make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charter of the audit committee of our general partner’s board of directors are also available on our Internet website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s secretary at Williams Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

 

Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000.

 

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

 

Operations of our businesses are located in the United States. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into three business segments:

 

 

 

We account for the Wamsutter Ownership Interests and our 60% interest in Discovery as equity investments and, therefore, do not consolidate their financial results.

 

Our assets were owned by Williams prior to the initial public offering (IPO) of our common units in August 2005, our acquisition of Four Corners in 2006, our acquisition of an additional 20% ownership percentage of Discovery in 2007 and our acquisition of the Wamsutter Ownership Interests in 2007. Williams indirectly owns an approximate 21.6% limited partnership interest in us and all of our 2% general partner interest.

 

Williams is an integrated energy company with 2007 revenues in excess of $10.5 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 NGL industry for more than 20 years.

 

Conversion of Subordinated Units.  On January 28, 2008, our general partner’s board of directors confirmed that the financial test contained in our partnership agreement required for conversion of all of our outstanding subordinated units into common units had been satisfied. Accordingly, our 7,000,000 subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis on February 19, 2008.

 

Acquisition of Wamsutter Ownership Interests.  On December 11, 2007, we acquired the Wamsutter Ownership Interests from Williams for aggregate consideration of $750.0 million. The acquisition was financed as follows:

 

 

 

Williams Partners L.P.’s. New Credit Facility.  We entered into a $450.0 million five-year senior unsecured credit facility comprised initially of a $250.0 million term loan used to finance a portion of the aggregate consideration for the Wamsutter Ownership Interests and a $200.0 million revolving credit facility, which is available for borrowings and letters of credit. On November 21, 2007, we were removed as a borrower under Williams’ $1.5 billion revolving credit facility and, therefore, no longer have access to $75.0 million borrowing capacity under that facility.

 

Wamsutter’s $20.0 million revolving credit facility.  Prior to our acquisition of the Wamsutter Ownership Interests, Wamsutter entered into a $20.0 million revolving credit facility with Williams as the lender. This facility is available to fund working capital requirements and for other purposes. Any borrowings under the facility will mature on December 9, 2008.

 

Ignacio gas processing plant fire.  On November 28, 2007, there was a fire at the Ignacio gas processing plant. This fire resulted in severe damage to the facility’s cooling tower, control room, adjacent warehouse buildings and control systems. The plant was shut down from November 28 to January 18, 2008. There were no injuries as a result of this incident and the plant now has full cryogenic recovery and fractionation facilities in operation.

 

Additional Investment in Discovery.  On June 28, 2007, we acquired an additional 20% limited liability company interest in Discovery from Williams for aggregate consideration of $78.0 million.

 

Conversion of Class B Units.  On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis by a majority vote of common units eligible to vote.

 

See Part II, Item 8 — Financial Statements and Supplementary Data.

 

Operations of our businesses are located in the United States and are organized into three reporting segments: (1) Gathering and Processing — West, (2) Gathering and Processing — Gulf and (3) NGL Services.

 

Our Gathering and Processing — West segment is comprised of our Four Corners assets and Wamsutter Ownership Interests.

 

Four Corners — General

 

The Four Corners assets include:

 

 

Our Four Corners’ customers are primarily natural gas producers in the San Juan Basin. We provide our customers with a full range of gathering, processing and treating services. Fee-based gathering, processing and

treating services accounted for approximately 69% of our Four Corners’ total revenue less its product cost and shrink replacement costs and expenses for the year ended December 31, 2007. The remaining 31% of Four Corners’ total revenues less product cost and shrink replacement for the year ended December 31, 2007 was derived from the sale of NGLs received as consideration for processing services.

 

For the year ended December 31, 2007, our Four Corners gathering system gathered 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 our Four Corners pipeline system in the San Juan Basin is produced from conventional formations with approximately 60% coming from coal bed formations. We are currently the only company 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.

 

Four Corners Natural Gas Gathering System

 

Our Four Corners natural gas gathering pipeline system consists of:

 

 

We generally charge a fee on the volume of natural gas gathered on our gathering pipeline systems. We do not, however, take title to the natural gas gathered on the system other than natural gas we retain for fuel and purchases for shrinkage.

 

Four Corners Processing and Treating Plants

 

Natural Gas Processing Plants

 

Our Four Corners assets include three natural gas processing plants with a combined processing capacity of 760 MMcf/d and combined NGL production capacity of 41,000 bpd. We own and operate these three plants.

 

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 Mid-America Pipeline (MAPL) system to Gulf Coast markets, but some NGLs we retain 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 natural 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 we retain are fractionated at Lybrook and distributed locally via truck. The Kutz plant has gas outlets to the El Paso Natural Gas, Public Service Company of New Mexico (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.

Treating Plants

 

Coal bed methane gas typically contains high levels of carbon dioxide that must be reduced to 2% or less for transportation through pipelines to end markets. Our Four Corners assets include two natural gas treating plants, the Milagro and Esperanza plants, which are located in New Mexico and have a combined carbon dioxide treating capacity of 750 MMcf/d. We own and operate these two plants. The Milagro treating plant can deliver natural gas to the El Paso Natural Gas, Transwestern, Southern Trails and PNM pipelines. The Esperanza treating plant treats coal bed methane volumes and removes carbon dioxide from the gas stream upstream of the Milagro plant.

 

Four Corners Customers and Contracts

 

Customers.  One producer customer, ConocoPhillips, accounted for approximately 53% of Four Corners’ total gathered volumes and 24% of its total revenues for the year ended December 31, 2007. Four Corners’ total revenues are comprised of product sales and fee-based gathering, processing, and treating revenues. With respect to total revenues, a subsidiary of Williams, to which we sell at market prices substantially all of the NGLs we retain under our keep-whole and percent-of-liquids processing contracts, accounted for approximately 52% of Four Corners’ total revenues for the year ended December 31, 2007. However, all of the NGLs sold to the subsidiary of Williams are derived from our processing of producer customers’ natural gas. In any given period, our product sales revenues can vary significantly depending on commodity prices and the extent to which we purchase third-party processing customer’s NGLs.

 

Contracts.  Gathering, processing and treating services are usually provided to each customer under long-term contracts with applicable acreage dedications, reserve dedications, or both, for the life of the contract. Gathering and treating services are generally provided pursuant to fee-based contracts. These revenues are based on the volumes gathered and the associated per-unit fee. Our portfolio of Four Corners’ natural gas processing agreements includes the following types of contracts:

 

 

We do not take title to gas as payment for services, other than for the reimbursement of gas used or lost during the gathering, processing or treating of natural gas.

Four Corner’s Competition

 

Our Four Corners system competes with other gathering, processing and treating options available to producers in the San Juan Basin. The Enterprise system is comprised of approximately 5,400 miles of gathering lines and two processing plants, one owned by Enterprise and the other by two large producers. Enterprise owns and operates primarily conventional natural gas gathering and processing facilities in the San Juan Basin. The Red Cedar system consists of approximately 800 miles of gathering lines, and is a joint venture between the Southern Ute Indian tribe and Kinder Morgan Energy Partners. The Texas Eastern Products Pipeline Company (TEPPCO) system consists of 400 miles of gathering lines. Red Cedar and TEPPCO own and operate primarily coal bed methane gathering and treating facilities in the San Juan Basin.

 

Four Corner’s Gas Supply

 

Our contracts with major customers contain certain production dedications whereby natural gas produced from a particular area and/or group of receipt points flows to our Four Corners system for the life of the contract. Those contracts also contain provisions requiring the connection of newly drilled wells within dedicated areas to our Four Corners system. For Four Corners, we anticipate that additional well connects, together with sustained drilling activity, other expansion opportunities and production enhancement activities by producers, will substantially offset the impact of normal decline in gathered, processed and treated volumes or even temporarily increase these volumes. We have also, on occasion, successfully pursued customers connected to competing gathering systems when the customer’s contract with the competing gathering system expired.

 

Wamsutter — General

 

We own the Wamsutter Ownership Interests and account for this investment under the equity method of accounting due to the voting provisions of Wamsutter’s limited liability company agreement which provide the other member of Wamsutter, Williams, significant participatory rights such that we do not control the investment. Wamsutter owns:

 

 

Wamsutter’s customers are primarily natural gas producers in the Washakie Basin. Wamsutter provides its customers with a broad range of gathering and processing services. Fee-based gathering and processing services accounted for approximately 53% of Wamsutter’s total revenues less related product costs for the year ended December 31, 2007. The remaining 47% of Wamsutter’s total revenues less related product costs for the year ended December 31, 2007 were derived primarily from the sale of NGLs received by Wamsutter as consideration for processing services.

 

The Wamsutter pipeline system gathers approximately 69% of the natural gas produced in the Washakie Basin and connects with four natural gas pipeline systems that transport natural gas to end markets from the basin.

 

Wamsutter Natural Gas Gathering System

 

The Wamsutter natural gas gathering pipeline system consists of:

 

 

Wamsutter Processing Plant

 

Wamsutter’s Echo Springs natural gas processing plant was constructed in 1994 and is located in Sweetwater County, Wyoming. The primary processing components of the Echo Springs plant were installed in 1994 and were subsequently upgraded and expanded in 1996 and 2001. The Echo Springs plant has three cryogenic trains with 28,900 horsepower of compression, processing capacity of 390 MMcf/d and NGL production capacity of 30,000 bpd. The Echo Springs plant has pipeline outlet connections to Wyoming Interstate Company, Colorado Interstate Gas Company, Southern Star Central Gas Pipeline and Rockies Express, which transport natural gas to end markets in the Mid-Continent and Western United States from the Washakie Basin. The Echo Springs plant also connects to MAPL, which transports NGLs to the Mid-Continent and Gulf Coast. We expect that in 2008 the plant will have access to the Overland Pass Pipeline, which will transport NGLs to the Mid-Continent. The Echo Springs plant is able to recover approximately 80% of the ethane contained in the natural gas stream and nearly all of the propane and heavier NGLs.

 

The Echo Springs plant is currently operating at capacity with gas in excess of capacity being bypassed around the plant. When gas is bypassed around the plant, Wamsutter does not recover all of the NGLs available from the gas. In order to capture some of the value attributable to these NGLs, Wamsutter has entered into an agreement with Colorado Interstate Gas’ Rawlins natural gas processing plant to process up to 80 MMcf/d of gas in excess of Wamsutter’s processing capacity from the Wamsutter gathering system. This connection to the Rawlins plant will increase the total processing capacity available to Wamsutter by 80 MMcf/d, or approximately 20%.

 

Wamsutter is planning to expand its processing capacity to accommodate volumes of natural gas committed to Wamsutter. Wamsutter expects this expansion to be completed before the end of 2011. We expect Wamsutter’s Class B member, owned by Williams, will fund this project.

 

Wamsutter Customers and Contracts

 

For Wamsutter, six producer customers, BP, Anadarko Petroleum Corporation, Devon Energy Corporation, Marathon Oil Corporation, Samson Resources Company and EnCana Corporation, accounted for approximately 92% of Wamsutter’s total gathered volumes for the year ended December 31, 2007. With respect to total revenues, a subsidiary of Williams, to which Wamsutter sells at market prices substantially all of the NGLs it retains under keep-whole contracts, accounted for approximately 56% of Wamsutter’s total revenues for the year ended December 31, 2007. Although this revenue is identified as sales to a subsidiary of Williams, all of the NGLs sold to the subsidiary of Williams are derived from the processing of producer customers’ natural gas.

 

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

 

Wamsutter has a portfolio of natural gas processing agreements that include fee-based and keep-whole contracts. The terms of these agreements are consistent with those described for Four Corners. For the year ended December 31, 2007, Wamsutter processed 75% and 25% of its processing volumes under fee-based and keep-whole contracts, respectively. Under a contract with one of Wamsutter’s significant customers, Wamsutter has agreed to limit its margins on NGLs (other than ethane) to $0.25 per gallon, with the balance above $0.25 per gallon accruing to the customer. Effective January 1, 2007, one of Wamsutter’s significant customers made an election to switch from a keep-whole processing arrangement to a fee-based processing arrangement for three years, which significantly decreased the NGL volumes received by Wamsutter.

 

Approximately 80% of the current gathering and processing volumes on the Wamsutter system are subject to contracts with terms of eight years or longer. All of Wamsutter’s gathering contracts are fee-based. Wamsutter generally charges a fee on the volume of natural gas gathered on its gathering pipeline system. Wamsutter does not take title to the natural gas that it gathers other than natural gas it retains for fuel and purchases for shrinkage.

Wamsutter Competition

 

Wamsutter has three primary competitors. Anadarko’s Patrick Draw and Red Desert facilities compete for both gathering and processing volumes. The Patrick Draw processing plant has 150 MMcf/d of cryogenic processing capacity and the Anadarko Red Desert plant has 40 MMcf/d of cryogenic processing capacity. The Colorado Interstate Gas Rawlins plant has 250 MMcf/d of lean oil processing capacity. The Rawlins plant is a regulated facility that is part of the Colorado Interstate Gas interstate pipeline system. The Rawlins plant’s primary purpose is to process the gas in the Colorado Interstate Gas pipeline system before natural gas is transported east to Front Range markets in Colorado.

 

Wamsutter LLC Agreement

 

Overview

 

We own the Wamsutter Ownership Interests previously described and Williams owns 100% of the Class B limited liability company membership interests and the remaining 50% of the initial Class C units in Wamsutter that we do not own. Wamsutter is obligated to issue additional Class C units based on future capital contributions that the Class A member and the Class B member are obligated or permitted to make in the circumstances described below.

 

Cash Distribution Policy

 

The Wamsutter LLC Agreement provides for distributions of available cash to be made quarterly, with available cash defined as Wamsutter’s cash on hand at the end of a distribution period less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law, debt instruments or other agreements to which it is a party. We expect that Wamsutter will fund its maintenance capital expenditures through its cash flows from operations. Williams, as the Class B member, has the discretion to establish the reserves necessary for Wamsutter, including the amount set aside for maintenance capital expenditures and thus can influence the amount of available cash.

 

Wamsutter will distribute its available cash as follows:

 

 

In addition, to the extent that at the end of the fourth quarter of a distribution year, we as the Class A member have received less than $70.0 million under the first and second bullets above, the Class C members will be required to repay, pro rata, any distributions they received in that distribution year such that we as the Class A member receive $70.0 million for that distribution year. If this repayment is insufficient to result in us as the Class A member receiving $70.0 million, the shortfall will not carry forward to the next distribution year. The initial distribution year commenced on December 1, 2007 and ends on November 30, 2008. Subsequent distribution years for Wamsutter will commence on December 1 and end on November 30.

 

Additionally, each month during fiscal years 2008 through 2012, the Class B member is obligated to pay to Wamsutter a transition support payment in an amount equal to the amount by which Wamsutter’s general and administrative expenses exceed a monthly cap. Any such amounts received from the Class B member will be distributed to the holder of the Class A membership interests, which is us, but will not be counted for purposes of determining whether or not Wamsutter has distributed the $70.0 million in aggregate annual distributions as described above. The Class B members will not be issued any Class C units as a result of making a transition support payment.

We will be allocated net income by Wamsutter based upon the allocation and distribution provisions of their LLC Agreement. In general, the agreement allocates income to the Class A, B and C ownership interests in a manner that will maintain capital account balances reflective of the amounts each ownership interest would receive if Wamsutter were dissolved and liquidated at carrying value. In general, pursuant to those provisions, income allocations follow the provisions of the LLC agreement for the distribution of available cash.

 

Capital Investments

 

If Wamsutter elects to make a growth capital investment in an amount less than $2.5 million, we as the Class A member are obligated to make a capital contribution to Wamsutter in an amount necessary to fund such growth capital investment. If Wamsutter elects to make a growth capital investment in an amount equal to or greater than $2.5 million, Williams as the Class B member is obligated to make a capital contribution to Wamsutter in an amount necessary to fund such growth capital investment. Wamsutter will issue to the contributing member one Class C unit for each $50,000 contributed by it. Wamsutter will issue fractional Class C units as necessary. A growth capital investment is any investment other than a maintenance capital investment or a growth well connection investment.

 

In addition, starting in 2009, Wamsutter will calculate the growth well connection investments it has made in the fiscal year immediately concluded. The Class B member is obligated to make a capital contribution to Wamsutter in an amount necessary to fund such growth well connection investments. Growth well connection investments are investments made over a one-year period for well connections that Wamsutter expects will more than offset the estimated decline in its throughput volumes over that period. The Class B member will receive one Class C unit for each $50,000 contributed by such member for these growth well connection investments.

 

Governance

 

Most decisions regarding Wamsutter’s day to day operations are made by Williams, in its capacity as the owner of the Class B membership interests. However, certain decisions require our consent as owner of the Class A membership interests. Because of these governance provisions, we do not control Wamsutter; hence, we account for our interest in Wamsutter as an equity method investment, and do not consolidate its financial results.

 

Our Gathering and Processing — Gulf segment is comprised of our 60% interest in Discovery and the Carbonate Trend gathering pipeline.

 

Discovery — General

 

We own a 60% interest in Discovery and account for this investment under the equity method of accounting due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment. Discovery owns:

 

 

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 our Gathering and Processing — Gulf segment.

Discovery Natural Gas Pipeline System

 

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 and is located in the offshore Louisiana Outer Continental Shelf at Ewing Bank 873. The mainline extends northerly to the Larose gas processing plant near Larose, Louisiana. Producers have dedicated their production from approximately 60 offshore blocks to Discovery. The mainline has a FERC-certificated capacity of approximately 600 MMcf/d.

 

The Discovery system connects to six natural gas pipeline systems: the Bridgeline system, the Texas Eastern Pipeline system, the Gulfsouth system, the Tennessee Gas Pipeline system, the Columbia Gulf Transmission system and the Transcontinental Gas Pipe Line system (Transco). 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:

 

 

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

 

Deepwater Gathering.  Discovery’s deepwater gathering assets consist of 73 miles of gathering laterals that extend to deepwater producing areas in the Gulf of Mexico such as the Morpeth prospect, Allegheny prospect and Front Runner prospect. Additionally, Discovery has signed definitive agreements with Chevron Corporation, Royal Dutch Shell plc and StatoilHydro ASA 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. In October 2007, Chevron announced that it will face delays because of metallurgical problems discovered in the facility’s mooring shackles and that it does not expect first production to commence until the third quarter of 2009. The FERC does not regulate any of Discovery’s deepwater laterals.

 

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. 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%.

 

Paradis Fractionation Facility

 

The fractionator is located onshore near Paradis, Louisiana. The fractionator and a 22-mile mixed NGL pipeline connecting it to the Larose processing plant went into service in January 1998. The Paradis fractionator is designed to fractionate 32,000 bpd of mixed NGLs and is expandable to 42,000 bpd. 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 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 at market prices and reselling them to end-users.

 

Discovery Management

 

Currently, Discovery is owned 60% by us and 40% by DCP Assets Holding, LP. Discovery is managed by a two-member management committee consisting of representation from each of the two 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.  Product sales to a subsidiary of Williams, which purchases at market prices substantially all of the NGLs and excess natural gas to which Discovery takes title, accounted for approximately 83% of Discovery’s revenues for the year ended December 31, 2007. This amount includes the sales of NGLs received under processing contracts with producer customers and NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs. In any given period, these product sales revenues can vary significantly depending on commodity prices and the extent to which third-party processing customer’s elect to have Discovery purchase their NGLs. 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. For the year ended December 31, 2007, 44% of Discovery’s total revenues less related product costs related to Discovery’s top three offshore natural gas producer customers.

 

In October 2006, Discovery signed a one-year contract with Texas Eastern Transmission Company (TETCO) that was subsequently extended through March 31, 2008. The TETCO agreement was recently extended through May 2008 at which time we expect no further volumes under this agreement. In the fourth quarter of 2007, Discovery began contracting significant volumes from the Tennessee Gas Pipeline system (TGP) and expects to expand during 2008 as the TETCO contract expires. Discovery is currently transporting TGP volumes of approximately 170 BBtu/d under month-to-month keep-whole contracts and expects to contract a substantial portion of this gas under longer-term percent-of-liquids or fee-based arrangements. For the year ended December 31, 2007, 15% of Discovery’s total revenues less related product costs related to TETCO.

 

Contracts.  Discovery’s wholly owned subsidiary, Discovery Gas Transmission (DGT), owns the mainline and the FERC-regulated laterals, which generate revenues through a tariff on file with the FERC for several types of service: traditional firm transportation service with reservation fees (although no current shippers have elected this service); firm transportation service on a commodity basis with reserve dedication; and interruptible transportation service. In addition, for any of these general services, DGT has the authority to negotiate a specific rate arrangement with an individual shipper and has several of these arrangements currently in effect.

 

In November 2007, DGT filed a settlement at FERC which would increase the maximum regulated rate for mainline transportation, market expansion and jurisdictional gathering. Please read “— FERC Regulation.”

 

Discovery’s portfolio of processing contracts includes the following types of contracts:

 

 

 

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.

 

Operation and Contract Optimization

 

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.

 

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.

 

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. In 2007, Discovery connected Energy Partner’s ST 46 and Mariners’ ST 288 blocks and received significant volumes from the Tennessee system from multiple shippers. In February 2008, Discovery executed agreements with LLOG Exploration Company to provide production handling, transportation, processing and fractionation

services for their MC 705 and 707 production. Also in February 2008, Discovery executed agreements with ATP to provide services, beginning in 2009, related to their production from MC 941 942 and AT 63. ATP has also added four new blocks related to their existing MC 711 production. 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 the U.S. Department of the Interior (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.

 

Third-Party Pipeline Supply

 

Hurricane Katrina’s emergency connections to TETCO and TGP have continued to flow gas throughout 2007. Discovery entered a one-year processing contract with TETCO, effective October 2006, for a minimum volume of 100 BBtu/d and a maximum of 300 BBtu/d while the Venice gas plant is being rebuilt. This contract was recently extended through May 2008 with a minimum volume of 150 BBtu/d. Additionally, as noted earlier, Discovery is currently contracting on a monthly basis approximately 170 BBtu/d of gas from TGP.

 

Carbonate Trend Pipeline — General

 

Our Carbonate Trend gathering pipeline is a sour gas gathering pipeline consisting of approximately 34 miles of pipeline 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, 2007, our average transportation volume was approximately 22 MMcf/d.

 

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. For the year ended December 31, 2007, volumes from Chevron leases represented approximately 69% of Carbonate Trend’s total throughput and 74% of Carbonate Trend’s total revenue.

 

Contracts.  We have long-term transportation agreements with Chevron and Beryl Resources LP (Beryl). Pursuant to these agreements, Chevron and Beryl have agreed to transport on our pipeline all gas produced on their 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 Beryl expire or the underlying reserves are depleted, Chevron and Beryl 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. 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 sour gas gathering pipelines.

 

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. Smaller producers are now entering the area which could result in the discovery of additional amounts of gas.

 

Our NGL Services segment is comprised of our Conway, Kansas businesses which consist of:

 

 

Our Conway assets are strategically located at one of the two major NGL trading hubs in the continental United States.

 

Conway Storage Assets

 

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.

 

Our Conway storage facilities interconnect directly with three end-use interstate NGL pipelines: MAPL, NuStar and the Oneok North System (formerly Kinder Morgan) pipeline. We also, through connections of less than a mile, indirectly interconnect to an additional end-use interstate NGL pipeline: 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.

Conway Storage 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 Oneok North System pipeline. Other competitors include a ONEOK-owned facility 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. 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 with 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 Oneok North System pipeline, NuStar 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 or our rail loading and unloading facility.

 

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 and forward purchase and sales contracts. 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.

 

These product sales and purchases are completed with a subsidiary of Williams. If this arrangement with the Williams subsidiary were terminated, we believe we could make these product sales and purchases through third parties.

 

The Conway Fractionation Facility

 

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 pipeline and the ConocoPhillips Chisholm pipeline, each of which transports mixed NGLs to our facility. The Conway fractionation facility has a total design capacity of approximately 107,000 bpd.

 

We own a 50% undivided interest in the Conway fractionation facility, representing capacity of approximately 53,500 bpd. ConocoPhillips and ONEOK own 40% and 10% undivided interests, respectively. 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.

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.

 

Conway Fractionation 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, a ONEOK-owned fractionator located in Bushton, Kansas and an Enterprise-owned fractionator located in Hobb, Texas. We compete with the two other joint owners of the Conway fractionation facility for third party customers. We also compete with fractionation facilities on the Gulf Coast, to the extent that NGL product commodity prices differ between the Mid-Continent region and the Gulf Coast.

 

An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. 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 Energy Information Administration 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 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. We are currently analyzing the feasibility of processing volumes sourced through connections to Overland Pass Pipeline, which will originate in Wyoming and flow into the Mid-Continent.

 

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.

 

Customers and Contracts

 

Customers.  Our NGL Services segment customers include NGL producers, NGL pipeline operators, NGL service providers and NGL end-users. Our three largest customers accounted for 33% of our segment revenues in 2007.

 

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. We also have several long-term contracts for terms that expire between 2009 and 2018. Each of these long-term contracts is based on a percentage of our published price of storage in our Conway facilities, which we adjust annually. Our storage revenues are not generally affected by seasonality because our customers generally pay for storage capacity, not injected or withdrawn volumes.

We currently offer our customers four types of storage contracts — single product fungible, two product fungible, multi-product fungible and segregated product storage — in various quantities and at varying terms. Single product fungible storage allows customers to store a single product. Two-product fungible storage allows customers to store any combination of two fungible products. Multi-product fungible storage allows customers to store any combination of fungible products. In the case of two-product and multi-product storage, the customer designates the quantity of storage space for each product at the beginning of the lease period. Customers may change their quantity configurations throughout the year based upon our ability to accommodate each change. Segregated storage also is available to customers who desire to store non-fungible products at Conway, such as propylene, refinery grade butane and naphtha. We evaluate pricing, volume and availability for segregated storage on a case-by-case basis.

 

Segregated storage allows a customer to lease an entire storage cavern and have its own product injected and withdrawn without having its product commingled with the products of our other customers. In addition to the fees we charge for fungible product storage and segregated product storage, we also receive fees for overstorage.

 

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

 

Certain of our natural gas pipelines are subject to regulation by, among others, the United States Department of Transportation (DOT) under the Accountable Pipeline and Safety Partnership Act of 1996 (often referred to as the Hazardous Liquid Pipeline Safety Act) and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management. These statutes require access to and copying of records and the filing of certain reports and 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. 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 anticipate incurring costs of approximately $0.8 million in 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.

 

We implement continuous inspection and compliance programs designed to keep our facilities in most efficient operating condition and to ensure compliance with pipeline safety and pollution control requirements. For example, our Carbonate Trend pipeline undergoes a corrosion control program that both protects the integrity of the pipeline and prolongs 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.

 

We are also 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 United States Environmental Protection Agency (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 some of 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, with a few exemptions, 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. 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.

 

Discovery

 

The Discovery 105-mile mainline, approximately 60 miles of laterals and its market expansion project are subject to regulation by the FERC, under the Natural Gas Act. The Natural Gas Act requires, among other things, that an interstate pipeline’s rates be “just and reasonable” and not unduly discriminatory or preferential. Under the Natural Gas Act, the FERC has authority over the construction, operation and expansion of interstate pipeline facilities, as well as the rates, terms and conditions of service provided by the operator of such facilities. In general, Discovery must receive prior FERC approval to construct, operate or expand its FERC-regulated facilities, to initiate new service using such facilities, to alter the terms and conditions of service provided on such facilities and to abandon service provided by its FERC-regulated facilities. With respect to certain types of construction activities and certain types of service, the FERC has issued rules that allow regulated pipelines to obtain blanket authorizations that obviate the need for prior specific FERC approvals for initiating and abandoning service. The natural gas pipeline industry has historically been heavily regulated by federal and state governments, and we cannot predict what further actions the FERC, state regulators, or federal and state legislators may take in the future. Under the Natural Gas Act the FERC regulates transmission facilities, but does not regulate gathering facilities. Discovery’s wholly owned subsidiary, Discovery Gas Transmission, owns the mainline and laterals subject to FERC regulation. Discovery owns some gathering facilities that are not subject to FERC Natural Gas Act regulation.

 

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. In November 2007, Discovery filed a settlement in lieu of a general rate case filing. If approved by the FERC, the settlement would resolve numerous rate and other issues and achieve rate certainty on Discovery for at least five years. As proposed, the terms of the settlement would become effective January 1, 2008. Under the settlement, Discovery would increase its maximum mainline, gathering and market expansion rates to $0.1729/dekatherm (Dth), $0.0430/Dth and $0.1116/Dth, respectively. Additionally, the settlement would permit Discovery to recover certain natural disaster related costs through the Hurricane Mitigation and Reliability Enhancement surcharge and to charge a market outlet surcharge to certain customers receiving discounted services. The settlement rates, if approved, would not impact the vast majority of the existing volumes on the Discovery system because those historical volumes are dedicated to the system under a life of lease rate. The proposed surcharges would affect some of the dedicated volumes. The FERC must approve the settlement for its terms to be effective. On February 5, 2008, the FERC issued an order approving the settlement except as to the protestor ExxonMobil Gas & Power Marketing Company, but the order is subject to rehearing and therefore not final or effective.

In 2005, the FERC indicated that 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 the FERC on a case-by-case basis. Please read “Risk Factors — Discovery’s interstate tariff rates and terms and conditions are subject to changes in policy by federal regulators, which could have a material adverse effect on our business and operating results.”

 

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated.

 

Other

 

The Carbonate Trend pipeline and the Four Corners and Wamsutter systems are gathering pipelines, and are not subject to the FERC’s jurisdiction under the Natural Gas Act.

 

The primary function of natural gas processing plants is the extraction of NGLs and the conditioning of natural gas for marketing into the natural gas pipeline grid. The 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 the FERC.

 

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.

 

General

 

Our operation of pipelines, plants and other facilities for gathering, transporting, processing and treating or storing natural gas, NGLs and other products is subject to stringent and complex federal, state, and local laws and regulations relating to the protection of the environment. As such, 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, operate and upgrade equipment and facilities. While these laws and regulations carry costs, we believe that they do not affect our competitive position because 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 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. Please read “Risk Factors — Our operations are subject to governmental laws and regulations related to the protection of the environment, which may expose us to significant costs and liabilities.”

 

In the omnibus agreement executed in connection with our IPO, 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 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. Pursuant to the purchase and sale agreements by which we acquired Four Corners and the Wamsutter Ownership Interests, Williams agreed to indemnify us against certain losses resulting from, among other things, Williams’ failure to disclose a violation of any environmental law by Four Corners or Wamsutter or relating to their assets, operations or businesses that occurred prior to the respective closings.

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 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

 

Hazardous substance laws generally regulate the generation, storage, treatment, use, transportation and disposal of solid and hazardous waste. They may 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 may or may not have 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. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently includes natural gas, we may nonetheless handle other “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 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, among others, CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.

 

We are a participant in certain hydrocarbon removal and groundwater monitoring activities at Four Corners associated with certain well sites in New Mexico. For a discussion of these hydrocarbon removal and

groundwater monitoring activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental.”

 

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 Kansas Department of Health and Environment (KDHE) under the Underground Hydrocarbon and Natural Gas Storage Program. The current revision of the Underground Hydrocarbon and Natural Gas Storage regulations became effective in 2003; 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 $1.2 million per year to install a double liner on a brine pond. 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 NGLs observed in the subsurface at the Conway Underground East facility. In addition, we have also recently detected 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.

 

For more information about environmental compliance and other environmental issues, please read “Environmental” under Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements in this report.

 

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. 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 unitholders.

 

Our right of way agreement with the Jicarilla Apache Nation (JAN), which covered certain gathering system assets in Rio Arriba County of northern New Mexico, expired on December 31, 2006. We currently operate our gathering assets on the JAN lands pursuant to a special business license granted by the JAN which expires February 29, 2008. We are engaged in discussions with the JAN designed to result in the sale of our gathering assets which are located on or are isolated by the JAN lands. Provided the parties are able to reach an acceptable value on the sale of the subject gathering assets, our expectation is that we will nonetheless maintain partial revenues associated with gathering and processing downstream of the JAN lands and continue to operate the gathering assets on the JAN lands for an undetermined period of time beyond February 29, 2008. Based on current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the JAN lands represents approximately $20 million to $30 million of Four Corners’ annual gathering and processing revenue less related product costs. For more information about this matter, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Gathering and Processing — West — Outlook 2008.”

 

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 our general partner or its affiliates employed approximately 266 people, as of December 31, 2007, who directly support the operations of the Four Corners, Conway and Carbonate Trend facilities. Additionally, our general partner and its affiliates provide general and administrative services to us. Wamsutter and Discovery are operated by Williams pursuant to agreements and the employees who operate these assets are therefore not included in the above numbers. For further information, please read “Directors and Executive Officers of the Registrant — Reimbursement of Expenses of our General Partner” and “Certain Relationships and Related Transactions.”

 

We have no revenue or segment profit/loss attributable to international activities.

 

 

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations.

 

All statements, other than statements of historical facts, included in this report which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

 

 

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. 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. The reader should carefully consider the risk factors discussed below in addition to the other information in this annual report. 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 and the trading price of our common units could decline and unitholders could lose all or part of their investment. Many of the factors that could adversely affect our business, results of operations and financial condition are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

 

 

 

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

 

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

 

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors include the following:

 

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:

 

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:

 

 

Unitholders 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. Our Four Corners gathering system receives natural gas directly from producers in the San Juan Basin, and our Wamsutter gathering system receives natural gas directly from producers in the Washakie Basin. The production from existing wells connected to these pipelines and our Four Corners and Wamsutter gathering systems 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 gathering systems and the utilization rate of our natural gas processing plants and fractionators, we 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 assets; (2) our ability to compete for volumes from successful new wells and existing wells connected to third parties; and (3) our ability to successfully complete lateral expansion projects to connect to new wells.

 

We do not have any current significant lateral expansion projects planned and Discovery has only one significant lateral expansion project under construction. Discovery signed definitive agreements with Chevron Corporation, Royal Dutch Shell plc, and StatoilHydro ASA 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. In October 2007, Chevron announced that it will face delays because of metallurgical problems discovered in the facility’s mooring shackles and that it does not expect first production to commence until the third quarter of 2009.

 

The level of drilling activity in the fields served by our pipelines and gathering systems 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 systems and the utilization rates of our natural gas processing plants and fractionators would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

 

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 gathering systems. 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 our unitholders.

 

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:

 

 

 

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, we receive NGLs removed from the natural gas stream during processing and may 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 us and our 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, we 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. One producer customer, ConocoPhillips, accounted for approximately 53% of the Gathering and Processing — West segment’s total gathered volumes for the year ended December 31, 2007. With respect to total revenues, a subsidiary of Williams, to which we sell substantially all of the NGLs we retain under our keep-whole and percent-of-liquids processing contracts, accounted for approximately 49% of our total revenues for the year ended December 31, 2007. However, all of the NGLs sold to the subsidiary of Williams are derived from our processing of producer customers’ natural gas. For the year ended December 31, 2007, ConocoPhillips accounted for 24% of the Gathering and Processing — West segment’s total revenues.

 

Six producer customers, BP, Anadarko Petroleum Corporation, Devon Energy Corporation, Marathon Oil Corporation, Samson Resources Company, and EnCana Corporation, accounted for approximately 92% of Wamsutter’s total gathered volumes for the year ended December 31, 2007. With respect to total revenues, a subsidiary of Williams, to which Wamsutter sells substantially all of the NGLs it retains under its keep-whole contracts, accounted for approximately 56% of Wamsutter’s total revenues for the year ended December 31, 2007. Although this revenue is identified as sales to a subsidiary of Williams, all of the NGLs sold to the subsidiary of Williams are derived from Wamsutter’s processing of producer customers’ natural gas.

 

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. In addition, we are subject to active negotiations with several customers to renew gathering, processing and treating contracts that are in evergreen status and that represent 19% of the total MMBtu gathered by our Four Corners system. All of the agreements

in evergreen status represent approximately 33% of our total MMBtu gathered revenues for the year ended December 31, 2007. The negotiations may not result in any extended commitments from these customers or may result in extended commitments on less favorable terms. The loss of all or even a portion of the revenues from 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 unitholders, 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 current liquids pipeline access to multiple end markets for NGL products that are recovered from our Four Corners and Wamsutter 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, we would be unable to deliver a substantial portion of the NGLs recovered at our Four Corners and Wamsutter processing plants. This would have an immediate impact on our ability to sell or deliver NGL products recovered at our Four Corners and Wamsutter processing plants. In addition, the five pipeline systems that move natural gas to end markets from the San Juan Basin connected to our Four Corners treating and processing facilities, including the El Paso Natural Gas, Transwestern, Williams’ Northwest Pipeline, Public Service Company of New Mexico and Southern Trails systems. The four pipeline systems that move natural gas to end markets from our Wamsutter processing facilities are the Colorado Interstate Gas, Wyoming Interstate Gas, Southern Star Central Gas Pipeline and Rockies Express 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, our customers may be unable to deliver natural gas to end markets. This could reduce the volumes of natural gas processed or treated at our Four Corners treating and processing facilities and our Wamsutter processing facilities. Either of such events could materially and adversely affect our business results of operations, financial condition and ability to make distributions to unitholders.

 

Any temporary or permanent interruption in operations on 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 unitholders.

 

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

 

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

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.

 

Discovery and Wamsutter may reduce their cash distributions to us in some situations.

 

Discovery’s and Wamsutter’s limited liability company agreements provide that they will distribute their available cash to their members on a quarterly basis. Discovery’s available cash includes cash on hand less any reserves that may be appropriate for operating its business and Wamsutter’s available cash includes cash generated from Wamsutter’s business less any reserves that may be appropriate for operating its business. As a result, reserves established by Discovery and Wamsutter, including those for working capital, will reduce the amount of available cash. The amount of Discovery’s quarterly distributions, including the amount of cash reserves not distributed, is determined by the members of its management committee representing a majority-in-interest in such entity. The amount of Wamsutter’s quarterly distributions, including the amount of cash reserves not distributed, is determined by the affirmative vote of the Class B member’s representative on the management committee.

 

We own a 60% interest in Discovery. In addition, to the extent Discovery requires working capital in excess of applicable reserves, we 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.

 

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.

 

The 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. The FERC could lower the tariff rates Discovery is currently permitted to charge its customers, on its own initiative, or as a result of challenges raised by Discovery’s customers or third parties and the FERC could require refunds of amounts collected under rates which it finds unlawful. An adverse decision by the FERC in approving Discovery’s regulated rates or on the rehearing of the proposed settlement discussed below could adversely affect our cash flows. Although the 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.

On November 16, 2007, Discovery filed a settlement, which is uncontested by its active shippers, in lieu of a general rate case filing. If approved by the FERC, the settlement would resolve numerous rate and other issues and achieve rate certainty on Discovery for at least five years. On February 5, 2008, the FERC approved the settlement but the order is subject to rehearing and therefore not final or effective. If the settlement does not become effective and if Discovery files a rate case, all aspects of Discovery’s cost of service and design of its rates could be reviewed.

 

Please read “Business and Properties — FERC Regulation — Discovery” for further information.

 

Discovery’s interstate tariff rates and terms and conditions are subject to changes in policy by federal regulators, which could have a material adverse effect on our business and operating results.

 

FERC standards of conduct govern how interstate pipelines communicate and do business with their marketing affiliates. Among other things, the standards of conduct require that interstate pipelines do not operate their systems to preferentially benefit their marketing affiliates. The current rule, which is an interim rule, applies only to natural gas transmission providers that are affiliated with a marketing or brokering entity that conducts transportation transactions on that natural gas transmission provider’s pipeline. Therefore, the interim rule does not currently apply to Discovery. FERC has issued a notice of proposed rulemaking that proposes permanent standards of conduct. We have no way to predict with certainty the scope of FERC’s permanent rules on the standards of conduct. However, we do not believe that Discovery’s natural gas pipeline will be affected by any action taken previously or in the future on these matters materially differently than other natural gas service providers with whom Discovery competes.

 

In 2005, the FERC indicated that it will permit pipelines to include in cost-of-service an income tax allowance to reflect actual or potential income 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 (See FERC Regulation). If the settlement discussed above does not become final and instead Discovery files a general rate case, under the FERC’s current policy Discovery would be required to prove that it is permitted to include an income tax allowance in its cost of service. These aspects of Discovery’s rates could also be reviewed if the FERC or a shipper initiated a complaint proceeding. If the FERC were to disallow a substantial portion of Discovery’s income tax allowance, it may be more difficult for Discovery to justify its rates.

 

In 2006, the FERC issued a new order addressing rates on one of the interstate oil pipelines of SFPP, L.P. The FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly-traded partnerships. It noted that the tax deferral features of a publicly-traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which the FERC characterized as a “tax savings.” The FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, the FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly-traded partnership’s cash flow exceeded taxable income. In February 2007, SFPP, L.P. asked the FERC to reconsider this ruling. The rehearing request is still pending before the FERC. The ultimate outcome of this proceeding is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost-of-service. If the FERC does not approve the settlement discussed above and instead Discovery files a general rate case, Discovery may be subject to potential adjustment of its equity rate-of-return that underlies its recourse rates to the extent that cash distributions in excess of taxable income are allowed to some unitholders.

 

In July 2007, the FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate returns on equity for natural gas and oil pipelines. The proposed policy statement would permit the inclusion of publicly traded master limited partnerships (MLPs) in the proxy group for purposes of calculating returns on equity under the discounted cash flow analysis, a change from its prior view that MLPs had not been shown to be appropriate for such inclusion. The FERC’s proposed policy statement is subject to change. Therefore, we cannot predict the scope of the final policy statement. If the settlement discussed above does not become final and Discovery files a general rate case instead, and

Discovery has not completed the hearing phase of the rate case as of the date the FERC issues its final policy statement, as currently proposed the final policy statement would apply to Discovery’s rate case.

 

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, other than:

 

 

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, Exterran and Devon 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 unitholders.

 

Williams’ public indentures and our credit facility 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.

 

Williams’ public indentures contain covenants that restrict Williams’ and our ability to incur liens to support indebtedness. 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.

 

Our credit facility contains various covenants that, among other things, limit our ability to incur indebtedness, grant certain liens to support indebtedness, merge, or sell substantially all of our assets. 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. Our ability to comply with the covenants contained in the credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

 

Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. Any future down grading of a Williams’ credit rating would likely also result in a down grading of our 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.

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

 

In December 2007, we borrowed $250.0 million under the term loan portion of our new $450.0 million five-year senior unsecured credit facility. Our total outstanding long-term debt as of December 31, 2007 was $1.0 billion, representing approximately 86% of our total book capitalization.

 

Our debt service obligations and restrictive covenants in the indentures governing our senior unsecured notes could have important consequences. For example, they could:

 

 

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. If we are unable to meet our debt service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

 

We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our senior notes.

 

Discovery and Wamsutter are not prohibited from incurring indebtedness, which may affect our ability to make distributions to unitholders.

 

Discovery and Wamsutter are not prohibited by the terms of their respective limited liability company agreements from incurring indebtedness. If Discovery or Wamsutter was to incur significant amounts of indebtedness, such occurrence may inhibit their ability to make distributions to us. An inability by Discovery or Wamsutter to make distributions to us would materially and adversely affect our ability to make distributions to unitholders because we expect distributions we receive from Discovery and Wamsutter to represent a significant portion of the cash we distribute to unitholders.

 

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 fractionators located in each of Hutchinson, Kansas, Medford, Oklahoma, and Bushton, Kansas owned by ONEOK Partners, L.P., 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 of gas or consumers of NGLs may develop their own gathering, processing, treating, fractionation and storage facilities in lieu of using ours.

 

Wamsutter competes with other natural gas gathering and processing facilities in the Washakie Basin, including Anadarko’s Patrick Draw and Red Desert facilities and Colorado Interstate Gas’ Rawlins facility. In addition, customers who are significant producers of gas or consumers of NGLs may develop their own gathering and processing facilities in lieu of using Wamsutter’s gathering and processing facility.

 

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 unitholders.

 

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

 

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

 

 

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 and replaced three sections of brine systems at a cost of $0.7 million. We have completed most of the testing and expect to complete the remainder of the testing in 2008.

 

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 corrosion.

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:

 

 

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.

 

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 unitholders. Further, if we issue additional common units in connection with future acquisitions, unitholders’ interest in us will be diluted and distributions to unitholders may be reduced.

 

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, processing and treating of natural gas and the fractionation and storage of NGLs, including:

 

 

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

Discovery’s pipelines due to an influx of seawater while connecting a new lateral. In addition, on November 28, 2007, we had a fire at our Ignacio gas processing plant that resulted in a significant disruption of our operations associated with that plant. Although the plant is now operating, the fire destroyed much of the plant’s spare parts inventory. Consequently, there could be additional disruptions of operations due to failure of parts for which the acquisition of replacements requires significant lead time.

 

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 unitholders.

 

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

 

We do not own 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. 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 unitholders. For example, portions of our Four Corners gathering system are located on Native American rights-of-way. Four Corners is currently in discussions with the Jicarilla Apache Nation regarding rights-of-way that expired at the end of 2006 for a segment of the gathering system which flows less than 10% of Four Corners’ gathered volumes. We continue to operate these assets under a special business license that expires February 29, 2008. Based upon current estimated gathering volumes and a range of annual average commodity prices over the past five years, we estimate that gas produced on or isolated by the Jicarilla Apache Nation lands represents approximately $20.0 million to $30.0 million of Four Corners’ annual gathering and processing revenue less related product costs.

 

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, processing and treating, 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:

 

 

Various governmental authorities, including the 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, some of which may be material, 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. 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 materially increase our compliance costs and the cost of any remediation that may become necessary.

 

For example, 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 promulgated more stringent regulations regarding safety and integrity of brine ponds and storage caverns. 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. In addition, the Department of Environmental Quality in Wyoming has created a new emissions rule for sites with production greater than 3,000 million cubic feet per day. Wamsutter has reacted by installing methanol injectors at these sites. This requirement increases the well connect costs for new wells in Wyoming.

 

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, we may have to make capital expenditures to muffle noise from our 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 if 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 laws and regulations might adversely affect our products and activities, including processing, fractionation, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of fossil fuels, are examples of greenhouse gases. In response to such studies, the U.S. Congress is actively considering legislation and more than a dozen states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap and trade programs. Moreover, the U.S. Supreme Court only recently held in a case, Massachusetts, et al. v. EPA, that greenhouse gases fall within the federal Clean Air Act’s definition of “air pollutant,” which could result in the regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas in which we conduct business could have an adverse affect on our operations and demand for our services.

 

The natural gas gathering operations in the San Juan Basin and Washakie Basin may be subjected to regulation by the state of New Mexico, which could negatively affect our revenues and cash flows.

 

The New Mexico state legislature has previously called for hearings to take place to examine the regulation of natural gas gathering systems in the state. It is unclear if further discussions or hearings in New Mexico will occur, but they could result in gathering regulation that could affect the fees that we could collect for gathering services. This type of regulation could adversely impact our revenues and cash flow.

Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future.

 

Regulators and legislators continue 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 Securities Exchange Commission (SEC) could enact new accounting standards that might impact how we would be 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 unitholders.

 

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 unitholders.

 

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 unitholders.

 

Risks Inherent in an Investment in Us

 

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make payments on our debt obligations and distributions on our common units.

 

We have a holding company structure, and our subsidiaries conduct all of our operations and own all of our operating assets. Williams Partners L.P. has no significant assets other than the ownership interests in its subsidiaries. As a result, our ability to make required payments on our debt obligations and distributions on our common units depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, applicable state partnership and limited liability company laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of our debt obligations, to repurchase our debt obligations upon the occurrence of a change of control or make distributions on our common units, we may be required to adopt one or more alternatives, such as a refinancing of our debt obligations or borrowing funds to

make distributions on our common units. We cannot assure you that we will be able to borrow funds to make distributions on our common units.

 

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

 

As of February 19, 2008, Williams held 11,613,527 common units, including common units issued to Williams as partial consideration for the Wamsutter Ownership Interests representing a 21.6% limited partnership interest in us. Williams may, from time to time, sell all or a portion of its 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.

 

Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest with us and limited fiduciary duties, and they favor their own interests to the detriment of our unitholders.

 

Williams owns and controls our general partner, and appoints all of the directors of our general partner. All of the executive officers and certain directors of our general partner are officers and/or directors of Williams and its affiliates, including Williams Pipeline Partners’ 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 officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Williams. Therefore, conflicts of interest may arise between Williams and its affiliates, including our general partner and Williams Pipeline Partners, 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:

 

 

 

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, our partnership agreement restricts the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

 

 

Common unitholders are bound by the provisions in the partnership agreement, including the provisions discussed above.

 

Even if unitholders are dissatisfied, they have little ability to remove our general partner without its consent.

 

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

 

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 662/3% of all outstanding common units is required to remove our general partner.

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. This effectively permits a change of control without your consent. 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.

 

In recent years, the United States credit markets experienced 50-year record lows in interest rates. If the overall economy strengthens, it is possible that monetary policy will tighten, resulting in higher interest rates to counter possible inflation risk. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt to make acquisitions or for other purposes.

 

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

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

Affiliates of our general partner, including Williams and Williams Pipeline Partners, are not limited in their ability to compete with us. Williams is also not obligated to offer us the opportunity to acquire additional assets or businesses from it, which could limit our commercial activities or our ability to grow. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Pipeline Partners’ general partner, and these persons will also owe fiduciary duties to those entities.

 

While our relationship with Williams and its affiliates is a significant attribute, it is also a source of potential conflicts. For example, Williams is in the natural gas business and is not restricted from competing with us. Williams and its affiliates, including Williams Pipeline Partners, which trades on the NYSE under the symbol “WMZ,” may compete with us. Williams and its affiliates may acquire, construct or dispose of natural gas industry assets in the future, some or all of which may compete with our assets, without any obligation to offer us the opportunity to purchase or construct such assets. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Pipeline Partners’ general partner and will owe fiduciary duties to those entities as well as our unitholders and us.

Our general partner has a limited call right that may require unitholders to sell their 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, non-affiliated unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such unitholders may also incur a tax liability upon a sale of their 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.

 

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 be voted 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 to our general partner and its affiliates will reduce cash available to pay distributions to unitholders.

 

We will reimburse our general partner and its affiliates, including Williams, for various general and administrative services they provide for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us, which amounts will be determined by our general partner in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Transactions, and Director Independence.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

 

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

 

 

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Williams and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, if the unitholders become dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

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 a material amount of entity-level taxation by states and localities. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, then our cash available for distribution to unitholders would be substantially reduced.

 

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

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35%, and would likely pay state and local income tax at the corporate tax rate of the various states and localities imposing a corporate income tax. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to unitholders 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 unitholders, 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 federal, state or local entity-level taxation. For example, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, 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 unitholders 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.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. Legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

An IRS contest of the federal income tax positions we take may adversely impact the market for the common units, and the costs of any contest will reduce our cash available for distribution to 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 or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for the 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.

Unitholders will be required to pay taxes on their share of our income even if unitholders do not receive any cash distributions from us.

 

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

 

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

 

If a unitholder sells its common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income it was allocated for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price the unitholder receives is less than its original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, if a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash it received 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), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including 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 common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholder tax returns.

 

Unitholders 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, unitholders 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 now or in the future, even if the unitholder does not live in any of those jurisdictions. Unitholders 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, unitholders may be subject to penalties for failure to comply with those requirements. We own property and conduct business in Colorado, Kansas, Louisiana, New Mexico, Alabama and Wyoming. We may own property or conduct business in other states or foreign countries in the future. It is the unitholder’s

responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

 

The sale or exchange of 50% or more of the total interest in our capital and profits 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 our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

 

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our methodologies, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.

 

 

None.

 

 

The information called for by this item is provided in Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements of this report, which information is incorporated into this Item 3 by reference.

 

 

None.

 

 

Market Information, Holders and Distributions

 

Our common units are listed on the New York Stock Exchange under the symbol “WPZ.” At the close of business on February 20, 2007, there were 52,774,728 common units outstanding, held by approximately 16,089 holders, including common units held in street name and by affiliates of Williams.

 

On January 28, 2008, our general partner’s board of directors confirmed that the financial test contained in our partnership agreement required for conversion of all of our outstanding subordinated units into common units had been satisfied. Accordingly, our 7,000,000 subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis on February 19, 2008.

 

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the New York Stock Exchange Composite Transactions Tape, and quarterly cash distributions paid to our unitholders.

 

 

 

 

Distributions of Available Cash

 

Within 45 days after the end of each quarter we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Available cash generally means, for each fiscal quarter all cash on hand at the end of the quarter:

 

 

 

 

 

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:

 

 

We will make distributions of available cash from operating surplus for any quarter in the following manner:

 

 

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

 

 

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.

 

The following table shows selected financial and operating data of Williams Partners L.P., Wamsutter LLC and Discovery Producer Services LLC for the periods and as of the dates indicated. We derived the financial data as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in this document. All other financial data are derived from our financial records.

 

Because Four Corners, Wamsutter and the additional 20% interest in Discovery were owned by affiliates of Williams at the time of these acquisitions, these transactions were between entities under common control, and have been accounted for at historical cost. Accordingly, our selected financial and operational data have been recast to reflect the combined historical results of these common control acquisitions throughout the periods presented. These acquisitions have no impact on historical earnings per unit as pre-acquisition earnings were allocated to our general partner.

 

The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information concerning significant trends in the financial condition and results of operations.

 

 

 

 

 

 

Overview

 

We are principally engaged in the business of gathering, transporting, processing and treating natural gas and fractionating and storing NGLs. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into three business segments:

 

 

Executive Summary

 

In 2007, a significant achievement was the December acquisition of the Wamsutter Ownership Interests from The Williams Companies, Inc. (Williams) for $750.0 million. The Wamsutter system serves the Washakie basin, which has stable production and high growth potential. At Four Corners, record commodity margins largely offset the negative impacts of the fire at the Ignacio plant, increased operating expenses and lower gathered volumes. Important capital investments were completed at Four Corners, which we believe will lead to slightly increased gathering volumes in 2008. We also acquired an additional 20% interest in Discovery from Williams in June for $78.0 million. Discovery has recently produced record quarterly profits and looks forward to continued strong performance in 2008. At Conway, we continue to see strong demand for leased storage and new product upgrade services. We have increased unitholder distributions each quarter since our initial public offering (IPO) and our fourth-quarter 2007 distribution was 22% higher than the fourth-quarter 2006 distribution. Our relationship with Williams and ability to raise capital has us well-positioned for continued growth through both internal projects and acquisition transactions with Williams and other third parties.

 

Recent Events

 

Conversion of Subordinated Units.  On January 28, 2008, our general partner’s board of directors confirmed that the financial test contained in our partnership agreement required for conversion of all of our

outstanding subordinated units into common units had been satisfied. Accordingly, our 7,000,000 subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis on February 19, 2008.

 

Acquisition of Wamsutter Ownership Interests.  On December 11, 2007, we acquired the Wamsutter Ownership Interests from Williams for aggregate consideration of $750.0 million. The acquisition was financed with the debt and equity issuances described below.

 

 

Williams Partners L.P.’s New Credit Facility.  We entered into a $450.0 million five-year senior unsecured credit facility comprised initially of a $250.0 million term loan used to finance a portion of the aggregate consideration for the Wamsutter Ownership Interests and a $200.0 million revolving credit facility, which is available for borrowings and letters of credit. On November 21, 2007, we were removed as a borrower under Williams’ $1.5 billion revolving credit facility and; therefore, no longer have access to a $75.0 million borrowing capacity under that facility.

 

Ignacio gas processing plant fire.  On November 28, 2007, there was a fire at the Ignacio gas processing plant. This fire resulted in severe damage to the facility’s cooling tower, control room, adjacent warehouse buildings and control systems. The plant was shut down from November 28 to January 18, 2008. There were no injuries as a result of this incident and the plant now has full cryogenic recovery and fractionation facilities in operation.

 

Additional Investment in Discovery.  On June 28, 2007, we acquired an additional 20% limited liability company interest in Discovery from Williams for aggregate consideration of $78.0 million.

 

Conversion of Class B Units.  On May 21, 2007, our outstanding Class B units were converted into common units on a one-for-one basis by a majority vote of common units eligible to vote.

 

How We Evaluate Our Operations

 

Our management uses a variety of financial and operational measures to analyze our segment performance, including the performance of Wamsutter and Discovery. These measurements include:

 

 

 

Four Corners

 

Gathering and Processing Volumes.  The gathering volumes on our Four Corners system and volumes processed at the Ignacio, Kutz and Lybrook natural gas processing plants are important components of maximizing its profitability. We gather approximately 37% of the San Juan Basin’s natural gas production on our Four Corners system at approximately 6,400 receipt points under mostly fee-based contracts. Our gathering volumes from existing wells connected to our pipeline will naturally decline over time. Accordingly, to maintain or increase gathering volumes we must continually obtain new supplies of natural gas. Our Four Corners system processes natural gas under keep-whole, percent-of-liquids, fee-based and fee-based and keep-whole contracts. Our processing volumes are largely dependent on the volume of natural gas gathered on our Four Corners’ system.

 

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 from the revenue Four Corners receives from the sale of its NGLs, which is net of transportation and fractionation charges. 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. Under certain agreement types, Four Corners receives NGLs as compensation for processing services provided to its customers. 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 and changes in the cost of transporting and fractionating the NGLs.

 

Wamsutter

 

Gathering and Processing Volumes.  The gathering volumes on the Wamsutter system and volumes processed at the Echo Springs natural gas processing plant are important components of maximizing its profitability. The Wamsutter pipeline system gathers approximately 69% of the natural gas produced in the Washakie Basin and connects with the Colorado Interstate Gas, Wyoming Interstate Gas, Southern Star Central Gas Pipeline, and Rockies Express systems that transport natural gas to end markets from the basin. Wamsutter’s gathering volumes from existing wells connected to our pipelines will naturally decline over time. Accordingly, to maintain or increase gathering volumes Wamsutter must continually obtain new supplies of natural gas. The Wamsutter system processes natural gas under keep-whole and fee-based contracts. Wamsutter’s processing volumes are largely dependent on the volume of natural gas gathered on its system.

 

Net Liquids Margin.  The net liquids margin is an important measure of Wamsutter’s ability to maximize the profitability of its processing operations. Liquids margin is derived by deducting the cost of shrink replacement gas from the revenue Wamsutter receives from the sale of its NGLs, which is net of transportation and fractionation charges. 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. Under certain agreement types, Wamsutter receives NGLs as compensation for processing services provided to its customers. 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 and changes in the cost of transporting and fractionating the NGLs.

 

Discovery and Carbonate Trend

 

Pipeline Throughput Volumes.  We view throughput volumes on Discovery’s pipeline system and our Carbonate Trend pipeline as an important component of measuring the results of these assets. 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 and Discovery’s pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas processing plant and fractionator, we and Discovery must continually obtain new supplies of natural gas. Our and Discovery’s ability to maintain existing supplies of natural gas and obtain new supplies are impacted by (1) the level of workovers or

recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our pipelines and (2) our ability to compete for volumes from successful new wells in other areas. We and Discovery 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 associated costs, primarily shrink replacement gas and fuel gas, are deducted from these revenues to determine gross processing margin. Discovery’s mix of processing contract types and its operation and contract optimization activities are determinants in processing revenues and gross margins.

 

Conway

 

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 versus 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, leased compression services, contract services, fuel, utilities, materials, supplies, insurance and ad valorem taxes comprise the most significant portion of operating and maintenance expenses. We have experienced increased operating and maintenance expenses in recent years due to the growth of the oil and gas industry, which has increased competition for resources. Other than system gains and losses, rented compression services and fuel expense, 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. In the course of providing gathering, processing and treating services to our customers, we realize over and under deliveries of 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 are reflected in operating and maintenance expense as system gains and losses. These system gains and losses are an unpredictable component of our operating costs. Leased compression services are dependent upon the extent and amount of additional compression needed to meet the needs of our customers and the cost at which compression can be purchased, leased and operated. 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 — Gulf segment are a component in assessing our gross processing margins.

General and Administrative Expenses

 

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 allocated corporate administrative expenses are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. Certain of these costs are charged back to the other Conway fractionator co-owners. Our share of direct and allocated administrative expenses is reflected in General and administrative expense — Affiliate in the accompanying Consolidated Statements of Income.

 

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. 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.

 

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 the board of directors 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 2007, we determined that the carrying value of our Carbonate Trend pipeline may not be recoverable because of forecasted declining cash flows. As a result, we recognized an impairment charge of $10.4 million to reduce the carrying value to managements’ estimate of fair value at December 31, 2007. (See Note 7, Other (Income) Expense, in our Notes to Consolidated Financial Statements.) Our computations utilized judgments and assumptions in the following areas:

 

 

Our projections are sensitive to changes in the above assumptions. A change to the estimated earnings multiple of one times would increase or decrease our fair value estimate by approximately $1.2 million.

 

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, 2007, we have an accrued asset retirement obligation liability of $8.7 million including estimated retirement costs associated with the abandonment of Four Corners’ gas processing and compression facilities located on leased land, Four Corners’ wellhead connections on federal land, Conway’s underground storage caverns and brine ponds in accordance with KDHE regulations and the Carbonate Trend pipeline. Our estimate utilizes

judgments and assumptions regarding the extent of our obligations, the costs to abandon and the timing of abandonment. Our recorded asset retirement obligation is based on the assumption that the abandonment of our Four Corners and Conway assets generally occurs in approximately 50 years. If this assumption had been changed to 30 years in 2007, and the expected retirement date for the Carbonate Trend pipeline had been significantly shortened, the recorded asset retirement obligation would have increased by approximately $3 million to $4 million. (See Note 8, Property, Plant and Equipment, in our 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, 2007, we have an accrual for estimated environmental remediation obligations of $4.0 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. (Please read “— Environmental” and Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements.)

 

Revenue Recognition — Derivative Instruments and Hedging Activities

 

We hold a portfolio of nontrading energy contracts. We review these contracts to determine whether or not they are derivatives. If they are derivatives, we further assess whether the contracts qualify for either cash flow hedge accounting or the normal purchases and normal sales exception.

 

The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in achieving offsetting cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.

 

Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand, and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.

 

The fair value of derivative contracts is determined based on the nature of the transaction and the market in which transactions are executed. We also incorporate assumptions and judgments about counterparty performance and credit considerations in our determination of their fair value. Our contracts are generally executed in over-the-counter markets with quoted prices. The fair value of all derivative contracts is

continually subject to change as the underlying commodity market changes and our assumptions and judgments change.

 

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, 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 

 

 

 

2007 vs. 2006

 

Revenues increased $9.4 million, or 2%, due primarily to higher revenues in our Gathering and Processing — West segment, slightly offset by lower revenues in our NGL Services segment. Revenues in our Gathering and Processing — West segment increased due primarily to higher product sales, partially offset by lower gathering, processing and other revenues. Revenues in our NGL Services segment decreased due primarily to lower product sales and fractionation revenues, partially offset by higher storage and product upgrade fee revenues. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section and “— Results of Operations — NGL Services” sections.

Product cost and shrink replacement increased $6.2 million, or 4%, due primarily to increased NGL purchases from producers in our Gathering and Processing — West segment, partially offset by lower shrink requirements related primarily to the fire at Ignacio in the same segment and decreased product sales volumes in our NGL Services segment. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

 

Operating and maintenance expense increased $7.1 million, or 5%, due primarily to higher expense in our Gathering and Processing — West segment, partially offset by lower expense in our NGL Services segment. Operating and maintenance expense in our Gathering and Processing — West segment increased due primarily to higher fuel costs, rent expense and leased compression, partially offset by lower maintenance costs. Operating and maintenance expense in our NGL Services segment decreased due primarily to lower fuel and power costs related to the lower fractionator throughput. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

 

General and administrative expense increased $6.2 million, or 16%, due primarily to higher Williams’ technical support services and other charges allocated by Williams to us for various administrative support functions.

 

Other (income) expense changed from $2.5 million income in 2006 to $12.1 million expense in 2007, due primarily to the fourth quarter 2007 impairment of the Carbonate Trend pipeline and a $3.6 million gain in 2006 on the sale of the La Maquina carbon dioxide treating facility in the Gathering and Processing — West segment.

 

Operating income declined $28.1 million, or 20%, due primarily to lower segment operating income in our Gathering and Processing — West segment, the fourth-quarter 2007 impairment of the Carbonate trend pipeline and higher general and administrative expense, partially offset by higher storage revenues and product storage upgrade fees and lower operating and maintenance expenses in our NGL Services segment. Segment operating income decreased in our Gathering and Processing — West segment due primarily to the impact of the Ignacio plant fire. These fluctuations are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

 

Equity earnings from Wamsutter increased $14.5 million, or 24%, due primarily to higher net liquids margins and fee-based gathering and processing revenues, partially offset by higher general and administrative expenses. Wamsutter’s results are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.

 

Equity earnings from Discovery increased $10.8 million, or 60%, due primarily to higher gross processing margins that more than offset lower fee-based revenues and higher operating and maintenance expense. Discovery’s results are discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

 

Interest expense increased $48.5 million due primarily to interest on our $750.0 million senior unsecured notes. We issued $150.0 million in June 2006 and $600.0 million in December 2006 to finance our acquisition of Four Corners.

 

Interest income increased $1.4 million, or 87%, due to higher cash balances during the first and second quarters of 2007.

 

2006 vs. 2005

 

Revenues increased $48.4 million, or 9%, due primarily to higher revenues in our Gathering and Processing — West segment reflecting increased product sales and gathering and processing revenues combined with increased storage revenues and product sales in our NGL Services segment. These increases are discussed in detail in the “— Results of Operations — Gathering and Processing — West” and “— Results of Operations — NGL Services” sections.

Operating and maintenance expense increased $25.5 million, or 20%, due primarily to higher compression, maintenance and labor costs in our Gathering and Processing — West segment. These increases are discussed in the “— Results of Operations — Gathering and Processing — West” section.

 

Operating income increased $23.7 million, or 20%, due primarily to our Gathering and Processing — West segment where higher net liquids margins and fee-based revenues were partially offset by higher operating and maintenance expense.

 

Equity earnings from Wamsutter increased $21.1 million, or 52%, due primarily to higher net liquids margins. These increases are discussed in detail in the “— Results of Operations — Gathering and Processing — West” section.

 

Equity earnings from Discovery increased $6.2 million, or 52%, due primarily to Discovery’s higher gross processing margins partially offset by higher operating and maintenance expense. These increases are discussed in detail in the “— Results of Operations — Gathering and Processing — Gulf” section.

 

Interest expense increased $1.6 million, or 19%, due primarily to $8.3 million of interest on our $750.0 million senior unsecured notes issued in June and December of 2006 to finance a portion of our acquisition of Four Corners. This increase was partially offset by $7.4 million lower interest following the forgiveness of advances from Williams in conjunction with the closing of our IPO on August 23, 2005.

 

Interest income increased $1.4 million due to interest earned on our cash balances following our IPO on August 23, 2005.

 

Results of operations — Gathering and Processing — West

 

The Gathering and Processing — West segment includes our Four Corners’ natural gas gathering, processing and treating assets and our ownership interest in Wamsutter.

 

 

Four Corners

 

2007 vs. 2006

 

Revenues increased $11.5 million, or 2%, due primarily to $23.7 million higher product sales, partially offset by $9.5 million lower gathering and processing revenues and $2.7 million lower other revenues. Product sales increased due primarily to:

 

 

 

These product sales increases were partially offset by $12.7 million lower revenues related to an 8% decrease in NGL volumes that Four Corners received under certain processing contracts. Based on 2006 prices, the $12.7 million includes approximately $9.3 million related to NGL volume reductions caused by the fire at the Ignacio gas processing plant in late November 2007.

 

Additionally, product sales decreased in 2007 as a result of $3.0 million lower condensate and LNG sales.

 

Gathering and processing revenues decreased $9.5 million, or 4%, due primarily to $8.3 million lower revenue from a 3% decrease in gathered and processed volumes and a $1.3 million decrease from a lower average rate charged for these services. Based on 2006 prices, the $8.3 million includes approximately $5.5 million related to gathered and processed volume reductions caused by the fire at the Ignacio plant. The decrease in the average rate was due primarily to a lower rate on one of our agreements with an affiliate that is adjusted annually based on changes in the average price of natural gas. The price of natural gas was substantially higher in 2006 than 2007.

 

Product cost and shrink replacement increased $10.4 million, or 7%, due primarily to:

 

 

These increases were partially offset by $6.4 million from 10% lower volumetric shrink requirements under our Four Corners’ keep-whole processing contracts. Based on 2006 prices, the $6.4 million includes approximately $5.1 million related to reduced processing activity caused by the fire at the Ignacio plant.

 

Operating and maintenance expense increased $11.0 million, or 9%, due primarily to:

 

 

Partially offsetting these increases were $5.6 million lower materials and supplies related primarily to decreased equipment maintenance activity.

 

General and administrative expense — direct decreased $4.1 million, or 35%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense but not in our segment results.

 

Other (income) expense, net in 2006 includes a $3.6 million gain recognized on the sale of the LaMaquina treating facility. The LaMaquina treating facility was shut down in 2002 and impairments were recorded in 2003 and 2004.

Segment operating income decreased $12.1 million, or 8%, due primarily to the estimated $13.0 million combined impact of the fire at the Ignacio gas processing plant. Higher product sales margins, excluding the impact of the fire, of $17.5 million and $4.1 million lower direct general and administrative expense were offset by $7.7 million higher operating and maintenance expense excluding fire-related items, $4.0 million lower fee-based gathering and processing revenues not related to the fire, $4.2 million lower other (income) expense and $2.7 million lower miscellaneous revenue.

 

2006 vs. 2005

 

Revenues increased $39.1 million, or 8%, due primarily to $24.6 million higher product sales and $14.3 million higher gathering and processing revenues. Product sales increased due primarily to:

 

 

These product sales increases were partially offset by $9.0 million lower sales of NGLs on behalf of third party producers for whom we purchase their NGLs for a fee under their contracts. Under these arrangements, we purchase the NGLs from the third party producers and sell them to an affiliate. This decrease is offset by lower associated product costs of $9.0 million discussed below.

 

The $14.3 million increase in fee-based gathering and processing revenues is due primarily to $15.2 million higher revenue from a 7% increase in the average gathering and processing rates, partially offset by $0.9 million lower revenue from a slight decrease in gathering and processing volumes. The average gathering and processing rates increased in 2006 largely as a result of inflation-sensitive contractual escalation clauses. One significant gathering agreement is adjusted based on changes in the average price of natural gas.

 

Product cost and shrink replacement gas costs decreased $5.7 million, or 3%, due primarily to:

 

 

These decreases were partially offset by a $9.8 million increase from 16% higher volumetric shrink requirements under our keep-whole processing contracts.

 

Operating and maintenance expense increased $20.1 million, or 19%, due primarily to:

 

 

Other (income) expense, net improved $3.1 million due primarily to a $3.6 million gain recognized on the sale of the LaMaquina treating facility in 2006. The LaMaquina treating facility was shut down in 2002 and impairments were recorded in 2003 and 2004.

 

Segment operating income increased $26.5 million, or 20%, due primarily to $24.7 million of higher net liquids margins resulting primarily from increased per-unit margins on higher NGL sales volumes, $14.3 million of higher fee-based gathering and processing revenues, $5.2 million from higher condensate and LNG sales, and the $3.1 million improvement in other (income) expense, net. These increases were partially offset by $20.1 million higher operating and maintenance expense.

 

Outlook for 2008

 

 

Wamsutter

 

Wamsutter is accounted for using the equity method of accounting. As such, our interest in Wamsutter’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Wamsutter.

 

 

2007 vs. 2006

 

Revenues decreased $1.2 million, or 1%, due primarily to a $12.3 million decrease in product sales revenues, substantially offset by a $10.0 million increase in gathering and fee-based processing revenues.

 

Product sales revenues decreased $12.3 million, or 11%, due primarily to:

 

 

These product sales decreases were partially offset by a $12.1 million increase related to 14% higher average NGL sales prices resulting from an increase in market prices for these commodities between the two periods.

 

Gathering and fee-based processing revenues increased $5.6 million due to a 9% increase in the average fee received for these services and $4.4 million due to an 8% increase in volumes. The average fee increased as a result of fixed annual percentage or inflation-sensitive contractual escalation clauses and incremental fee revenues from completed gathering system expansion projects. Certain agreements provide incremental fee-based revenues upon the completion of projects that lower system pressures, allowing these customers to flow higher volumes from their existing wells.

Other revenues increased $1.0 million, or 19%, due primarily to higher revenue from minimum throughput provisions under certain gathering contracts.

 

Product cost and shrink replacement decreased $25.0 million, or 35%, due primarily to:

 

 

Operating and maintenance expense increased $1.2 million, or 7%, due primarily to:

 

 

These increases were partially offset by $4.9 million lower non-shrink natural gas purchases due primarily to higher system gains.

 

Depreciation and accretion expense increased $2.2 million, or 14%, due primarily to new assets placed into service.

 

General and administrative expenses increased $3.8 million, or 42%, due primarily to higher charges allocated by Williams to Wamsutter for various technical and administrative support functions.

 

Net income increased $15.7 million, or 25%, due primarily to $12.9 million higher net liquids margins and $10.0 million higher gathering and fee-based processing revenues, partially offset $3.8 million higher general and administrative expenses and $2.2 million higher depreciation and accretion expense.

 

2006 vs. 2005

 

Revenues decreased $0.5 million due primarily to an $8.4 million decrease in product sales revenues substantially offset by a $7.4 million increase in gathering and fee-based processing revenues.

 

Product sales revenues decreased $8.4 million, or 7%, due primarily to:

 

 

These product sales decreases were partially offset by a $9.0 million increase related to 9% higher average NGL sales prices resulting from an increase in market prices for these commodities between the two periods.

Gathering and fee-based processing revenues increased $4.2 million due to an 8% increase in the average fee received for these services and $3.3 million due to a 7% increase in volumes. The average fee increased as a result of fixed annual percentage or inflation-sensitive contractual escalation clauses and incremental fee revenues discussed previously.

 

Product cost and shrink replacement decreased $29.3 million, or 29%, due primarily to:

 

 

Operating and maintenance expense increased $4.5 million, or 36%, due primarily to a $2.1 million increase in non-shrink natural gas purchases resulting from higher system losses, a $1.0 million increase in rental expense for leased compression added in late 2005 and a $0.5 million increase in labor and benefits expense.

 

Depreciation and accretion expense increased $1.9 million, or 13%, due primarily to new assets placed into service in 2006.

 

Net income increased $21.2 million, or 52%, due primarily to $20.9 million in higher net liquids margins and $7.4 million higher gathering and fee-based processing revenues, partially offset by $4.5 million higher operating and maintenance expense and $1.9 million higher depreciation and accretion expense.

 

Outlook for 2008

 

 

Results of operations — Gathering and Processing — Gulf

 

The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership interest in Discovery.

 

 

Carbonate Trend

 

2007 vs. 2006

 

Segment operating loss increased $11.2 million due primarily to the $10.4 million fourth quarter 2007 impairment of the Carbonate Trend pipeline. (See Note 7, Other (Income) Expense, of our Notes to Consolidated Financial Statements.)

 

2006 vs. 2005

 

Segment operating income decreased $1.8 million from income of $1.6 million in 2005 to a loss of $0.2 million in 2006 due to the $0.9 million increase in operating and maintenance expense associated mainly with increased insurance premiums following 2005 hurricane activity. Additionally, 2005 included $0.5 million in revenues from the settlement of a contractual volume deficiency payment.

 

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 Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Discovery.

 

2007 vs. 2006

 

Revenues increased $63.4 million, or 32%, due primarily to $73.8 million higher product sales, partially offset by a $9.9 million reduction in fee-based transportation, gathering, processing and fractionation revenues. The 2006 period included revenues from the Tennessee Gas Pipeline (TGP) and the Texas Eastern Transmission Company (TETCO) open season agreements. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita in 2005. TGP’s open season contract came to an end in early 2006. TETCO’s volumes continued throughout 2006 and in October 2006 we signed a one-year contract, which is discussed further in the Outlook section. The significant components of the revenue increase are addressed more fully below.

 

Product sales increased $73.8 million primarily due to:

 

 

The $9.9 million decrease in fee-based transportation, gathering, processing and fractionation revenues is due primarily to the reduced fee-based revenues related to processing TGP and TETCO volumes under the open season agreements discussed above.

 

Product cost and shrink replacement increased $36.2 million, or 30%, due primarily to