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Williams Partners L.P. 10-K 2009
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2008
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number 1-32599
 
     
Delaware   20-2485124
(State or Other Jurisdiction of
Incorporation or Organization)
  (IRS Employer
Identification No.)
One Williams Center, Tulsa, Oklahoma   74172-0172
(Address of Principal Executive Offices)   (Zip Code)
 
918-573-2000
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Units   New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller Reporting company 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 $1,348,907,264. This figure excludes common units beneficially owned by the directors and executive officers of Williams Partners GP LLC, our general partner.
 
The registrant had 52,777,452 common units outstanding as of February 25, 2009.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
None
 


Table of Contents

 
 
                 
        Page
 
      Business and Properties     1  
        Website Access to Reports and Other Information     1  
        General     1  
        Recent Events     2  
        Financial Information About Segments     3  
        Narrative Description of Businesses     3  
        Gathering and Processing — West Segment     3  
        Gathering and Processing — Gulf Segment     9  
        NGL Services Segment     13  
        Safety and Maintenance     16  
        FERC Regulation     17  
        Environmental Regulation     18  
        Title to Properties and Rights-of-Way     21  
        Employees     21  
        Financial Information about Geographic Areas     22  
      Risk Factors     22  
      Forward-Looking Statements/Risk Factors and Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995     22  
      Unresolved Staff Comments     43  
      Legal Proceedings     43  
      Submission of Matters to a Vote of Security Holders     43  
 
      Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     43  
      Selected Financial and Operational Data     45  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     48  
      Quantitative and Qualitative Disclosures About Market Risk     74  
      Financial Statements and Supplementary Data     76  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     113  
      Controls and Procedures     113  
      Other Information     113  
 
      Directors and Executive Officers of the Registrant     113  
      Executive Compensation     121  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     124  
      Certain Relationships and Related Transactions, and Director Independence     127  
      Principal Accountant Fees and Services     134  
 
      Exhibits and Financial Statement Schedules     135  
 EX-10.4
 EX-10.8
 EX-12
 EX-21
 EX-23.1
 EX-23.2
 EX-24
 EX-31.1
 EX-31.2
 EX-32
 EX-99.1


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We use the following oil and gas measurements and industry terms in this report:
 
Barrel:  One barrel of petroleum products equals 42 U.S. gallons.
 
Bcf/d:  One billion cubic feet of natural gas per day.
 
bpd:  Barrels per day.
 
British Thermal Units (Btu):  When used in terms of volumes, Btu is used to refer to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.
 
BBtu/d:  One billion Btus per day.
 
Dth:  One dekatherm.
 
¢/MMBtu:  Cents per one million Btus.
 
MMBtu:  One million Btus.
 
MMBtu/d:  One million Btus per day.
 
MMcf:  One million cubic feet.
 
MMcf/d:  One million cubic feet per day.
 
Other definitions:
 
Fractionation:  The process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane.
 
NGLs:  Natural gas liquids. 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.
 
NGL margins:  NGL revenues less Btu replacement cost, plant fuel, transportation and fractionation.
 
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.


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WILLIAMS PARTNERS L.P.
FORM 10-K
 
PART I
 
 
Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of Wamsutter LLC (Wamsutter) and Discovery Producer Services LLC (Discovery) in which we own interests accounted for as equity investments that are not consolidated in our financial statements. When we refer to Wamsutter or Discovery by name, we are referring exclusively to their businesses and operations.
 
 
We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents electronically with the U.S. Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (the Exchange Act). From time to time, we may also file registration and related statements and/or prospectuses or prospectus supplements pertaining to equity or debt offerings. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at http://www.sec.gov.
 
Our Internet website is http://www.williamslp.com. We make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charter of the audit committee of our general partner’s board of directors are also available on our Internet website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s secretary at Williams Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.
 
 
We are a publicly-traded Delaware limited partnership formed by The Williams Companies, Inc. (Williams) in February 2005 to own, operate and acquire a diversified portfolio of complementary energy assets. We gather, transport, process and treat natural gas and fractionate and store NGLs. Fractionation is the process by which a mixed stream of NGLs is separated into its constituent products, such as ethane, propane and butane. These NGLs 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:
 
  •  Gathering and Processing — West.  This segment includes a 100% interest in Williams Four Corners LLC (Four Corners) and ownership interests in Wamsutter, consisting of (i) 100% of the Class A limited liability company membership interests and (ii) 65% of the Class C limited liability company membership interests in Wamsutter (together, the Wamsutter Ownership Interests). Four Corners owns an approximate 3,800-mile natural gas gathering system, including three natural gas processing plants and two natural gas treating plants, located in the San Juan Basin in Colorado and New Mexico. Wamsutter owns an approximate 1,800-mile natural gas gathering system, including a natural gas processing plant, located in the Washakie Basin in Wyoming. The Four Corners and Wamsutter assets


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  generate revenues by providing natural gas gathering, transporting, processing and treating services to customers under a range of contractual arrangements.
 
  •  Gathering and Processing — Gulf.  This segment includes our equity investment in Discovery and the Carbonate Trend gathering pipeline. We own a 60% interest in Discovery, which is operated by Williams. Discovery owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to its natural gas processing plant and NGL fractionator in Louisiana. Our Carbonate Trend gathering pipeline is a sour gas gathering pipeline off the coast of Alabama. These assets generate revenues by providing natural gas gathering, transporting and processing services and integrated natural gas fractionating services to customers under a range of contractual arrangements.
 
  •  NGL Services.  This segment includes three integrated NGL storage facilities and a 50% undivided interest in an NGL fractionator near Conway, Kansas. These assets generate revenues by providing stand-alone NGL fractionation and storage services using various fee-based contractual arrangements where we receive a fee or fees based on actual or contracted volumetric measures.
 
Our assets were owned by Williams prior to the initial public offering (IPO) of our common units in August 2005, our acquisition of Four Corners in 2006, our acquisition of an additional 20% ownership percentage of Discovery in 2007 and our acquisition of the Wamsutter Ownership Interests in 2007. Williams indirectly owns an approximate 21.6% limited partnership interest in us and all of our 2% general partner interest.
 
Williams is an integrated energy company with 2008 revenues in excess of $12.4 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.
 
Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000.
 
 
The global recession and resulting drop in demand and prices for NGLs has significantly reduced the profitability and cash flows of our gathering and processing businesses including Four Corners, our ownership interests in Wamsutter and Discovery. We expect low NGL margins during 2009, including periods when it is not economical to recover ethane. As a result, we expect cash flow from operations, including cash distributions to us from Wamsutter and Discovery, to be significantly lower in 2009 than 2008.
 
Given the current energy commodity price and NGL margin environment, together with our cash balance of approximately $66 million at February 16, we expect to maintain our current level of cash distributions throughout 2009. During 2006 through 2008, we retained a portion of our excess cash flow for future periods when NGL prices and margins might be substantially lower — as they are now. However, if energy commodity prices and NGL margins decline further for a prolonged period of time, and/or if other unexpected events adversely affect cash flows and/or our available cash balance, we may need to reduce distributions.
 
During September 2008, Discovery’s offshore gathering system sustained hurricane damage and was unable to accept gas from producers while repairs were being made through the end of 2008. Inspections revealed that an 18-inch lateral was severed from its connection to the 30-inch mainline in 250 feet of water. The 30-inch mainline was repaired and returned to service in January 2009. The 30-inch mainline is now delivering 150 MMcf/d of production, which was its approximate volume prior to the hurricanes. Both the Larose processing plant and the Paradis fractionator are operational and processed gas from third-party sources during the fourth quarter of 2008.
 
We concluded our negotiations with the Jicarilla Apache Nation (JAN) during February 2009 with the execution of a 20-year right-of-way agreement. Under the new agreement, the JAN granted rights-of-way for Four Corners’ existing natural gas gathering system on JAN land as well as a significant geographical area for


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additional growth of the system. We paid an initial payment of $7.3 million upon execution of the agreement. Beginning in 2010, we will make annual payments of approximately $7.5 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could approximate the fixed amount. Additionally, five years from the effective date of the agreement, the JAN will have the option to acquire up to a 50% joint venture interest for 20 years in certain of Four Corners’ assets existing at the time the option is exercised. The joint venture option includes Four Corners’ gathering assets subject to the agreement and portions of Four Corners’ gathering and processing assets located in an area adjacent to the JAN lands. If the JAN selects the joint venture option, the value of the assets contributed by each party to the joint venture will be based upon a market value determined by a neutral third party at the time the joint venture is formed. This right-of-way agreement is subject to the consent of the United States Secretary of the Interior before it may become effective.
 
In January 2009, Wamsutter issued an additional 70.8 and 28.8 Class C units to us and Williams, respectively, related to funding of expansion capital expenditures placed in service during 2008. Therefore, we now own 65% and Williams owns 35% of Wamsutter’s outstanding Class C units. As of December 31, 2008, Williams has contributed $28.8 million for an expansion capital project that is expected to be placed in service during 2010. Williams will receive Class C units related to these expenditures after the asset is placed in service; thus, our Class C ownership interest will decline at that time.
 
FINANCIAL INFORMATION ABOUT SEGMENTS
 
See Part II, Item 8 — Financial Statements and Supplementary Data.
 
 
Operations of our businesses are located in the United States and are organized into three reporting segments: (1) Gathering and Processing — West, (2) Gathering and Processing — Gulf and (3) NGL Services.
 
 
Our Gathering and Processing — West segment is comprised of our Four Corners assets and Wamsutter Ownership Interests.
 
 
The Four Corners assets include a natural gas gathering system in the San Juan Basin in New Mexico and Colorado, three natural gas processing plants and two natural gas treating plants. We provide our customers, primarily natural gas producers in the San Juan Basin, with a full range of gathering, processing and treating services. Four Corners’ revenues are comprised of product sales and fee-based gathering, processing, and treating revenues. Fee-based gathering, processing and treating services accounted for approximately 64% of Four Corners’ total revenue less product cost and shrink replacement for the year ended December 31, 2008. The remaining 36% was derived from the sale of NGLs received as consideration for processing services. For more detail of Four Corners’ revenues, please read Note 15, Segment Disclosures, in our Notes to Consolidated Financial Statements in this report.
 
During 2008, our Four Corners gathering system gathered approximately 36% of the natural gas produced in the San Juan Basin. It connects with the five pipeline systems that transport natural gas to end markets from the basin. Approximately 40% of the supply connected to our Four Corners pipeline system in the San Juan Basin is produced from conventional formations with approximately 60% coming from coal bed formations. We are currently the only company that is the owner and operator of both major conventional natural gas and coal bed methane gathering, processing and treating facilities in the San Juan Basin.


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Our Four Corners natural gas gathering pipeline system consists of:
 
  •  Approximately 3,800 miles of 2-inch to 30-inch diameter natural gas gathering pipelines with capacity of two Bcf/d and approximately 6,450 receipt points; and
 
  •  Over 400,000 horsepower of compression comprised of distributed gathering compression, major gathering station compression and plant compression. A substantial portion of this compression is owned and operated by a third party. We have taken direct responsibility for some field compression that was previously operated by a third party, and we plan to assume responsibility in 2009 for compression that is currently third-party operated. By the end of 2009, we will operate approximately one-half of the field compression that has historically been operated by a third party.
 
We generally charge a fee on the volume of natural gas gathered on our gathering pipeline systems. We do not, however, take title to the natural gas gathered on the system other than natural gas we retain for fuel.
 
Four Corners Processing and Treating Plants
 
 
Our Four Corners assets include three natural gas processing plants with a combined processing capacity of 765 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 and installed and upgraded the primary processing components of the plant in 1984 and 1999, respectively. 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 we retain some NGLs, fractionate them at Ignacio and distribute them locally via trucks. Ignacio also produces liquefied natural gas, which is distributed via truck. The Ignacio plant is able to recover approximately 95% of the ethane contained in the natural gas stream and nearly all of the propane and heavier NGLs.
 
The Kutz and Lybrook natural gas processing plants, located in Bloomfield and Lybrook, New Mexico, respectively, have a combined processing capacity of approximately 315 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 we retain some liquids, fractionate them at Lybrook and distribute them locally via trucks. The Kutz plant has gas outlets to the El Paso Natural Gas, Public Service Company of New Mexico (PNM) and Transwestern pipeline systems. The Lybrook plant connects to the PNM pipeline. The Kutz and Lybrook plants are able to recover approximately 55% and 80%, respectively, of the ethane contained in the natural gas stream.
 
 
Coal bed methane gas typically contains high levels of carbon dioxide that must be reduced to 2% or less for transportation through pipelines to end markets. Our Four Corners assets include two natural gas treating plants, the Milagro and Esperanza plants, which are located in New Mexico and have a combined carbon dioxide removal capacity of approximately 67 MMcf/d and a combined gas inlet volume of approximately 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.


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Customers.  One producer customer, ConocoPhillips, accounted for approximately 50% of Four Corners’ total gathered volumes and 19% of its total revenues for the year ended December 31, 2008. We sold, at market prices, substantially all of the NGLs we retain to a subsidiary of Williams at the respective tailgates of our natural gas plants. These sales accounted for approximately 54% of Four Corners’ total revenues for the year ended December 31, 2008. Our NGLs sold to the Williams’ subsidiary are derived from our processing of producer customers’ natural gas under our keep-whole and percent-of-liquids processing contracts. 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 customers’ NGLs.
 
Contracts.  Gathering, processing and treating services are usually provided to each customer under long-term contracts with applicable acreage dedications, reserve dedications, or both, for the life of the contract. Gathering and treating services are generally provided pursuant to fee-based contracts. These revenues are based on the volumes gathered and the associated per-unit fee. Our portfolio of Four Corners’ natural gas processing agreements includes the following types of contracts:
 
  •  Keep-whole.  Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the Btu content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas and (4) deliver an equivalent Btu content of natural gas for customers at the plant outlet. We, in turn, sell the retained NGLs to a Williams’ subsidiary at market prices. For the year ended December 31, 2008, 37% of Four Corners’ processing volumes were under keep-whole contracts.
 
  •  Percent-of-liquids.  Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing. We sell the retained NGLs to a Williams’ subsidiary at market prices. For the year ended December 31, 2008, 12% of Four Corners’ processing volumes were under percent-of-liquids contracts.
 
  •  Fee-based.  Under fee-based contracts, we receive revenue based on the volume of natural gas processed and the per-unit fee charged and we retain none of the extracted NGLs. For the year ended December 31, 2008, 14% of Four Corners’ processing volumes were under fee-based contracts.
 
  •  Fee-based and keep-whole.  These contracts have both a per-unit fee component and a keep-whole component. The relative proportions of the fee component and the keep-whole component vary from contract to contract. The keep-whole component is never more than 50% of the total extracted NGLs. For the year ended December 31, 2008, 37% of the Four Corners’ processing volumes were under these fee-based and keep-whole contracts.
 
We do not take title to gas as payment for services, other than for the reimbursement of gas used or lost during the gathering, processing or treating of natural gas.
 
 
Our Four Corners system competes with other gathering, processing and treating options available to producers in the San Juan Basin. The Enterprise system is comprised of approximately 6,065 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 800 miles of gathering lines and three treating plants and is a joint venture between the Southern Ute Indian tribe and Kinder Morgan Energy Partners. The Texas Eastern Products Pipeline Company (TEPPCO) system consists of 400 miles of gathering lines and one treating plant. Red Cedar and TEPPCO own and operate primarily coal bed methane gathering and treating facilities in the San Juan Basin.


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Our contracts with major customers contain certain production dedications of natural gas from particular areas and/or group of receipt points to our Four Corners system for the life of the contract. Those contracts also contain provisions requiring the connection of newly drilled wells within dedicated areas to our Four Corners system. For Four Corners, drilling activity by producers is expected to decline in 2009. However, when drilling activity increases, we anticipate that our historical capital investments will support producer customers’ drilling activity, expansion opportunities and production enhancement activities. We have also, on occasion, successfully pursued customers connected to competing gathering systems when the customer’s contract with the competing gathering system expired.
 
 
We own the Wamsutter Ownership Interests and account for this investment under the equity method of accounting due to the voting provisions of Wamsutter’s limited liability company agreement which provide the other member of Wamsutter, Williams, significant participatory rights such that we do not control the investment.
 
Wamsutter owns a natural gas gathering system in the Washakie Basin and a natural gas processing plant in Sweetwater County, Wyoming. Wamsutter provides its customers, primarily natural gas producers in the Washakie Basin, with a broad range of gathering and processing services. Fee-based gathering, processing and other services accounted for approximately 48% of Wamsutter’s total revenues less product costs for the year ended December 31, 2008. The remaining 52% was derived primarily from the sale of NGLs received by Wamsutter as consideration for processing services.
 
The Wamsutter pipeline system gathers and processes approximately 69% of the natural gas produced in the Washakie Basin and connects with four natural gas pipeline systems that transport natural gas to end markets from the basin.
 
 
The Wamsutter natural gas gathering pipeline system consists of:
 
  •  Approximately 1,800 miles of 2-inch to 20-inch diameter natural gas gathering pipelines with capacity of 500 MMcf/d at current operating pressures and approximately 2,000 receipt points; and
 
  •  Approximately 39,700 horsepower of gathering compression.
 
 
Wamsutter’s Echo Springs natural gas processing plant was constructed in 1994 and is located in Sweetwater County, Wyoming. The primary processing components of the Echo Springs plant were installed in 1994 and were subsequently upgraded and expanded in 1996 and 2001. The Echo Springs plant has three cryogenic trains with 28,900 horsepower of compression, processing capacity of 390 MMcf/d and NGL production capacity of 30,000 bpd. The Echo Springs plant has pipeline outlet connections to Wyoming Interstate Company, Colorado Interstate Gas Company, Southern Star Central Gas Pipeline and Rockies Express, which transport natural gas to end markets in the Mid-Continent and Western United States from the Washakie Basin. In 2008, the Echo Springs plant gained access to the new Overland Pass Pipeline, which transports NGLs to the Mid-Continent. The plant also connects to MAPL, which transports NGLs to the Mid-Continent and Gulf Coast. The Echo Springs plant is able to recover approximately 80% of the ethane contained in the natural gas stream and nearly all of the propane and heavier NGLs.
 
The Echo Springs plant is currently operating at capacity with gas in excess of capacity being bypassed around the plant. When gas is bypassed around the plant, Wamsutter does not recover all of the NGLs available from the gas. In order to capture some of the value attributable to these NGLs, Wamsutter has entered into an agreement with Colorado Interstate Gas’ Rawlins natural gas processing plant to process up to 80 MMcf/d of gas in excess of Wamsutter’s processing capacity from the Wamsutter gathering system. This


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connection to the Rawlins plant has increased the total processing capacity available to Wamsutter by 80 MMcf/d, or approximately 20%.
 
Wamsutter is expanding its processing capacity to accommodate volumes of natural gas committed to Wamsutter. Wamsutter expects this expansion to be completed before the end of 2010. Wamsutter’s Class B member, Williams, will fund this project.
 
 
Customers.  Three of Wamsutter’s producer customers (BP America Production Company, Devon Energy Corporation and Anadarko Petroleum Corporation) accounted for approximately 78% of Wamsutter’s total gathered volumes for the year ended December 31, 2008. Wamsutter sells, at market prices, substantially all of the NGLs it retains to a subsidiary of Williams at the tailgate of the Echo Springs plant. These sales accounted for approximately 56% of Wamsutter’s total revenues for the year ended December 31, 2008. Its NGLs sold to the Williams’ subsidiary are derived from its processing of producer customers’ natural gas.
 
Contracts.  Wamsutter usually provides these services to each customer under long-term contracts with applicable acreage dedications, reserve dedications or both, for the life of the contract. Approximately 80% of the current gathering and processing volumes on the Wamsutter system are subject to contracts with terms of seven years or longer. All of Wamsutter’s gathering contracts are fee-based. Wamsutter generally charges a fee on the volume of natural gas gathered on its gathering pipeline system. Wamsutter does not take title to the natural gas that it gathers other than natural gas it retains for fuel and purchases for shrinkage.
 
Wamsutter has a portfolio of natural gas processing agreements that include fee-based and keep-whole contracts. The terms of these agreements are consistent with those described for Four Corners. For the year ended December 31, 2008, 73% and 27% of Wamsutter’s processing volumes were under fee-based and keep-whole contracts, respectively.
 
 
Wamsutter has three primary competitors. Anadarko’s Patrick Draw and Red Desert facilities compete for both gathering and processing volumes. The Patrick Draw processing plant has 150 MMcf/d of cryogenic processing capacity and the Anadarko Red Desert plant has 40 MMcf/d of cryogenic processing capacity. The Colorado Interstate Gas’ Rawlins plant has 250 MMcf/d of lean oil processing capacity. The Rawlins plant is a regulated facility that is part of the Colorado Interstate Gas interstate pipeline system.
 
Wamsutter LLC Agreement
 
 
We own the Wamsutter Ownership Interests previously described and Williams owns 100% of the Class B limited liability company membership interests and the remaining 35% of the Class C units in Wamsutter that we do not own. Wamsutter is obligated to issue additional Class C units based on future capital contributions that the Class A member and the Class B member are obligated or permitted to make in the circumstances described below.
 
 
The Wamsutter LLC Agreement provides for distributions of available cash to be made quarterly, with available cash defined as Wamsutter’s cash on hand at the end of a distribution period less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law, debt instruments or other agreements to which it is a party. We expect that Wamsutter will fund its maintenance capital expenditures through its cash flows from operations. Williams, as the Class B member, has the discretion to establish the reserves necessary for Wamsutter, including the amount set aside for maintenance capital expenditures and thus can influence the amount of available cash.


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Wamsutter will distribute its available cash as follows:
 
  •  First, an amount equal to $17.5 million per quarter to us as the holder of the Class A membership interests;
 
  •  Second, an amount to us as the holder of the Class A membership interests, if needed, equal to the amount the distribution to us as the Class A membership interests in prior quarters of the current distribution year was less than $17.5 million per quarter; and
 
  •  Third, 5% of remaining available cash shall be distributed to us as the holder of the Class A membership interests, and 95% shall be distributed to the holders of the Class C units, on a pro rata basis.
 
In addition, to the extent that at the end of the fourth quarter of a distribution year, we as the Class A member have received less than $70.0 million under the first and second bullets above, the Class C members will be required to repay, pro rata, any distributions they received in that distribution year such that we as the Class A member receive $70.0 million for that distribution year. If this repayment is insufficient to result in us as the Class A member receiving $70.0 million, the shortfall will not carry forward to the next distribution year. The initial distribution year began December 1, 2007 and ended November 30, 2008. Subsequent distribution years for Wamsutter will begin December 1 and end November 30.
 
Additionally, each month during fiscal years 2008 through 2012, the Class B member is obligated to pay to Wamsutter a transition support payment in an amount equal to the amount by which Wamsutter’s general and administrative expenses exceed a monthly cap. Any such amounts received from the Class B member will be distributed to us as the holder of the Class A membership interests but will not be counted for purposes of determining whether or not Wamsutter has distributed the $70.0 million in aggregate annual distributions as described above. The Class B members will not be issued any Class C units as a result of making a transition support payment.
 
We will be allocated net income by Wamsutter based upon the allocation and distribution provisions of their LLC Agreement. In general, the agreement allocates income to the Class A, B and C ownership interests in a manner that will maintain capital account balances reflective of the amounts each ownership interest would receive if Wamsutter were dissolved and liquidated at carrying value. In general, pursuant to those provisions, income allocations follow the provisions of the LLC agreement for the distribution of available cash.
 
 
Wamsutter may elect to make growth capital investments, which are investments other than maintenance capital investments or growth well connection investments. Such growth capital investments are required to be funded by the members as follows:
 
  •  We, as the Class A member, are obligated to fund growth capital investments under $2.5 million.
 
  •  The Class B member, Williams, is obligated to fund growth capital investments of $2.5 million or more.
 
In addition, the Class B member is obligated to make a capital contribution to Wamsutter in an amount necessary to fund growth well connection investments. Growth well connection investments are investments made over a one-year period for well connections that Wamsutter expects will more than offset the estimated decline in its throughput volumes over that period.
 
Wamsutter will issue to the contributing member one Class C unit for each $50,000 contributed by it for capital investments. Wamsutter will issue fractional Class C units as necessary.
 
 
Most decisions regarding Wamsutter’s day to day operations are made by Williams in its capacity as the owner of the Class B membership interests. However, certain decisions require our consent as owner of the Class A membership interests. Because of these governance provisions, we do not control Wamsutter; hence,


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we account for our interest in Wamsutter as an equity method investment, and do not consolidate its financial results.
 
 
Our Gathering and Processing — Gulf segment is comprised of our 60% interest in Discovery and the Carbonate Trend gathering pipeline.
 
 
We own a 60% interest in Discovery and account for this investment under the equity method of accounting due to the voting provisions of Discovery’s limited liability company agreement which provide the other member of Discovery significant participatory rights such that we do not control the investment. Discovery owns an approximate 300-mile natural gas gathering and transportation pipeline system, located primarily off the coast of Louisiana in the Gulf of Mexico, a cryogenic natural gas processing plant in Larose, Louisiana and a fractionator in Paradis, Louisiana.
 
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.
 
 
Transportation and Gathering Natural Gas Pipeline.  The mainline of the Discovery pipeline system consists of a 105-mile, 30-inch diameter natural gas and condensate pipeline, which begins at a platform owned by a third party and is located in the offshore Louisiana Outer Continental Shelf at Ewing Bank 873. The mainline extends northerly to the Larose gas processing plant near Larose, Louisiana. Producers have dedicated their production from approximately 80 offshore blocks to Discovery. The mainline has a Federal Energy Regulatory Commission (FERC) certificated capacity of approximately 600 MMcf/d.
 
The Discovery system connects to six natural gas pipeline systems: the Bridgeline system, the Texas Eastern Pipeline system, the Gulfsouth system, the Tennessee Gas Pipeline system, the Columbia Gulf Transmission system and the Transcontinental Gas Pipe Line system (Transco). Discovery’s interconnections allow producers to benefit from flexible and diversified access to a variety of natural gas markets from the Gulf of Mexico to the eastern United States.
 
Shallow Water/Onshore Gathering.  Discovery also owns shallow water and onshore gathering assets that consist of:
 
  •  91 miles of offshore laterals with connections to the mainline. The FERC regulates 60 miles of these shallow water laterals.
 
  •  A fixed-leg shelf production handling facility installed at Grand Isle 115. The platform facility allows for the injection of gas and condensate into the pipeline and is equipped with two production handling facilities.
 
  •  A five-mile onshore gathering lateral that extends from a production area north of the Larose gas processing plant directly to the plant. The FERC does not regulate this lateral.
 
Deepwater Gathering.  Discovery’s deepwater gathering assets consist of 73 miles of gathering laterals that extend to deepwater producing areas in the Gulf of Mexico such as the Morpeth prospect, Allegheny prospect and Front Runner prospect. Additionally, Discovery has signed definitive agreements with Chevron Corporation, Total E&P USA, Inc. and StatoilHydro ASA to construct an approximate 34-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 has a design capacity of approximately 200 MMcf/d. Chevron expects first production of gas to begin in the third quarter of 2009. The FERC does not regulate any of Discovery’s deepwater laterals.


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Discovery’s cryogenic gas processing plant is located near Larose, Louisiana at the onshore terminus of Discovery’s natural gas pipeline. The plant was placed in service in January 1998 and has a design capacity of approximately 600 MMcf/d. 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%. A Chevron-owned gathering system also connects to the Larose gas processing plant. Discovery has historically received title to approximately one-half of the mixed NGL volumes leaving the Larose plant.
 
 
Discovery fractionates NGLs for third-party customers and for itself at the fractionator located onshore near Paradis, Louisiana. The fractionator and a 22-mile mixed NGL pipeline connecting it to the Larose processing plant went into service in January 1998. The Paradis fractionator is designed to fractionate 32,000 bpd of mixed NGLs and is expandable to 42,000 bpd. All products can be delivered through the Chevron TENDS NGL pipeline system, and propane and heavier products may be transported by truck or railway.
 
 
Currently, Discovery is owned 60% by us and 40% by DCP Assets Holding, LP. A two-member management committee, consisting of representation from each of the two owners, manages Discovery. 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 Discovery all opportunities to construct pipeline laterals within an “area of interest.”
 
 
Customers.  Product sales to subsidiaries of Williams, which purchase at market prices substantially all of the NGLs and excess natural gas to which Discovery takes title, accounted for approximately 86% of Discovery’s revenues for the year ended December 31, 2008. This amount includes the sales of NGLs received under processing contracts with producer customers and NGL sales related to third-party processing customers’ elections to have Discovery purchase their NGLs. In any given period, these product sales revenues can vary significantly depending on commodity prices and the extent to which third-party processing customers elect to have Discovery purchase their NGLs.
 
Discovery’s third-party 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 gas dehydration. For the year ended December 31, 2008, 55% of Discovery’s total revenues less related product costs related to Discovery’s top four third-party customers.
 
In October 2006, Discovery signed a one-year contract with Texas Eastern Transmission Company (TETCO) that was subsequently extended through June 2008 after which there were no further volumes under this agreement. For the year ended December 31, 2008, 14% of Discovery’s total revenues less related product costs were related to TETCO.
 
In the fourth quarter of 2007, Discovery began contracting significant volumes from the Tennessee Gas Pipeline system (TGP) and continued to expand during 2008 as the TETCO contract expired. Discovery transported and processed approximately 160 BBtu/d from various customers delivering volumes from TGP. For the year ended December 31, 2008, 19% of Discovery’s total revenues less related product costs were


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related to TGP. Discovery is currently transporting TGP volumes of approximately 100 BBtu/d. This decrease in the volumes from 2008 is primarily due to the lower NGL margins in early 2009.
 
Contracts.  Discovery’s wholly owned subsidiary, Discovery Gas Transmission (DGT), owns the mainline and the FERC-regulated laterals, which generate revenues through a tariff on file with the FERC for several types of service: traditional firm transportation service with reservation fees, firm transportation service on a commodity basis with reserve dedication, and interruptible transportation service. In addition, for any of these general services, DGT has the authority to negotiate a specific rate arrangement with an individual shipper and has several of these arrangements currently in effect.
 
In November 2007, DGT filed a settlement at FERC which was approved and implemented in 2008. This settlement increased the maximum regulated rate for mainline transportation, market expansion and jurisdictional gathering. Please read “— FERC Regulation.”
 
Discovery’s portfolio of processing contracts includes the following types of contracts:
 
  •  Fee-based.  Under fee-based contracts, Discovery receives revenue based on the volume of natural gas processed and the per-unit fee charged.
 
  •  Percent-of-liquids.  Under percent-of-liquids gas processing contracts, Discovery (1) processes natural gas for customers, (2) delivers to customers an agreed upon percentage of the NGLs extracted in processing and (3) retains a portion of the extracted NGLs. Discovery generates revenue from the sale of these retained NGLs to a subsidiary of Williams at market prices. Some of Discovery’s contracts have a “bypass” option, which is explained below under “— Operation and Contract Optimization.”
 
  •  Keep-whole contracts.  Under keep-whole contracts, Discovery pays a fee to the customer to process their gas and Discovery receives all of the extracted NGLs. Discovery also sells these NGLs to a subsidiary of Williams at market prices and replaces the Btu content removed from the gas stream. The term of these contracts is typically less than one year in length.
 
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. As a result, Discovery is generally able to pass through increases in those fractionation expenses to its customers.
 
 
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.
 
 
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


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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.
 
 
Approximately 80 offshore production blocks are currently dedicated to the Discovery system. In February 2008, Discovery executed agreements with LLOG Exploration Company to provide production handling, transportation, processing and fractionation services for their MC 705 and 707 production. Production from these blocks began in July 2008. Also in February 2008, Discovery executed agreements with ATP to provide services, beginning in late third-quarter 2009, related to their production from MC 941 942 and AT 63. ATP has also added four new blocks related to their existing MC 711 production. In August 2008, Discovery received a dedication from Petrobras America Inc. for their Cascade and Chinook prospects which are comprised of eight blocks located in the Walker Ridge Area. Furthermore, in areas that we believe are accessible to the Discovery pipeline system, approximately 600 deepwater blocks are currently leased and approximately 100 have related exploration plans filed with the Minerals Management Service of the U.S. Department of the Interior (the MMS) or are named prospects. A named prospect is an individual lease or group of adjacent leases that are generally considered by a producer to have some economic potential for production.
 
 
Hurricane Katrina’s emergency connections to TETCO and TGP have continued to flow gas through December 2008. Discovery’s 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 was being rebuilt) terminated on June 30, 2008. Discovery continued to contract with individual shippers on TETCO and TGP throughout 2008 on a monthly basis when economical. Additionally, as noted earlier, Discovery is currently contracting on a monthly basis approximately 100 BBtu/d of gas from TGP.
 
Discovery is in the process of modifying the Columbia Gas Transmission’s (CGT) meter facilities to allow Discovery to receive gas from CGT. Construction will begin late in the first quarter of 2009 with first flow expected shortly thereafter. The modified metering facilities will have a capacity of 150 BBtu/d which further adds supply depth to the Discovery system.
 
 
Our Carbonate Trend gathering pipeline is a sour gas gathering pipeline consisting of approximately 34 miles of pipeline that is used to gather sour gas production from the Carbonate Trend area off the coast of Alabama. “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, 2008, our average transportation volume was approximately 22 MMcf/d. 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.
 
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. The Carbonate Trend pipeline generates revenue 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.


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Customers.  Our primary customer on the Carbonate Trend pipeline is Chevron. For the year ended December 31, 2008, volumes from Chevron leases represented approximately 68% of Carbonate Trend’s total throughput and 71% of Carbonate Trend’s total revenue.
 
Contracts.  We have long-term transportation agreements with Chevron and Beryl Resources LP (Beryl). Under these agreements, Chevron and Beryl have agreed to transport on our pipeline all gas produced on their Carbonate Trend leases for the life of the leases or the economic life of the underlying reserves. There is no minimum volume requirement, and if the leases held by Chevron and Beryl expire or the underlying reserves are depleted, Chevron and Beryl will not be committed to ship any natural gas on our pipeline. In addition, if any lease expires, and is reacquired by the same company within ten years of such expiration, all production from that lease must again be transported via our pipeline. We have the option to terminate these agreements if expenses exceed certain levels or if revenues fall below certain levels and we are not compensated for these expenses or shortfalls.
 
 
Other than the producer gathering lines that connect to the Carbonate Trend pipeline, there are no other sour gas gathering and transportation pipelines in the Carbonate Trend area, and we know of no current plans to build competing sour gas gathering pipelines.
 
 
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. Production from this area has declined in recent years, and we no longer expect significant, near-term discoveries of sour gas in the area served by the Carbonate Trend gathering pipeline.
 
 
Our NGL Services segment includes our three integrated NGL storage facilities and a 50% interest in an NGL fractionator near Conway, Kansas. These assets are strategically located at one of the two major NGL trading hubs in the continental United States.
 
 
We own and operate three integrated underground NGL storage facilities in the Conway, Kansas area with an aggregate storage 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. A brine pond is an above-ground location that stores brine, or salt water, until it is pumped into the storage cavern to displace and move NGLs.
 
Our Conway storage facilities interconnect directly with three end-use interstate NGL pipelines: MAPL, NuStar and the ONEOK North System (formerly Kinder Morgan) pipeline. We also, through connections of less than a mile, indirectly interconnect to an additional end-use interstate NGL pipeline: the ONEOK pipeline. Through these pipelines and other storage facilities we can provide our customers interconnectivity to additional interstate NGL pipelines. We believe that the attributes of our storage facilities, such as the number and size of our caverns and well bores and our extensive brine system, coupled with our direct connectivity to MAPL through multiple meters allows our customers to inject, withdraw and deliver all of their products stored in our facilities more rapidly than products stored with our competitors.


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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 30 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.
 
 
The Conway fractionation facility is strategically located at the junction of the south, east and west legs of MAPL and has interconnections with the Buckeye pipeline and the ConocoPhillips Chisholm pipeline, each of which transports mixed NGLs to our facility. The Conway fractionation facility has a total design capacity of approximately 107,000 bpd.
 
We own a 50% undivided interest in the Conway fractionation facility resulting in proportionate capacity of approximately 53,500 bpd. ConocoPhillips and ONEOK own 40% and 10% undivided interests, respectively. Each joint owner markets its own capacity independently. Each owner can also contract with the other owners for additional capacity at the Conway fractionation facility, if necessary. We are the operator of the facility pursuant to an operating agreement that extends until May 2011.
 
The results of operations of the Conway fractionation facility are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. Overall, the NGL fractionation business exhibits little to no seasonal variation as NGL production is relatively constant throughout the year. We have capacity available at our fractionation facility to accommodate additional volumes.
 
 
Customers.  Our NGL Services segment customers include NGL producers, NGL pipeline operators, NGL service providers and NGL end-users. Our largest customer accounted for 14% of our segment revenues in 2008. We sold, at market prices, substantially all NGLs derived from our operating supply management (discussed below) to a subsidiary of Williams. These sales accounted for approximately 22% of Conway’s total revenues for the year ended December 31, 2008.
 
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 2010 and 2018. Each of these long-term contracts is based on a percentage of our published price for 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. 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. We evaluate pricing, volume and availability for


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segregated storage on a case-by-case basis. We also charge overstorage fees to the customers when their product storage inventory exceeds their leased capacity.
 
We primarily fractionate NGLs for third-party customers for a fee based on the volumes of mixed NGLs fractionated. The per-unit fee we charge is generally subject to adjustment for changes in certain fractionation expenses, including natural gas, electricity and labor costs, which are the principal variable costs in NGL fractionation. As a result, we are generally able to pass through increases in those fractionation expenses to our customers. We generally enter into fractionation contracts that cover portions of our remaining capacity at the Conway facility for periods of one year or less.
 
 
We also generate revenues by managing product imbalances at our Conway facilities. In response to market conditions, we actively manage the fractionation process to optimize the resulting mix of products. Generally, this process leaves us with a surplus of propane volumes and a deficit of ethane volumes. We sell the surplus propane and make up the ethane deficit through open-market purchases and forward purchase and sales contracts. We refer to these transactions as product sales and product purchases. In addition, product imbalances may arise due to measurement variances that occur during the routine operation of a storage cavern. These imbalances are realized when storage caverns are emptied. We are able to sell any excess product volumes for our own account, but must make up product deficits. The flexibility we enjoy as operator of the storage facility allows us to manage the economic impact of deficit volumes by settling deficit volumes either from our storage inventory or through opportunistic open-market purchases.
 
These product sales and purchases are completed with a Williams’ subsidiary. If this arrangement with the Williams’ subsidiary were terminated, we believe we could make these product sales and purchases through third parties.
 
 
Storage services.  Our most direct storage competitor is a ONEOK-owned Bushton, Kansas storage facility that is directly connected to a ONEOK North System pipeline. Other competitors include a ONEOK-owned facility in Conway, Kansas, an NCRA-owned facility in Conway, Kansas, a ONEOK-owned facility in Hutchinson, Kansas and an Enterprise Products Partners-owned facility in Hutchinson, Kansas. We also compete with interstate pipelines to the extent that they offer storage services.
 
Fractionation Services.  Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products are also important competitive factors and are determined by the existence of the necessary pipeline and storage infrastructure. NGL fractionators connected to extensive storage, transportation and distribution systems such as ours have direct access to larger markets than those with less extensive connections. Our principal competitors are a ONEOK-owned fractionator located in Medford, Oklahoma, a ONEOK-owned fractionator located in Hutchinson, Kansas, a ONEOK-owned fractionator located in Bushton, Kansas and an Enterprise-owned fractionator located in Hobb, Texas. We compete with the two other joint owners of the Conway fractionation facility for third-party customers.
 
We also compete with storage and fractionation 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. An increase in competition in the overall 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 costs and rates of our competitors, (3) the ability to offer service from multiple storage locations, (4) competitors’ services including the purchase of customers’ mixed NGLs as an alternative to fee-based fractionation services and (5) NGL commodity prices in the Mid-Continent region compared to prices in other regions.


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Based on Energy Information Administration projections of relatively stable production levels of natural gas in the Mid-Continent region over the next ten years, we believe that sufficient volumes of mixed NGLs will be available for fractionation in the foreseeable future. In addition, through connections with MAPL and the Buckeye pipeline, the Conway fractionation facility has access to mixed NGLs from additional major supply basins in North America, including additional major supply basins in the Rocky Mountain production area. We are currently analyzing the feasibility of processing volumes sourced through connections to Overland Pass Pipeline which originates in Wyoming and flows into the Mid-Continent.
 
After we separate the mixed NGLs at the fractionator, the NGL products are typically transported to our storage facilities. We also receive a portion of the NGLs that we inject into our facilities from our customers. Our customers may transport the NGLs through the interstate NGL pipelines that interconnect with our storage facilities including MAPL, a ONEOK North System pipeline, NuStar pipeline and a ONEOK pipeline. Our customers may deliver or transport their NGL products through our truck loading and unloading facility and our rail loading and unloading 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.
 
 
Certain of our natural gas pipelines are subject to regulation by, among others, the United States Department of Transportation (DOT) under the Accountable Pipeline and Safety Partnership Act of 1996 (often referred to as the Hazardous Liquid Pipeline Safety Act) and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management. These statutes require access to and copying of records and the filing of certain reports and carry 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 certain high-consequence areas. The DOT has developed regulations implementing the Pipeline Safety Improvement Act that will require pipeline operators to implement integrity management programs, including more frequent inspections and other safeguards in areas where the potential consequences of pipeline accidents pose the greatest risk to people and property. We currently anticipate incurring costs of approximately $0.6 million in 2009 to implement integrity management program testing along certain segments of Discovery’s 16, 20 and 30-inch diameter natural gas pipelines and its 10, 14 and 18-inch diameter NGL pipelines. This does not include the costs, if any, of repair, remediation, preventative or any mitigating actions that may be deemed necessary as a result of the testing program.
 
States are largely preempted by federal law from regulating pipeline safety but may, in certain cases, assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we or the entities in which we own an interest operate.
 
We implement continuous inspection and compliance programs designed to keep our facilities in the most efficient operating condition and to ensure compliance with pipeline safety and pollution control requirements. For example, our Carbonate Trend pipeline undergoes a corrosion control program that both protects the integrity of the pipeline and prolongs its life. The corrosion control program consists of continuous monitoring and injection of corrosion inhibitor into the pipeline, periodic chemical treatments and annual detailed comprehensive inspections. We believe that this aggressive and proactive corrosion control program will reduce metal loss, limit corrosion and possibly extend the service life of the pipe by 15 to 20 years.


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We are also subject to a number of federal and state laws and regulations such as 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 and the general public, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the United States Environmental Protection Agency (EPA) community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and some of the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations, with a few exemptions, apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we remain in material compliance with the OSHA and similar state and local regulations.
 
 
 
The Discovery 105-mile mainline, approximately 60 miles of laterals and its market expansion project are subject to regulation by the FERC under the Natural Gas Act. The Natural Gas Act requires, among other things, that an interstate pipeline’s rates be “just and reasonable” and not unduly discriminatory or preferential. Under the Natural Gas Act, the FERC has authority over the construction, operation and expansion of interstate pipeline facilities, as well as the rates, terms and conditions of service provided by the operator of such facilities. In general, Discovery must receive prior FERC approval to construct, operate or expand its FERC-regulated facilities, to initiate new service using such facilities, to alter the terms and conditions of service provided on such facilities and to abandon service provided by its FERC-regulated facilities. With respect to certain types of construction activities and certain types of service, the FERC has issued rules that allow regulated pipelines to obtain blanket authorizations that obviate the need for prior specific FERC approvals for initiating and abandoning service. The natural gas pipeline industry has historically been heavily regulated by federal and state governments, and we cannot predict what further actions the FERC, state regulators, or federal and state legislators may take in the future. Under the Natural Gas Act, the FERC regulates transmission facilities but, as a general rule, does not regulate gathering facilities except under certain conditions. Discovery’s wholly owned subsidiary, Discovery Gas Transmission, owns the mainline and certain shallow water offshore gathering laterals subject to FERC regulation. Discovery owns some gathering facilities that are not subject to FERC Natural Gas Act regulation.
 
In November 2007, Discovery filed a settlement in lieu of a general rate case filing. The FERC approved the settlement effective January 1, 2008 for all parties except as to one protestor, ExxonMobil Gas & Power Marketing Company. The settlement resolved numerous rate and other issues and achieved rate certainty on Discovery for at least five years. Pursuant to the terms of the settlement agreement, we and the other parties to the settlement are precluded from filing for any further increases or decreases in existing rates prior to January 1, 2013. Under the settlement, Discovery increased its maximum mainline, gathering and market expansion rates to $0.1729/Dth, $0.0430/Dth and $0.1116/Dth, respectively. Additionally, the settlement permits Discovery to recover certain natural disaster related costs through the Hurricane Mitigation and Reliability Enhancement surcharge and to charge a market outlet surcharge to certain customers receiving discounted services. The settlement rates did not impact the vast majority of the existing volumes on the Discovery system because those historical volumes are dedicated to the system under a life of lease rate. The surcharges affect some of the dedicated volumes.
 
In 2005, the FERC indicated that it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability


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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.
 
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.
 
 
The Carbonate Trend pipeline and the Four Corners and Wamsutter systems are gathering pipelines, and are not subject to the FERC’s jurisdiction under the Natural Gas Act.
 
The primary function of natural gas processing plants is the extraction of NGLs and the conditioning of natural gas for marketing into the natural gas pipeline grid. The FERC has traditionally maintained that a processing plant that primarily extracts NGLs is not a facility for transportation or sale of natural gas for resale in interstate commerce and, therefore, is not subject to its jurisdiction under the Natural Gas Act. We believe that the natural gas processing plant is primarily involved in removing NGLs and, therefore, is exempt from the jurisdiction of the FERC.
 
The Carbonate Trend sour gas gathering pipeline and the offshore portion of Discovery’s natural gas pipeline are subject to regulation under the Outer Continental Shelf Lands Act, which calls for nondiscriminatory transportation on pipelines operating in the outer continental shelf region of the Gulf of Mexico.
 
 
 
Our operation of pipelines, plants and other facilities for gathering, transporting, processing and treating or storing natural gas, NGLs and other products is subject to stringent and complex federal, state, and local laws and regulations relating to the protection of the environment. As such, you should not rely on the following discussion of certain laws and regulations as an exhaustive review of all regulatory considerations affecting our operations.
 
As with the industry generally, compliance with existing and anticipated laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate and upgrade equipment and facilities. While these laws and regulations carry costs, we believe that they do not affect our competitive position because our competitors are similarly affected. We believe that our operations are in material compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with these laws and regulations or the future impact of these laws and regulations on our operations. Please read “Risk Factors — Our operations are subject to governmental laws and regulations related to the protection of the environment, which may expose us to significant costs and liabilities.”
 
In the omnibus agreement executed in connection with our initial public offering (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 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. This indemnification obligation terminated three years after the closing of our IPO, except in the case of the remediation costs associated with Consent Orders issued by the Kansas Department of Health and Environment (KDHE). Please read “— Kansas Department of Health and Environment Obligations.” Pursuant to the purchase and sale agreements by which we acquired Four Corners and the Wamsutter Ownership Interests, Williams agreed to indemnify us against certain losses resulting from, among other things, Williams’ failure to disclose a violation of any environmental law by Four Corners or Wamsutter or relating to their assets, operations or businesses that occurred prior to the respective closings.


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Our operations are subject to the Clean Air Act and comparable state and local statutes. Amendments to the Clean Air Act enacted in late 1990 require or will require most industrial operations in the United States to incur capital expenditures in order to meet air emission control standards developed by the EPA and state environmental agencies. As a result of these amendments, our facilities that emit volatile organic compounds or nitrogen oxides are subject to increasingly stringent regulations, including requirements that some sources install maximum or reasonably available control technology. In addition, the 1990 Clean Air Act Amendments established a more consistent permitting process; however, threshold limits and control technologies written into the regulations regularly change over time keeping specific allowable limits and technologies dynamic. 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 substance laws generally regulate the generation, storage, treatment, use, transportation and disposal of solid and hazardous waste. They may also require corrective action, including the investigation and remediation of certain units, at a facility where such waste may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, often without regard to fault or the legality of the original conduct, on certain classes of persons that may or may not have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site, as well as successors in interest. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently includes natural gas, we may nonetheless handle other “hazardous substances” within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations, or our predecessors in interest may have so handled “hazardous substances” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
 
We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the federal Solid Waste Disposal Act, the federal Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. From time to time, the EPA considers the adoption of stricter disposal standards for wastes currently designated as “non-hazardous.” However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements than non-hazardous wastes. Any such changes in the laws and regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
 
We currently own or lease, and our predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to, among others, CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination.
 
We are a participant in certain hydrocarbon removal and groundwater monitoring activities at Four Corners associated with certain well sites in New Mexico. For a discussion of these hydrocarbon removal and


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groundwater monitoring activities, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental.”
 
 
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.
 
 
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. Please read “— Safety and Maintenance.”
 
 
We currently own and operate underground storage caverns near Conway, Kansas. These storage caverns are used to store NGLs and other liquid hydrocarbons and are subject to strict environmental regulation by the KDHE. The current revision of the Underground Hydrocarbon and Natural Gas Storage regulations became effective in 2003 and regulates the storage of liquefied petroleum gas and other hydrocarbons in bedded salt for the purpose of protecting public health and safety, property and the environment. The revision also regulates the construction, operation and closure of brine ponds associated with our storage caverns. These regulations specify several compliance deadlines including the due date for final permit submittals, which was met by April 1, 2006, and the April 1, 2010 deadline for completion of mechanical integrity and casing testing requirements, which our facilities are in the process of completing. 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 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 to two brine ponds per year. The incremental cost of these activities is approximately $5.0 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 have installed and are operating a containment and monitoring system to contain the 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


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is located near the Groundwater Management District No. 2’s jurisdictional boundary of the Equus Beds aquifer. At the Conway West facility, remediation of residual hydrocarbon derivatives from a historic pipeline release is included in the consent order required activities.
 
Although not mandated by any consent order, we are currently cooperating with the KDHE and other area operators in an investigation of NGLs observed in the subsurface at the Conway Underground East facility. In addition, we have also recently detected NGLs in groundwater monitoring wells adjacent to two abandoned storage caverns at the Conway West facility. Although the complete extent of the contamination appears to be limited and appears to have been arrested, we are continuing to work to delineate further the scope of the contamination. To date, the KDHE has not undertaken any enforcement action related to the NGL releases around the abandoned storage caverns.
 
We are continuing to evaluate our assets to prevent future releases. While we maintain an extensive inspection and audit program designed, as appropriate, to prevent and to detect and address such releases promptly, there can be no assurance that future environmental releases from our assets will not have a material effect on us.
 
For more information about environmental compliance and other environmental issues, please read “Environmental” under Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements in this report.
 
 
Our real property falls into two categories: (1) parcels that we own in fee, such as land at the Conway fractionation and storage facility, and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. The fee sites upon which major facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, right-of-way and licenses. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to unitholders.
 
 
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 283 people, as of December 31, 2008, who directly support the operations of the Four Corners, Conway and Carbonate Trend facilities. Additionally, our general partner and its affiliates provide general and administrative services to us. Wamsutter and Discovery are equity investments and are operated by Williams pursuant to agreements; therefore, the employees who operate these assets are 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.”


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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” that 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:
 
  •  amounts and nature of future capital expenditures;
 
  •  expansion and growth of our business and operations;
 
  •  business strategy;
 
  •  cash flow from operations;
 
  •  the levels of cash distributions to unitholders;
 
  •  seasonality of certain business segments; and
 
  •  natural gas and natural gas liquids prices and demand.
 
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, 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:
 
  •  availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices and the availability and costs of capital;
 
  •  inflation, interest rates and general economic conditions (including the recent economic slowdown and the disruption of global credit markets and the impact of these events on our customers and suppliers);
 
  •  the strength and financial resources of our competitors;
 
  •  development of alternative energy sources;
 
  •  the impact of operational and development hazards;
 
  •  costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation and rate proceedings;
 
  •  increasing maintenance and construction costs;


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  •  changes in the current geopolitical situation;
 
  •  our exposure to the credit risks of our customers;
 
  •  risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;
 
  •  risks associated with future weather conditions;
 
  •  acts of terrorism; and
 
  •  additional risks described in our filings with the Securities and Exchange Commission.
 
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 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 are described in the following section.
 
 
You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results and financial condition as well as adversely affect the value of an investment in our securities.
 
Risks Inherent in Our Business
 
 
We may not have sufficient available cash from operating surplus each quarter to maintain current levels of cash distributions or to pay the minimum quarterly distribution. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
 
  •  the prices we obtain for our services;
 
  •  the prices of, level of production of, and demand for natural gas and NGLs and our NGL margins;
 
  •  the volumes of natural gas we gather, transport, process and treat and the volumes of NGLs we fractionate and store;
 
  •  the level of our operating costs, including payments to our general partner; and
 
  •  prevailing economic conditions.
 
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, such as:
 
  •  the level of capital expenditures we make;
 
  •  the restrictions contained in Williams’ indentures, our indentures and credit facility and our debt service requirements;
 
  •  the cost of acquisitions, if any;


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  •  fluctuations in our working capital needs;
 
  •  our ability to borrow for working capital or other purposes;
 
  •  the amount, if any, of cash reserves established by our general partner; and
 
  •  the amount of cash that each of Wamsutter and Discovery distributes to us.
 
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.
 
 
A principal focus of our strategy is to continue to grow by expanding our business. Our future growth will depend upon our ability to successfully identify, finance, acquire, integrate and operate projects and businesses. 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.
 
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 may require substantial new capital and could result in the incurrence of indebtedness, 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. If we issue additional common units in connection with future acquisitions, unitholders’ interest in us will be diluted and distributions to unitholders may be reduced. Further, any limitations on our access to capital, including limitations caused by illiquidity in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all.
 
 
Lower natural gas and oil prices could result in a decline in the production of natural gas and NGLs resulting in reduced throughput on our pipelines and gathering systems. Any such decline would reduce the amount of NGLs we fractionate and store, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.
 
In general terms, the prices of natural gas, NGLs and other hydrocarbon products fluctuate in response to changes in supply, changes in demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include:
 
  •  worldwide economic conditions;
 
  •  weather conditions and seasonal trends;
 
  •  the levels of domestic production and consumer demand;
 
  •  fluctuations in the storage levels of natural gas and NGLs;
 
  •  the availability of imported natural gas and NGLs;
 
  •  the availability of transportation systems with adequate capacity;
 
  •  the price and availability of alternative fuels;
 
  •  the effect of energy conservation measures;


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  •  the nature and extent of governmental regulation and taxation; and
 
  •  the anticipated future prices of natural gas, NGLs and other commodities.
 
 
The relationship between natural gas prices and NGL prices affects our profitability. When natural gas prices are low relative to NGL prices, it is more profitable for us and our customers to process natural gas. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas both because of the higher value of natural gas and of the increased cost of separating the mixed NGLs from the natural gas. As a result, we have experienced and, if low NGL prices persist for a prolonged period of time, will likely continue to experience significant reductions in the volumes of NGLs removed at our processing plants, which also significantly reduces our margins. Higher natural gas prices relative to NGL prices may also make it uneconomical to recover ethane, which may further negatively impact sales volumes and 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.
 
 
Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in Discovery’s long-term transportation and storage contracts or throughput on Discovery’s system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on Discovery’s system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on Discovery’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to unitholders.
 
 
Our business is dependent on the continued availability of natural gas production and reserves. The development of additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, adversely impacting our ability to fill the capacities of our gathering, transmission and processing facilities.
 
Production from existing wells connected to our and Discovery’s pipelines and our gathering systems will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase throughput levels on our pipelines and gathering systems and the utilization rate of our natural gas processing plants and fractionators, we must continually connect to new supplies of natural gas.
 
If we are not able to connect new supplies of natural gas to replace the natural decline in volumes from the existing supply area, throughput on our pipelines and gathering systems and the utilization rates of our natural gas processing plants and fractionators will decline, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to unitholders.
 
 
We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Some of our competitors are large oil, natural gas and petrochemical companies that have greater


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access to supplies of natural gas and NGLs than we do. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make investments or acquisitions. Other companies with which we compete may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion or refurbishment of their facilities than we can. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.
 
 
We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. In addition, we are in active negotiations with several customers to renew gathering, processing and treating contracts that are in evergreen status. The negotiations may not result in any extended commitments from these customers or may result in extended commitments on less favorable terms. The loss of all or even a portion of the revenues from natural gas or NGLs, as applicable, supplied by these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to unitholders, unless we are able to acquire comparable volumes from other sources.
 
 
We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers in the ordinary course of our business. 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.
 
 
Despite performing credit analysis prior to extending credit, we are exposed to the credit risk of our contractual counterparties in the ordinary course of business even though we monitor these situations and attempt to take appropriate measures to protect ourselves. In addition to credit risk, counterparties to our commercial agreements, such as product sales, gathering, treating, storage, transportation, processing and fractionation agreements, may fail to perform their other contractual obligations. A failure of counterparties to perform their contractual obligations, including Williams, could cause us to write down or write off doubtful accounts, which could materially adversely affect our operating results, financial condition and cash available to pay distributions. The recent general downturn in the economy and tightening of global credit markets could cause more of our counterparties to fail to perform than we have expected.
 
 
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. If any of them 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, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to store or


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deliver NGL products or to receive deliveries of mixed NGLs and deliver gas to end markets thereby reducing our revenues. Further, although there are laws and regulations designed to encourage competition in wholesale market transactions, some companies may fail to provide fair and equal access to their transportation systems or may not provide sufficient transportation capacity for other market participants.
 
Any temporary or permanent interruption in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to unitholders.
 
 
In 2008, public equity markets experienced significant declines, and global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. Under current market conditions, it is unclear whether we could issue additional equity or debt securities or, even if we were able, whether we could do so at prices and pursuant to terms that would be acceptable to us. We have availability under our credit facility, but our ability to borrow under the facility could be impaired if one or more of our lenders fail to honor its contractual obligation to lend to us. Continuing or additional disruptions in the global financial marketplace, including the bankruptcy or restructuring of certain financial institutions, could make equity and debt markets inaccessible and adversely affect the availability of credit already arranged and the availability and cost of credit in the future.
 
As a publicly traded partnership, these developments could significantly impair our ability to make acquisitions or finance growth projects. We distribute all of our available cash to our unitholders on a quarterly basis. We typically rely upon external financing sources, including the issuance of debt and equity securities and bank borrowings, to fund acquisitions or expansion capital expenditures. Any limitations on our access to external capital, including limitations caused by illiquidity or volatility in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all. As a result, we may be at a competitive disadvantage as compared to businesses that reinvest all of their available cash to expand ongoing operations, particularly under current economic conditions.
 
 
Williams’ public indentures contain covenants that restrict Williams’ and our ability to incur liens to support indebtedness. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Williams’ ability to comply with the covenants contained in its debt instruments may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions continue to deteriorate, Williams’ ability to comply with these covenants may be negatively impacted.
 
Our credit facility and public indentures contain various covenants that, among other things, limit our ability to incur indebtedness, grant certain liens to support indebtedness, merge, or sell substantially all of our assets. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with the covenants contained in our debt agreements and other related transactional documents may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions continue to deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.


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Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under our public indentures could cause a cross-default or cross-acceleration of our credit facility. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other credit facility cross-defaults, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. 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.”
 
 
Our total outstanding long-term debt as of December 31, 2008 was $1.0 billion, representing approximately 81% 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:
 
  •  make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes;
 
  •  impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;
 
  •  adversely affect our ability to pay cash distributions to unitholders;
 
  •  diminish our ability to withstand a downturn in our business or the economy generally;
 
  •  require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes;
 
  •  limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
 
  •  place us at a competitive disadvantage compared to our competitors that have proportionately less debt.
 
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. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, 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.
 
A downgrade of our current credit rating could impact our liquidity, access to capital and our costs of doing business, and maintaining current credit ratings is within the control of independent third parties. In addition, Williams’ credit ratings affect our ability to obtain credit in the future.
 
A downgrade of our credit rating might increase our cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our ability to access capital markets


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could also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:
 
  •  economic downturns;
 
  •  deteriorating capital market conditions;
 
  •  declining market prices for natural gas, natural gas liquids and other commodities;
 
  •  terrorist attacks or threatened attacks on our facilities or those of other energy companies;
 
  •  the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
 
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Our current credit ratings for Moody’s Investor Service is Ba2, for Standard & Poor’s is BBB-, and for Fitch Ratings is BB+. On November 6, 2008, Moody’s Investor Service changed our ratings outlook to “Negative.” No assurance can be given that we will maintain our current credit ratings. In addition, due to our relationship with Williams, our ability to obtain credit is also 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.
 
 
Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans and dividends paid to it by its subsidiaries. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as contributions to capital.
 
Our ratings and credit are impacted by Williams’ credit standing. If Williams were to experience a deterioration in its credit standing or financial difficulties, our access to credit and our ratings could be adversely affected.
 
 
Employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs and funding obligations in defined benefit pension plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of other postretirement benefit plans covering certain eligible participants providing services to us. The timing and amount of our allocations under the defined benefit pension plans depend upon a number of factors Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition. The amount of expenses recorded for the defined benefit pension plans and other postretirement benefit plans is also dependent on changes in several factors, including market interest rates and the returns on plan assets. Significant changes in any of these factors may significantly increase our allocations and adversely impact our future results of operations.
 
 
Wamsutter and Discovery are not prohibited by the terms of their respective limited liability company agreements from incurring indebtedness. If Discovery or Wamsutter was to incur significant amounts of indebtedness, such occurrence may inhibit their ability to make distributions to us. An inability by Discovery or Wamsutter to make distributions to us would materially and adversely affect our ability to make


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distributions to unitholders because we expect distributions we receive from Wamsutter and Discovery to represent a significant portion of the cash we distribute to unitholders.
 
 
Because we do not wholly own Wamsutter, the Conway fractionator or Discovery, we may have limited flexibility to control the operation of or cash distributions received 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.
 
 
More than any other NGLs, demand for propane impacts our Conway storage and fractionation operations. Demand for propane at Conway is principally driven by demand for its use as a heating fuel which is significantly affected by weather conditions and the availability of alternative heating fuels. 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 could be adversely impacted by many factors, including general economic conditions, reductions in demand for end products made from NGLs, increases in competition from petroleum-based products and government regulations. Any decline in demand for propane or other NGLs could cause a reduction in demand for our storage and fractionation services.
 
 
Discovery’s and Wamsutter’s limited liability company agreements require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. The amount of Wamsutter’s quarterly distributions, including the amount of cash reserves not distributed, is determined by the affirmative vote of the management committee representative of the Class B member, Williams.
 
If Discovery requires working capital in excess of applicable reserves, we must make working capital advances to Discovery of up to the amount of Discovery’s two most recent prior quarterly distributions of available cash, but Discovery must repay any such advances before it can make future distributions to its members. As a result, the repayment of advances could reduce the amount of cash distributions we would otherwise receive from Discovery.
 
 
Discovery’s interstate natural gas transportation operations are subject to federal, state and local regulatory authorities. Specifically, Discovery’s interstate pipeline transportation service is subject to regulation by FERC. The federal regulation extends to such matters as:
 
  •  transportation and sale for resale of natural gas in interstate commerce;
 
  •  rates, operating terms and conditions of service, including initiation and discontinuation of services;
 
  •  the types of services Discovery may offer to its customers;
 
  •  certification and construction of new facilities;
 
  •  acquisition, extension, disposition or abandonment of facilities;
 
  •  accounts and records;


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  •  relationships with affiliated companies who are involved in marketing functions of the natural gas business; and
 
  •  market manipulation in connection with interstate sales, purchases or transportation of natural gas.
 
Under the Natural Gas Act (NGA), FERC has authority to regulate providers of natural gas pipeline transportation services in interstate commerce, and such providers may only charge rates that have been determined to be just and reasonable by FERC. In addition, FERC prohibits providers from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
 
The rates, terms and conditions for Discovery’s interstate pipeline services are set forth in its FERC-approved tariff. Pursuant to the terms of Discovery’s most recent rate settlement agreement, Discovery may not file a new rate case before January 1, 2013. Any successful complaint or protest against its rates could have an adverse impact on their revenues associated with providing transportation services. In addition, there is a risk that rates set by the FERC in future rate cases filed by Discovery will be inadequate to recover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that higher rates would cause Discovery’s customers to look for alternative ways to transport their natural gas.
 
 
Discovery’s transportation and storage operations are regulated by FERC. Should Discovery fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. Any material penalties or fines imposed by FERC could have a material adverse impact on Discovery’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to unitholders.
 
 
There are operational risks associated with the gathering, transporting, processing and treating of natural gas and the fractionation and storage of NGLs, including:
 
  •  hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural disasters;
 
  •  damages to pipelines and pipeline blockages;
 
  •  uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial chemicals;
 
  •  collapse of NGL storage caverns;
 
  •  operator error;
 
  •  damage inadvertently caused by third party activity, such as operation of construction equipment;
 
  •  pollution and other environmental risks;
 
  •  fires, explosions, craterings and blowouts;
 
  •  risks related to truck and rail loading and unloading;
 
  •  risks related to operating in a marine environment; and
 
  •  terrorist attacks or threatened attacks on our facilities or those of other energy companies.
 
Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described


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above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. In addition, certain insurance companies that provide coverage to us, Wamsutter and Discovery, including American International Group, Inc., have experienced negative developments that could impair their ability to pay any potential claims. As a result, we could be exposed to greater losses than anticipated and replacement insurance may have to be obtained, if available, at a greater cost. Such circumstances could materially impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows, and our ability to make cash distributions to unitholders.
 
 
The risk of substantial environmental costs and liabilities is inherent in natural gas gathering, transportation, processing and treating, and in the fractionation and storage of NGLs, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. For a description of these laws and regulations, please read “Business and Properties — Environmental Regulation.”
 
Various governmental authorities, including the U.S. Environmental Protection Agency and analogous state agencies and the United States Department of Homeland Security, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.
 
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. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including the Federal Comprehensive Environmental Response, Compensation, and Liability Act, the Federal Resource Conservation and Recovery Act, and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. 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.
 
Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits.
 
New environmental laws and regulations might adversely affect our products and activities, including processing, fractionation, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies also could impose additional safety requirements, any of which could affect our profitability. In addition, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. The


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United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. Increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate the emission of greenhouse gases. Numerous states have announced or adopted programs to stabilize and reduce greenhouse gases, and similar federal legislation has been introduced in both houses of the Congress. We may be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws. If we are unable to recover or pass through all costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively impact our cost of and access to capital.
 
 
Our growth may be dependent upon the construction of new natural gas gathering, transportation, processing or treating pipelines and facilities or natural gas liquids fractionation or storage facilities, as well as the expansion of existing facilities. Construction or expansion of these facilities is subject to various regulatory, development and operational risks, including:
 
  •  the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms;
 
  •  the availability of skilled labor, equipment, and materials to complete expansion projects;
 
  •  potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;
 
  •  impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;
 
  •  the ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor or other factors beyond our control, that may be material; and
 
  •  the ability to access capital markets to fund construction projects.
 
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect our results of operations, financial position or cash flows and our ability to make distributions to unitholders.
 
 
Williams and other third parties operate all of our assets. We have a limited ability to control these operations and the associated costs. 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 rely on Williams for certain 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 and others as operators and on Williams’ outsourcing relationships, 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.


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We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are 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.
 
 
Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. 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.
 
In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.
 
 
Regulators and legislators continue to take a renewed look at accounting practices, financial disclosure, the relationships between companies and their independent auditors, and retirement plan practices. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board, the Securities Exchange Commission (SEC) or FERC could enact new accounting standards or FERC orders 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.
 
 
In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.
 
 
Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of


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such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.
 
Certain of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.
 
 
Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport or distribute natural gas, natural gas liquids or other commodities. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows and on our ability to make cash distributions to unitholders
 
Risks Inherent in an Investment in Us
 
Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.
 
Williams owns and controls our general partner and appoints all of the directors of our general partner. All of the executive officers and certain directors of our general partner are officers and/or directors of Williams and its affiliates, including Williams Pipeline Partners’ general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Williams. Therefore, conflicts of interest may arise between Williams and its affiliates, including our general partner and Williams Pipeline Partners, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following factors:
 
  •  neither our partnership agreement nor any other agreement requires Williams or its affiliates to pursue a business strategy that favors us. Williams’ directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Williams, which may be contrary to ours;
 
  •  all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Partners’ general partner, and these persons will also owe fiduciary duties to those entities;
 
  •  our general partner is allowed to take into account the interests of parties other than us, such as Williams and its affiliates, in resolving conflicts of interest;
 
  •  Williams owns common units representing a 21.6% limited partner interest in us, and if a vote of limited partners is required, Williams will be entitled to vote its units in accordance with its own interests, which may be contrary to our interests or your interests;
 
  •  all of the executive officers and certain of the directors of our general partner will devote significant time to the business of Williams and/or Williams Partners, and will be compensated by Williams for the services rendered to them;


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  •  our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;
 
  •  our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure or investment capital expenditure, neither of which reduces operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner with respect to its incentive distribution rights;
 
  •  in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions even if the purpose or effect of the borrowing is to make incentive distributions to our general partner;
 
  •  our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
 
  •  our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
 
  •  our general partner intends to limit its liability regarding our contractual and other obligations and in some circumstances is required to be indemnified by us;
 
  •  our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;
 
  •  our general partner controls the enforcement of obligations owed to us by it and its affiliates; and
 
  •  our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
 
 
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, our partnership agreement restricts the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
 
  •  permits our general partner to make a number of decisions in its individual capacity as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
 
  •  provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
 
  •  generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general


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  partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
 
  •  provides that our general partner, its affiliates and their officers and directors will not be liable for monetary damages to us or our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct; and
 
  •  provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner or the conflicts committee of its board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
 
Common unitholders are bound by the provisions in the partnership agreement, including the provisions discussed above.
 
Affiliates of our general partner, including Williams and Williams Pipeline Partners, are not limited in their ability to compete with us. Williams is also not obligated to offer us the opportunity to acquire additional assets or businesses from it, which could limit our commercial activities or our ability to grow. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Pipeline Partners’ general partner, and these persons will also owe fiduciary duties to those entities.
 
While our relationship with Williams and its affiliates is a significant attribute, it is also a source of potential conflicts. For example, Williams is in the natural gas business and is not restricted from competing with us. Williams and its affiliates, including Williams Pipeline Partners, which trades on the NYSE under the symbol “WMZ,” may compete with us. Williams and its affiliates may acquire, construct or dispose of natural gas industry assets in the future, some or all of which may compete with our assets, without any obligation to offer us the opportunity to purchase or construct such assets. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Pipeline Partners’ general partner and will owe fiduciary duties to those entities as well as our unitholders and us.
 
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Williams and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, if the unitholders become dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
 
We will reimburse our general partner and its affiliates, including Williams, for various general and administrative services they provide for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us. Our general partner determines the amount of these reimbursements in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read “Certain Relationships and Related Transactions, and Director Independence.” In addition, under Delaware partnership law, our general partner has


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unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.
 
 
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is chosen by Williams. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
 
Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 662/3% of all outstanding common units is required to remove our general partner.
 
 
We have a holding company structure, and our subsidiaries conduct all of our operations and own all of our operating assets. Williams Partners L.P. has no significant assets other than the ownership interests in its subsidiaries. As a result, our ability to make required payments on our debt obligations and distributions on our common units depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, applicable state partnership and limited liability company laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of our debt obligations, to repurchase our debt obligations upon the occurrence of a change of control or make distributions on our common units, we may be required to adopt one or more alternatives, such as a refinancing of our debt obligations or borrowing funds to make distributions on our common units. We cannot assure you that we will be able to borrow funds to make distributions on our common units.
 
 
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 effectively permits a change of control without your consent.
 
 
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
 
  •  our unitholders’ proportionate ownership interest in us will decrease;
 
  •  the amount of cash available to pay distributions on each unit may decrease;
 
  •  the ratio of taxable income to distributions may decrease;


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  •  the relative voting strength of each previously outstanding unit may be diminished; and
 
  •  the market price of the common units may decline.
 
 
As of December 31, 2008, Williams held 11,613,527 common units, representing a 21.6% limited partnership interest in us. Williams may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of its common 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 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, 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. Our general partner may assign this right to any of its affiliates or to us. 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 unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings, to acquire information about our operations and to influence the manner or direction of management.
 
 
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
 
  •  we were conducting business in a state but had not complied with that particular state’s partnership statute; or
 
  •  your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.


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Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
 
 
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the Internal Revenue Service (IRS) were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
 
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
 
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35%, and would likely pay state and local income tax at the corporate tax rate of the various states and localities imposing a corporate income tax. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units.
 
Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distributions to unitholders would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.
 
 
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation (the Qualifying Income Exception), affect or cause us to change our business activities, affect the tax considerations of an


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investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code Section 7704(d) and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
 
 
We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
 
 
We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the federal income tax positions we take. Any contest with the IRS may materially and adversely impact the market for the common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.
 
 
Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.
 
 
If a unitholder sells its common units, it will recognize gain or loss equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income that was allocated to a unitholder for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price the unitholder receives is less than its original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation


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recapture. In addition, if a unitholder sells its common units, the unitholder may incur a tax liability in excess of the amount of cash it received from the sale.
 
 
Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to the unitholders who are organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be taxable to them as “unrelated business taxable income.” 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.
 
 
Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholder tax returns.
 
 
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, even if the unitholder does not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax. 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.
 
 
We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.


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When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.
 
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 3.   Legal Proceedings
 
The information called for by this item is provided in Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements of this report, which information is incorporated into this Item 3 by reference.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
None.
 
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
 
Our common units are listed on the New York Stock Exchange under the symbol “WPZ.” At the close of business on February 17, 2009, there were 52,777,452 common units outstanding, held by approximately 21,823 holders, including common units held in street name and by affiliates of Williams.


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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.
 
                         
            Cash Distribution
    High   Low   per Unit(a)
 
2008
                       
Fourth Quarter
  $ 26.25     $ 9.96     $ 0.635  
Third Quarter
    32.84       22.77       0.635  
Second Quarter
    37.66       31.33       0.625  
First Quarter
    39.31       31.24       0.600  
2007
                       
Fourth Quarter
  $ 45.79     $ 36.60     $ 0.575  
Third Quarter
    52.00       40.26       0.550  
Second Quarter
    50.00       46.00       0.525  
First Quarter(b)
    48.20       38.20       0.500  
 
 
(a) Represents cash distributions attributable to the quarter and declared and paid or to be paid within 45 days after quarter end. We paid cash distributions to our general partner with respect to its 2% general partner interest and incentive distribution rights that totaled $10.7 million and $30.0 million for the 2007 and 2008 periods, respectively. On February 19, 2008, the 7,000,000 outstanding subordinated units held by four subsidiaries of Williams converted into common units on a one-for-one basis. Subordinated units participated in all of the cash distributions for the 2007 periods indicated above.
 
(b) Class B units participated in the first quarter 2007 cash distributions. Class B units were outstanding between December 13, 2006 and May 21, 2007, on which date all 6,805,492 Class B units converted into common units on a one-for-one basis.
 
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:
 
  •  less the amount of cash reserves established by our general partner to:
 
  •  provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);
 
  •  comply with applicable law, any of our debt instruments or other agreements; or
 
  •  provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;
 
  •  plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being made. Working capital borrowings are generally borrowings that will be made under our working capital facility with Williams and in all cases are used solely for working capital purposes or to pay distributions to partners.
 
We will make distributions of available cash from operating surplus for any quarter in the following manner:
 
  •  first, 98% to all unitholders, pro rata, and 2% to our general partner, until each outstanding common unit has received the minimum quarterly distribution for that quarter; and
 
  •  thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the incentive percentages below.


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Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:
 
                     
        Marginal Percentage
    Total Quarterly Distribution   Interest in Distributions
    Target Amount   Unitholders   General Partner
 
Minimum Quarterly Distribution
  $0.35     98 %     2 %
First Target Distribution
  up to $0.4025     98 %     2 %
Second Target Distribution
  above $0.4025 up to $0.4375     85 %     15 %
Third Target distribution
  above $0.4375 up to $0.5250     75 %     25 %
Thereafter
  Above $0.5250     50 %     50 %
 
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:
 
  •  any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
 
  •  our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.
 
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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition and Liquidity.”
 
Item 6.   Selected Financial and Operational Data
 
The following table shows our selected financial and operating data and selected financial and operating data of Wamsutter and Discovery for the periods and as of the dates indicated. We derived the financial data as of December 31, 2008 and 2007 and for the years ended December 31, 2008, 2007 and 2006 in the following table from, and that information should be read together with, and is qualified in its entirety by reference to, the consolidated financial statements and the accompanying notes included elsewhere in this document. All other financial data are derived from our financial records.
 
Because Four Corners, Wamsutter and a 20% interest in Discovery were owned by affiliates of Williams at the time of these acquisitions, these transactions were between entities under common control, and have been accounted for at historical cost. Accordingly, our selected financial and operational data have been retrospectively adjusted to reflect the combined historical results of these common control acquisitions throughout the periods presented. These acquisitions have no impact on historical earnings per unit as pre-acquisition earnings were allocated to our general partner.


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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.
 
                                         
    Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (Dollars in thousands, except per-unit amounts)  
 
Statement of Income Data:
                                       
Revenues
  $ 637,060     $ 572,817     $ 563,410     $ 514,972     $ 469,199  
Costs and expenses
    490,052       457,880       420,342       395,556       364,602  
                                         
Operating income
    147,008       114,937       143,068       119,416       104,597  
Equity earnings — Wamsutter
    88,538       76,212       61,690       40,555       39,016  
Discovery investment income
    22,357       28,842       18,050       11,880       5,619  
Impairment of investment in Discovery
                            (16,855 )
Interest expense
    (67,220 )     (58,348 )     (9,833 )     (8,238 )     (12,476 )
Interest income
    706       2,988       1,600       165        
                                         
Income before cumulative effect of change in accounting principle
  $ 191,389     $ 164,631     $ 214,575     $ 163,778     $ 119,901  
                                         
Net income(a)
  $ 191,389     $ 164,631     $ 214,575     $ 162,373     $ 119,901  
                                         
Income before cumulative effect of change in accounting principle per limited partner unit:
                                       
Common unit
  $ 2.55     $ 1.97     $ 1.62     $ 0.49 (b)     N/A  
Subordinated unit
  $ N/A     $ 1.97     $ 1.62     $ 0.49 (b)     N/A  
Net income per limited partner unit:
                                       
Common unit
  $ 2.55     $ 1.97     $ 1.62     $ 0.44 (b)     N/A  
Subordinated unit
  $ N/A     $ 1.97     $ 1.62     $ 0.44 (b)     N/A  
Balance Sheet Data (at period end):
                                       
Total assets
  $ 1,291,819     $ 1,283,477     $ 1,292,299     $ 1,190,508     $ 1,121,862  
Property, plant and equipment, net
    640,520       642,289       647,578       658,965       669,503  
Investment in Wamsutter
    277,707       284,650       262,245       240,156       221,360  
Investment in Discovery
    184,466       214,526       221,187       225,337       184,199  
Advances from affiliate
                            186,024  
Long-term debt
    1,000,000       1,000,000       750,000              
Partners’ capital
    203,610 (c)     161,487 (c)     471,341 (c)     1,142,478       895,476  
Cash Flow Data:
                                       
Cash distributions declared per unit
  $ 2.435     $ 2.045     $ 1.605     $ 0.1484       N/A  
Cash distributions paid per unit
  $ 2.435     $ 2.045     $ 1.605     $ 0.1484       N/A  


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    Year Ended December 31,  
    2008     2007     2006     2005     2004  
    (Dollars in thousands, except per-unit amounts)  
 
Operating Information:
                                       
Williams Partners L.P.:
                                       
Four Corners gathering volumes (BBtu/d)
    1,380       1,442       1,500       1,522       1,560  
Four Corners plant inlet natural gas volumes (BBtu/d)
    646       620       678       685       716  
Four Corners NGL equity sales (million gallons)
    162       167       182       165       198  
Four Corners NGL margin ($/gallon)
  $ .75     $ .61     $ .47     $ .37     $ .29  
Four Corners NGL production (million gallons)
    518       545       569       550       566  
Conway storage revenues
  $ 31,429     $ 28,016     $ 25,237     $ 20,290     $ 15,318  
Conway fractionation volumes (bpd) — our 50%
    39,019       34,460       38,859       39,965       39,062  
Carbonate Trend gathering volumes (BBtu/d)
    22       23       29       36       50  
Wamsutter — 100%:
                                       
Wamsutter gathering volumes (BBtu/d)
    499       516       490       464       452  
Wamsutter plant inlet natural gas volumes (BBtu/d)
    409       425       432       422       417  
Wamsutter NGL equity sales (million gallons)
    139       113       141       160       175  
Wamsutter NGL margin ($/gallon)
  $ .59     $ .48     $ .29     $ .13     $ .11  
Wamsutter NGL production (million gallons)
    415       420       377       419       435  
Discovery Producer Services — 100%:
                                       
Discovery plant inlet natural gas volumes (BBtu/d)
    457       582       467       345       348  
Discovery gross processing margin ($/MMbtu)
  $ .37     $ .33     $ .23     $ .19     $ .17  
Discovery NGL equity sales (million gallons)
    85       99       60       38       61  
Discovery NGL production (million gallons)
    181       252       232       147       134  
 
 
(a) Our operations are treated as a partnership with each member being separately taxed on its ratable share of our taxable income. Therefore, we have excluded income tax expense from this financial information.
 
(b) The period of August 23, 2005 through December 31, 2005.
 
(c) Because Four Corners, Wamsutter and a 20% interest in Discovery were owned by affiliates of Williams at the time of their acquisition by us, the acquisitions are accounted for as a combination of entities under common control, whereby the assets and liabilities acquired are combined with ours at their historical amounts for all periods presented. This accounting causes a reduction of the capital balance for the general partner for the difference between the historical cost of these assets and liabilities and the aggregate consideration paid to the general partner.

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Item 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF 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.
 
 
We gather, transport, process and treat natural gas and fractionate and store NGLs. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into three business segments:
 
  •  Gathering and Processing — West (West).  Our West segment includes (1) Williams Four Corners LLC (Four Corners) and (2) certain ownership interests in Wamsutter LLC (Wamsutter) consisting of (i) 100% of the Class A limited liability company membership interests and (ii) 65% of the Class C limited liability company membership interests in Wamsutter (together, the Wamsutter Ownership Interests). The Four Corners system gathers and processes or treats 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. The Wamsutter system gathers and processes natural gas produced in the Washakie Basin and connects with four pipeline systems that transport natural gas to end markets from the basin.
 
  •  Gathering and Processing — Gulf (Gulf).  Our Gulf segment includes (1) our 60% ownership interest in Discovery Producer Services LLC (Discovery) and (2) the Carbonate Trend gathering pipeline off the coast of Alabama. Discovery owns an integrated natural gas gathering and transportation pipeline system extending from offshore in the Gulf of Mexico to its natural gas processing facility and NGL fractionator in Louisiana. These systems gather, transport and process natural gas and fractionate NGLs to customers under a range of contractual arrangements. Although Discovery includes fractionation operations, which would normally fall within the NGL Services segment, it primarily gathers and processes, and is so managed.
 
  •  NGL Services.  Our NGL Services segment includes three integrated NGL storage facilities and a 50% undivided interest in a fractionator near Conway, Kansas. These assets provide stand-alone NGL fractionation and storage services using various fee-based contractual arrangements.
 
 
In the first three quarters of 2008, our segment profit improved considerably compared to 2007. However, these results were followed by a steep decline in the fourth quarter due to a rapid decline in NGL prices. As evidenced by recent events, NGL, crude oil and natural gas prices are highly volatile. NGL price changes have historically tracked with changes in the price of crude oil; however, ethane prices have recently disassociated from crude oil prices. As NGL prices, especially ethane, decline, we experience significantly lower per-unit NGL margins and periods when it is not economical to recover ethane. Additionally, as discussed below, Hurricanes Gustav and Ike severely disrupted Discovery’s operations in September and limited its operations throughout the fourth quarter. Discovery’s operations have been significantly restored, but will continue to be impacted while additional repairs are ongoing. We maintained our fourth-quarter unitholder distribution at $0.635 per unit, which was the same as the third-quarter 2008 distribution and 10% higher than the fourth-quarter 2007 distribution.
 
 
The global recession and resulting drop in demand and prices for NGLs has significantly reduced the profitability and cash flows of our gathering and processing businesses including Four Corners, our ownership interests in Wamsutter and Discovery. We expect low NGL margins during 2009, including periods when it is not economical to recover ethane. As a result, we expect cash flow from operations, including cash distributions to us from Wamsutter and Discovery, to be significantly lower in 2009 than 2008.


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Given the current energy commodity price and NGL margin environment, together with our cash balance of approximately $66 million at February 16, we expect to maintain our current level of cash distributions throughout 2009. During 2006 through 2008, we retained a portion of our excess cash flow for future periods when NGL prices and margins might be substantially lower — as they are now. However, if energy commodity prices and NGL margins decline further for a prolonged period of time, and/or if other unexpected events adversely affect cash flows and/or our available cash balance, we may need to reduce distributions.
 
During September 2008, Discovery’s offshore gathering system sustained hurricane damage and was unable to accept gas from producers while repairs were being made through the end of 2008. Inspections revealed that an 18-inch lateral was severed from its connection to the 30-inch mainline in 250 feet of water. The 30-inch mainline was repaired and returned to service in January 2009. The 30-inch mainline is now delivering 150 MMcf/d of production, which was its approximate volume prior to the hurricanes. Both the Larose processing plant and the Paradis fractionator are operational and processed gas from third-party sources during the fourth quarter of 2008.
 
We concluded our negotiations with the Jicarilla Apache Nation (JAN) during February 2009 with the execution of a 20-year right-of-way agreement. Under the new agreement, the JAN granted rights-of-way for Four Corners’ existing natural gas gathering system on JAN land as well as a significant geographical area for additional growth of the system. We paid an initial payment of $7.3 million upon execution of the agreement. Beginning in 2010, we will make annual payments of approximately $7.5 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could approximate the fixed amount. Additionally, five years from the effective date of the agreement, the JAN will have the option to acquire up to a 50% joint venture interest for 20 years in certain of Four Corners’ assets existing at the time the option is exercised. The joint venture option includes Four Corners’ gathering assets subject to the agreement and portions of Four Corners’ gathering and processing assets located in an area adjacent to the JAN lands. If the JAN selects the joint venture option, the value of the assets contributed by each party to the joint venture will be based upon a market value determined by a neutral third party at the time the joint venture is formed. This right-of-way agreement is subject to the consent of the United States Secretary of the Interior before it may become effective.
 
In January 2009, Wamsutter issued an additional 70.8 and 28.8 Class C units to us and Williams, respectively, related to funding of expansion capital expenditures placed in service during 2008. Therefore, we now own 65% and Williams owns 35% of Wamsutter’s outstanding Class C units. As of December 31, 2008, Williams has contributed $28.8 million for an expansion capital project that is expected to be placed in service during 2010. Williams will receive Class C units related to these expenditures after the asset is placed in service; thus, our Class C ownership interest will decline at that time.
 
 
Our management uses a variety of financial and operational measures to analyze our segment performance, including the performance of Wamsutter and Discovery. These measurements include:
 
  •  Four Corners’ and Wamsutter’s gathering and processing throughput volumes;
 
  •  Four Corners’ and Wamsutter’s NGL margins;
 
  •  Discovery’s and Carbonate Trend’s pipeline throughput volumes;
 
  •  Discovery’s gross processing margins;
 
  •  Conway’s fractionation volumes;
 
  •  Conway’s storage revenues; and
 
  •  Operating and maintenance expenses.


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Gathering, processing and throughput volumes on the following assets are important components of maximizing our profitability and the profitability of Wamsutter and Discovery:
 
  •  Our Four Corners gathering system and Ignacio, Kutz and Lybrook natural gas processing plants;
 
  •  Wamsutter’s gathering system and Echo Springs natural gas processing plant;
 
  •  Discovery’s gathering and transportation system, Larose gas processing plant and Paradis fractionator; and
 
  •  Our Carbonate Trend transportation pipeline.
 
We gather approximately 36% of the San Juan Basin’s natural gas production on our Four Corners system at approximately 6,450 receipt points, and the Wamsutter pipeline system gathers approximately 69% of the natural gas produced in the Washakie Basin. Gathering and transportation services are provided primarily under fee-based contracts. Gathering and transportation throughput volumes from existing wells will naturally decline over time. In order to maintain or increase gathering volumes, we, Wamsutter and Discovery must continually obtain new supplies of natural gas. The 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 gathering pipelines and (2) the ability to compete for volumes from successful new wells in other areas. Offshore drilling activity, which supplies Discovery’s gathering system, is generally subject to significantly higher costs and longer lead times than the onshore drilling, which supplies the Four Corners and Wamsutter gathering systems. We, Wamsutter and Discovery routinely monitor producer activity in the areas served by our assets and pursue opportunities to connect new wells to these pipelines.
 
Processing volumes are largely dependant on the volume of natural gas gathered or transported on these systems. Our Four Corners system processes natural gas under keep-whole, percent-of-liquids, fee-based and combination fee-based and keep-whole contracts. Wamsutter and Discovery process natural gas under keep-whole and fee-based contracts.
 
 
We and Wamsutter use NGL margins as an important measure of our ability to maximize the profitability of the processing operations. NGL margins are derived by deducting the cost of shrink replacement gas from the revenue received from the sale of NGLs, net of transportation and fractionation charges. Shrink replacement gas refers to natural gas that is required to replace the Btu content lost when NGLs are extracted from the natural gas stream. Under certain agreement types, we and Wamsutter receive NGLs as compensation for processing services provided to customers. The NGL margin will either increase or decrease as a result of a corresponding change in the relative market prices of NGLs and natural gas and changes in the cost of transporting and fractionating the NGLs.
 
 
We view total gross processing margins as an important measure of Discovery’s ability to maximize the profitability of its processing operations. Gross processing margins include revenue derived from:
 
  •  The rates stipulated under fee-based contracts multiplied by the actual volumes processed.
 
  •  Sales of NGL volumes received under certain processing contracts for Discovery’s account and keep-whole contracts.
 
  •  Sales of natural gas volumes that are in excess of operational needs.
 
The associated costs, primarily shrink replacement gas and fuel gas, are deducted from these revenues to determine gross processing margin. Discovery’s mix of processing contract types and its operation and contract optimization activities are determinants in processing revenues and gross margins.


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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.  We calculate storage revenues 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 are costs associated with the operations of a specific asset. Direct labor, compression and other contract services, right-of-way costs, fuel, utilities, materials and supplies, insurance and ad valorem taxes comprise the most significant portion of operating and maintenance expenses. We have experienced increased operating and maintenance expenses in recent years due to the growth of the oil and gas industry, which has increased competition for resources. Other than system gains and losses, rented compression services and fuel expense, these expenses generally remain relatively stable across broad ranges of throughput volumes but can fluctuate depending on the activities performed during a specific period. For example, plant overhauls and turnarounds result in increased expenses in the periods during which they are performed. In the course of providing gathering, processing and treating services to our customers, we realize over and under deliveries of customers’ products and over and under purchases of shrink replacement gas when our purchases vary from operational requirements. In addition, we realize gains and losses which we believe are related to inaccuracies inherent in the gas measurement process. These gains and losses are reflected in operating and maintenance expense as system gains and losses. These system gains and losses are an unpredictable component of our operating costs. Compression service costs are dependent upon the extent and amount of additional compression needed to meet the needs of our customers and the cost at which compression can be purchased, leased and operated. We include fuel cost in our operating and maintenance expense although it is generally recoverable from our customers in our NGL Services segment. As noted above, fuel costs are a component in assessing Discovery’s gross processing margins.
 
 
Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. The selection of these policies has been discussed with the audit committee of the board of directors of our general partner. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.
 
 
We evaluate our long-lived assets and investments for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of certain long-lived assets or that the decline in value of an investment is other-than-temporary.
 
In analyses conducted during 2007 and 2008, we determined that the carrying value of our Carbonate Trend pipeline may not be recoverable because of forecasted declining cash flows. As a result, we recognized impairment charges of $10.4 million and $6.2 million in 2007 and 2008, respectively, to reduce the carrying value to management’s estimate of fair value at the end of each of those years. As of December 31, 2008, the carrying value of this asset has been written down to zero. (See Note 7, Other (Income) Expense, in our Notes


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to Consolidated Financial Statements.) Our most recent analysis utilized judgments and assumptions in the following areas:
 
  •  expected future drilling in the area,
 
  •  estimated future volumes from currently producing wells and new discoveries,
 
  •  estimated future gathering rates, and
 
  •  estimated operating and maintenance cost increases.
 
 
We record asset retirement obligations for legal and contractual obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset in the period in which it is incurred if a reasonable estimate of fair value can be made. At December 31, 2008, we have accrued asset retirement obligations of $13.2 million including estimated retirement costs associated with the abandonment of Four Corners’ gas processing and compression facilities located on leased land, Four Corners’ wellhead connections on federal land, Conway’s underground storage caverns and brine ponds in accordance with Kansas Department of Health and Environment (KDHE) regulations and the Carbonate Trend pipeline. Our estimate utilizes judgments and assumptions regarding the extent of our obligations, the costs to abandon and the timing of abandonment. In 2008, we revised our estimated asset retirement obligations by $3.6 million. 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 2008, and the expected retirement date for the Carbonate Trend pipeline had been significantly shortened, the recorded asset retirement obligation would have increased by an additional $12.0 million to $14.0 million. (See Note 8, Property, Plant and Equipment, in our Notes to Consolidated Financial Statements.)
 
 
We record liabilities for estimated environmental remediation obligations when we assess that a loss is probable and the amount of the loss can be reasonably estimated. At December 31, 2008, we have an accrual for estimated environmental remediation obligations of $4.8 million. This remediation accrual is revised, and our associated income is affected, during periods in which new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. We base liabilities for environmental remediation upon our assumptions and estimates regarding what remediation work and post-remediation monitoring will be required and the costs of those efforts, which we develop from information obtained from outside consultants and from discussions with the applicable governmental authorities. As new developments occur or more information becomes available, it is possible that our assumptions and estimates in these matters will change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarter or annual period. (Please read “— Environmental” and Note 14, Commitments and Contingencies, in our Notes to Consolidated Financial Statements.)
 
Results of Operations
 
Consolidated Overview
 
The following table and discussion summarizes our consolidated results of operations for the three years ended December 31, 2008. The results of operations by segment are discussed in further detail following this


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consolidated overview discussion and relate to the segment tables in Note 15, Segment Disclosures, in our Notes to Consolidated Financial Statements.
 
                                         
          % Change
          % Change
       
          from
          from
       
    2008     2007(1)     2007     2006(1)     2006  
    (Dollars in thousands)  
 
Revenues
  $ 637,060       +11 %   $ 572,817       +2 %   $ 563,410  
Costs and expenses:
                                       
Product cost and shrink replacement
    206,078       (13 )%     181,698       (4 )%     175,508  
Operating and maintenance expense
    185,901       (15 )%     162,343       (5 )%     155,214  
Depreciation, amortization and accretion
    45,029       +3 %     46,492       (6 )%     43,692  
General and administrative expense
    47,059       (3 )%     45,628       (16 )%     39,440  
Taxes other than income
    9,508       +1 %     9,624       (7 )%     8,961  
Other (income) expense — net
    (3,523 )     NM       12,095       NM       (2,473 )
                                         
Total costs and expenses
    490,052       (7 )%     457,880       (9 )%     420,342  
                                         
Operating income
    147,008       +28 %     114,937       (20 )%     143,068  
Equity earnings — Wamsutter
    88,538       +16 %     76,212       +24 %     61,690  
Discovery investment income
    22,357       (22 )%     28,842       +60 %     18,050  
Interest expense
    (67,220 )     (15 )%     (58,348 )     NM       (9,833 )
Interest income
    706       (76 )%     2,988       +87 %     1,600  
                                         
Net income
  $ 191,389       +16 %   $ 164,631       (23 )%   $ 214,575  
                                         
 
 
(1) + = Favorable Change; ( ) = Unfavorable Change; NM = A percentage calculation is not meaningful due to change in signs, a zero-value denominator or a percentage change greater than 200.
 
2008 vs. 2007
 
Revenues increased $64.2 million, or 11%, due primarily to higher product sales in our West segment and higher fractionation, product sales and storage revenues in our NGL Services segment.
 
Product cost and shrink replacement increased $24.4 million, or 13%, due primarily to higher cost of product sales in both our West and NGL Services segments and higher average natural gas prices for shrink replacement in our West segment.
 
Operating and maintenance expense increased $23.6 million, or 15%, due primarily to higher repairs and maintenance, materials and supplies and system losses in our West segment.
 
Other (income) expense — net in 2008 reflects an $11.6 million involuntary conversion gain related to the November 2007 Ignacio plant fire. Other (income) expense— net for 2008 and 2007 includes a $6.2 million and $10.4 million impairment, respectively, of our Carbonate Trend pipeline in our Gulf segment.
 
Operating income increased $32.1 million, or 28%, due primarily to higher per-unit NGL margins on slightly lower sales volumes, an $11.6 million involuntary conversion gain in 2008, higher other fee revenue and higher condensate sales margins in our West segment, combined with higher fractionation and storage revenues in our NGL Services segment and a $4.2 million lower impairment loss on the Carbonate Trend pipeline in our Gulf segment. Partially offsetting these favorable variances were lower fee-based gathering revenues and higher operating and maintenance expenses in our West segment.


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Equity earnings — Wamsutter increased $12.3 million, or 16%, due primarily to higher average per-unit NGL margins on increased NGL sales volumes.
 
Discovery investment income decreased $6.5 million, or 22%, due primarily to lower equity earnings caused by Hurricanes Ike and Gustav, partially offset by hurricane-related receipts under our Discovery-related business interruption policy.
 
Interest expense increased $8.9 million, or 15%, due primarily to interest on our $250.0 million term loan issued in December 2007 to finance a portion of our acquisition of ownership interests in Wamsutter.
 
Interest income decreased $2.3 million, or 76%, due primarily to significantly lower daily interest rates on higher fourth-quarter 2008 cash balances compared to fourth quarter 2007.
 
2007 vs. 2006
 
Revenues increased $9.4 million, or 2%, due primarily to higher product sales, partially offset by lower fee-based gathering and processing in our West segment, slightly offset by lower revenues in our NGL Services segment.
 
Product cost and shrink replacement increased $6.2 million, or 4%, due primarily to increased NGL purchases from producers in our West segment, partially offset by lower shrink requirements from the fire at Ignacio and decreased product sales volumes in our NGL Services segment.
 
Operating and maintenance expense increased $7.1 million, or 5%, due primarily to higher expense in our West segment from increased fuel, rent and leased compression expense, partially offset by lower expense in our NGL Services segment from lower fuel and power costs on lower fractionator throughput.
 
General and administrative expense increased $6.2 million, or 16%, due primarily to higher Williams’ technical support services and other charges allocated by Williams to us for various administrative support functions.
 
Other (income) expense — net changed from $2.5 million income in 2006 to $12.1 million expense in 2007 due primarily to the 2007 impairment of the Carbonate Trend pipeline and a $3.6 million gain in 2006 on the sale of the La Maquina carbon dioxide treating facility in the West segment.
 
Operating income declined $28.1 million, or 20%, due primarily to the impact of the 2007 Ignacio plant fire in our West segment, the 2007 impairment of the Carbonate trend pipeline and higher general and administrative expense. These unfavorable variances were slightly offset by higher revenues and lower operating and maintenance expenses in our NGL Services segment.
 
Equity earnings — Wamsutter increased $14.5 million, or 24%, due primarily to higher NGL margins and fee-based gathering and processing revenues, partially offset by higher general and administrative expenses.
 
Discovery investment income increased $10.8 million, or 60%, due primarily to higher gross processing margins that more than offset lower fee-based revenues and higher operating and maintenance expense.
 
Interest expense increased $48.5 million due primarily to interest on our $750.0 million senior unsecured notes. We issued $150.0 million in June 2006 and $600.0 million in December 2006 to finance our acquisition of Four Corners.
 
Results of operations — Gathering and Processing — West
 
The Gathering and Processing — West segment includes our Four Corners’ natural gas gathering, processing and treating assets and our ownership interest in Wamsutter.
 


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    2008     2007     2006  
    (In thousands)  
 
Segment revenues
  $ 560,138     $ 513,787     $ 502,313  
Costs and expenses:
                       
Product cost and shrink replacement
    189,192       170,434       159,997  
Operating and maintenance expense
    156,713       135,782       124,763  
Depreciation, amortization and accretion
    41,215       41,523       40,055  
General and administrative expense — direct
    8,333       7,790       11,920  
Taxes other than income
    8,770       8,869       8,245  
Other (income) expense — net
    (9,709 )     1,698       (2,476 )
                         
Total costs and expenses, including interest income
    394,514       366,096       342,504  
                         
Segment operating income
    165,624       147,691       159,809  
Equity earnings — Wamsutter
    88,538       76,212       61,690  
                         
Segment profit
  $ 254,162     $ 223,903     $ 221,499  
                         
 
Four Corners
 
2008 vs. 2007
 
Revenues increased $46.4 million, or 9%, due primarily to $43.0 million higher product sales revenues and $9.0 million improved other fee revenue, slightly offset by $7.1 million lower gathering revenues. The significant components of the revenue fluctuations are addressed more fully below.
 
Product sales revenues increased $43.0 million due primarily to:
 
  •  $35.3 million from 22% higher average per-unit NGL sales prices realized on NGL volumes we received under keep-whole and percent-of-liquids processing contracts. NGL sales prices were sharply higher in the first three quarters of 2008 compared to 2007; however, NGL sales prices declined significantly in the fourth quarter of 2008.
 
  •  $6.6 million higher sales of NGLs on behalf of third-party producers. Under these arrangements, we purchase NGLs from the third-party producers and sell them to an affiliate. This increase is offset by higher associated product costs of $6.9 million discussed below.
 
  •  $4.6 million higher condensate sales resulting primarily from higher prices.
 
These increases in product sales revenues were slightly offset by a $4.4 million impact of 3% lower NGL sales volumes.
 
Other fee revenue improved $9.0 million due primarily to a $4.4 million fourth-quarter 2008 insurance reimbursement for lost profits under our business interruption insurance related to the November 2007 Ignacio plant fire and the absence of a $3.5 million third-quarter 2007 unfavorable revenue recognition correction for electronic flow measurement fees.
 
Fee-based gathering revenues decreased $7.1 million, or 4%, due primarily to a $7.6 million decline in revenue from lower gathering volumes. This resulted from the prolonged, severe weather during early 2008 which inhibited both our and our customers’ abilities to access facilities, connect new wells and maintain production. The 2007 volumes were reduced by the fire at the Ignacio gas processing plant in late November 2007.
 
Product cost and shrink replacement increased $18.8 million, or 11%, due primarily to $10.7 million from higher average natural gas prices for shrink replacement and $6.9 million higher NGL purchases from third-party producers who elected to have us purchase their NGLs (offset by the corresponding increase in product sales discussed above).

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Operating and maintenance expense increased $20.9 million, or 15%, due primarily to $12.0 million higher system and imbalance losses and $9.1 million higher repairs and maintenance and materials and supplies expense. During 2008 our volumetric system loss, as a percentage of total volume received, was significantly higher than in 2007. While our system losses are generally an unpredictable component of our operating costs, they can be higher during periods of prolonged, severe weather, such as those we experienced during early 2008. Additionally, operating inefficiencies caused by the fire at Ignacio plant unfavorably impacted our system losses.
 
Other (income) expense — net improved $11.4 million due primarily to an $11.6 million involuntary conversion gain recognized in 2008 related to the November 2007 Ignacio plant fire.
 
Segment operating income increased $17.9 million, or 12%, due primarily to:
 
  •  $20.0 million higher NGL margins resulting primarily higher per-unit NGL margins. Record NGL margins experienced during the first three quarters were impacted unfavorably in the fourth-quarter 2008 when NGL sales prices declined significantly.
 
  •  $11.6 million of 2008 involuntary conversion gains.
 
  •  $9.0 million higher other revenues.
 
Partially offsetting these increases were $20.9 million higher operating and maintenance expenses and $7.1 million lower fee-based gathering revenues.
 
2007 vs. 2006
 
Revenues increased $11.5 million, or 2%, due primarily to $23.7 million higher product sales, partially offset by $9.5 million lower gathering and processing revenues. Product sales increased due primarily to:
 
  •  $24.2 million related to a 17% increase in average NGL sales prices realized on sales of NGLs which we received under certain processing contracts.
 
  •  $15.3 million higher sales of NGLs on behalf of third party producers from whom we purchase NGLs for a fee under their contracts. We subsequently sell the NGLs to an affiliate. This increase is offset by higher associated product costs of $15.3 million discussed below.
 
These product sales increases were partially offset by $12.7 million lower revenues related to a decrease in NGL sales volumes. Based on 2006 prices, the $12.7 million includes approximately $9.3 million related to NGL volume reductions caused by the fire at the Ignacio gas processing plant in late November 2007.
 
Gathering and processing revenues decreased $9.5 million, or 4%, due primarily to $8.3 million lower revenue from a 3% decrease in gathered and processed volumes. Based on 2006 prices, the $8.3 million includes approximately $5.5 million related to gathered and processed volume reductions caused by the fire at the Ignacio plant.
 
Product cost and shrink replacement increased $10.4 million, or 7%, due primarily to a $15.3 million increase from third-party producers who elected to have us purchase their NGLs, offset by the corresponding increase in product sales revenues discussed above. This increase was partially offset by $6.4 million from lower volumetric shrink requirements under Four Corners’ keep-whole processing contracts. Based on 2006 prices, the $6.4 million includes approximately $5.1 million related to reduced processing activity caused by the fire at the Ignacio plant.
 
Operating and maintenance expense increased $11.0 million, or 9%, due primarily to:
 
  •  $9.6 million higher non-shrink natural gas purchases caused primarily by $7.9 million higher natural gas costs for steam generation at our Milagro facility. In 2006, our purchase of this natural gas from an affiliate of Williams was favorably impacted by that affiliate’s fixed price natural gas fuel contracts. These contracts expired in the fourth quarter of 2006. Additionally, in 2007 gathering fuel increased $3.3 million including approximately $2.3 million related to lower customer fuel reimbursements and operational inefficiencies caused by the fire at the Ignacio plant.


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  •  $3.9 million higher rent expense related to the purchase of a temporary special business license upon the expiration of a right-of-way agreement with the Jicarilla Apache Nation.
 
  •  $3.4 million higher leased compression costs.
 
Partially offsetting these increases were $5.6 million lower materials and supplies related primarily to decreased equipment maintenance activity.
 
General and administrative expense — direct decreased $4.1 million, or 35%, due primarily to certain management costs that were directly charged to the segment in 2006 but allocated to the partnership in 2007. As a result of this change, these 2007 management costs are included in our overall general and administrative expense but not in our segment results.
 
Other (income) expense — net in 2006 includes a $3.6 million gain recognized on the sale of the LaMaquina treating facility. The LaMaquina treating facility was shut down in 2002 and impairments were recorded in 2003 and 2004.
 
Segment operating income decreased $12.1 million, or 8%, due primarily to an estimated $13.0 million combined impact of the fire at the Ignacio gas processing plant. Higher product sales margins, excluding the impact of the fire, of $17.5 million and $4.1 million lower direct general and administrative expense were offset by $7.7 million higher operating and maintenance expense excluding fire-related items, $4.0 million lower fee-based gathering and processing revenues not related to the fire and $4.2 million lower other (income) expense.
 
 
  •  NGL and natural gas commodity prices.  Because NGL prices, especially ethane, have recently declined, we expect significantly lower per-unit NGL margins in 2009 compared to 2008. We also anticipate periods when it will not be economical to recover ethane, which will reduce our margins. We have no hedges in place in 2009 for either our NGL sales or our natural gas shrink replacement purchases. As evidenced by recent events, NGL, crude and natural gas prices are highly volatile. NGL price changes have historically tracked with changes in the price of crude oil, however ethane prices have recently disassociated from crude prices.
 
  •  Gathering and processing volumes.  We expect average gathering and processing volumes for 2009 to be slightly below 2008. Drilling activity by producers is expected to decline in 2009 due to the current credit crisis and economic downturn, together with the low commodity price environment. However, when drilling activity increases, we anticipate that capital investments we completed in 2008 will support producer customers’ drilling activity, expansion opportunities and production enhancement activities.
 
  •  Drilling in Paradox Basin.  Third-party producers are drilling in the Paradox Basin in Colorado and we expect to be successful in competing for processing contracts for this gas.
 
  •  Operating costs.  We expect and will pursue reductions in certain costs as demand for these resources declines.
 
  •  Assets on Jicarilla land.  As previously discussed, we concluded our negotiations with the Jicarilla Apache Nation (JAN) during February 2009 with the execution of a 20-year right-of-way agreement. These terms represent a significant increase over our 2008 JAN expense, including the cost of our special business licenses with the JAN, of $3.5 million. We paid an initial payment of $7.3 million upon execution of the agreement. Beginning in 2010, we will make annual payments of approximately $7.5 million and an additional annual payment which varies depending on per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the agreement. Throughout 2009, we will record an estimate of the additional annual payment to be paid in 2010, based on 2009 NGL margins. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could approximate the fixed amount.


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Wamsutter is accounted for using the equity method of accounting. As such, our interest in Wamsutter’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The following discussion addresses in greater detail the results of operations for 100% of Wamsutter. Please read Note 6, Equity Investments, of our Notes to Consolidated Financial Statements for discussion of how Wamsutter allocates its net income between its member owners including us.
 
                         
    Years Ended December 31,  
    2008     2007     2006  
    (In thousands)  
 
Revenues
  $ 239,534     $ 175,309     $ 176,546  
Costs and expenses, including interest:
                       
Product cost and shrink replacement
    78,809       46,039       71,088  
Operating and maintenance expense
    20,973       18,257       17,047  
Depreciation and accretion
    21,182       18,424       16,189  
General and administrative expense
    13,507       12,623       8,866  
Taxes other than income
    1,868       1,637       1,411  
Other (income) expense, net
    (569 )     944       255  
                         
Total costs and expenses
    135,770       97,924       114,856  
                         
Net income
  $ 103,764     $ 77,385     $ 61,690  
                         
Williams Partners’ interest
  $ 88,538     $ 76,212     $ 61,690  
                         
 
2008 vs. 2007
 
Revenues increased $64.2 million, or 37%, due primarily to $61.6 million higher sales of NGLs which Wamsutter received under keep-whole processing contracts. This increase reflects $39.5 million related to higher average sales prices and $22.1 million related to 23% higher sales volumes. This volumetric increase was due primarily to a lower volume of gas delivered by Wamsutter’s fee-based customers in the first quarter of 2008 due to inclement weather which allowed Wamsutter to process additional keep-whole gas at the Echo Springs plant. Additionally, Wamsutter benefited from the ability to process additional keep-whole gas at CIG’s Rawlins natural gas processing plant.
 
Product cost and shrink replacement increased $32.8 million, or 71%, due primarily to a $24.2 million increase from higher average natural gas prices and $9.5 million from higher volumetric shrink requirements due to higher volumes processed under Wamsutter’s keep-whole processing contracts. Gas prices in 2007 were impacted by very low local natural gas costs compared with other natural gas markets.
 
Operating and maintenance expense increased $2.7 million, or 15%, due primarily to higher gathering fuel, third-party processing, and material and supply costs, substantially offset by $5.0 million higher system gains.
 
Depreciation and accretion increased $2.8 million, or 15%, due primarily to new assets placed into service.
 
Net income increased $26.4 million, or 34%, due primarily to $27.9 million higher NGL margin resulting from increased per-unit margins on higher NGL sales volumes.


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As described in Note 6, Equity Investments, of our Notes to Consolidated Financial Statements, Wamsutter’s net income is allocated based upon the allocation, distribution, and liquidation provisions of its limited liability company agreement. The following table presents the allocation of Wamsutter’s 2008 net income to its unitholders:
 
                                         
    Our Share     Other
    Wamsutter
 
Wamsutter Net Income Allocation
  Class A     Class C     WPZ Total     Class C     Net Income  
                (Millions)              
 
Net income, beginning December 1, 2007 up to $70.0 million.*
  $ 62.6     $     $ 62.6     $     $ 62.6  
Net income allocation related to 5% of amount over $70.0 million
    2.1             2.1             2.1  
Net income for December 2008
    1.0             1.0             1.0  
Net income allocation related to transition support payments paid to us
    7.6             7.6             7.6  
Remainder net income allocated to Class C members
          15.2       15.2       15.2       30.4  
                                         
Totals
  $ 73.3     $ 15.2     $ 88.5     $ 15.2     $ 103.7  
                                         
 
 
* $7.4 million of the $70.0 million was recognized in 2007.
 
2007 vs. 2006
 
Revenues decreased $1.2 million, or 1%, due primarily to a $12.3 million decrease in product sales revenues, substantially offset by a $10.0 million increase in gathering and fee-based processing revenues.
 
  •  Product sales revenues decreased $20.8 million from 20% lower NGL volumes Wamsutter received under certain processing contracts. Effective January 1, 2007, one significant customer made an election to switch from a keep-whole processing arrangement to a fee-based processing arrangement for three years. This significantly decreased the NGL volumes received by Wamsutter under its keep-whole processing contracts. These product sales decreases were partially offset by a $12.1 million increase related to higher average NGL sales prices.
 
  •  Gathering and fee-based processing revenue increased $5.6 million due to a 9% increase in the average fee and $4.4 million due to an 8% increase in average volumes.
 
Product cost and shrink replacement decreased $25.0 million, or 35%, due primarily to an $11.2 million decrease from lower average natural gas prices and a $10.4 million decrease from lower volumetric shrink requirements under Wamsutter’s keep-whole processing contracts following the election of one customer to switch to fee-based processing discussed above.
 
Operating and maintenance expense increased $1.2 million, or 7%, due primarily to higher materials and supplies and outside services expense caused primarily by increased equipment maintenance activity, partially offset by $4.9 million higher system gains.
 
Depreciation and accretion expense increased $2.2 million, or 14%, due primarily to new assets placed into service.
 
General and administrative expense increased $3.8 million, or 42%, due primarily to higher charges allocated by Williams to Wamsutter for various technical and administrative support functions.
 
Net income increased $15.7 million, or 25%, due primarily to $12.9 million higher NGL margins and $10.0 million higher gathering and fee-based processing revenues, partially offset $3.8 million higher general and administrative expenses and $2.2 million higher depreciation and accretion expense.


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  •  NGL margins.  We expect significantly lower cash distributions from Wamsutter in 2009 as compared to 2008, primarily as a result of lower per-unit NGL margins. As evidenced by recent events, NGL, crude and natural gas prices are highly volatile. NGL price changes have historically tracked with changes in the price of crude oil, however ethane prices have recently disassociated from crude prices. As NGL prices, especially ethane, have declined, Wamsutter is experiencing lower per-unit NGL margins in 2009 compared to 2008. Natural gas prices in the Rockies’ basins have been lower than other areas of the country, and we expect this trend to continue. Because natural gas cost is a component of Wamsutter’s NGL margins, Wamsutter expects that per-unit NGL margins may be higher than some other areas of the country. However, Wamsutter may still experience periods when it is not economical to recover ethane, which will reduce its margins.
 
  •  Gathering and processing volumes.  We anticipate that our 2009 average gathering volumes will increase slightly over 2008 levels as a result of our well connect activity, producers’ sustained drilling activity, expansion opportunities and production enhancement activities that should be sufficient to more than offset the historical production decline.
 
  •  Third-party processing.  In 2008, we executed a new agreement that extended our ability to send excess unprocessed gas to Colorado Interstate’s Rawlins natural gas processing plant through October 2010. This agreement provides Wamsutter with third-party processing of 80 MMcf/d. We expect a full year of natural gas processing in 2009 under this agreement. As a result, total gas processed will increase, Wamsutter will be able to sell higher volumes of NGLs, and operating costs will increase approximately $2 million.
 
  •  Operating costs.  We expect and will pursue reductions in certain costs as demand for these resources declines.
 
Results of operations — Gathering and Processing — Gulf
 
The Gulf segment includes the Carbonate Trend gathering pipeline and our 60% ownership interest in Discovery.
 
                         
    2008     2007     2006  
    (In thousands)  
 
Segment revenues
  $ 2,096     $ 2,119     $ 2,656  
Costs and expenses:
                       
Operating and maintenance expense
    1,668       1,875       1,660  
Depreciation, amortization and accretion
    751       1,249       1,200  
General and administrative expense — direct
                1  
Other, net
    6,187       10,406        
                         
Total costs and expenses
    8,606       13,530       2,861  
                         
Segment operating loss
    (6,510 )     (11,411 )     (205 )
Discovery investment income
    22,357       28,842       18,050  
                         
Segment profit
  $ 15,847     $ 17,431     $ 17,845  
                         
 
Carbonate Trend
 
2008 vs. 2007
 
Segment operating loss improved $4.9 million because the impairment loss recognized on the Carbonate Trend assets was $4.2 million lower in 2008 than in 2007. (See Note 7, Other (Income) Expense, of our Notes to Consolidated Financial Statements.)


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2007 vs. 2006
 
Segment operating loss increased $11.2 million due primarily to a $10.4 million impairment of the Carbonate Trend pipeline recognized in 2007. (See Note 7, Other (Income) Expense, of our Notes to Consolidated Financial Statements.)
 
 
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.
 
                         
    2008     2007     2006  
    (In thousands)  
 
Revenues
  $ 241,248     $ 260,672     $ 197,313  
Costs and expenses, including interest:
                       
Product cost and shrink replacement
    146,998       155,704       119,552  
Operating and maintenance expense
    36,670       28,988       23,049  
Depreciation and accretion
    21,324       25,952       25,562  
General and administrative expense
    4,500       2,280       2,150  
Interest income
    (650 )     (1,799 )     (2,404 )
Other (income) expense, net
    (1,994 )     1,476       (679 )
                         
Total costs and expenses
    206,848       212,601       167,230  
                         
Net income
  $ 34,400     $ 48,071     $ 30,083  
                         
Williams Partners’ interest
  $ 20,641     $ 28,842     $ 18,050  
                         
 
2008 vs. 2007
 
Revenues decreased $19.4 million, or 7%, due primarily to $13.1 million lower product sales described below and $8.0 million lower fee-based gathering, processing, fractionation and transportation revenue resulting from third and fourth quarter lost revenues in the aftermath of Hurricanes Ike and Gustav. The lower product sales revenues are due primarily to:
 
  •  $21.5 million lower sales of NGLs on behalf of third-party producers as a result of the hurricanes which is offset by lower associated product costs of $21.5 million discussed below.
 
  •  $16.8 million decrease from lower NGL volumes processed under keep-whole and percent-of-liquids arrangements, including lower NGL volumes following Hurricanes Ike and Gustav.
 
These decreases were partially offset by $26.3 million higher product sales from higher average NGL sales prices realized on sales of NGLs which Discovery received under certain processing contracts.
 
Product cost and shrink replacement decreased $8.7 million, or 6%, due primarily to a $21.5 million decrease in product purchased from third-party producers as a result of the impact of the hurricanes, partially offset by $15.9 million from higher average natural gas prices.
 
Operating and maintenance expense increased $7.7 million, or 27%, due primarily to 2008 hurricane survey and repair costs on the gathering system damaged by Hurricane Ike that are not recoverable from insurance.
 
Depreciation and accretion decreased $4.6 million, or 18%, due primarily to a change in the estimated remaining useful lives of the Larose processing plant and the regulated pipeline and gathering system.
 
General and administrative expense increased $2.2 million, or 97%, due to an increase in Discovery’s management fee charged by Williams.


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Other (income) expense, net improved $3.5 million due to a recently approved Federal Energy Regulatory Commission (FERC) settlement filing that allowed the 2008 reversal of a $3.5 million reserve for system fuel and lost and unaccounted for gas related to 1998 through 2003.
 
Net income decreased $13.7 million, or 28%, due primarily to $8.0 million lower fee-based gathering, processing, fractionation and transportation revenue resulting from third and fourth quarter lost revenues in the aftermath of Hurricanes Ike and Gustav, $7.7 million higher operating and maintenance expense and $5.4 million lower NGL sales margins, slightly offset by $4.6 million lower depreciation and accretion expense.
 
2007 vs. 2006
 
Revenues increased $63.4 million, or 32%, due primarily to $73.8 million higher product sales, partially offset by a $9.9 million reduction in fee-based transportation, gathering, processing and fractionation revenues. The 2006 period included revenues from the Tennessee Gas Pipeline (TGP) and the Texas Eastern Transmission Company (TETCO) open season agreements. The open seasons provided outlets for natural gas that was stranded following damage to third-party facilities during hurricanes Katrina and Rita in 2005.
 
Product sales increased $73.8 million primarily due to a $36.8 million increase in NGL sales volumes received under certain processing contracts, including an October 2006 TETCO percent-of-liquids processing agreement, $26.2 million from higher average NGL prices and an $8.1 million increase in NGL sales related to processing customers’ elections to have Discovery purchase their NGLs.
 
The $9.9 million decrease in fee-based transportation, gathering, processing and fractionation revenues is due primarily to the reduced fee-based revenues related to processing TGP and TETCO volumes under the open season agreements discussed above.
 
Product cost and shrink replacement increased $36.2 million, or 30%, due primarily to $19.4 million higher volumetric natural gas requirements from increased processing activity and $7.8 million higher product purchase costs for the processing customers who elected to have Discovery purchase their NGLs.
 
Operating and maintenance expense increased $5.9 million, or 26%, due primarily to higher property insurance premiums related to increased hurricane activity in the Gulf Coast region in prior years and other costs related to decommissioning two pipelines.
 
Net income increased $18.0 million, or 60%, due primarily to $39.0 million higher gross processing margins resulting from higher NGL sales volumes and prices, partially offset by $9.9 million lower fee-based transportation, gathering, processing and fractionation revenues and $5.9 million higher operating and maintenance expense.
 
 
  •  Gross processing margins.  We expect significantly lower cash distributions from Discovery in 2009 compared to 2008 primarily as a result of lower per-unit NGL margins. As evidenced by recent events, NGL, crude and natural gas prices are highly volatile. NGL price changes have historically tracked with changes in the price of crude oil, however ethane prices have recently disassociated from crude prices. As NGL prices, especially ethane, have declined, Discovery is experiencing significantly lower gross processing margins in 2009 compared to 2008. We anticipate periods when it is not economical to recover ethane, which will reduce Discovery’s margins.
 
  •  Plant inlet volumes.  Discovery’s Larose gas processing plant is currently processing approximately 400 BBtu/d from all sources and we expect this volume to be similar through the first quarter due to the current unfavorable economic processing environment. This represents a decrease from the 600 BBtu/d being processed prior to Hurricanes’ Gustav and Ike in 2008. Throughout the pipeline repair period, Discovery continued to process approximately 200 BBtu/d of on-shore gas from third-party pipelines. In the late third quarter of 2009, we expect ATP Oil and Gas Corporation will begin


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  delivering volumes of approximately 30 BBtu/d from the dedicated blocks in their Gomez prospect and their Mirage and Morgas prospects.
 
  •  Hurricane Damage Impact.  We expect little, if any, ongoing impact beyond February 2009 from the 2008 hurricanes. Discovery’s 30-inch mainline gathering system was repaired and returned to service in mid-January 2009. We expect business interruption insurance to largely mitigate lost profits associated with outages beyond the 60-day deductible period which ended in 2008.
 
  •  First Quarter Discovery Distribution.  As a result of lower margins and reduced volumes flowing through Discovery’s offshore gathering system in the first quarter of 2009, we do not expect to receive a cash distribution in April 2009 from Discovery’s first-quarter 2009 operating cash flows.
 
  •  Tahiti Production.  Discovery expects to begin receiving revenues from its Tahiti pipeline lateral by the third quarter of 2009 based on Chevron’s announcement regarding expected timing of first production. Any delays Chevron experiences in bringing their production online will further impact the initial timing of revenues for Discovery. Discovery expects approximately 50 BBtu/d from Tahiti.
 
  •  Other new supplies.  During 2009, Discovery expects to add approximately 75 BBtu/d of throughput volumes from the Clipper, Daniel Boone, Pegasus, Valley Forge and Yosemite prospects.
 
  •  Operating costs.  As a result of the damage caused by the 2008 hurricanes, Discovery expects a significant increase in property damage insurance premiums in 2009.
 
 
The NGL Services segment includes our three NGL storage facilities near Conway, Kansas and our 50% undivided interest in the Conway fractionator.
 
                         
    2008     2007     2006  
    (In thousands)  
 
Segment revenues
  $ 74,826     $ 56,911     $ 58,441  
Costs and expenses:
                       
Product cost
    16,886       11,264       15,511  
Operating and maintenance expense
    27,520       24,686       28,791  
Depreciation and accretion
    3,063       3,720       2,437  
General and administrative expense — direct
    2,582       2,190       1,149  
Other, net
    737       746       719  
                         
Total costs and expenses
    50,788       42,606       48,607  
                         
Segment profit
  $ 24,038     $ 14,305     $ 9,834  
                         
 
2008 vs. 2007
 
Segment revenues increased $17.9 million, or 31%, due primarily to higher fractionation, product sales and storage revenues. The significant components of the revenue fluctuations are addressed more fully below.
 
  •  Fractionation revenues increased $7.8 million due primarily to a 59% higher average fractionation rate and 6% higher volumes. The higher average rate is due primarily to the December 2007 expiration of a fractionation contract with a cap on the per-unit fee, which limited our ability to pass through increases in fractionation fuel expense to this customer.
 
  •  Product sales increased $5.4 million due to higher sales volumes and an increase in average product sales prices. This increase was slightly offset by the related increase in product cost discussed below.
 
  •  Storage revenues increased $3.4 million due primarily to higher storage revenues from new storage leases.


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Product cost increased $5.6 million, or 50%, due to the higher product sales volumes and prices discussed above.
 
Operating and maintenance expense increased $2.8 million, or 11%, due primarily to $4.0 million unfavorable storage product losses, $2.5 million higher maintenance costs and $1.3 million higher fractionation fuel costs. These increases were partially offset by a $2.9 million product imbalance adjustment in 2008 and $2.0 million of fractionation blending gains.
 
Segment profit increased $9.7 million, or 68%, due primarily to higher fractionation and storage revenues, partially offset by higher operating and maintenance expenses.
 
2007 vs. 2006
 
Segment revenues decreased $1.5 million, or 3%, due primarily to $4.7 million lower product sales revenues and a $2.1 million decrease in fractionation revenues resulting from lower volumes and rates, partially offset by $2.8 million higher storage revenues and $2.5 million higher product upgrade fee revenues.
 
Product cost decreased $4.2 million, or 27%, due to the lower product sales volumes.
 
Operating and maintenance expense decreased $4.1 million, or 14%, due primarily to lower fuel and power costs related to lower fractionator throughput and lower repairs and maintenance costs.
 
Depreciation and accretion expense increased $1.3 million, or 53%, due primarily to asset retirement obligation assumption changes and higher depreciation expense related to a larger property base.
 
Segment profit increased $4.5 million, or 45%, due primarily to higher storage and product upgrade fee revenues and lower repair and maintenance costs. These increases were partially offset by higher depreciation and accretion expense and higher general and administrative expense.
 
 
  •  We expect 2009 storage revenues will remain approximately consistent with 2008 due to continued strong demand for propane and natural gasoline storage as well as higher priced specialty storage services.
 
  •  We continue to perform a large number of storage cavern workovers and wellhead modifications to comply with KDHE regulatory requirements. We expect outside service costs to continue at current levels throughout 2009 to ensure that we meet the regulatory compliance requirements.
 
Financial Condition and Liquidity
 
The global recession and resulting drop in demand and prices for NGLs has significantly reduced the profitability and cash flows of our gathering and processing businesses including Four Corners, Wamsutter and Discovery. We expect low NGL margins during 2009 and periods when it is not economical to recover ethane, which will further reduce our margins. As a result, we expect cash flow from operations, including cash distributions from Wamsutter and Discovery, to be significantly lower in 2009 than 2008. While our goal is to maintain the current level of distributions, we may need to reduce distributions if energy prices and margins decline further or remain at low levels for a prolonged period of time, and/or if other unexpected events adversely affect cash flows. Additionally, the recent instability in financial markets has created global concerns about the liquidity of financial institutions and is having overarching impacts on the economy as a whole. However, we have no debt maturities until 2011, and as of February 23, 2009, we have approximately $70.0 million of cash and cash equivalents and $208 million of available capacity under our credit facilities. The availability of the capacity under the credit facilities may be restricted under certain circumstances as discussed below under “ — Credit Facilities.” Therefore, we believe we have the financial resources and liquidity necessary to meet requirements for working capital, capital and investment expenditures, debt service and quarterly cash distributions.


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We anticipate our more significant sources of liquidity will include:
 
  •  Cash and cash equivalents on hand;
 
  •  Cash generated from operations, including cash distributions from Wamsutter and Discovery; and
 
  •  Credit facilities, as needed and available.
 
We anticipate our more significant liquidity requirements to be:
 
  •  Maintenance and expansion capital expenditures for our Four Corners and Conway assets;
 
  •  Contributions we must make to Wamsutter to fund certain of its capital expenditures;
 
  •  Cash calls from Discovery for hurricane damage repairs, which generally should be reimbursed by insurance;
 
  •  Interest on our long-term debt; and
 
  •  Quarterly distributions to our unitholders.
 
Additionally, we plan to continue pursuing select value-adding growth opportunities in a prudent manner.
 
Available Liquidity at December 31, 2008 (in millions):
 
         
Cash and cash equivalents
  $ 116.2  
Available capacity under our $450 million five-year senior unsecured credit facility(1)
    188.0  
Available capacity under our $20 million revolving credit facility with Williams as lender
    20.0  
         
Total
  $ 324.2  
         
 
 
(1) The original amount has been reduced by $12.0 million due to the bankruptcy of the parent company and certain affiliates of Lehman Brothers Commercial Bank (Lehman). See Note 10, Long-Term Debt, Credit Facilities and Leasing Activities, of our Notes to Consolidated Financial Statements. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction. Additionally, availability of our capacity under this credit facility in future periods could be constrained by compliance with required covenants.
 
These liquidity sources and cash requirements are discussed in greater detail below.
 
 
Wamsutter expects to make quarterly distributions of available cash to its members pursuant to the terms of its limited liability company agreement. Available cash is defined as cash generated from Wamsutter’s business less reserves that are necessary or appropriate to provide for the conduct of its business and to comply with applicable law and/or debt instrument or other agreement to which it is a party. Wamsutter has made the following distributions to its members for 2008 (all amounts in thousands):
 
                                 
          Our Share        
Date of Distribution
  Total Distribution to Members     Class A     Class C     Other Class C  
 
3/28/08
  $ 25,000     $ 17,876     $ 3,562     $ 3,562  
6/30/08
    30,500       18,150       6,175       6,175  
9/30/08
    35,500       18,400       8,550       8,550  
12/30/08
    20,000       17,624       1,188       1,188  
                                 
Total
  $ 111,000     $ 72,050     $ 19,475     $ 19,475  
                                 
 
We expect significantly lower cash distributions from our Wamsutter investment as a result of sharply lower expected NGL margins in 2009.


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See Note 6, Equity Investments, of our Notes to Consolidated Financial Statements for a description of how Wamsutter distributes its available cash. Generally, as holder of the Class A membership interests we are entitled to the first $17.5 million that Wamsutter distributes each quarter.
 
 
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 2008-2009 distributions to its members (all amounts in thousands):
 
                 
Date of Distribution
  Total Distribution to Members   Our 60% Share
 
1/30/08
  $ 28,000     $ 16,800  
4/30/08
  $ 26,000     $ 15,600  
7/30/08
  $ 22,000     $ 13,200  
10/30/08
  $ 18,000     $ 10,800  
1/30/09
  $     $  
 
As a result of disruptions and damage from Hurricanes Gustav and Ike, Discovery did not make a distribution for the fourth quarter of 2008 in January 2009. We also expect significantly lower cash distributions from our Discovery investment as a result of sharply lower expected NGL margins in 2009.
 
 
On September 13, 2008, Hurricane Ike hit the Gulf Coast area, and Discovery’s offshore gathering system sustained damage. Inspections revealed that an 18-inch lateral was severed from its connection to the 30-inch mainline in 250 feet of water. The estimated total cost to repair the gathering system is approximately $60.5 million, including $52.1 million in potentially reimbursable expenditures in excess of the insurance deductible and $2.0 million in unreimbursable expenditures. Of the total amount, $33.5 million has been incurred through December 31, 2008. Discovery funded the $6.4 million deductible amount with cash on hand and filed for and received a prepayment of $23.6 million from the insurance provider. Repair costs in excess of the deductible, net of any insurance prepayments, may be funded with cash calls from its members, including us. Once Discovery receives the related insurance proceeds, it will make special distributions back to its members. We have filed for reimbursement from our insurance carrier for lost profits under our Discovery-related business interruption policy, which has a 60-day deductible period, and have received $4.4 million to date.
 
 
We have a $200.0 million revolving credit facility with Citibank, N.A. as administrative agent available for borrowings and letters of credit. The parent company and certain affiliates of Lehman, who is committed to fund up to $12.0 million of our revolving credit facility, have filed for bankruptcy. We expect that our ability to borrow under this facility is reduced by this committed amount. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction. Borrowings under this agreement must be repaid on or before December 11, 2012. There were no amounts outstanding at December 31, 2008 under the revolving credit facility.
 
The credit agreement contains various covenants that limit, among other things, our, and certain of our subsidiaries’, ability to incur indebtedness, grant certain liens supporting indebtedness, merge, consolidate or allow any material change in the character of its business, sell all or substantially all of our assets, or make distributions or other payments other than distributions of available cash under certain conditions. Significant financial covenants under the credit agreement include the following:
 
  •  We are required to maintain a ratio of consolidated indebtedness to consolidated EBITDA (each as defined in the credit agreement) of no greater than 5.00 to 1.00. This ratio may be increased in the case of an acquisition of $50.0 million or more, in which case the ratio will be 5.50 to 1.00 for the fiscal quarter in which the acquisition occurs and three fiscal quarter-periods following such acquisition. At


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  December 31, 2008, our ratio of consolidated indebtedness to the consolidated EBITDA, as calculated under this covenant, of approximately 2.98 is in compliance with this covenant.
 
  •  Our ratio of consolidated EBITDA to consolidated interest expense (as defined in the credit agreement) must be not less than 2.75 to 1.00 as of the last day of any fiscal quarter commencing March 31, 2008 unless we obtain an investment grade rating from Standard and Poor’s Ratings Services or Moody’s Investors Service and the rating from the other agency is not less than Ba1 or BB+, as applicable. At December 31, 2008, our ratio of consolidated EBITDA to consolidated interest expense, as calculated under this covenant, of approximately 5.13 is in compliance with this covenant.
 
Although it is difficult to predict future commodity pricing, we expect to remain in compliance with the credit agreement ratios described above throughout 2009 given the current energy commodity price and NGL margin environment. Inasmuch as the ratios are calculated on a rolling four-quarter basis, the ratios at December 31, 2008, do not reflect a full-year impact of the lower earnings we experienced in the fourth quarter of 2008. If unexpected events happen or economic conditions or energy commodity prices and NGL margins decline further for a prolonged period of time, our financial covenant ratios may fall below required levels. If such a situation appeared likely, we would take actions necessary to avoid a breach of our covenants, including seeking covenant relief through waivers or the restructuring or replacement of our facility, reducing our indebtedness or seeking assistance from our general partner. Market conditions could make these alternatives challenging, and no assurances can be given that we would be successful in our efforts. Even if successful, we could experience increased borrowing costs and reduced liquidity which could limit our ability to fund capital expenditures and make cash distributions to unitholders. In the event that despite our efforts we breach our financial covenants causing an event of default, the lenders could, among other things, accelerate the maturity of any borrowings under the facility (including our $250 million term loan) and terminate their commitments to lend.
 
In addition, our ability to borrow the remaining $188 million currently available under the credit facility could be restricted by the impact of weaker energy commodity prices or future borrowings. Either could limit our ability to borrow the full amount under the credit agreement because incremental future borrowings are only permitted if the financial ratios would be met when calculated with the inclusion of the new borrowing.
 
We also have a $20.0 million revolving credit facility with Williams as the lender. The facility is available exclusively to fund working capital borrowings. We are required to and have reduced all borrowings under this facility to zero for a period of at least 15 consecutive days once each 12-month period prior to the maturity date of the facility. Borrowings under the credit facility mature on June 20, 2009 and bear interest at the one-month LIBOR. As of December 31, 2008, we had no outstanding borrowings under the working capital credit facility.
 
Wamsutter has a $20.0 million revolving credit facility with Williams as the lender. The credit facility is available exclusively to fund Wamsutter’s working capital requirements. Borrowings under the credit facility mature on December 12, 2009 with four, one-year automatic extensions unless terminated by either party. Wamsutter pays a commitment fee to Williams on the unused portion of the credit facility of 0.125% annually. Interest on any borrowings under the facility will be calculated upon a periodic fixed rate equal to LIBOR plus an applicable margin, or a base rate plus the applicable margin. As of December 31, 2008, Wamsutter had no outstanding borrowings under the credit facility.
 
 
The table below presents our current credit ratings on our senior unsecured long-term debt.
 
             
            Senior Unsecured
Rating Agency
  Date of Last Change   Outlook   Debt Rating
 
Standard & Poor’s
  November 9, 2007   Stable   BBB-
Moody’s Investor Service
  November 6, 2008   Negative   Ba2
Fitch Ratings
  May 8, 2008   Stable   BB+


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At December 31, 2008, the evaluation of our credit rating is “stable outlook” from Standard and Poor’s and Fitch Ratings agencies. On November 6, 2008, Moody’s Investors Service (Moody’s) changed the ratings outlook for Williams and each of Williams’ rated subsidiaries, including WPZ, from “stable” to “negative” following the announcement that Williams’ management and board of directors were evaluating a variety of structural changes to Williams. On February 26, 2009, Moody’s revised Williams, and certain Williams’ rated subsidiaries, excluding us, to “stable” from “negative.”
 
With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.
 
With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
 
With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.
 
Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing.
 
 
The natural gas gathering, treating, processing and transportation, and NGL fractionation and storage businesses are capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital expenditures of these businesses consist primarily of:
 
  •  Maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets, including certain well connection expenditures, and to extend their useful lives including expenditures which are mandatory and/or essential for maintaining the reliability of our operations; and
 
  •  Expansion capital expenditures, which tend to be more discretionary than maintenance capital expenditures, include expenditures to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities.
 
Actual and estimated capital expenditures for the years ending December 31, 2008 and 2009, respectively, are as follows (all amounts in millions):
 
                                         
    Actual Expenditures
   
    December 31, 2008   Estimated Expenditures for 2009
Company
  Maintenance   Expansion   Total   Maintenance   Expansion   Total
 
Four Corners
  $ 18.9     $ 3.7     $ 22.6     $15 – 20   $ 5 – 10     $20 – 30
Conway
    2.9       6.1       9.0     3 – 6     8 – 12     11 – 18
Wamsutter (our share)
    21.4       3.5       24.9     20 – 25         20 – 25
Discovery (our share)
    0.7       9.0       9.7     1 – 3     1 – 3     2 – 6


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The table above does not include capital expenditures related to the replacement of capital assets destroyed by the November 2007 fire at Four Corners’ Ignacio gas processing plant nor repairs to Discovery’s offshore-gathering system damaged by Hurricane Ike. We expect those expenditures that exceed the property insurance deductible will be reimbursed by insurance. Our 2008 Statement of Cash Flows includes $14.3 million of these reimbursed or reimbursable capital expenditures for the Ignacio plant.
 
We expect to fund Four Corners’ and Conway’s maintenance and expansion capital expenditures with cash flows from operations. Four Corners’ estimated maintenance capital expenditures for 2009 include a range of $12.0 million to $14.0 million related to well connections necessary to connect new sources of throughput for the Four Corners’ system which serve to offset the historical decline in throughput volumes. Four Corners’ expansion capital expenditures relate primarily to plant and gathering system expansion projects. Four Corners’ actual maintenance expenditures for 2008 have been reduced $3.5 million for amounts reimbursed by producers for prior-year well connect costs. Conway’s expansion capital expenditures relate to two projects: first, the drilling of five new ethane/propane mix caverns and conversion of certain ethane/propane caverns for use as propane storage caverns and second, the completion of a project to improve our flexibility and storage capabilities with respect to refinery grade butane.
 
Wamsutter’s estimated maintenance capital expenditures for 2009 include a range of $20.0 million to $22.0 million related to well connections necessary to connect new sources of throughput for the Wamsutter system which serve to offset the historical decline in throughput volumes. We expect Wamsutter will fund its maintenance capital expenditures through its cash flows from operations.
 
Wamsutter funds its expansion capital expenditures through capital contributions from its members as specified in its limited liability company agreement. This agreement specifies that expansion capital projects with expected total expenditures in excess of $2.5 million at the time of approval and well connections that increase gathered volumes beyond current levels be funded by contributions from its Class B membership, which we do not own. However, our ownership of the Class A membership interest requires us to provide capital contributions related to expansion projects with expected total expenditures less than $2.5 million at the time of approval. Wamsutter will issue Class C units to us for the expansion capital projects we fund.
 
Discovery will fund its maintenance and expansion capital expenditures either by cash calls to its members or from its cash flows from operations. We expect that Discovery will cash call us for $4.2 million in February 2009 for the Tahiti project and we expect to receive a $1.8 million reimbursement of those costs pursuant to the requirements of our omnibus agreement with Williams. Also, we expect that in 2009, Discovery may cash call us for up to $6.3 million for repair costs on the offshore-gathering system damaged by Hurricane Ike. We expect to be reimbursed by Discovery after it receives the property insurance proceeds.
 
 
We have $150.0 million senior unsecured notes outstanding that bear interest at 7.5% per annum payable semi-annually in arrears on June 15 and December 15 of each year. The senior notes mature on June 15, 2011.
 
We have $600.0 million of 7.25% senior unsecured notes outstanding. The maturity date of the notes is February 1, 2017. Interest is payable semi-annually in arrears on February 1 and August 1 of each year.
 
We have a $250.0 million floating-rate term loan outstanding under a $450.0 million senior unsecured credit agreement with Citibank, N.A. as administrative agent. As previously discussed in “Credit Facilities,” we also have a revolving credit facility under this same credit agreement. This borrowing must be repaid before December 11, 2012.
 
 
We have paid quarterly distributions to our unitholders and our general partner interest after every quarter since our IPO on August 23, 2005. Our most recently declared quarterly distribution of $41.6 million was paid on February 13, 2009 to the general partner interest and common and subordinated unitholders of record at the close of business on February 6, 2009. This distribution included an incentive distribution to our general partner of approximately $7.3 million. As previously disclosed, sustained lower NGL margins, which are


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significantly reducing our profitability and cash flows, could result in a reduction in our cash distribution to unitholders.
 
Results of Operations — Cash Flows
 
 
                         
    2008   2007   2006
    (In thousands)
 
Net cash provided by operating activities
  $ 247,390     $ 179,104     $ 169,450  
Net cash used by investing activities
    (15,097 )     (385,871 )     (624,213 )
Net cash provided (used) by financing activities
    (152,325 )     185,423       505,465  
 
 
Net cash provided by operating activities increased $68.3 million in 2008 as compared to 2007 due primarily to $95.9 million higher distributions related to our Wamsutter ownership interests purchased in December 2007 and $9.8 million higher operating income excluding non-cash items.
 
Partially offsetting these increases was an additional $26.7 million of interest paid due primarily to our $250.0 million term loan issued in December 2007 and timing of interest payments on our $600.0 million senior unsecured notes. Additionally, distributions related to our Discovery investment decreased $5.6 million and changes in working capital excluding accrued interest decreased $5.0 million.
 
Net cash provided by operating activities increased $9.7 million in 2007 as compared to 2006 due primarily to $40.2 million from changes in working capital, excluding accrued interest. Cash provided by working capital increased due primarily to $25.4 million in lower accounts receivable and $17.8 million in higher accounts payable between periods. We also had $14.2 million higher distributions related to the equity earnings of Discovery.
 
Partially offsetting these increases were $33.2 million in higher cash interest payments for the interest on our $750.0 million senior unsecured notes issued in 2006 to finance our acquisition of Four Corners and $11.5 million lower operating income excluding non-cash items.
 
 
Net cash used by investing activities in 2008 includes $14.3 million of capital expenditures for the replacement of capital assets destroyed by the November 2007 fire at Four Corners’ Ignacio gas processing plant, partially offset by $13.1 million of related insurance proceeds. Additionally, net cash used by investing activities in 2008, 2007 and 2006 includes maintenance and expansion capital expenditures and related change in accrued liabilities.
 
Net cash used by investing activities in 2007 also includes the purchase of the Wamsutter ownership interests on December 11, 2007 and the additional 20% ownership interest in Discovery on June 28, 2007. Since these ownership interests were purchased from Williams, the transactions were between entities under common control, and have been accounted for at historical cost. Therefore the amount reflected as cash used by investing activities for these purchases represents the historical cost to Williams.
 
Net cash used by investing activities in 2006 relates primarily to the $607.5 million acquisition of Four Corners. Because Four Corners was an affiliate of Williams at the time of these acquisitions, these transactions are accounted for as a combination of entities under common control and the acquisition is recorded at historical cost rather than the actual consideration paid to Williams.
 
Net cash provided (used) by financing activities:
 
Net cash used by financing activities in 2008 includes distributions to unitholders and our general partner of $155.4 million.


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Net cash provided by financing activities in 2007 includes $265.9 million of net proceeds from debt and equity issuances related to our acquisition of the Wamsutter ownership interests less the related amounts distributed to Williams in excess of Wamsutter’s contributed basis and $87.3 million of distributions to unitholders and our general partner.
 
Net cash provided by financing activities in 2006 includes $624.5 million of net proceeds from debt and equity issuances related to our acquisition of Four Corners less the related amounts distributed to Williams in excess of Four Corners’ contributed basis. It also includes a $114.5 million pass through of Four Corners’ net cash flows to Williams under the cash management program in place prior to the purchase of Four Corners by us and $25.5 million of contributions from our general partner, partially offset by $30.0 million of distributions to unitholders and our general partner.
 
 
                         
    Years Ended December 31,
    2008   2007   2006
    (In thousands)
 
Net cash provided by operating activities
  $ 133,641     $ 85,541     $ 75,641  
Net cash used by investing activities
    (57,539 )     (31,624 )     (36,040 )
Net cash used by financing activities
    (76,102 )     (53,917 )     (39,601 )
 
Net cash provided by operating activities increased $48.1 million from 2008 to 2007 due primarily to a $27.7 million increase in operating income, as adjusted for non-cash expenses, and a $20.4 million increase in cash provided primarily by changes in accounts receivable.
 
The $9.9 million increase in net cash provided by operating activities in 2007 as compared to 2006 is due primarily to $19.3 million increase in operating income, as adjusted for non-cash expenses, partially offset by $9.4 million lower cash provided from changes in working capital.
 
Net cash used by investing activities in 2008 is primarily comprised of capital expenditures related to plant expansion projects and connection of new wells. Net cash used by investing activities in 2007 and 2006 is primarily comprised of capital expenditures related to the connection of new wells.
 
Net cash used by financing activities for 2008 is almost entirely related to cash distributions to Wamsutter’s members pursuant to the distribution provisions of Wamsutter’s limited liability company agreement. Net cash used by financing activities in 2007 and 2006 is primarily distributions of Wamsutter’s net cash flows to Williams pursuant to its participation in Williams’ cash management program.
 
 
                         
    2008   2007   2006
    (In thousands)
 
Net cash provided by operating activities
  $ 91,654     $ 62,092     $ 63,456  
Net cash used by investing activities
    (7,187 )     (5,914 )     (17,162 )
Net cash used by financing activities
    (80,924 )     (55,252 )     (30,089 )
 
Net cash provided by operating activities increased $29.6 million in 2008 as compared to 2007 due primarily to a $49.1 million increase in cash provided by working capital changes resulting from the impact of the hurricanes, partially offset by $18.7 million lower net income as adjusted for non-cash items.
 
Net cash provided by operating activities decreased $1.4 million in 2007 as compared to 2006 due primarily to an increase in cash used for working capital of $20.3 million, substantially offset by an increase of $19.0 million in operating income as adjusted for non-cash items.
 
Net cash used by investing activities includes $9.9 million, $29.1 million and $32.9 million of capital spending in 2008, 2007 and 2006, respectively. The 2008 expenditures were for the Tahiti lateral and other smaller projects. The 2007 and 2006 expenditures were primarily for the Tahiti project, partially offset by the use of $22.6 million and $15.8 million of Tahiti-related restricted cash in 2007 and 2006, respectively.


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Net cash used by financing activities include normal cash distributions to Discovery’s members of $94.0 million, $59.2 million and $43.6 million in 2008, 2007 and 2006, respectively. Net cash used by financing activities in 2008 also includes $13.1 million of capital contributions from Discovery’s members for the Tahiti pipeline lateral expansion, other capital expansion projects and hurricane damage repair. Net cash used by financing activities in 2006 includes $13.5 million of capital contributions related to the Tahiti pipeline lateral expansion.
 
Contractual Obligations
 
A summary of our contractual obligations as of December 31, 2008, is as follows (in thousands):
 
                                         
    2009     2010-2011     2012-2013     2014+     Total  
 
Long-term debt:
                                       
Principal
  $     $ 150,000     $ 250,000     $ 600,000     $ 1,000,000  
Interest
    67,804 (a)     130,014       99,517       152,250       449,585  
Capital leases
                             
Operating leases(b)
    1,357       1,276       90             2,723  
Purchase obligations
    15,958 (c)     240       240       120 (d)     16,558  
Other long term liabilities(e)
                             
                                         
Total
  $ 85,119     $ 281,530     $ 349,847     $ 752,370     $ 1,468,866  
                                         
 
 
(a) The assumed interest rate on our $250.0 million term loan is based on the forecasted forward LIBOR plus the applicable margin.
 
(b) Subsequent to year end, we entered into a 20-year right-of-way agreement with the JAN, which is considered an operating lease. We are required to make a fixed payment of $7.5 million annually and an additional annual payment, which varies depending on per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way agreement. The table above does not include any amounts related to this agreement.
 
(c) Includes the open purchase orders as of December 31, 2008 to be paid in 2009.
 
(d) Year 2014 represents one year of payments associated with an operating agreement whose term is tied to the life of the underlying gas reserves.
 
(e) Subsequent to year end, we entered into a five-year agreement for compression services. Payments under this agreement will vary depending upon the extent and amount of compression services needed to meet producer service requirements. The table above does not include any amounts related to this agreement, which are estimated to be approximately $24.0 million annually.
 
Our equity investee, Wamsutter, also has contractual obligations for which we are not contractually liable. These contractual obligations, however, will impact Wamsutter’s ability to make cash distributions to us. A summary of Wamsutter’s total contractual obligations as of December 31, 2008, is as follows (in thousands):
 
                                         
    2009     2010-2011     2012-2013     2014+     Total  
 
Notes payable/long-term debt
  $     $     $     $     $  
Capital leases
                             
Operating leases
    1,362       1,429       50       10       2,851  
Purchase obligations(a)
    74,058       47,313                   121,371  
Other long-term liabilities
                             
                                         
Total
  $ 75,420     $ 48,742     $ 50     $ 10     $ 124,222  
                                         
 
 
(a) Includes the open purchase orders as of December 31, 2008 to be paid in 2009 and 2010. This amount includes large growth projects of $120.0 million that will be funded by contributions from Wamsutter’s Class B membership, which we do not own.


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Our equity investee, Discovery, also has contractual obligations for which we are not contractually liable. These contractual obligations, however, will impact Discovery’s ability to make cash distributions to us. A summary of Discovery’s total contractual obligations as of December 31, 2008, is as follows (in thousands):
 
                                         
    2009     2010-2011     2012-2013     2014+     Total  
 
Notes payable/long-term debt
  $     $     $     $     $  
Capital leases
                             
Operating leases
    1,241       2,482       2,482       2,105       8,310  
Purchase obligations
    7,917                         7,917  
Other long-term liabilities
                             
                                         
Total
  $ 9,158     $ 2,482     $ 2,482     $ 2,105     $ 16,227  
                                         
 
 
We have experienced increased costs in recent years due to the effects of growth in the oil and gas industry, which has increased competition for resources. A significant portion of Four Corners’ and Wamsutter’s respective gathering and processing revenues are from contracts that include escalation clauses that provide for an annual escalation based on an inflation-sensitive index. These escalations, combined with increased fees where competition permits for new and amended contracts, help to offset these inflationary pressures; however, they may not always approximate the actual inflation rate we experience due to geographic and/or industry-specific inflationary pressures on our costs and expenses. We have significant annual capital expenditures related to well connections and gathering system expansions necessary to connect new sources of throughput to these systems as throughput volumes from existing wells will naturally decline over time.
 
 
Discovery’s natural gas pipeline transportation and some gathering are subject to rate regulation by the FERC under the Natural Gas Act. For more information on federal and state regulations affecting our business, please read “Risk Factors” and “FERC Regulation” elsewhere in this report.
 
 
We are a participant in certain hydrocarbon removal and groundwater monitoring activities associated with certain well sites in New Mexico. Of nine remaining active sites, product removal is ongoing at four and groundwater monitoring is ongoing at each site. As groundwater concentrations reach and sustain closure criteria levels and state regulator approval is received, the sites will be properly abandoned. We expect the remaining sites will be closed within four to seven years. As of December 31, 2008, we had accrued liabilities totaling $1.5 million for these environmental activities. Actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by governmental authorities and other factors.
 
Our Conway storage facilities are subject to strict environmental regulation by the Kansas Department of Health and Environment (KDHE) under the Underground Hydrocarbon and Natural Gas Storage program, which became effective in 2003. We are in the process of modifying our Conway storage facilities, including the caverns and brine ponds, and we expect our storage operations will be in compliance with the Underground Hydrocarbon and Natural Gas Storage program regulations by the applicable required compliance dates. In response to these increased costs, we raised our storage rates by an amount sufficient to preserve our margins in this business. Accordingly, we do not believe that these increased costs have had a material effect on our business or results of operations. We expect on average to complete workovers on each of our caverns every five to ten years and install double liners on each of our brine ponds every 18 years.
 
We are a participant in certain environmental remediation activities associated with soil and groundwater contamination at our Conway storage facilities. These activities relate to four projects that are in various remediation stages including assessment studies, cleanups and/or remedial operations and monitoring. We


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continue to coordinate with the KDHE to develop screening, sampling, cleanup and monitoring programs. The costs of such activities will depend upon the program scope ultimately agreed to by the KDHE and are expected to be paid over the next two to six years. Under an omnibus agreement with Williams entered into at the closing of the IPO, Williams agreed to indemnify us for certain remediation expenditures, including Conway plumes and required wellhead control equipment and well meters. At December 31, 2008, approximately $7.3 million remains available for this indemnification. We had accrued liabilities totaling $3.3 million for these costs at December 31, 2008. Actual costs incurred will depend on the actual number of contaminated sites identified, the amount and extent of contamination discovered, the final cleanup standards mandated by KDHE and other governmental authorities and other factors.
 
In connection with our operations at the Conway facilities, we are required by the KDHE regulations to provide assurance of our financial capability to plug and abandon the wells and abandon the brine facilities we operate at Conway. Williams has posted a letter of credit on our behalf in the amount of $19.9 million to guarantee our plugging and abandonment responsibilities for these facilities. We anticipate providing assurance in the form of letters of credit in future periods until such time as we obtain an investment-grade credit rating or are capable of meeting KDHE financial strength tests. After our filing of this Annual Report on Form 10-K, we will request the state to accept a financial test in lieu of the letters of credit.
 
In connection with the construction of Discovery’s pipeline, approximately 73 acres of marshland was traversed. Discovery is required to restore marshland in other areas to offset the damage caused during the initial construction. In Phase I of this project, Discovery created new marshlands to replace about half of the traversed acreage. Phase II, which completed the project, began during 2005 and was completed in October 2008.
 
Item 7A.   Qualitative and Quantitative Disclosures About Market Risk
 
Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are commodity price risk and interest rate risk.
 
 
We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as well as other market factors, such as market volatility and commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets and our long-term energy-related contracts. In 2007 and 2008, we managed a portion of the risks associated with these market fluctuations using various derivative contracts. All of our derivatives expired as of December 31, 2008.
 
 
Our current interest rate risk exposure is related primarily to our debt portfolio. A majority of our current debt portfolio is comprised of fixed interest rate debt which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit agreements would be at a variable interest rate and would expose us to the risk of increasing interest rates.


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The tables below provide information about our interest rate-sensitive instruments as of December 31, 2008 and 2007. Long-term debt in the table represents principal cash flows by expected maturity date. The fair value of our private debt is valued based on the prices of similar securities with similar terms and credit ratings.
 
                                                 
                    Fair Value
  Fair Value
                    December 31,
  December 31,
    2011   2012   2017   Total   2008   2007
    (Dollars in millions)
 
Long-term debt:
                                               
Fixed rate
  $ 150.0     $     $ 600.0     $ 750.0     $ 591.9     $ 777.5  
Interest rate
    7.50 %             7.25 %                        
Variable rate
  $     $ 250.0     $     $ 250.0     $ 233.4     $ 250.0  
Interest rate(1)
            1.221 %                                
 
 
(1) The weighted-average interest rate for 2008 is LIBOR plus .75 percent.


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Item 8.   Financial Statements and Supplementary Data
 
 
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a — 15(f) and 15d — 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
 
All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
 
Under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2008, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, our internal control over financial reporting was effective.
 
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.


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The Board of Directors of Williams Partners GP LLC,
General Partner of Williams Partners L.P.,
and the Limited Partners of Williams Partners L.P.
 
We have audited Williams Partners L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Williams Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Williams Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of Williams Partners L.P. as of December 31, 2008 and 2007, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008, and our report dated February 23, 2009 expressed an unqualified opinion thereon.
 
/s/  Ernst & Young LLP
 
Tulsa, Oklahoma
February 23, 2009


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The Board of Directors of Williams Partners GP LLC,
General Partner of Williams Partners L.P.,
and the Limited Partners of Williams Partners L.P.
 
We have audited the accompanying consolidated balance sheets of Williams Partners L.P. as of December 31, 2008 and 2007, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Williams Partners L.P.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2009 expressed an unqualified opinion thereon.
 
/s/  Ernst & Young LLP
 
Tulsa, Oklahoma
February 23, 2009


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WILLIAMS PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,  
    2008     2007  
    (In thousands)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 116,165     $ 36,197  
Accounts receivable:
               
Trade
    16,279       12,860  
Affiliate
    11,652       20,402  
Other
    2,919       2,543  
Product imbalance
    6,344       20,660  
Prepaid expenses
    4,102       4,056  
Reimbursable projects
          8,989  
Other current assets
    3,642       3,805  
                 
Total current assets
    161,103       109,512  
Investment in Wamsutter
    277,707       284,650  
Investment in Discovery Producer Services
    184,466       214,526  
Gross property, plant and equipment
    1,265,153       1,239,792  
Less accumulated depreciation
    (624,633 )     (597,503 )
                 
Property, plant and equipment, net
    640,520       642,289  
Other noncurrent assets
    28,023       32,500  
                 
Total assets
  $ 1,291,819     $ 1,283,477  
                 
 
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
               
Accounts payable:
               
Trade
  $ 22,348     $ 35,947  
Affiliate
    11,122       17,676  
Product imbalance
    8,926       21,473  
Deferred revenue
    4,916       4,569  
Derivative liabilities — affiliate
          2,718  
Accrued interest
    18,705       19,500  
Other accrued liabilities
    6,172       8,243  
                 
Total current liabilities
    72,189       110,126  
Long-term debt
    1,000,000       1,000,000  
Environmental remediation liabilities
    2,321       2,599  
Other noncurrent liabilities
    13,699       9,265  
Commitments and contingent liabilities (Note 14)
               
Partners’ capital:
               
Common unitholders (52,777,452 and 45,774,728 units outstanding at December 31, 2008 and 2007)
    1,619,954       1,473,814  
Subordinated unitholders (7,000,000 units outstanding at December 31, 2007)
          109,542  
Accumulated other comprehensive loss
          (2,487 )
General partner
    (1,416,344 )     (1,419,382 )
                 
Total partners’ capital
    203,610       161,487  
                 
Total liabilities and partners’ capital
  $ 1,291,819     $ 1,283,477  
                 
 
See accompanying notes to consolidated financial statements.


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WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME
 
                         
    Year Ended December 31,  
    2008     2007     2006  
    (Dollars in thousands, except per-unit amounts)  
 
Revenues:
                       
Product sales:
                       
Affiliate
  $ 314,299     $ 267,970     $ 255,075  
Third-party
    24,981       22,962       16,919  
Gathering and processing:
                       
Affiliate
    37,893       35,819       42,228