UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 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 o     No þ

 

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o     Accelerated filer þ     Non-accelerated filer o

 

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 $417,974,414. This figure excludes common units beneficially owned by the directors and executive officers of Williams Partners GP LLC, our general partner.

 

The registrant had 25,553,306 common units, 6,805,492 Class B units and 7,000,000 subordinated units outstanding as of February 27, 2007.

 

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.

 

¢/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

 

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of Discovery, in which we own a 40% interest. “Discovery” consists of Discovery Producer Services LLC and its wholly owned subsidiary, Discovery Gas Transmission LLC. When we refer to Discovery by name, we are referring exclusively to its 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. From time-to-time, we may also file registration and related statements 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.

 

We make available free of charge on or through our Internet website at http://www.williamslp.com, 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., or Williams, in February 2005, to own, operate and acquire a diversified portfolio of complementary energy assets. We are principally engaged in the business of gathering, transporting, 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 our 40% interest in Discovery as an equity investment and, therefore, do not consolidate its financial results.

 

Our assets were owned by Williams prior to the initial public offering (“IPO”) of our common units in August 2005 and our acquisition of Four Corners in 2006. Williams indirectly owns an approximate 21% limited partnership interest in us and all of our 2% general partner interest.

 

Williams is an integrated energy company with 2006 revenues in excess of $11.8 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.

 

Acquisition of Four Corners.  In 2006, in two separate transactions, we acquired 100% of Four Corners from Williams. On June 20, 2006, we acquired a 25.1% membership interest in Four Corners for aggregate consideration of $360.0 million. On December 13, 2006, we acquired the remaining 74.9% membership interest for aggregate consideration of $1.223 billion. These two transactions were financed with the following debt and equity issuances.

 

Issuance of Common Units.  On June 20 and December 13, 2006, respectively, we sold 7,590,000 and 8,050,000 common units (including 990,000 and 1,050,000 common units pursuant to the underwriters’ over-allotment purchase option) in public offerings. We received net proceeds of approximately $227.1 million and $293.7 million, respectively, from the sale of the common units after deducting underwriting discounts but before estimated offering expenses.

 

Issuance of Common Units and Class B units in a Private Placement.  On December 13, 2006, we sold 2,905,030 common units and 6,805,492 unregistered Class B units in a private placement. We received net proceeds of approximately $346.5 million after deducting placement fees but before estimated offering expenses. The Class B units are convertible into common units on a one-for-one basis upon the approval of a majority of the votes cast by common unitholders, provided that the total number of votes cast is at least a majority of common units eligible to vote (excluding common units held by Williams and its affiliates).

 

Issuance of Senior Unsecured Notes.  On June 20 and December 13, 2006, respectively, we issued $150.0 million and $600.0 million aggregate principal amount of 7.5% and 7.25% senior unsecured notes due 2011 and 2017, respectively. We received net proceeds of approximately $146.8 million and $590.0 million, respectively, from the sale of the senior unsecured notes after deducting initial purchaser discounts and estimated offering expenses.

 

Williams’ New Credit Facility.  In May 2006, Williams replaced its $1.275 billion secured credit facility with a $1.5 billion unsecured credit agreement. The new facility contains similar terms and covenants as the prior facility. The new credit agreement is available for borrowings and letters of credit and will continue to allow us to borrow up to $75.0 million for general partnership purposes, including acquisitions, but only to the

extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. Please read “— Financial Condition and Liquidity — Credit Facilities” for more information.

 

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, which 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 72% of our Gathering and Processing — West segment’s total revenue less its product cost and shrink replacement costs and expenses for the year ended December 31, 2006. The remaining 28% of the segments total revenues less product cost and shrink replacement for the year ended December 31, 2006 was derived from the sale of NGLs received by Four Corners as consideration for processing services.

 

For the twelve months ended December 31, 2006, 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 reservoirs with approximately 60% coming from coal bed reservoirs. We are currently the only company in the basin that is the owner and operator of both major conventional natural gas and coal bed methane gathering, processing and treating facilities in the San Juan Basin. Despite the topographically challenging terrain, we have gathering pipelines throughout most of 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 Four Corners pipeline system. 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 Gathering and Processing — West segment includes 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 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, 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 sources typically contain high levels of carbon dioxide that must be reduced to 2% or less for transportation through pipelines to end markets. Our Gathering and Processing — West segment includes 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 charges a fee for the volume of natural gas treated at its facilities and does not take gas as payment for its treating services, other than for the reimbursement of gas used or lost during the treating of natural gas.

 

Four Corners Customers and Contracts

 

Customers.  ConocoPhillips’ fee-based gathering and processing revenue accounted for approximately 24% of this segment’s total revenues. Total revenues are comprised of product sales and fee-based gathering and processing revenues. 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. ConocoPhillips’ fee-based gathering and processing revenue accounted for 50% of this segment’s total fee-based gathering and processing revenues, including revenues attributable to Burlington Resources prior to its acquisition by ConocoPhillips on March 31, 2006.

 

Additionally, product sales to a subsidiary of Williams, to which Four Corners sells substantially all of the NGLs it retains under its keep-whole and percent-of-liquids contracts, accounted for approximately 45% of the segment’s total revenues for the year ended December 31, 2006. This amount includes NGL sales related to third-party processing customers’ NGLs that Four Corners purchases.

 

Contracts.  We provide our Four Corners customers with a full range of gathering, processing and treating 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. Our portfolio of Four Corners’ natural gas processing agreements includes the following types of contracts:

 

 

Competition

 

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

 

Gas Supply

 

All of our contracts with major customers contain certain production dedications whereby natural gas produced from a particular area and/or group of receipt points may only flow to 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. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts, on favorable terms, if at all. For example, Four Corners is in active negotiations with several customers to renew gathering, processing and treating contracts that are in evergreen status and that represent approximately 9% of our total revenues for the year ended December 31, 2006. 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 and processed 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.

 

Our Gathering and Processing — Gulf segment is comprised of our 40% interest in Discovery and the Carbonate Trend gathering pipeline.

 

Discovery — General

 

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

 

 

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

 

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 located in the offshore Louisiana Outer Continental Shelf at Ewing Bank 873. It extends northerly to the Larose gas processing plant and a four-mile, 20-inch natural gas pipeline that connects the Larose plant to the Texas Eastern Pipeline. Approximately 66 miles of the mainline is located offshore in water depths ranging from approximately 40 to 800 feet. Producers have dedicated their production from approximately 60 offshore blocks to Discovery. Each block represents an area of 5,760 acres (nine square miles). The mainline has a FERC-certificated capacity of approximately 600 MMcf/d.

 

The Discovery system connects to six natural gas pipeline systems, two of which provide 1.6 Bcf/d of takeaway capacity: the Bridgeline system, which serves southern Louisiana and connects to the Henry Hub natural gas market point, the Texas Eastern Pipeline system, which serves markets from Texas to the northeastern United States and Gulfsouth, which provides gas markets to the entire gulf coast region. Additionally, Discovery completed a market expansion project in June 2005 that connects Discovery to three additional pipeline systems: Tennessee Gas Pipeline, Columbia Gulf Transmission and Transcontinental Gas Pipe Line, or Transco. Together, these three pipeline systems provide up to an additional 500 MMcf/d of takeaway capacity. This market expansion project, consisting of approximately 40 miles of 20-inch diameter pipe extending from the Larose processing plant to Pointe Au Chien, Louisiana and Old Lady Lake, Louisiana has a FERC-certificated capacity of approximately 150 MMcf/d. Discovery’s interconnections allow producers to benefit from flexible and diversified access to a variety of natural gas markets from the Gulf of Mexico to the eastern United States.

 

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

 

 

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

 

Deepwater Gathering.  Discovery’s deepwater gathering assets, which are located in water depths of greater than 1,000 feet, consist of 73 miles of gathering laterals, with pipeline diameters ranging from eight inches to 16 inches that extend to deepwater producing areas in the Gulf of Mexico such as the Morpeth prospect, Allegheny prospect and Front Runner prospect. The maximum water depth of these deepwater laterals is approximately 3,200 feet. Additionally, Discovery has signed definitive agreements to construct a gathering pipeline lateral to connect Discovery’s existing pipeline system to certain producers’ production facilities for the Tahiti prospect described above. 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 and is located on land that Discovery leases from a third party. The initial term of the lease is 20 years and is renewable for ten-year intervals thereafter at Discovery’s option for up to a total of 50 years.

 

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%. The Larose plant consumes very low amounts of natural gas as fuel, using only approximately 1.4% of the volume of natural gas processed.

 

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

 

Paradis Fractionation Facility

 

The fractionator is located onshore near Paradis, Louisiana. The fractionator and mixed NGL pipeline went into service in January 1998 and is located on land that Discovery leases from a third party. The initial term of the lease is 20 years and is renewable for ten-year intervals thereafter at Discovery’s option for up to a total of 50 years. The Paradis fractionator is designed to fractionate 32,000 bpd of mixed NGLs and is expandable to 42,000 bpd. In 2006, Discovery fractionated an average of 15,139 bpd of mixed NGLs. All products can be delivered through the Chevron TENDS NGL pipeline system, and propane and heavier products may be transported by truck or railway.

 

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

 

Discovery Management

 

Currently, Discovery is owned 40% by us, 20% by Williams and 40% by DCP Midstream, LLC (“DCP”). Discovery is managed by a three-member management committee consisting of representation from each of the three owners. The members of the management committee have voting power that corresponds to the ownership interest of the owner they represent. However, except under limited circumstances, all actions and decisions relating to Discovery require the unanimous approval of the owners. Discovery must make quarterly distributions of available cash (generally, cash from operations less required and discretionary reserves) to its owners. The management committee, by majority approval, will determine the amount of such distributions. In addition, the owners are required to offer to Discovery all opportunities to construct pipeline laterals within an “area of interest.”

 

Discovery Customers and Contracts

 

Customers.  Product sales to a subsidiary of Williams, which purchases substantially all of the NGLs and excess natural gas to which Discovery takes title, accounted for approximately 75.3% of Discovery’s revenues for the year ended December 31, 2006. This amount includes 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.

 

Texas Eastern Transmission Company (“TETCO”) accounted for approximately 25% of Discovery’s fee-based, transportation, gathering and processing, fractionation and related revenues. TETCO’s revenues related to the open seasons, which provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita. In October 2006, Discovery signed a one-year contract with TETCO. Discovery’s other 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.

 

Contracts.  Discovery’s wholly owned subsidiary, Discovery Gas Transmission, 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, Discovery Gas Transmission has the authority to negotiate a specific rate arrangement with an individual shipper and has several of these arrangements currently in effect.

 

Discovery’s maximum regulated rate for mainline transportation is scheduled to decrease in 2008. At that time, Discovery may be required to reduce the mainline transportation portion of the rate on any of its contracts that have rates above the new reduced rate. This could reduce the revenues generated by Discovery. Discovery may elect to file a rate case with the FERC to alter this scheduled reduction. However, if filed, a rate case may not be successful in even partially preventing the scheduled rate reduction. Please read “— FERC Regulation.”

 

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

 

 

Operation and Contract Optimization

 

Long-haul natural gas pipelines, generally interstate pipelines that serve end use markets, publish specifications for the maximum NGL content of the natural gas that they will transport. Normally, NGLs must be removed from the natural gas stream at a gas processing facility in order to meet these pipeline specifications. It is common industry practice, however, to blend some unprocessed gas with processed gas to the extent that the combined gas stream is still able to meet the pipeline specifications at the point of injection into the long-haul pipeline.

 

Although it is typically profitable for producers to separate NGLs from their natural gas streams, there can be periods of time in which the relative value of NGL market prices to natural gas market prices may result in negative processing margins and, as a result, lack of profit from NGL extraction. Because of this margin risk, producers are often willing to pay for the right to bypass the gas processing facility if the circumstances permit. Owners of gas processing facilities may often allow producers to bypass their facilities if they are paid a “bypass fee.” The bypass fee helps to compensate the gas processing facility for the loss of processing volumes. Under Discovery’s contracts that include a bypass option, Discovery’s customers may exercise their option to bypass the gas processing plant. Producers with these contracts notify Discovery of their decision to bypass prior to the beginning of each month.

 

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. Recently connected blocks include Murphy’s Front Runner discovery, Energy Partners’ Rock Creek discovery, Apache’s Tarantula discovery and ATP’s Gomez discovery. Additionally, Discovery has signed definitive agreements

with Chevron, Total and Statoil to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect described above. Furthermore, in areas that we believe are accessible to the Discovery pipeline system, approximately 600 deepwater blocks are currently leased and approximately 100 have related exploration plans filed with the Minerals Management Service of the U.S. Department of the Interior, or the MMS, or are named prospects. A named prospect is an individual lease or group of adjacent leases that are generally considered by a producer to have some economic potential for production.

 

Third-Party Pipeline Supply

 

Last year’s emergency connections to TETCO and Tennessee Gas Pipeline (“TGP”) have continued to flow gas throughout 2006. Discovery signed 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. Additionally, Discovery is competing for additional gas throughput from TETCO and TGP.

 

Carbonate Trend Pipeline — General

 

Our Carbonate Trend gathering pipeline is a sour gas gathering pipeline consisting of approximately 34 miles of 12-inch diameter pipe that is used to gather sour gas production from the Carbonate Trend area off the coast of Alabama. Our Carbonate Trend pipeline is not regulated under the Natural Gas Act but is regulated under the Outer Continental Shelf Lands Act, which requires us to transport gas supplies on the Outer Continental Shelf on an open and non-discriminatory access basis. “Sour” gas is natural gas that has relatively high concentrations of acidic gases such as hydrogen sulfide and carbon dioxide. Our pipeline is designed to transport gas with a hydrogen sulfide and carbon dioxide content that exceeds normal gas transportation specifications. The pipeline was built and placed in service in 2000 and has a maximum design throughput capacity of approximately 120 MMcf/d. For the year ended December 31, 2006, our average transportation volume was approximately 29 MMcf/d.

 

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

 

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

 

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

 

Carbonate Trend Customers and Contracts

 

Customers.  Our primary customer on the Carbonate Trend pipeline is Chevron, which, together with Coldren Resources L.P. (“Coldren”), who purchased Noble Energy’s interest, have large lease positions in the Carbonate Trend area. Chevron and Coldren own an interest in more than seven federal leases in the Carbonate Trend area and Chevron is the operator for the majority of these leases. For the year ended December 31, 2006, volumes from these Chevron leases represented approximately 70% of Carbonate Trend’s total throughput and 77% of Carbonate Trend’s total revenue with volumes from Coldren constituting the remainder.

 

Contracts.  We have long-term transportation agreements with Chevron and Coldren. Pursuant to these agreements, Chevron and Coldren have agreed to transport on our pipeline all gas produced on their seven 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 Coldren expire or the underlying reserves are depleted, Chevron and Coldren will not be committed to ship any natural gas on our pipeline. In addition, if any lease expires, and is reacquired by the same company within ten years of such expiration, all production from that lease must again be transported via our pipeline. Under these agreements Chevron and Coldren may make an annual election to utilize capacity along a segment of Transco. When Chevron or Coldren utilize this capacity, our per-unit gathering fee is determined by subtracting the FERC tariff-based rate charged by Transco for this capacity from the total negotiated fee. If these customers elect not to utilize the capacity along this segment of Transco, we can make no assurance that this capacity will be made available to these customers in the future. We have the option to terminate these agreements if expenses exceed certain levels or if revenues fall below certain levels and we are not compensated for these expenses or shortfalls.

 

Competition

 

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

 

Gas Supply

 

Chevron developed the Viosca Knoll Carbonate Trend area in the shallow waters of the Mobile and Viosca Knoll areas in the eastern Gulf of Mexico. Chevron has filed several exploration plans with the MMS that we believe could result in the discovery of additional amounts of natural gas. Other producers may also transport gas on the Carbonate Trend pipeline.

 

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

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

 

Conway West.  The Conway West facility located adjacent to the Conway fractionation facility in McPherson County, Kansas is our primary storage facility. This facility has an aggregate storage capacity of approximately ten million barrels.

 

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

 

Mitchell.  The Mitchell facility is located approximately 14 miles west of the Conway West facility in Rice County, Kansas and has an aggregate storage capacity of approximately five million barrels.

 

Competition

 

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

 

Historically, we completed these product sales and purchases with third parties. However, in December of 2004, we began to complete these purchases and sales with a subsidiary of Williams. If this arrangement with the Williams subsidiary were terminated, we believe we could once again transact with third parties.

 

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 BP Wattenberg 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 owns a 40% undivided interest, representing capacity of approximately 42,800 bpd, and ONEOK owns a 10% undivided interest, representing capacity of approximately 10,700 bpd. Each joint owner markets its own capacity independently. Each owner can also contract with the other owners for additional capacity at the Conway fractionation facility, if necessary. We are the operator of the facility pursuant to an operating agreement that extends until May 2011.

 

We primarily fractionate NGLs for third party customers for a fee based on the volumes of mixed NGLs fractionated. The per-unit fee we charge is generally subject to adjustment for changes in certain fractionation expenses, including natural gas, electricity and labor costs, which are the principal variable costs in NGL fractionation. As a result, we are generally able to pass through increases in those fractionation expenses to our customers. However, under one of our long-term fractionation contracts described below, there is a cap on the per-unit fee and, under current natural gas market conditions, we are not able to pass through the full amount of increases in variable expenses to this customer. In order to mitigate the fuel price risk with respect to our purchases of natural gas needed to perform under this contract, upon the closing of our initial public offering, Williams transferred to us a contract for the purchase of a sufficient quantity of natural gas from a wholly owned subsidiary of Williams at a price not to exceed a specified price to satisfy our fuel requirements under this fractionation contract.

 

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.

 

Competition

 

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

 

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 BP Wattenberg pipeline, the Conway fractionation facility has access to mixed NGLs from additional major supply basins in North America, including additional major supply basins in the Rocky Mountain production area.

 

NGL Transportation Options

 

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

 

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 37% of our segment revenues in 2006.

 

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.

 

One such long-term fractionation contract expires on January 1, 2008. Another long-term fractionation contract expires in 2009. We generally enter into fractionation contracts that cover a portion of our remaining capacity at the Conway facility for periods of one year or less.

 

Discovery’s natural gas pipeline system is subject to regulation by the United States Department of Transportation, referred to as DOT, under the Accountable Pipeline and Safety Partnership Act of 1996, referred to as the Hazardous Liquid Pipeline Safety Act, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management. The Hazardous Liquid Pipeline

Safety Act covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations.

 

Discovery’s gas pipeline system is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002. The Natural Gas Pipeline Safety Act regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States oil and natural gas transportation pipelines and some gathering lines in high-consequence areas within ten years. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. We currently estimate we will incur costs of approximately $0.8 million between 2007 and 2008 to implement integrity management program testing along certain segments of Discovery’s 16, 20, and 30-inch diameter natural gas pipelines and its 10, 14, and 18-inch diameter NGL pipelines. This does not include the costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program.

 

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

 

Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements. In compliance with applicable permit requirements, we completed a survey of portions of our Carbonate Trend pipeline. As a result of this survey, we have determined that it will be necessary to undertake certain restoration activities to repair the partial erosion of the pipeline overburden caused by Hurricane Ivan in September 2004 and Hurricane Katrina in August 2005. We estimate that these restoration activities could be completed by the end of 2007. During these repairs, the pipeline would be shutdown for approximately 40 days, which would decrease our cash flows from operations by approximately $0.3 million. We would fund these repairs with cash flows from operations and seek reimbursement from our insurance carrier and/or contractual counterparties. Additionally, in the omnibus agreement, Williams agreed to reimburse us for the cost of the restoration activities related to Hurricane Ivan to the extent that we are not reimbursed by our insurance carrier and subject to an overall limitation of $14.0 million for all indemnified environmental and related expenditures generally for a period of three years that ends in August 2008. We are assessing our options for meeting our obligations with respect to these restoration activities.

 

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

 

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive

chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with the OSHA regulations.

 

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 the rates be “just and reasonable” and nondiscriminatory. Under the Natural Gas Act, the FERC has authority over the construction, operation and expansion of interstate pipeline facilities, as well as the 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. Commencing in 1992, the FERC issued a series of orders (“Order No. 636”), which require interstate pipelines to provide transportation service separate or “unbundled” from the pipelines’ sales of gas. Order No. 636 also required interstate pipelines, such as Discovery to provide open access transportation on a non-discriminatory basis that is equal for all similarly situated shippers. The Natural Gas Act also gives the FERC the authority to regulate the rates that Discovery charges for service on portions of its natural gas pipeline system. The natural gas pipeline industry has historically been heavily regulated by federal and state governments, and we cannot predict what further actions the FERC, state regulators, or federal and state legislators may take in the future.

 

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

 

 

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

 

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

waivers from compliance with Order No. 2004 are necessary to accommodate the management committee structure under which Discovery operates. Discovery filed for additional limited waivers from Order No. 2004 compliance on May 6, 2005 requesting a limited waiver to permit three DCP employees to be shared between Discovery and DCP and to provide information necessary for DCP to carry out its responsibilities as an owner of Discovery. The FERC has not yet acted on this filing. However, on November 17, 2006, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded Order No. 2004 as applied to interstate natural gas pipelines and their affiliates. On January 9, 2007, the FERC issued an interim rule. The Interim Rule re-promulgates, on an interim basis, the standards of conduct that were not challenged before the Court. The Interim Rule applies to the relationship between interstate natural gas pipelines and their marketing and brokering affiliates, but not necessarily to their other affiliates, such as gatherers, processors or exploration and production companies. On January 18, 2007, the FERC issued a Notice of Proposed Rulemaking to propose permanent regulations regarding the standards of conduct. A comment period will ensue through April 4, 2007, after which the FERC may enact a final rule. At this stage, it cannot be determined how a final rule may or may not affect Discovery.

 

Under Discovery’s current FERC-approved tariff, the maximum rate that Discovery may charge its customers for the transportation of natural gas along its mainline is $0.1569/MMBtu. This maximum rate is scheduled to decrease in January 2008 to $0.08/MMBtu. At that time, Discovery may be required to reduce the mainline transportation portion of the rate on any of its contracts that have rates above the new maximum rate. This could reduce the revenues generated by Discovery. Discovery may elect to file a rate case with the FERC seeking to alter this scheduled reduction. However, if filed, a rate case may not be successful in even partially preventing the scheduled rate reduction.

 

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

 

 

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

proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary to determine its income allowance. The FERC’s BP West Coast remand decision and the new tax allowance policy have been appealed to the D.C. Circuit, and rehearing requests have been filed with respect to the December 2005 order. Therefore, the ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. 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.

 

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

 

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 system are gathering pipelines, and are not subject to the FERC’s jurisdiction under the Natural Gas Act.

 

The primary function of Discovery’s natural gas processing plant is the extraction of NGLs and the conditioning of natural gas for marketing into the natural gas pipeline grid. 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 governing the discharge of materials into the environment, or otherwise relating to the protection of the environment. Due to the myriad of complex federal, state and local laws and regulations that may affect us, directly or indirectly, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.

 

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

 

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

 

In the omnibus agreement 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.

 

Air Emissions

 

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

 

Hazardous Substances and Waste

 

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

 

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

 

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

 

We are a participant in certain hydrocarbon removal and groundwater monitoring activities at Four Corners associated with certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at seven and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and sustain closure criteria levels and state regulator approval is received, the sites will be properly abandoned. Four Corners expects the remaining sites will be closed within four to eight years.

 

Water

 

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

 

Hazardous Materials Transportation Requirements

 

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

 

Kansas Department of Health and Environment Obligations

 

We currently own and operate underground storage caverns near Conway, Kansas that have been created by solution mining the caverns in the Hutchinson salt formation. These storage caverns are used to store NGLs and other liquid hydrocarbons. These caverns are subject to strict environmental regulation by the Underground Storage Unit within the Bureau of Water, Geology Section of the KDHE under the Underground Hydrocarbon and Natural Gas Storage Program. The current revision of the Underground Hydrocarbon and Natural Gas Storage regulations became effective on April 1, 2003 (temporary) and August 8, 2003 (permanent); these rules regulate the storage of liquefied petroleum gas, hydrocarbons and natural gas in bedded salt for the purpose of protecting public health and safety, property and the environment and regulates the construction, operation and closure of brine ponds associated with our storage caverns. The regulations specify several compliance deadlines including the final permit application for existing hydrocarbon storage wells by April 1, 2006, certain equipment requirements no later than April 1, 2008 and mechanical integrity and casing testing

requirements by April 1, 2010. Failure to comply with the Underground Hydrocarbon and Natural Gas Storage Program may lead to the assessment of administrative, civil or criminal penalties.

 

We are in the process of modifying our Conway storage facilities, including the caverns and brine ponds, and we believe that our storage operations will be in compliance with the Underground Hydrocarbon and Natural Gas Storage Program regulations by the applicable compliance dates. In 2003, we began to complete workovers on approximately 30 to 35 salt caverns per year and install, on average, a double liner on one brine pond per year. The incremental costs of these activities is approximately $5.5 million per year to complete the workovers and approximately $1.2 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 fugitive NGLs observed in the subsurface at the Conway Underground East facility. In addition, we have also recently detected fugitive NGLs in groundwater monitoring wells adjacent to two abandoned storage caverns at the Conway West facility. Although the complete extent of the contamination appears to be limited and appears to have been arrested, we are continuing to work to delineate further the scope of the contamination. To date, the KDHE has not undertaken any enforcement action related to the releases around the abandoned storage caverns.

 

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

 

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.

 

We are currently in discussions with the Jicarilla Apache Nation regarding rights-of-way that expired at the end of 2006 for a segment of Four Corners’ gathering system which flows less than 10% of the system’s gathered volumes. We continue to operate our assets on these reservation lands pursuant to a three-month agreement while we conduct further discussions that could result in renewal of our rights of way, sale of the gathering assets on reservation land or other options that might be in the mutual interest of both parties.

 

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 304 people, as of December 31, 2006, who will spend at least a majority of their time operating the Four Corners, Conway and Carbonate Trend facilities and approximately 110 general and administrative full-time equivalent employees in support of these operations. Discovery is operated by Williams pursuant to an operating and maintenance agreement and the employees who operate the Discovery assets are therefore not included in the above numbers. 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.

Item 1A.  Risk Factors

 

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. The production from existing wells connected to these pipelines and our Four Corners gathering system will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. We do not produce an aggregate reserve report on a regular basis or regularly obtain or update independent reserve evaluations. The amount of natural gas reserves underlying these wells may be less than we anticipate, and the rate at which production will decline from these reserves may be greater than we anticipate. Accordingly, to

maintain or increase throughput levels on these pipelines and the utilization rate of Discovery’s natural gas processing plant and fractionator and our Four Corners processing plants and treating plants, we and Discovery must continually connect new supplies of natural gas. The primary factors affecting our ability to connect new supplies of natural gas and attract new customers to our pipelines include: (1) the level of successful drilling activity near these pipelines; (2) our ability to compete for volumes from successful new wells and existing wells connected to third parties; and (3) our and Discovery’s 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 currently planned significant lateral expansion project. Discovery signed definitive agreements with Chevron, Shell and Statoil to construct an approximate 35-mile gathering pipeline lateral to connect Discovery’s existing pipeline system to these producers’ production facilities for the Tahiti prospect in the deepwater region of the Gulf of Mexico. Initial production is expected in the first half of 2008.

 

The level of drilling activity in the fields served by our and Discovery’s pipelines and our Four Corners gathering system is dependent on economic and business factors beyond our control. The primary factors that impact drilling decisions are oil and natural gas prices. A sustained decline in oil and natural gas prices could result in a decrease in exploration and development activities in these fields, which would lead to reduced throughput levels on our pipelines and gathering system. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits, the availability of qualified personnel and equipment, the quality of drilling prospects in the area and regulatory changes. Because of these factors, even if new oil or natural gas reserves are discovered in areas served by our pipelines and gathering system, producers may choose not to develop those reserves. If we were not able to connect new supplies of natural gas to replace the natural decline in volumes from existing wells, due to reductions in drilling activity, competition, or difficulties in completing lateral expansion projects to connect to new supplies of natural gas, throughput on our pipelines and gathering system and the utilization rates of Discovery’s natural gas processing plant and fractionator and our Four Corners processing plants and treating plants would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to 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 our Four Corners gathering system. Any such decline would reduce the amount of NGLs we fractionate and store, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to 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, Discovery and Four Corners both receive NGLs removed from the natural gas stream during processing. Discovery and Four Corners can then choose to either fractionate and sell the NGLs or to sell the NGLs directly. In addition, product optimization at our Conway fractionator generally leaves us with excess propane, an NGL, which we sell. We also sell excess storage volumes resulting from measurement variances at our Conway storage facilities.

 

The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for Discovery, Four Corners and their customers to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, Discovery and Four Corners may experience periods in which higher natural gas prices reduce the volumes of NGLs removed at their processing plants, which would reduce their margins. Finally, higher natural gas prices relative to NGL prices could also reduce volumes of gas processed generally, reducing the volumes of mixed NGLs available for fractionation.

 

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

 

We rely on a limited number of customers for a significant portion of our revenues. Our largest customer for the year ended December 31, 2006, other than a subsidiary of Williams that purchases NGLs, is ConocoPhillips which accounted for approximately 24% of the Gathering and Processing — West segment’s total revenues, including revenues attributable to Burlington Resources prior to its acquisition by ConocoPhillips on March 31, 2006.

 

In addition, although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts, on favorable terms, if at all. For example, Four Corners is in active negotiations with several customers to renew gathering, processing and treating contracts that are in evergreen status and that represent approximately 9% of our total revenues for the year ended December 31, 2006. The negotiations may not result in any extended commitments from these customers. The loss of all or even a portion of the volumes of natural gas or NGLs, as applicable, supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to 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 liquids pipeline access to multiple end markets for NGL products that are recovered from our Four Corners processing plants. If MAPL were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, we would be unable to deliver a substantial portion of the NGLs recovered at our Four Corners processing plants. This would have an immediate impact on our ability to sell or deliver NGL products recovered at our Four Corners processing plants. In addition, the five pipeline systems that move natural gas to end markets from the San Juan Basin connect to our Four Corners treating and processing facilities, including the El Paso Natural Gas, Transwestern, Williams’ Northwest Pipeline, PNM and Southern Trails systems. Some of these natural gas pipeline systems have minimal excess capacity. If any of these pipeline systems were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines, reduced operating pressures, lack of capacity or other causes, our customers would be unable to deliver natural gas to end markets. This would reduce the volumes of natural gas processed or treated at our Four Corners treating and processing facilities. Either of such events could materially and adversely affect our business results of operations, financial condition and ability to make distributions to unitholders.

 

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

 

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

 

We have the ability to incur up to $75.0 million of indebtedness under Williams’ $1.5 billion revolving credit facility. However, this $75.0 million of borrowing capacity will only be available to us to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. As a result, borrowings by Williams could restrict our access to credit. As of December 31, 2006, letters of credit totaling $29.0 million had been issued on behalf of Williams by the participating institutions under the facility and no revolving credit loans were outstanding. In addition, Williams’ public indentures contain covenants that restrict Williams’ and our ability to incur liens to support indebtedness. As a result, if Williams were not in compliance with these covenants, we could be unable to make any borrowings under our $75.0 million borrowing limit, even if capacity were otherwise available. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

 

Williams’ ability to comply with the covenants contained in its debt instruments may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ ability to comply with these covenants may be impaired. While we are not individually subject to any financial covenants or ratios under Williams’ revolving credit facility, Williams and its subsidiaries as a whole are subject to these tests. Accordingly, any breach of these or other covenants, ratios or tests, would terminate our and Williams’ and its other subsidiaries’ ability to make additional borrowings under the credit facility and, as a result, could limit our ability to finance our operations, make acquisitions or pay distributions to unitholders. In addition, a breach of these covenants by Williams would cause the acceleration of Williams’ and, in some cases, our outstanding borrowings under the facility. In the event of acceleration of indebtedness, Williams, the other borrowers or we might not have, or be able to obtain, sufficient funds to make required repayments of the accelerated indebtedness. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — 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 June 2006, we issued $150.0 million of senior unsecured notes and in December 2006, we issued an additional $600.0 million of senior unsecured notes, both of which caused our leverage to increase. Our total outstanding long-term debt as of December 31, 2006 was $750.0 million, representing approximately 85% 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 is not prohibited from incurring indebtedness, which may affect our ability to make distributions to unitholders.

 

Discovery is not prohibited by the terms of its limited liability company agreement from incurring indebtedness. If Discovery was to incur significant amounts of indebtedness, it may inhibit its ability to make distributions to us. An inability by Discovery 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 to represent a significant portion of the cash we distribute to unitholders.

 

We do not own all of the interests in 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 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.

 

Discovery may reduce its cash distributions to us in some situations.

 

Discovery’s limited liability company agreement provides that Discovery will distribute its available cash to its members on a quarterly basis. Discovery’s available cash includes cash on hand less any reserves that may be appropriate for operating its business. As a result, reserves established by Discovery, including those for working capital, will reduce the amount of available cash. The amount of Discovery’s quarterly distributions, including the amount of cash reserves not distributed, is determined by the members of its management committee representing a majority-in-interest in such entity.

 

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

 

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

 

Williams operates all of our assets, 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, our reliance on Hanover 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.

 

Hanover operates our Four Corners field compression pursuant to agreements that are on a month-to-month status and can be terminated by Hanover at any time by providing notice thirty days before the termination. If Hanover terminates the agreements, we would need to find another operator for the field compression. A change in operators could result in a significant interruption of service.

 

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. In April 2006, ONEOK, Inc. transferred its entire gathering and processing, natural gas liquids, and pipelines and storage segments to ONEOK Partners, L.P. (formerly known as Northern Border Partners, L.P.), or ONEOK. 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, fractionation and storage facilities in lieu of using ours.

 

Also, competitors may establish new connections with pipeline systems that would create additional competition for services we provide to our customers. For example, other than the producer gathering lines that connect to the Carbonate Trend pipeline, there are no other sour gas pipelines near our Carbonate Trend pipeline, but the producers that are currently our customers could construct or commission such pipelines in the future.

 

Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to 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.

 

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. In addition, Williams is not restricted from competing with us. Williams may acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

 

We may acquire new facilities or expand our existing facilities to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, our new or expanded facilities may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into our operations may result in unforeseen operating difficulties, may absorb significant management attention and may require financial resources that would otherwise be available for the ongoing development and expansion of our existing operations. Future acquisitions or construction projects could result in the incurrence of indebtedness and additional liabilities and excessive costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders. Further, if we issue additional common units in connection with future acquisitions, unitholders’ interest in the partnership will be diluted and distributions to unitholders may be reduced.

 

Discovery’s interstate tariff rates are subject to review and possible adjustment by federal regulators, which could have a material adverse effect on our business and operating results. Moreover, because Discovery is a non-corporate entity, it may be disadvantaged in calculating its cost of service for rate-making purposes.

 

The FERC, pursuant to the Natural Gas Act, regulates Discovery’s interstate pipeline transportation service. Under the Natural Gas Act, interstate transportation rates must be just and reasonable and not unduly discriminatory. If the FERC lowers the tariff rates Discovery is permitted to charge its customers, on its own initiative, or as a result of challenges raised by Discovery’s customers or third parties, 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 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.

 

Discovery’s maximum regulated rate for mainline transportation is scheduled to decrease in 2008. At that time, Discovery may be required to reduce its mainline transportation rate on all of its contracts that have rates above the new maximum rate. This could reduce the revenues generated by Discovery. Discovery may elect to file a rate case with the FERC seeking to alter this scheduled maximum rate reduction. However, if filed, a rate case may not be successful in even partially preventing the rate reduction. If Discovery makes

such a filing, all aspects of Discovery’s cost of service and rate design could be reviewed, which could result in additional reductions to its regulated rates.

 

Pursuant to an order on and remand of a decision by the U.S. Court of Appeals for the District of Columbia Circuit in BP West Coast Products, LLC v. FERC and a policy statement regarding income tax allowances issued by the FERC, 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. Both the FERC’s income tax allowance policy and its initial application in an individual pipeline rate proceeding are, however, currently being challenged in the court of appeals. As a result, the ultimate outcome of these proceedings is not certain and could result in a reversal of the FERC’s policy or other changes to the FERC’s treatment of income tax allowances in cost-of -service. Under the FERC’s current policy, if Discovery were to file a rate case, as discussed above, it would be required to prove pursuant to the new policy’s standard that the inclusion of an income tax allowance in Discovery’s cost-of -service was permitted. If 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.

 

On November 17, 2006, the U.S. Court of Appeals for the District of Columbia Circuit vacated and remanded the FERC’s Order No. 2004, which adopted standards of conduct governing interstate pipelines’ interactions with their energy affiliates. Discovery had previously received certain waivers from compliance with portions of Order No. 2004. It is uncertain what action, if any, the FERC will take in response to the remand. If the FERC issues new standards of conduct, Discovery may incur additional compliance costs.

 

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

 

There are operational risks associated with the gathering, transporting and processing of natural gas and the fractionation and storage of NGLs, including:

 

 

Any of these or any other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of life, property damage, damage to the environment or other significant exposure to liability. For example, in 2004 we experienced a temporary interruption of service on one of our pipelines due to an influx of seawater while connecting a new lateral. Also, Hurricanes Ivan and Katrina in 2004 and 2005, respectively, eroded part of the overburden covering our Carbonate Trend Pipeline. During the repair, it would be shutdown for approximately 40 days, which would decrease our cash flows from operations by approximately $0.3 million. We expect that the cost of the repair would be recoverable from insurance.

 

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.

 

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

 

MAPL, the only pipeline in the San Juan Basin that provides NGL transportation capacity, has filed at the FERC to increase certain of its tariff rates. If the FERC grants this request to increase those tariff rates, we estimate that our cost of transporting NGLs to certain markets would increase by approximately $1.5 million per year, which could have an adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

 

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

 

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs for gas transportation pipelines located 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 approximately one-third of the testing and expect to complete the remainder of the testing in 2007 and 2008. The results of these testing programs will be analyzed, and could cause us to incur significant capital and operating expenditures in response to any repair, remediation, preventative or mitigating actions that are determined to be necessary.

 

Additionally, the transportation of sour gas in our Carbonate Trend pipeline necessitates a corrosion control program in order to protect the integrity of the pipeline and prolong its life. Our corrosion control program may not be successful and the sour gas could compromise pipeline integrity. Our inability to reduce corrosion on our Carbonate Trend pipeline to acceptable levels could significantly reduce the service life of the pipeline and could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

 

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

 

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

 

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs to retain necessary land use. We obtain the rights to construct and operate our pipelines and gathering systems on land owned by third parties and governmental agencies for a specific period of time. 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.

 

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.

 

The risk of substantial environmental costs and liabilities is inherent in natural gas gathering, transportation and processing, and in the fractionation and storage of NGLs, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to stringent federal, state and local laws and regulations relating to protection of the public and the environment. These laws include, for example:

 

 

Various governmental authorities, including the U.S. Environmental Protection Agency, or EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under CERCLA, RCRA and analogous state laws for the remediation of contaminated areas.

 

There is inherent risk of the incurrence of environmental costs and liabilities in our business, 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.

 

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 in the event an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, new environmental regulations might adversely affect our products and activities, including processing, fractionation, storage and transportation, as well as waste management and air emissions. Federal and state agencies also could impose additional safety requirements, any of which could affect our profitability.

 

The natural gas gathering operations in the San Juan Basin may be subjected to regulation by the state of New Mexico, which could negatively affect 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 will occur, but they could result in gathering regulation that would affect the fees that we could collect for gathering services. This type of regulation could adversely impact our revenues and cash flow.

 

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 outstanding notes 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 outstanding notes 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 outstanding notes, or to repurchase our outstanding notes 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 outstanding notes or borrowing funds to make distributions on our common units. We cannot assure our notes holders that we would be able to refinance our outstanding notes or 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 December 31, 2006, Williams held 1,250,000 common units and 7,000,000 subordinated units, representing a 21% 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.

 

If we fail to obtain the approval of the unitholders for the conversion of the Class B units to common units, the minimum quarterly distribution payable in respect of the Class B units will increase, which will reduce the amount of cash available for distribution on our common units.

 

If conversion of our Class B units is not approved by our unitholders within six months of the closing of the issuance of the Class B units, which is June 11, 2007, the holders of the Class B units will be entitled to receive an increased quarterly distribution equal to 115% of the quarterly distribution and distributions on liquidation payable on each common unit, but in each case the holders of the Class B units will remain subordinated to the holders of common units with respect to quarterly distributions and any arrearages thereon. Based on our current quarterly distribution of $0.47 per unit, this increase would result in an aggregate of approximately $0.5 million of additional quarterly distributions on Class B units. If we become obligated to pay an increased quarterly distribution on the Class B units, our cash on hand will be reduced and we may not have sufficient cash available to pay distributions on our common units.

 

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

 

Recently-discovered accounting irregularities in various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosure, the relationships between companies and their independent auditors, and retirement plan practices. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to 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.

 

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

 

Williams owns the 2% general partner interest and a 21% limited partner interest in us and owns and controls our general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and executive officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, Williams. Conflicts of interest may arise between our general partner and its affiliates, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

 

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

 

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

 

 

By purchasing a common unit, a common unitholder will be 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 and subordinated units voting together as a single class is required to remove our general partner. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

 

Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of

charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

 

The control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of our general partner from transferring their member interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of the general partner with their own choices and to control the decisions taken by the board of directors and officers of the general partner. In addition, pursuant to the omnibus agreement with Williams, any new owner of the general partner would be required to change our name so that there would be no further reference to Williams.

 

Increases in interest rates may cause the market price of our common units to decline.

 

An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

 

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

 

Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional units subject to the limitations imposed by the New York Stock Exchange. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

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

 

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

 

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 vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.

 

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

 

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

 

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

 

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

 

Tax Risks

 

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

 

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

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to 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 entity-level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available to pay distributions to 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.

 

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

 

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

 

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

 

Unitholders are 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 our common units could be different than expected.

 

If a unitholder sell 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, whether or not representing gain, may be ordinary income to the unitholder.

 

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

 

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

 

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform will all aspects of existing Treasury regulations. 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 our 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. 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 Kansas, Louisiana, Colorado and New Mexico. 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 our capital and profits interests will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

 

None.

 

The information called for by this item is provided in Note 14, Commitments and Contingencies included in the 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 25,553,306 common units outstanding, held by approximately 13,238 holders, including common units held in street name and by affiliates of Williams.

 

As of February 26, 2007, there were 7,000,000 subordinated units outstanding held by four subsidiaries of Williams. The subordinated units are not publicly traded.

 

As of February 26, 2007, there were 6,805,492 Class B units outstanding, held by 22 holders. The Class B units were issued in December 2006 and are not publicly traded.

 

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the 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:

 

 

 

 

During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $0.35 per quarter,

plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. In addition, as described in more detail below, the Class B units rank junior to common units in their right to receive distributions but senior of the subordinated units. The Class B units, if any remain outstanding, would continue to rank junior to the common units even after the expiration of the subordination period.

 

The subordination period will extend until the first day of any quarter beginning after June 30, 2008 that each of the following tests are met:

 

 

In addition, the subordination period may terminate before June 30, 2008 if the following tests are met:

 

 

If the unitholders remove our general partner without cause, the subordination period may also end before June 30, 2008.

 

Upon expiration of the subordination period, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

 

 

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

 

 

 

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. In addition, the description of distributions payable on the Class B units above reflect the distributions payable on the Class B units within 180 days of their issuance on December 13, 2006. The Class B units will convert into common units on a one-for-one basis upon the approval of a majority of the votes cast by common unitholders provided that the total number of votes cast is at least a majority of common units eligible to vote (excluding common units held by Williams and its affiliates). We are required to seek such approval as promptly as practicable and not later than 180 days from December 13, 2006. If we have not obtained the requisite unitholder approval of the conversion of the Class B units within 180 days from December 13, 2006, the Class B units will be entitled to receive 115% of the quarterly distribution and distributions on liquidation payable on each common unit. We expect to call a special meeting of common unitholders in the second quarter of 2007 to seek approval for the conversion of the Class B units.

 

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 following table shows selected financial and operating data of Williams Partners L.P. and of Discovery Producer Services LLC for the periods and as of the dates indicated. We derived the financial data as of December 31, 2006 and 2005 and for the years ended December 31, 2006, 2005 and 2004 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 was an affiliate 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 consolidated financial statements and notes have been restated to reflect the combined historical results of Four Corners 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.

 

 

 

 

Please read the following discussion of our financial condition and results of operations in conjunction with the consolidated financial statements and related notes included in Item 8 of this annual report.

 

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 2006, the two most important events for our business were the June and December acquisitions of 25.1% and 74.9%, respectively, of Four Corners from Williams. The combined value of these transactions was approximately $1.6 billion, which is a dramatic increase in size from the $100.2 million we raised at our IPO in August of 2005. The acquisition of Four Corners provides us with a large-scale gathering and processing system with stable cash flows and a relatively high percentage of fee-based revenues. The 2006 results of our Gathering and Processing — West segment, which includes Four Corners, were exceptionally strong based on record commodity margins for the NGLs it receives under certain processing contracts. However, we also experienced significant increases in operating costs in that segment. Discovery continued work on its important Tahiti lateral expansion project, which remains on schedule to receive initial throughput in the first half of 2008. Discovery also benefited from record commodity margins and the continuation of processing volumes initially received following damage to third-party facilities during Hurricanes Katrina and Rita. In our NGL Services segment, we continued storage cavern workovers and wellhead modifications at Conway while generating increased storage revenues from higher average storage volumes. We have increased distributions each quarter in an aggregate amount of $0.12, or 34%, per unit since our IPO. We believe that we have adequate cash reserves to finance our working capital and maintenance capital requirements, and we have had no borrowings under our revolving credit facilities. Our capitalization and relationship with Williams has us well-positioned to continue to grow through both internal projects and acquisition transactions with Williams and other third parties.

 

Recent Events

 

Acquisition of Four Corners.  In 2006, in two separate transactions, we acquired 100% of Four Corners from Williams. On June 20, 2006, we acquired a 25.1% membership interest in Four Corners for aggregate consideration of $360.0 million. On December 13, 2006, we acquired the remaining 74.9% membership

interest for aggregate consideration of $1.223 billion. These two transactions were financed with the following debt and equity issuances.

 

Issuance of Common Units.  On June 20 and December 13, 2006, respectively, we sold 7,590,000 and 8,050,000 common units (including 990,000 and 1,050,000 common units pursuant to the underwriters’ over-allotment purchase option) in public offerings. We received net proceeds of approximately $227.1 million and 293.7 million, respectively, from the sale of the common units after deducting underwriting discounts but before estimated offering expenses.

 

Issuance of Common Units and Class B units in a Private Placement.  On December 13, 2006, we sold 2,905,030 common units and 6,805,492 unregistered Class B units in a private placement. We received net proceeds of approximately $346.5 million after deducting placement fees but before estimated offering expenses. The Class B units are convertible into common units on a one-for-one basis upon the approval of a majority of the votes cast by common unitholders, provided that the total number of votes cast is at least a majority of common units eligible to vote (excluding common units held by Williams and its affiliates).

 

Issuance of Senior Unsecured Notes.  On June 20 and December 13, 2006, respectively, we issued $150.0 million and $600.0 million aggregate principal amount of 7.5% and 7.25% senior unsecured notes due 2011 and 2017. We received net proceeds of approximately $146.8 million and $590.0 million from the sale of the senior unsecured notes after deducting initial purchaser discounts and estimated offering expenses.

 

Because Four Corners was an affiliate 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 consolidated financial statements and notes have been restated to include the historical results of Four Corners throughout the periods presented. These two acquisitions of a combined 100% membership interest in Four Corners increased net income $142.7 million, $113.5 million and $96.6 million for 2006, 2005 and 2004, respectively. These acquisitions have no impact on historical earnings per unit as pre-acquisition earnings were allocated to our general partner.

 

New Credit Facility with Williams.  In May 2006, Williams replaced its $1.275 billion secured credit facility with a $1.5 billion unsecured credit agreement. The new facility contains similar terms and covenants as the prior facility. The new credit agreement is available for borrowings and letters of credit and will continue to allow us to borrow up to $75.0 million for general partnership purposes, including acquisitions, but only to the extent that sufficient amounts remain unborrowed by Williams and its other subsidiaries. Please read “— Financial Condition and Liquidity — Credit Facilities” for more information.

 

How We Evaluate Our Operations

 

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

 

 

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. 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.

 

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

 

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. In certain prior years, such as 2003, we generated significant revenues from the sale of excess natural gas volumes. However, in response to a final rule issued by the FERC in 2004, we expect that Discovery will generate only minimal revenues, if any, from the sale of excess natural gas in the future. However, this rule has been vacated and remanded back to the FERC because the courts found that the FERC offered no evidence of abusive behavior to warrant such restriction.

 

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 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. Leased compression services are dependent upon the extent and amount of additional compression needed to meet the needs of our Four Corners’ 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.

 

In addition to the foregoing measures, we also review our general and administrative expenditures, substantially all of which are incurred through Williams. In an omnibus agreement, executed in connection with our IPO, Williams agreed to provide a five-year partial credit for general and administrative expenses incurred on our behalf. The amount of the credit was $3.2 million in 2006 and will decrease by approximately $800,000 in each subsequent year.

 

We record total general and administrative costs, including those costs that are subject to the credit by Williams, as an expense, and we record the credit as a capital contribution by our general partner. Accordingly, our net income does not reflect the benefit of the credit received from Williams. However, the cost subject to this credit is allocated entirely to our general partner. As a result, the net income allocated to limited partners on a per-unit basis reflects the benefit of this credit.

 

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. 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.

 

Accounting for Asset Retirement Obligations

 

We record asset retirement obligations for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset in the period in which it is incurred if a reasonable estimate of fair value can be made. At December 31, 2006, we have an accrued asset retirement obligation liability of $4.5 million for estimated retirement costs associated with the abandonment of Four Corners’ gas processing and compression facilities located on leased land, its wellhead connections on federal land and Conway’s underground storage caverns and brine ponds in accordance with KDHE regulations. 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 2006, the recorded asset retirement obligation would have increased by approximately $2.8 million. Our estimate utilizes judgments and assumptions regarding the extent of our

obligations, the costs to abandon and the timing of abandonment. Please read Note 8 of Notes to Consolidated Financial Statements.

 

Environmental Remediation Liabilities

 

We record liabilities for estimated environmental remediation liabilities when we assess that a loss is probable and the amount of the loss can be reasonably estimated. At December 31, 2006, we have an accrual for estimated environmental remediation obligations of $6.6 million. This remediation accrual is revised, and our associated income is affected, during periods in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. We base liabilities for environmental remediation upon our assumptions and estimates regarding what remediation work and post- remediation monitoring will be required and the costs of those efforts, which we develop from information obtained from outside consultants and from discussions with the applicable governmental authorities. As new developments occur or more information becomes available, it is possible that our assumptions and estimates in these matters will change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarter or annual period. During 2004, we purchased an insurance policy covering certain of our environmental liabilities. Please read “— Environmental” and Note 14 of Notes to Consolidated Financial Statements for further information.

 

Results of Operations

 

Consolidated Overview

 

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2006. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 

 

 

 

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 as well as increased storage revenues and increased product sales revenues 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 higher net liquids margins and fee-based revenues, partially offset by higher operating and maintenance expense.

 

Equity earnings from Discovery increased $3.7 million, or 44%, due primarily to Discovery’s higher gross processing margins partially offset by their 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. We issued $150.0 million in June 2006 and $600.0 million in December 2006 to finance our acquisition of 100% 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.

 

2005 vs. 2004

 

Revenues increased $45.8 million, or 10%, due primarily to higher product sales and gathering and processing revenues in our Gathering and Processing — West segment as well as increased storage and product sales revenues in our NGL Services segment.

 

Product cost and shrink replacement increased $24.6 million, or 16%, directly related to the increase in product sales volumes in our Gathering and Processing — West and NGL Services segments.

 

Operating and maintenance expense increased $13.3 million, or 11%, due primarily to higher maintenance, fuel and power costs in both our Gathering and Processing — West and NGL Services segments.

 

General and administrative expense increased $4.4 million, or 14%, due primarily to the increased costs of being a publicly-traded partnership. These costs included $1.1 million for audit fees, tax return preparation, director fees and registration and transfer agent fees, $0.7 million for direct and specific charges allocated by Williams for accounting, legal and other support, $0.6 million for business development and $0.3 million for other various expenses.

 

Other (income) expense, net improved $10.5 million, or 94%, due primarily to the 2004 impairment of our Four Corners’ LaMaquina carbon dioxide treating facility and other 2004 losses on asset dispositions and materials and supplies inventory adjustments.

 

Operating income increased $14.8 million, or 14%, due primarily to higher fee-based revenues and net liquids margins in our Gathering and Processing — West segment and the absence of a 2004 impairment charge, partially offset by higher operating and maintenance expenses.

 

Equity earnings from Discovery increased $3.8 million due primarily to Discovery’s 2005 recognition of deferred gains and higher revenues, partially offset by their increased expenses. This increase is discussed in detail in the “Results of Operations — Gathering and Processing — Gulf” section.

 

The 2004 impairment of our investment in Discovery is the result of our analysis pursuant to which we concluded that we had experienced an other than temporary decline in the fair value of our investment in Discovery.

 

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

 

The Cumulative effect of change in accounting principle of $1.3 million in 2005 relates to our December 31, 2005 adoption of Financial Accounting Standards Board Interpretation (“FIN”) No. 47. Please read Note 8 of Notes to Consolidated Financial Statements.

 

Results of operations — Gathering and Processing — West

 

The Gathering and Processing — West segment includes our Four Corners natural gas gathering, processing and treating assets.

 

 

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 Four Corners’ 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 the first quarter of 2006. The LaMaquina treating facility was shut down in 2002 and impairments were recorded in 2003 and 2004.

 

Segment profit 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 $3.5 million improvement in other (income) expense, net. These increases were partially offset by $20.1 million higher operating and maintenance expense.

 

2005 vs. 2004

 

Revenues increased $35.0 million, or 8%, due primarily to $26.4 million higher product sales and $9.8 million higher gathering and processing revenue. Product sales revenues increased due primarily to:

 

 

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

 

Fee-based gathering and processing revenues increased $9.8 million due to $17.1 million higher revenue from a 8% increase in the average gathering and processing rates, partially offset by $7.3 million lower revenue from 3% lower gathering volumes. The average gathering and processing rates increased in 2005 largely as a result of inflation-sensitive contractual escalation clauses. The volume decrease was driven by normal reservoir declines, which were partially offset by new well connects. The overall net decline is related primarily to the slightly steeper decline rate associated with coal bed methane production. Historically, we have substantially offset the impact of production declines at Four Corners with new well connects.

 

Products cost, primarily shrink replacement gas, increased $19.4 million, or 13%, due primarily to the $21.5 million increase from third party customers who elected to have us purchase their NGLs and

$15.1 million from a 30% increase in the average price of natural gas, partially offset by $17.2 million from 26% lower volumetric shrink requirements from our keep-whole processing contracts resulting from a customer exercising an annual option to switch from a keep-whole contract to a fee-based contract.

 

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

 

 

These increases were partially offset by $2.0 million of other various operating and maintenance expense decreases.

 

General and administrative — direct expense increased $3.7 million, or 44%, due primarily to including certain management costs that were directly charged in 2005 and allocated in 2004.

 

Other (income) expense, net improved $10.6 million, from $11.2 million in 2004, due primarily to the following 2004 charges that were not present in 2005:

 

 

Segment profit increased $15.7 million, or 13%, due primarily to $9.8 million higher gathering and processing revenues, $7.0 million higher product sales margins on lower NGL sales volumes and lower other expenses of $10.6 million, partially offset by $7.6 million higher operating and maintenance expenses and $3.7 million higher general and administrative — direct expenses.

 

Outlook 2007

 

Throughput volumes on our Four Corners gathering, processing and treating system are an important component of maximizing its profitability. Throughput volumes from existing wells connected to its pipelines will naturally decline over time. Accordingly, to maintain or increase throughput levels we must continually obtain new supplies of natural gas.

 

 

Results of operations — Gathering and Processing — Gulf

 

The Gulf segment includes the Carbonate Trend gathering pipeline and our 40% ownership interest in Discovery.

 

 

Carbonate Trend

 

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 resulting from hurricanes. Additionally, operating income decreased due to the absence of $0.5 million in revenues from the settlement of a contractual volume deficiency payment recognized in 2005 and lower gathering revenues.

 

2005 vs. 2004

 

Segment operating income decreased $1.5 million, or 48%, due primarily to lower gathering revenues and the absence of $1.0 million of revenue from the settlement of a contractual volume deficiency payment recognized in 2004, partially offset by $0.5 million of revenue from the settlement of a contractual volume deficiency payment recognized in 2005.

 

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.

 

 

2006 vs. 2005

 

Revenues increased $74.6 million, or 61%, due primarily to higher NGL product sales from the purchasing of customers’ NGLs. In addition, the Tennessee Gas Pipeline (“TGP”) and the Texas Eastern Transmission Company (“TETCO”) open season agreements, which began in the last quarter of 2005, contributed an increase of $7.5 million. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita. TGP’s open season contract came to an end in early 2006. TETCO’s volumes continued throughout 2006, and in October 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.

 

 

Partially offsetting these increases were the following:

 

 

Product cost and shrink replacement increased $55.1 million, or 85%, due primarily to $59.9 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs and $6.7 million higher costs related primarily to increased processing volumes in 2006, partially offset by a $10.0 million decrease due to the absence of excess fuel and shrink replacement gas sales in 2006.

 

Operating and maintenance expense increased $12.9 million, or 127%, due primarily to a $10.7 million credit recognized in 2005 related to amounts previously deferred for net system gains from 2002 through 2004. These deferred gains were recognized following the acceptance in 2005 of a filing with the FERC. Additionally, Discovery had higher fuel costs caused by increased processing activity, $1.8 million higher property insurance premiums related to the increased hurricane activity in the Gulf Coast region in prior years, partially offset by $1.0 million insurance deductible expensed in 2005.

 

Depreciation and accretion expense increased $0.7 million, or 3%, due primarily to the market expansion project placed in service in September 2005.

 

Interest income increased $0.7 million due primarily to interest earned on funds restricted for use in the construction of the Tahiti pipeline lateral expansion project.

 

Other (income) expense, net improved $2.8 million due primarily to a net improvement of $3.1 million in foreign currency transaction gains from the revaluation of restricted cash accounts denominated in Euros. These restricted cash accounts were established from contributions made by Discovery’s members, including us, for the construction of the Tahiti pipeline lateral expansion project. We are required to pay a significant portion of the construction costs in Euros.

 

Net income increased $9.3 million, or 44%, due primarily to $18.1 million higher gross processing margins and $7.5 million higher revenues from TGP and TETCO open seasons, partially offset by $12.9 million higher operating and maintenance and $3.8 million lower gathering revenues.

 

2005 vs. 2004

 

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

 

 

Partially offsetting these increases were the following:

 

 

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

 

 

Partially offsetting these increases were the following:

 

 

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

 

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

 

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

 

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

 

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

 

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

 

Outlook for 2007

 

Carbonate Trend

 

In compliance with applicable permit requirements, we completed a survey of portions of our Carbonate Trend pipeline. As a result of this survey, we have determined that it will be necessary to undertake certain restoration activities to repair the partial erosion of the pipeline overburden caused by Hurricane Ivan in September, 2004 and Hurricane Katrina in August 2005. We estimate that these restoration activities could be completed by the end of 2007. During these repairs, the pipeline would be shut down for approximately 40 days, which would decrease our cash flows from operations by approximately $0.3 million. We would fund these repairs with cash flows from operations and seek reimbursement from our insurance carrier and/or contractual counterparties. Additionally, in the omnibus agreement, Williams agreed to reimburse us for the cost of the restoration activities related to Hurricane Ivan to the extent that we are not reimbursed by our insurance carrier and subject to an overall limitation of $14.0 million for all indemnified environmental and related expenditures generally for a period of three years that ends in August 2008. We are assessing our options for meeting our obligations with respect to these restoration activities.

 

Discovery

 

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

 

 

Results of operations — NGL Services

 

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

 

 

2006 vs. 2005

 

Segment revenues increased $10.2 million, or 21%, due primarily to higher storage, product sales and other revenues. The significant components of these revenue increases are addressed more fully below.

 

 

Operating and maintenance expense increased $4.4 million, or 18%, due primarily to increased storage cavern workovers and increases to Conway’s environmental remediation liability, partially offset by favorable changes in product imbalance adjustments.

 

Product cost increased $3.7 million, or 31%, due to the higher product sales volumes discussed above as well as an increase in per-unit costs of 21%.

 

Segment profit increased $2.0 million, or 25%, due primarily to $10.2 million higher revenues, substantially offset by $8.1 million higher product cost and operating and maintenance expense.

 

2005 vs. 2004

 

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

 

 

 

Operating and maintenance expense increased $5.6 million, or 30%, due primarily to increased fuel and power costs, some of which we are able to pass through to our customers, and increased product imbalance valuation adjustments.

 

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

 

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

 

Segment profit increased $0.8 million, or 11%, due primarily to the $6.7 million higher storage and fractionation revenues, partially offset by $5.6 million higher operating and maintenance expense.

 

Outlook for 2007

 

 

Financial Condition and Liquidity

 

We believe we have the financial resources and liquidity necessary to meet future requirements for working capital, capital and investment expenditures, debt service and quarterly cash distributions. We anticipate our sources of liquidity for 2007 will include:

 

 

Our cash and cash equivalents increased $16.5 million and $19.2 million on June 20, 2006 and December 13, 2006, respectively, upon the completion of our acquisitions of 25.1% and 74.9% ownership interests in Four Corners. These amounts represent excess net proceeds generated by our offerings of common units and issuances of senior unsecured notes above the consideration paid to Williams for the respective Four Corners interests. We have retained this cash to be used for general partnership purposes.

 

We anticipate our more significant cash requirements for 2007 to be:

 

 

 

Discovery

 

Discovery expects to make quarterly distributions of available cash to its members pursuant to the terms of its limited liability company agreement. Discovery made the following 2006-2007 distributions to its members (all amounts in thousands):