10-K 1 d302220d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

(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, 2011

OR

 

¨ 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

 

 

WILLIAMS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware   20-2485124

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

One Williams Center, Tulsa, Oklahoma   74172-0172
(Address of Principal Executive Offices)   (Zip Code)

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

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

(Title of Class)

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

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  ¨    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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ     No   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
     Yes  ¨     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 $3,968,507,019. This figure excludes common units beneficially owned by the directors and executive officers of Williams Partners GP LLC, our general partner.

The registrant had 305,008,540 common units outstanding as of February 23, 2012.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

 


Table of Contents

WILLIAMS PARTNERS L.P.

FORM 10-K

TABLE OF CONTENTS

 

     Page  
PART I  

Item 1.

   Business      3   
   Website Access to Reports and Other Information      3   
   General      3   
   Recent Events      3   
   Financial Information About Segments      3   
  

Business Segments

     4   
   Gas Pipeline      4   
   Midstream Gas & Liquids      7   
   Regulatory Matters      12   
   Environmental Matters      13   
   Competition      13   
   Employees      14   
   Financial Information about Geographic Areas      14   

Item 1A.

   Risk Factors      15   

Item 1B.

   Unresolved Staff Comments      43   

Item 2.

   Properties      43   

Item 3.

   Legal Proceedings      43   

Item 4.

   Mine Safety Disclosures      44   

PART II

  

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      45   

Item 6.

   Selected Financial Data      47   

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      48   

Item 7A.

   Quantitative and Qualitative Disclosures About Market Risk      71   

Item 8.

   Financial Statements and Supplementary Data      73   

Item 9.

   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      113   

Item 9A.

   Controls and Procedures      113   

Item 9B.

   Other Information      113   

PART III

  

Item 10.

   Directors, Executive Officers and Corporate Governance      114   

Item 11.

   Executive Compensation      121   

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      126   

Item 13.

   Certain Relationships and Related Transactions, and Director Independence      129   

Item 14.

   Principal Accounting Fees and Services      134   

PART IV

  

Item 15.

   Exhibits and Financial Statement Schedules      134   

 

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DEFINITIONS

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

Barrel: One barrel of petroleum products equals 42 U.S. gallons.

Bcf: One billion cubic feet of natural gas.

Bcf/d: One billion cubic feet of natural gas 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.

Dekatherms (Dth): A unit of energy equal to one million Btus.

Mbbls/d: One thousand barrels per day.

Mdth/d: One thousand dekatherms per day.

MMBtu: One million Btus.

MMcf/d: One million cubic feet per day.

MMdth: One million dekatherms or approximately one trillion Btus.

MMdth/d: One million dekatherms per day.

TBtu: One trillion Btus.

Other definitions:

FERC: Federal Energy Regulatory Commission.

Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane.

LNG: Liquefied natural gas. Natural gas which has been liquefied at cryogenic temperatures.

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.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest, including principally Discovery, Gulfstream, Laurel Mountain, Aux Sable, and Overland Pass Pipeline.

Pipeline Entities: Our regulated pipeline entities, including principally Northwest Pipeline, Transco, Gulfstream, Discovery, Overland Pass Pipeline, and Black Marlin Pipeline LLC.

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

 

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PART I

Items 1. Business

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 our Partially Owned Entities in which we own interests accounted for as equity investments that are not consolidated in our financial statements. When we refer to our Partially Owned Entities by name, we are referring exclusively to their businesses and operations.

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

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). 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 www.sec.gov.

Our Internet website is www.williamslp.com. We make available free of charge 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 under the “Corporate Responsibility” tab. 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 Corporate Secretary at Williams Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

GENERAL

We are a publicly traded Delaware limited partnership formed by The Williams Companies, Inc. (Williams) in 2005. We were formed to own, operate and acquire a diversified portfolio of complementary energy assets. We focus on natural gas transportation; gathering, treating, and processing; storage; NGL fractionation; and oil transportation. Williams owns an approximate 70 percent limited partnership interest in us and all of our 2 percent general partner interest.

Williams is an energy infrastructure company that trades on the New York Stock Exchange (NYSE) under the symbol “WMB.”

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

RECENT EVENTS

In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments and approximately 7.5 million of our common units. These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. This acquisition represents a strategic platform to enhance our expansion in the Marcellus Shale by providing our customers with both operational flow assurance and marketing flexibility. (See Results of Operations – Segments, Midstream Gas & Liquids.)

FINANCIAL INFORMATION ABOUT SEGMENTS

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

 

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BUSINESS SEGMENTS

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 two business segments:

 

   

Gas Pipeline — this segment includes our interstate natural gas pipelines and pipeline joint venture investments.

 

   

Midstream Gas & Liquids — this segment includes our natural gas gathering, treating and processing business and is comprised of several wholly owned and partially owned subsidiaries.

Detailed discussion of each of our business segments follows.

Gas Pipeline

We own and operate a combined total of approximately 13,700 miles of pipelines with a total annual throughput of approximately 3,000 TBtu of natural gas and peak-day delivery capacity of approximately 13 MMdth of natural gas. Gas Pipeline consists primarily of Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline). Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 49 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream).

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,800-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 11 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., New York, New Jersey and Pennsylvania.

Pipeline system and customers

At December 31, 2011, Transco’s system had a mainline delivery capacity of approximately 5.6 MMdth of natural gas per day from its production areas to its primary markets, including delivery capacity from the mainline to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 4.0 MMdth of natural gas per day for a system-wide delivery capacity total of approximately 9.6 MMdth of natural gas per day. Transco’s system includes 45 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.5 million horsepower.

Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers storage services and interruptible transportation services under short-term agreements.

Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas. At December 31, 2011, our customers had stored in our facilities approximately 164 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

 

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Transco expansion projects

The pipeline projects listed below were completed during 2011 or are future significant pipeline projects for which Transco has customer commitments.

Mobile Bay South II

The Mobile Bay South II Expansion Project involved the addition of compression at Transco’s Station 85 in Choctaw County, Alabama, and modifications to existing facilities at Transco’s Station 83 in Mobile County, Alabama, to allow Transco to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. The project was placed into service in May 2011 and provides incremental firm capacity of 380 Mdth/d.

85 North

The 85 North Expansion Project involved an expansion of Transco’s existing natural gas transmission system from Station 85 in Choctaw County, Alabama, to various delivery points as far north as North Carolina. The first phase was placed into service in July 2010 and provides incremental firm capacity of 90 Mdth/d, and the second phase was placed into service in May 2011 and provides incremental firm capacity of 219 Mdth/d.

Mid-South

The Mid-South Expansion Project involves an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama, to markets as far downstream as North Carolina. In August 2011, Transco received approval from the FERC. The capital cost of the project is estimated to be approximately $217 million. Transco plans to place the project into service in phases in September 2012 and June 2013, and it is expected to increase capacity by 225 Mdth/d.

Mid-Atlantic Connector

The Mid-Atlantic Connector Project involves an expansion of Transco’s mainline from an existing interconnection in North Carolina to markets as far downstream as Maryland. In July 2011, Transco received approval from the FERC. The capital cost of the project is estimated to be approximately $55 million. Transco plans to place the project into service in November 2012, and it is expected to increase capacity by 142 Mdth/d.

Northeast Supply Link

In December 2011, Transco filed an application with the FERC to expand its existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The capital cost of the project is estimated to be approximately $341 million. Transco plans to place the project into service in November 2013, and it is expected to increase capacity by 250 Mdth/d.

Rockaway Delivery Lateral

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to a distribution system in New York. Transco anticipates filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $182 million. Transco plans to place the project into service as early as April 2014, and its capacity is expected to be 647 Mdth/d.

Northeast Connector

The Northeast Connector Project involves expansion of Transco’s existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. Transco anticipates filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $39 million. Transco plans to place the project into service as early as April 2014, and it is expected to increase capacity by 100 Mdth/d.

 

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Northwest Pipeline

Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in California, Arizona, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon, and Washington directly or indirectly through interconnections with other pipelines.

Pipeline system and customers

At December 31, 2011, Northwest Pipeline’s system, having long-term firm transportation agreements including peaking service of approximately 3.8 MMdth/d, was composed of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 477,000 horsepower.

Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Northwest Pipeline’s firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.

Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for storage service in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working gas storage capacity of 13 Bcf of natural gas, which is substantially utilized for third-party natural gas, and firm delivery capability of approximately 700 MMcf/d enable Northwest Pipeline to provide storage services to its customers and to balance daily receipts and deliveries.

Northwest Pipeline expansion project

North and South Seattle Lateral Delivery Expansions

Northwest Pipeline has executed agreements with a customer to expand the North and South Seattle laterals and provide additional lateral capacity of approximately 84 Mdth/d and 74 Mdth/d, respectively. Northwest Pipeline estimates the expansion of the two laterals to cost between $28 million and $30 million. North Seattle is currently targeted for service in fall 2012 and South Seattle is currently targeted for service in fall 2013.

Gulfstream

Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. We own, through a subsidiary, a 49 percent interest in Gulfstream while Williams owns a 1 percent interest through a subsidiary. Spectra Energy Corporation, through its subsidiary, and Spectra Energy Partners, LP, owns the other 50 percent interest. We share operating responsibilities for Gulfstream with Spectra Energy Corporation.

Gulfstream Phase V

The Gulfstream Phase V expansion involved the addition of compression to provide 35 Mdth/d of incremental firm transportation capacity. The expansion was placed in service in April 2011.

 

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Midstream Gas & Liquids

Our Midstream Gas & Liquids segment (Midstream), one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico and Pennsylvania. The primary businesses are: (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; and (3) oil transportation. These fall within the middle of the process of taking raw natural gas and crude oil from the producing fields to the consumer.

Key variables for our business will continue to be:

 

   

Retaining and attracting customers by continuing to provide reliable services;

 

   

Revenue growth associated with additional infrastructure either completed or currently under construction;

 

   

Disciplined growth in our core service areas and new step-out areas;

 

   

Prices impacting our commodity-based activities.

Gathering, processing and treating

Our gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Our treating facilities remove water vapor, carbon dioxide and other contaminants and collect condensate, but do not extract NGLs. We are generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the BTU heating value.

In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide and other contaminants. NGL products include:

 

   

Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;

 

   

Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials and molded plastic parts;

 

   

Normal butane, iso-butane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.

  Our gas processing services generate revenues primarily from the following three types of contracts:

 

   

Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the BTU heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. For the year ended December 31, 2011, 59 percent of the NGL production volumes were under fee-based 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. NGLs we retain in connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity exposure to the difference between NGL prices and natural gas prices. For the year ended December 31, 2011, 38 percent of the NGL production volumes were under keep-whole contracts.

 

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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, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2011, 3 percent of the NGL production volumes were under percent-of-liquids contracts.

Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements.

Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Our gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding our infrastructure. During 2011, our facilities gathered and processed gas for approximately 210 customers. Our top 5 gathering and processing customers accounted for approximately 50 percent of our gathering and processing revenue.

Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks.

Geographically, our Midstream natural gas assets are positioned to maximize commercial and operational synergies with Williams’ and our other assets. For example, most of our offshore gathering and processing assets attach, and process or condition natural gas supplies delivered, to the Transco pipeline. Our San Juan basin, southwest Wyoming and Piceance systems are capable of delivering residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party interstate systems. Our gathering system in Pennsylvania delivers residue gas volumes into Transco’s pipeline in addition to third-party interstate systems.

We own and operate gas gathering, processing and treating assets within the states of Wyoming, Colorado, New Mexico and in Pennsylvania. We also own and operate gas gathering and processing assets and pipelines primarily within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

The following table summarizes our significant operated natural gas gathering assets as of December 31, 2011:

 

     Natural Gas Gathering Assets  
     Location      Pipeline
Miles
   Inlet
Capacity
(Bcf/d)
   Ownership
Interest
  Supply Basins  

Onshore

             

Rocky Mountain

     Wyoming       3,587    1.1    100%     Wamsutter & SW Wyoming   

Four Corners

     Colorado & New Mexico       3,823    1.8    100%     San Juan   

Piceance

     Colorado       328    1.4    100%     Piceance   

NE Pennsylvania (2)

     Pennsylvania       75    0.7    100%     Appalachian   

Laurel Mountain (1)

     Pennsylvania       1,386    0.2    51%     Appalachian   

Gulf Coast

             

Canyon Chief & Blind Faith

     Deepwater Gulf of Mexico       139    0.4    100%     Eastern Gulf of Mexico   

Seahawk

     Deepwater Gulf of Mexico       115    0.4    100%     Western Gulf of Mexico   

 

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Perdido Norte

     Deepwater Gulf of Mexico      105      0.3      100%   Western Gulf of Mexico

Offshore shelf & other

     Gulf of Mexico      46      0.2      100%   Eastern Gulf of Mexico

Offshore shelf & other

     Gulf of Mexico      245      0.9      100%   Western Gulf of Mexico

Discovery (1)

     Gulf of Mexico      319      0.6      60%   Central Gulf of Mexico

 

(1) Statistics reflect 100 percent of the assets from the equity method investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

 

(2) In the first quarter of 2012, our Springville gathering pipeline was put into service, initially providing an optional takeaway for 0.3 Bcf/d of gas gathered on our system in northeast Pennsylvania. Also in the first quarter of 2012, 0.3 Bcf/d of capacity was added from the Laser gathering system acquisition.

In addition we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and Louisiana which bring natural gas to specifications allowable by major interstate pipelines. At our Milagro treating facility, we also use gas-driven turbines to produce approximately 60 mega-watts per day of electricity which we primarily sell into the local electrical grid.

The following table summarizes our significant operated natural gas processing facilities as of December 31, 2011:

 

     Natural Gas Processing Facilities  
     Location      Inlet
Capacity
(Bcf/d)
     NGL
Production
Capacity
(Mbbls/d)
     Ownership
Interest
    Supply Basins  

Onshore

             

Opal

     Opal, WY         1.5        67        100     SW Wyoming   

Echo Springs

     Echo Springs, WY         0.7        58        100     Wamsutter   

Ignacio

     Ignacio, CO         0.5        23        100     San Juan   

Kutz

     Bloomfield, NM         0.2        12        100     San Juan   

Lybrook (2)

     Lybrook, NM         0.1        6        100     San Juan   

Willow Creek

     Rio Blanco County, CO         0.5        30        100     Piceance   

Parachute

     Garfield County, CO         1.4        7        100     Piceance   

Gulf Coast

             

Markham

     Markham, TX         0.5        45        100     Western Gulf of Mexico   

Mobile Bay

     Coden, AL         0.7        30        100     Eastern Gulf of Mexico   

Discovery (1)

     Larose, LA         0.6        32        60     Central Gulf of Mexico   

 

(1) Statistics reflect 100 percent of the assets from the equity method investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

 

(2) Our Lybrook plant has been idled as of January 2012. Gas previously processed at Lybrook has been redirected to our Ignacio plant.

Crude oil transportation and production handling assets

In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Our offshore floating production platforms provide centralized services to deepwater producers such as

 

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compression, separation, production handling, water removal and pipeline landings. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis.

The following table summarizes our significant crude oil transportation pipelines as of December 31, 2011:

 

     Crude Oil Pipelines  
     Pipeline
Miles
     Handling
Capacity
(Mbbls/d)
     Ownership
Interest
    Supply Basins  
          

Mountaineer & Blind Faith

     155        150        100     Eastern Gulf of Mexico   

BANJO

     57        90        100     Western Gulf of Mexico   

Alpine

     96        85        100     Western Gulf of Mexico   

Perdido Norte

     74        150        100     Western Gulf of Mexico   

The following table summarizes our production handling platforms as of December 31, 2011:

 

     Production Handling Platforms  
     Gas Inlet
Capacity
(MMcf/d)
     Crude/NGL
Handling
Capacity
(Mbbls/d)
     Ownership
Interest
    Supply Basins  

Devils Tower

     210        60        100     Eastern Gulf of Mexico   

Canyon Station

     500        16        100     Eastern Gulf of Mexico   

Discovery Grand Isle 115 (1)

     150        10        60     Central Gulf of Mexico   

 

(1) Statistics reflect 100 percent of the assets from the equity method investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

NGL marketing services

In addition to our gathering and processing operations, we market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery Producer Services LLC (Discovery). The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. Other than a long-term agreement to sell our equity NGLs transported on Overland Pass Pipeline to ONEOK Hydrocarbon L.P., the majority of sales are based on supply contracts of one year or less in duration. Sales to ONEOK Hydrocarbon L.P., accounted for 20 percent, 17 percent, and 10 percent of our consolidated revenues in 2011, 2010, and 2009, respectively.

Other operations

We own interests in and/or operate NGL fractionation and storage assets. These assets include a 50 percent interest in an NGL fractionation facility near Conway, Kansas with capacity of slightly more than 100 Mbbls/d and a 31.45 percent interest in another fractionation facility in Baton Rouge, Louisiana with a capacity of 60 Mbbls/d. We also own approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.

 

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We own approximately 115 miles of pipelines in the Houston Shipping Channel area which transport a variety of products including ethane, propane and other products used in the petrochemical industry.

We also own a 14.6 percent equity interest in Aux Sable Liquid Products L.P. (Aux Sable) and its Channahon, Illinois gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 102 Mbbls/d of extracted liquids into NGL products. Additionally, in June 2011, Aux Sable acquired an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.

Operated Equity Investments

Discovery

We own a 60 percent equity interest in and operate the facilities of Discovery. Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico.

Laurel Mountain

We own a 51 percent interest in a joint venture, Laurel Mountain Midstream, LLC (Laurel Mountain), in the Marcellus Shale located in western Pennsylvania. Laurel Mountain’s assets, which we operate, include a gathering system of nearly 1,400 miles of pipeline with a capacity of approximately 230 MMcf/d. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with some exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale. Construction is ongoing for numerous new pipeline segments and compressor stations, the largest of which is our Shamrock compressor station. The Shamrock compressor station currently has a capacity of 60 MMcf/d and is expandable to 350 MMcf/d.

Overland Pass Pipeline

We operate and own a 50 percent ownership interest in Overland Pass Pipeline Company LLC (OPPL). OPPL includes a 760-mile NGL pipeline from Opal, Wyoming, to the Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the Piceance and Denver-Joules basins in Colorado, respectively. Our equity NGL volumes from our two Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement. We plan to participate in the construction of a pipeline connection and capacity expansions expected to be complete in early 2013, to increase the pipeline’s capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.

Operating statistics

The following table summarizes our significant operating statistics for Midstream:

 

     2011      2010      2009  

Volumes: (1)

  

Gathering (Tbtu)

     1,377        1,262        1,370  

Plant inlet natural gas (Tbtu)

     1,592        1,599        1,342  

NGL production (Mbbls/d) (2)

     189        178        164  

NGL equity sales (Mbbls/d) (2)

     77        80        80  

Crude oil transportation (Mbbls/d) (2)

     105        94        109  

 

(1) Excludes volumes associated with partially owned assets such as our Discovery and Laurel Mountain investments that are not consolidated for financial reporting purposes.

 

(2) Annual average Mbbls/d.

 

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REGULATORY MATTERS

Gas Pipeline. Gas Pipeline’s interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA), as amended, and under the Natural Gas Policy Act of 1978, as amended, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, its accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit gas marketing functions.

Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are:

 

   

Costs of providing service, including depreciation expense;

 

   

Allowed rate of return, including the equity component of the capital structure and related income taxes;

 

   

Contract and volume throughput assumptions.

The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.

Pipeline Integrity Regulations

Transco and Northwest Pipeline have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, Transco and Northwest Pipeline have identified high consequence areas and developed baseline assessment plans. Transco and Northwest Pipeline are on schedule to complete the required assessments within required timeframes. Currently, we estimate the cost to complete the required initial assessments through 2012 and associated remediation will be primarily capital in nature and range between $25 million and $40 million for Transco and between $30 million and $35 million for Northwest Pipeline. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business, and, therefore, recoverable through our rates.

Midstream. For our Midstream segment, onshore gathering is subject to regulation by states in which we operate and offshore gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Of the states where Midstream gathers gas, currently only Texas actively regulates gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement. Although offshore gathering facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and in recent years the FERC has taken a broad view of offshore transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most offshore gathering facilities are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonowner shippers.”

 

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Midstream also owns interests in and operates two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect.

Midstream owns a 50 percent interest in and is the operator of OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.

See Note 15 of our Notes to Consolidated Financial Statements for further details on our regulatory matters.

ENVIRONMENTAL MATTERS

Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:

 

   

Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities and storage tanks;

 

   

Damage to facilities resulting from accidents during normal operations;

 

   

Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;

 

   

Blowouts, cratering and explosions.

In addition, we may be liable for environmental damage caused by former owners or operators of our properties.

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.

For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors – We are subject to risks associated with climate change and – Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental” and “Environmental Matters” in Note 15 of our Notes to Consolidated Financial Statements.

COMPETITION

Gas Pipeline. The natural gas industry has undergone significant change over the past two decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. More recently large reserves of shale gas have been discovered, in many cases much closer to major market centers. As a result, pipeline capacity is being used more efficiently and competition among pipeline suppliers to attach growing supply to market has increased.

 

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Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs, but the changes implemented at the state level have not required renegotiation of LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.

Many states have developed energy plans that require utilities to encourage energy saving measures and diversify their energy supplies to include renewable sources. This has lowered the growth of residential gas demand. However, due to relatively low prices of natural gas, demand for electric power generation has increased.

These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity from traditional producing areas. Future utilization of pipeline capacity will depend on these factors and others impacting both U.S. and global demand for natural gas.

Midstream Gas & Liquids. In our Midstream segment, we face regional competition with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, reliability, timeliness of services to be provided, pressure obligations and contract structure.

EMPLOYEES

We do not have any employees. We are managed and operated by the directors and officers of our general partner. At February 1, 2012, our general partner or its affiliates employed approximately 3,455 full-time employees, including 1,825 at Gas Pipelines and 1,630 at Midstream. Additionally, our general partner and its affiliates provide general and administrative services to us. For further information, please read “Directors, Executive Officers and Corporate Governance” and “Certain Relationships and Related Transactions, and Director Independence — Reimbursement of Expenses of our General Partner.”

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

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

 

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR

PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters.

All statements, other than statements of historical facts, included in this report that 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,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” or other similar expressions. These statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

 

   

Amounts and nature of future capital expenditures;

 

   

Expansion and growth of our business and operations;

 

   

Financial condition and liquidity;

 

   

Business strategy;

 

   

Cash flow from operations or results of operations;

 

   

The levels of cash distributions to unitholders;

 

   

Seasonality of certain business components;

 

   

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 report. Limited partner units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the risk factors discussed below in addition to the other information in this 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 will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

 

   

Whether we have sufficient cash from operations to enable us to maintain current levels of cash distributions or to pay cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner;

 

   

Availability of supplies, market demand, volatility of prices, and the availability and cost of capital;

 

   

Inflation, interest rates and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

 

   

The strength and financial resources of our competitors;

 

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Ability to acquire new businesses and assets and integrate those operations and assets into our existing businesses, as well as expand our facilities;

 

   

Development of alternative energy sources;

 

   

The impact of operational and development hazards;

 

   

Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), environmental liabilities, litigation and rate proceedings;

 

   

Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;

 

   

Changes in maintenance and construction costs;

 

   

Changes in the current geopolitical situation;

 

   

Our exposure to the credit risks of our customers and counterparties;

 

   

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, including cybersecurity threats and related disruptions;

 

   

Additional risks described in our filings with the Securities and Exchange Commission (SEC).

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

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

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

RISK FACTORS

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 cash from operations to enable us to make cash distributions or to maintain current levels of cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

 

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We may not have sufficient available cash from operating surplus each quarter to make cash distributions or maintain current levels of cash distributions. 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;

 

   

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;

 

   

Fluctuations in our working capital needs;

 

   

Our ability to borrow for working capital or other purposes;

 

   

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

 

   

The amount of cash that the Partially Owned Entities and our subsidiaries distribute 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 noncash 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.

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

A principal focus of our strategy is to continue to grow by expanding our business. Our future growth will depend upon 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 our 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.

 

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Prices for NGLs, natural gas, oil, and other commodities, including oil, are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses.

Our revenues, operating results, future rate of growth and the value of certain components of our businesses depend primarily upon the prices of NGLs, natural gas, oil, or other commodities, and the differences between prices of these commodities. Price volatility can impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Any of the foregoing can also have an adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to unitholders.

The markets for NGLs, natural gas and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including:

 

   

Worldwide and domestic supplies of and demand for natural gas, NGLs, oil, petroleum, and related commodities;

 

   

Turmoil in the Middle East and other producing regions;

 

   

The activities of the Organization of Petroleum Exporting Countries;

 

   

Terrorist attacks on production or transportation assets;

 

   

Weather conditions;

 

   

The level of consumer demand;

 

   

The price and availability of other types of fuels;

 

   

The availability of pipeline capacity;

 

   

Supply disruptions, including plant outages and transportation disruptions;

 

   

The price and quantity of foreign imports of natural gas and oil;

 

   

Domestic and foreign governmental regulations and taxes;

 

   

Volatility in the natural gas and oil markets;

 

   

The overall economic environment;

 

   

The credit of participants in the markets where products are bought and sold;

 

   

The adoption of regulations or legislation relating to climate change and changes in natural gas production from exploration and production areas that we serve.

We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.

Our portfolio of derivative and other energy contracts may consist of wholesale contracts to buy and sell commodities, including contracts for natural gas, NGLs and other commodities that are settled by the delivery of the commodity or cash throughout the United States. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain

 

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marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our businesses, we often extend credit to our counterparties. Despite performing credit analysis prior to extending credit, we are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral that secures our counterparty’s obligation is inadequate, we will suffer a loss. Downturns in the economy or disruptions in the global credit markets could cause more of our counterparties to fail to perform than we expect.

The long-term financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access, demand for those supplies in our traditional markets, and the prices of and market demand for natural gas.

The development of the additional natural gas reserves that are essential for our gas transportation and midstream businesses to thrive requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline systems. Low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transportation and processing facilities.

Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will also 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 the contracted capacity or the volume of natural gas transported on or gathered through our pipeline systems and cash flows associated with the gathering and transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas. In addition, if natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply areas, if natural gas supplies are diverted to serve other markets, if development in new supply basins where we do not have significant gathering or pipeline systems reduces demand for our services, or if environmental regulators restrict new natural gas drilling, the overall volume of natural gas transported, gathered and stored on our system would decline, which could have a material adverse effect on our business, financial condition and results of operations, and our ability to make cash distributions to unitholders. In addition, new LNG import facilities built near our markets could result in less demand for our gathering and transportation facilities.

Our risk management and measurement systems and hedging activities might not be effective and could increase the volatility of our results.

The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified.

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used and may in the future use fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For

 

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example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.

Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under generally accepted accounting principles (“GAAP”), to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.

The impact of changes in market prices for NGLs and natural gas on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for NGLs or natural gas were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss in certain circumstances, including instances in which:

 

   

Volumes are less than expected;

 

   

The hedging instrument is not perfectly effective in mitigating the risk being hedged;

 

   

The counterparties to our hedging arrangements fail to honor their financial commitments.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The final impact of the Dodd-Frank Act on our hedging activities is uncertain at this time due to the requirement that the SEC and the Commodities Futures Trading Commission (the “CFTC”) promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be impacted by position limits and should be exempt from the requirement to clear transactions through a central exchange or to post collateral, the impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC.

Depending on the rules and definitions adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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

 

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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 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. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. 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, and financial condition and our ability to make cash distributions to unitholders.

We are exposed to the credit risk of our customers and counterparties, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer and counterparty credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ and counterparties’ creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results in the periods in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows, and financial condition and our ability to make cash distributions to unitholders.

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

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, 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 transport, store or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues.

Any temporary or permanent interruption at any key pipeline interconnect or 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, and financial condition and our ability to make cash distributions to unitholders.

Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations.

Our businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings (either due to tighter rating standards or the negative impacts described above), which could reduce our access to credit markets, raise the cost of such access or require us to provide additional collateral to our

 

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counterparties. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.

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 adverse economic conditions.

Restrictions in our debt agreements and our leverage may affect our future financial and operating flexibility.

Our total outstanding long-term debt (including current portion) as of December 31, 2011, was $7.2 billion.

Our debt service obligations and restrictive covenants in our Credit Facility and 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 partnership purposes or other purposes;

 

   

Adversely affect our ability to pay cash distributions to unitholders;

 

   

Diminish our ability to withstand a continued or future 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 partnership purposes or other purposes;

 

   

Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

 

   

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.

Our debt agreements and Williams’ and our public indentures contain financial and operating restrictions that may limit our access to credit and affect our ability to operate our business. In addition, our ability to obtain credit in the future will be affected by Williams’ credit ratings.

 

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Our public indentures contain various covenants that, among other things, limit our ability to grant certain liens to support indebtedness, merge, or sell all or substantially all of our assets. In addition, our Credit Facility contains certain financial covenants and restrictions on our ability and our material subsidiaries’ ability to grant certain liens to support indebtedness, our ability to merge or consolidate or sell all or substantially all of our assets, or allow any material change in the nature of our business, enter into certain affiliate transactions and make certain distributions during the continuation of an event of default. 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 these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions 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.

Williams’ and our 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 and Williams’ control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ ability to comply with these covenants may be negatively impacted.

Our failure to comply with the covenants in our debt agreements 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. Certain payment defaults or an acceleration under our public indentures or other material indebtedness 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 our 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 — Management’s Discussion and Analysis of Financial Condition and Liquidity”.

Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans, dividends and distributions 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 loans or contributions to capital. Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. If Williams were to experience a deterioration in its credit standing or financial condition, our access to credit and our ratings could be adversely affected. Any future downgrading of a Williams credit rating would likely also result in a downgrading of our credit rating. A downgrading of a Williams credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

Our subsidiaries are not prohibited from incurring indebtedness by their organizational documents, which may affect our ability to make distributions to unitholders.

Our subsidiaries are not prohibited by the terms of their respective organizational documents from incurring indebtedness. If they were to incur significant amounts of indebtedness, such occurrence may inhibit their ability to make distributions to us. An inability by our subsidiaries to make distributions to us would materially and adversely affect our ability to make distributions to unitholders because we expect distributions we receive from our subsidiaries to represent a significant portion of the cash available to make cash distributions to unitholders.

A downgrade of our credit ratings could impact our liquidity, access to capital and our costs of doing business, and independent third parties outside of our control determine our credit ratings.

 

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A downgrade of our credit ratings 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 could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:

 

   

Economic downturns;

 

   

Deteriorating capital market conditions;

 

   

Declining market prices for natural gas, NGLs, oil, 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. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies and no assurance can be given that we will maintain our current credit ratings.

Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.

We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable. The following are some of the risks associated with acquisitions, including any completed or future acquisitions:

 

   

Some of the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;

 

   

We may assume liabilities that were not disclosed to us or that exceed our estimates;

 

   

We may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operationally, technical or financial problems;

 

   

Acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.

We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases (“GHGs”) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.

In addition, legislative and regulatory responses related to GHGs and climate change creates the potential for financial risk. The U.S. Congress and certain states have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions.

Numerous states and other jurisdictions have announced or adopted programs to stabilize and reduce GHGs. In 2009, the U.S. Environmental Protection Agency (“EPA”) issued a final determination that six GHGs are a threat to public safety and welfare. In 2011, the EPA implemented permitting for new and/or modified large sources of GHG emissions through the existing Prevention of Signification Deterioration permitting program. Additional direct regulation of GHG emissions in our industry may be implemented under other Clean Air Act programs, including the New Source Performance Standards program.

The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.

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

Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing and treating of natural gas and fractionation of NGLs, and as a result, we

 

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may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, Native American, and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

 

   

Clean Air Act (“CAA”), and analogous state laws, which impose obligations related to air emissions;

 

   

Clean Water Act (“CWA”), and analogous state laws, which regulate discharge of wastewaters and storm water from our facilities to state and federal waters, including wetlands;

 

   

Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

 

   

Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities;

 

   

Endangered Species Act (“ESA”), and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;

 

   

Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit plans to the federal government detailing how they will respond to large discharges, regulates petroleum storage tanks and related equipment, and imposes liability for spills on responsible parties.

Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, 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, the imposition of stricter conditions on or revocation of permits, and the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.

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 as they are gathered, transported, processed, fractionated and stored, air emissions related to our operations, historical industry operations, and waste and 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 CERCLA, RCRA, and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil 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 and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, 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.

In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. To address its concerns regarding the pollution risks raised by new techniques for oil and gas extraction and coal mining, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. We cannot predict what the results of this initiative would be, or whether federal, state, or local laws or regulations will be enacted in this area. If regulations were imposed related to oil and gas extraction, the volumes of natural gas that we transport could decline and our results of operations could be adversely affected.

 

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Our business may be adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

Hydraulic fracturing is exempt from federal regulation pursuant to the federal Safe Drinking Water Act (except when the fracturing fluids or propping agents contain diesel fuels). However, public concerns have been raised related to its potential environmental impact. Additional federal, state and local laws and regulations to more closely regulate hydraulic fracturing have been considered or implemented. Legislation to further regulate hydraulic fracturing has been proposed in Congress. The U.S. Department of Interior has announced plans to formalize obligations for disclosure of chemicals associated with hydraulic fracturing on federal lands. The results of a pending EPA investigation by a committee of the House of Representatives and two recent reports by the U.S. Department of Energy’s Shale Gas Subcommittee could lead to further restrictions on hydraulic fracturing. The EPA has proposed regulations under the CAA regarding certain emissions from the hydraulic fracturing of oil and natural gas wells and announced its intention to propose regulations by 2014 under the CWA regarding wastewater discharges from hydraulic fracturing and other gas production. In addition, some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including additional permit requirements, operational restrictions, disclosure obligations and temporary or permanent bans on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. We cannot predict whether any additional federal, state or local laws or regulations will be enacted in this area and if so, what their provisions would be. If additional levels of reporting, regulation or permitting moratoria were required or imposed related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process and treat could decline and our results of operations could be adversely affected.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions and expectations may also change, and any new capital costs incurred to comply with such changes may not be recoverable under our regulatory rate structure or our customer contracts. In addition, new environmental laws and regulations might adversely affect our products and activities, including fractionation, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability.

Our assets and operations can be adversely affected by weather and other natural phenomena.

Our assets and operations, including those located offshore, can be adversely affected by hurricanes, floods, earthquakes, landslides, 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 have been unable to obtain insurance on commercially reasonable terms or insurance has not been available at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to unitholders.

 

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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.

We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. If we lost any of these key customers or producers or contracted volumes, our revenues and cash available to pay distributions could decline.

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. The loss of all, or even a portion of, the revenues from natural gas, NGLs or contracted volumes, as applicable, supplied by these customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts 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 do not own all of the interests in Partially Owned Entities, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.

Because we do not control the Partially Owned Entities, we may have limited flexibility to control the operation of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. At December 31, 2011, our investments in the Partially Owned Entities accounted for approximately 10 percent of our total consolidated 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.

Significant prolonged changes in natural gas prices could affect supply and demand, cause a reduction in or termination of the long-term transportation and storage contracts or throughput on the Pipeline Entities’ systems, and adversely affect our cash available to make distributions.

Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in the Pipeline Entities’ long-term transportation and storage contracts or throughput on their respective systems. 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 their systems. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and cash flows, and on our ability to make cash distributions to unitholders.

Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of these ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current

 

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legal proceedings or other matters against us including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us, our facilities or our customers, and future changes in laws and regulations could have a material adverse effect on our financial condition, results of operations and ability to make cash distributions to unitholders. For example, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed recently, including the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 enacted on January 3, 2012. This law will result in the promulgation of new regulations to be administered by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) affecting the operations of our Pipeline Entities including, but not limited to, requirements relating to pipeline inspection, installation of additional valves and other equipment and records verification. These reforms and any future changes in related laws and regulations could significantly increase our costs.

The 2010 drilling moratorium in the Gulf of Mexico and potentially more stringent regulations and permitting requirements on drilling in the Gulf of Mexico could adversely affect our operating results, financial condition and cash available to make distributions.

The drilling moratorium in the Gulf of Mexico (in force from May to October 2010) impacted our production handling, gathering and transportation operations through production delays which reduced volumes of natural gas and oil delivered to our platform, pipeline and gathering facilities in 2010. In addition, the Bureau of Ocean Energy Management, Regulation and Enforcement continues to develop more stringent drilling and permitting requirements for producers in the Gulf of Mexico which could cause delays in production or new drilling. A significant decline or delay in production volumes in the Gulf of Mexico could adversely affect our operating results, financial condition and cash available to make distributions through reduced production handling activities, gathering and transportation volumes, processing activities or other midstream services.

The Pipeline Entities’ natural gas sales, transportation and storage operations are subject to regulation by FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.

The Pipeline Entities’ natural gas sales, transmission and storage operations are subject to federal, state and local regulatory authorities. Specifically, their interstate pipeline transportation and storage service is subject to regulation by the 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 service;

 

   

The types of services the Pipeline Entities may offer to their customers;

 

   

Certification and construction of new interstate pipelines and storage facilities;

 

   

Acquisition, extension, disposition or abandonment of existing interstate pipelines and storage facilities;

 

   

Accounts and records;

 

   

Depreciation and amortization policies;

 

   

Relationships with affiliated companies who are involved in marketing functions of the natural gas business;

 

   

Market manipulation in connection with interstate sales, purchases or transportation of natural gas.

 

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Under the Natural Gas Act (“NGA”), FERC has authority to regulate providers of natural gas pipeline transportation and storage 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.

Regulatory actions in these areas can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our pipeline business.

Unlike other interstate pipelines that own facilities in the offshore Gulf of Mexico, Transco charges its transportation customers a separate fee to access its offshore facilities. The separate charge is referred to as an “IT feeder” charge. The “IT feeder” rate is charged only when gas is actually transported on the facilities and typically it is paid by producers or marketers. Because the “IT feeder” rate is typically paid by producers and marketers, it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. This rate design disparity could result in producers bypassing Transco’s offshore facilities in favor of alternative transportation facilities.

The rates, terms and conditions for the Pipeline Entities’ interstate pipeline services are set forth in their respective FERC-approved tariffs. Any successful complaint or protest against the Pipeline Entities’ rates could have an adverse impact on their revenues associated with providing transportation services.

The Pipeline Entities could be subject to penalties and fines if they fail to comply with laws governing our business.

The Pipeline Entities’ operations are regulated by numerous governmental agencies including the FERC, the EPA and PHMSA. Should the Pipeline Entities fail to comply with all applicable statutes, rules, regulations and orders, they could be subject to substantial penalties and fines. For example, under the Energy Policy Act of 2005, the 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 and under the recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has civil penalty authority up to $200,000 per day (from the prior $100,000), with a maximum of $2 million for any related series of violations (from the prior $1 million). Any material penalties or fines under these or other statutes, rules, regulations or orders could have a material adverse impact on the Pipeline Entities’ business, financial condition, results of operations and cash flows, and on our ability to make cash distributions to unitholders.

The outcome of future rate cases to set the rates the Pipeline Entities can charge customers on their respective pipelines might result in rates that lower their return on the capital invested in those pipelines.

There is a risk that rates set by FERC in the Pipeline Entities’ future rate cases 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 will cause their customers to look for alternative ways to transport their natural gas.

Our costs of testing, maintaining or repairing our facilities may exceed our expectations and the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.

We have experienced leaks and ruptures on one of our gas pipeline systems, including a rupture near Appomattox, Virginia in 2008 and a rupture near Sweet Water, Alabama in 2011. We could experience additional unexpected leaks or ruptures on our gas pipeline systems, or be required by regulatory authorities to test or undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the costs of testing, maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service. For example, in response to a recent third party pipeline rupture, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. More recently, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 became law and under this statute PHMSA may issue additional regulations

 

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addressing such records. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines.

Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial impact on us.

We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, Williams and its other affiliates may not be limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative energy sources.

The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to make cash distributions to unitholders.

We may not be able to maintain or replace expiring natural gas transportation and storage contracts at favorable rates or on a long-term basis.

Our primary exposure to market risk for our gas pipelines occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Upon expiration of the terms, we may not be able to extend contracts with existing customers to obtain replacement contracts at favorable rates or on a long-term basis.

The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

 

   

The level of existing and new competition to deliver natural gas to our markets;

 

   

The growth in demand for natural gas in our markets;

 

   

Whether the market will continue to support long-term firm contracts;

 

   

Whether our business strategy continues to be successful;

 

   

The level of competition for natural gas supplies in the production basins serving us;

 

   

The effects of state regulation on customer contracting practices.

 

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Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and cash flows and our ability to make cash distributions to unitholders.

Competitive pressures could lead to decreases in the volume of natural gas contracted or transported through the Pipeline Entities’ pipeline systems.

Although most of the Pipeline Entities’ pipeline systems’ current capacity is fully contracted, FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. 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, and our ability to make cash distributions to unitholders.

Certain of the Pipeline Entities’ services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

The Pipeline Entities provide some services pursuant to long-term, fixed price contracts. It is possible that costs to perform services under such contracts will exceed the revenues they collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

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

There are operational risks associated with the gathering, transporting, storage, 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;

 

   

Aging infrastructure and mechanical problems;

 

   

Damages to pipelines and pipeline blockages or other pipeline interruptions;

 

   

Uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial chemicals;

 

   

Collapse or failure of storage caverns;

 

   

Operator error;

 

   

Damage caused by third party activity, such as operation of construction equipment;

 

   

Pollution and other environmental risks;

 

   

Fires, explosions, craterings and blowouts;

 

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Risks related to truck and rail loading and unloading;

 

   

Risks related to operating in a marine environment;

 

   

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 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.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.

Williams currently maintains excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.

Although we maintain property insurance on certain physical assets that we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss is due to a named windstorm event and coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured it could adversely affect our operations and financial condition.

In addition to the insurance coverage described above, Williams is a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured of OIL, Williams shares in the losses among other OIL members even if its property is not damaged. As a result, we may share in any losses incurred by Williams.

Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.

The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows, and our ability to repay our debt and make cash distributions to unitholders.

Execution of our capital projects subjects us to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.

 

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Our growth may be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines and facilities or NGL 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;

 

   

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 cash distributions to unitholders.

Our operating results for certain components of our business might fluctuate on a seasonal and quarterly basis.

Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.

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

Williams and other third parties operate certain 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, and financial condition and our ability to make cash distributions to unitholders.

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

We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, 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. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We may not have the right of eminent domain over land owned by Native American tribes. 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.

 

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Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.

Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, and companies’ relationships with their independent public accounting firms. 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 SEC or FERC could enact new accounting standards or FERC could issue rules 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, and financial condition and our ability to make cash distributions to unitholders.

Institutional knowledge residing with current employees nearing retirement eligibility or with employees going to WPX as part of the separation of our exploration and production business might not be adequately preserved.

In certain areas of our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, or with the loss of employees as part of the separation of our exploration and production business, 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.

Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.

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 service providers 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 and financial condition.

Some studies indicate a high failure rate of outsourcing relationships. 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 such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.

Certain of our accounting and information technology services are currently provided by an 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.

Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

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, NGLs 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.

 

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Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.

We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access, physical locations, or information otherwise known as “social engineering.”

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

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 has limited fiduciary duties, and it and its affiliates may have conflicts of interest with us and our unitholders, and our general partner and its affiliates may favor their 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 certain of its affiliates. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us, the directors and officers of our general partner also 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, 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 the best interests of us and our unitholders;

 

   

All of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and certain of its affiliates, 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 an approximate 70 percent limited partner interest in us, and if a vote of limited partners is required in which Williams is entitled to vote, Williams will be able to vote its units in accordance with its own interests, which may be contrary to our interests or the interests of our unitholders;

 

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All of the executive officers and certain of the directors of our general partner will devote significant time to our business and/or the business of Williams, and will be compensated by Williams for the services rendered to them;

 

   

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 and, in some instances, with the concurrence of the conflicts committee of its board of directors, 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 itself as 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 has limited liability regarding our contractual and other obligations and in some circumstances is required to be indemnified by us;

 

   

Pursuant to our partnership agreement, our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of our outstanding common units;

 

   

Our general partner controls the enforcement of obligations owed to us by it and its affiliates;

 

   

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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

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

 

   

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;

 

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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 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 respective 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 or, in the case of a criminal matter, acted with knowledge that such conduct was criminal;

 

   

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 our partnership agreement, including the provisions discussed above.

Affiliates of our general partner, including Williams, 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 these persons will also owe fiduciary duties to Williams.

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 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 certain of its affiliates and will owe fiduciary duties to those entities as well as our unitholders and us.

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Williams and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. 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.

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

 

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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 distributions to unitholders. Furthermore, Williams, which owns our general partner, recently completed the separation of its exploration and production business into a newly formed separate publicly-traded corporation. The spin-off of Williams’ exploration and production business is expected to increase the costs of the general and administrative services provided to us. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

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

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

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding common units is required to remove our general partner. Our general partner and its affiliates currently own approximately 71 percent of our outstanding common units and, as a result, our public unitholders cannot remove our general partner without its consent.

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

We have a holding company structure, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in these 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 would be able to borrow funds to make distributions on our common units.

Our allocation from Williams for costs for its defined benefit pension plans and other postretirement benefit plans are affected by factors beyond our and Williams’ control.

As we have no employees, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs in defined benefit pension plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of the costs 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 and results of operations.

 

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

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement effectively permits a change of control without unitholder consent.

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

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

 

   

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;

 

   

The relative voting strength of each previously outstanding unit may be diminished;

 

   

The market price of the common units may decline.

Common units held by Williams eligible for future sale may adversely affect the price of our common units.

As of December 31, 2011, Williams held 217,095,249 common units, representing an approximate 73 percent 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.

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

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80 percent 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 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 under the Exchange Act, we would no longer be subject to the reporting requirements of such Act.

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

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees, transferees of their transferees (provided that our general partner has notified such secondary transferees that the voting limitation shall not apply to them), 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.

 

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

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

 

   

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.

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

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

Tax Risks

Our tax treatment depends on our status as a partnership for U.S. 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 (the “IRS”) were to treat us as a corporation for U.S. federal income tax purposes 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 U.S. federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for U.S. federal income tax purposes unless it satisfies a “qualifying income” requirement. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

Failing to meet the qualifying income requirement or a change in current law may cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35 percent, 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.

 

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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 U.S. federal, state or local income tax purposes, then the levels of distributions at which our general partner will receive increasing percentages of the cash we distribute will be adjusted to reflect the impact of that law on us.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. The Obama administration and members of Congress have recently considered substantive changes to the existing U.S. federal income tax laws that affect certain publicly traded partnerships. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or 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.

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 although the U.S. Treasury Department issued proposed Treasury regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

An IRS contest of the U.S. federal income tax positions we take may adversely impact the market for the common units, and the costs of any contest will reduce our cash available for distribution to our unitholders and our general partner.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for U.S. 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 U.S. 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.

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

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, unitholders will be required to pay U.S. 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.

 

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

If a unitholder sells its common units, it will recognize gain or loss for U.S. federal income tax purposes 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 the original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our non-recourse liabilities, if a unitholder sells its common units, the unitholder may incur a U.S. federal income tax liability in excess of the amount of cash it received from the sale.

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

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), 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 U.S. 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 U.S. federal income tax returns and pay U.S. federal income tax on their share of our taxable income.

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

Because we cannot match transferors and transferees of common units, we have adopted 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 U.S. federal income tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholder tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to U.S. 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 U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

The sale or exchange of 50 percent or more of the total interest in our capital and profits within a 12-month period will result in a termination of our partnership for U.S. federal income tax purposes.

We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50 percent 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 partners, which would result

 

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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 U.S. 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. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to its partners for the tax years in the fiscal year during which the termination occurs.

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

When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our partners. 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 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 Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our partners.

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 2. Properties

Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others.

Item 3. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

In September 2007, the EPA requested, and our Transco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of Transco’s compliance with the Clean Air Act. On March 28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland.

 

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In February 2012, the New Mexico Environmental Department and Williams Four Corners LLC settled alleged violations of the New Mexico Air Quality Act at five separate facilities that we own or operate for $164,000.

In September 2011, the Colorado Department of Public Health and Environment proposed a penalty of $301,000 for alleged violations of the Colorado Clean Water Act related to excavation work being done for our Crawford Trail Pipeline. Under a settlement reached with the agency in November 2011, we agreed to pay $44,300 and undertake certain supplemental environmental projects, valued at $230,700.

Other

The additional information called for by this item is provided in Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements of this report, which information is incorporated by reference into this item.

Item 4. Mine Safety Disclosures

Not applicable.

 

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information, Holders and Distributions

Our common units are listed on the NYSE under the symbol “WPZ.” At the close of business on February 14, 2012, there were 297,477,159 common units outstanding, held by approximately 72,274 record holders and holders in street name, including common units held by affiliates of Williams. In addition, our general partner holds all of our 2 percent general partner interest and incentive distribution rights. On February 17, 2012, we issued an additional 7,531,381 of our common units to Delphi Midstream Partners, LLC in connection with our acquisition of the Laser Gathering System.

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

 

                   Cash Distribution  
     High      Low      per Unit(a)  

2011

        

Fourth Quarter

   $ 61.22      $ 49.11      $ 0.7625  

Third Quarter

     57.32        45.39        0.7475  

Second Quarter

     56.61        48.25        0.7325  

First Quarter

     52.00        44.81        0.7175  

2010

        

Fourth Quarter

   $ 48.99      $ 42.30      $ 0.7025  

Third Quarter

     48.95        41.32        0.6875  

Second Quarter

     44.15        34.62        0.6725  

First Quarter

     42.35        30.01        0.6575  

 

(a) Represents cash distributions attributable to the quarter and declared and paid within 45 days after quarter end. We paid cash distributions to our general partner with respect to its general partner interest and incentive distribution rights that totaled $302 million and $203 million for the 2011 and 2010 periods, respectively. The quarterly distribution with respect to the first quarter of 2010 on the Class C units and the additional general partner units issued in connection with Williams’ contribution of ownership interests in certain entities to us in February 2010 were prorated to reflect that these interests were not outstanding during the full quarterly period.

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

 

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made. Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions made pursuant to a credit facility or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year for an economically meaningful period of time.

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

 

   

First, 98 percent to all unitholders, pro rata, and 2 percent to our general partner, until each outstanding 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.

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 percent 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—Management’s Discussion and Analysis of Financial Condition and Liquidity.”

 

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Item 6. Selected Financial Data

The following financial data at December 31, 2011 and 2010 and for each of the three years in the period ended December 31, 2011, should be read in conjunction with Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.

 

     2011      2010      2009      2008      2007  
     (Millions, except per-unit amounts)  

Revenues

   $ 6,729      $ 5,715      $ 4,602      $ 5,847      $ 5,684  

Net income

     1,378        1,101        1,036        2,108        1,462  

Net income attributable to controlling interests

     1,378        1,085        1,009        2,083        1,462  

Net income per limited partner unit:

              

Common unit

     3.69        2.66        2.88        3.08        1.99  

Subordinated unit

     N/A         N/A         N/A         N/A         1.99  

Total assets at December 31

     14,380        13,404        12,475        12,167        11,419  

Short-term notes payable and long-term debt due within one year at December 31

     324        458        15        —           75  

Long-term debt at December 31 (1)

     6,913        6,365        2,981        2,971        2,821  

Total equity at December 31

     5,228        5,076        8,103        7,867        6,215  

Cash dividends declared per unit

     2.900        2.653        2.540        2.435        2.045  

 

(1) The increase in 2010 reflects borrowings entered into related to an acquisition of certain businesses from Williams.

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and natural gas liquids. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into two business segments: Gas Pipeline and Midstream Gas & Liquids (Midstream).

 

   

Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of approximately 13,700 miles of pipelines. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 49 percent interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), which owns an approximate 745-mile pipeline.

 

   

Midstream includes natural gas gathering, processing and treating facilities, and crude oil gathering and transportation facilities with primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, and Pennsylvania.

As of December 31, 2011, The Williams Companies, Inc. (Williams) holds an approximate 75 percent interest in us, comprised of an approximate 73 percent limited partner interest and all of our 2 percent general partner interest.

Distributions

In the months of April, July, and October of 2011, and in January 2012, our general partner’s Board of Directors approved approximately a 2 percent increase in our quarterly distribution to unitholders. (See Management’s Discussion and Analysis of Financial Condition and Liquidity.)

Overview

Crude oil and NGL prices increased in 2011, while natural gas prices have remained relatively low. We have benefited from this environment as our Net Income for 2011 increased by $277 million compared to 2010, primarily due to improved natural gas liquids (NGL) margins partially offset by higher interest expense associated with increased debt levels in conjunction with the 2010 contribution of subsidiaries from our general partner. (See Results of Operations – Consolidated Overview.)

Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth, as highlighted by the following accomplishments during 2011 through the present:

 

   

In October 2011, we executed an agreement with two significant producers to provide certain production handling services in the eastern deepwater Gulf of Mexico. We will design, construct and install a floating production system (Gulfstar FPS) that will have the capacity to handle 60 thousand barrels per day (Mbbls/d) of oil, up to 200 million cubic feet per day (MMcf/d) of natural gas, and the capability to provide seawater injection services. We expect Gulfstar FPS to be placed into service in 2014 and to be capable of serving as a central host facility for other deepwater prospects in the area. (See Results of Operations – Segments, Midstream Gas & Liquids.)

 

   

During 2011, we placed into service expansions of a natural gas transmission system, compression facilities, and line facilities that provide an aggregate additional 599 Mdth/d of incremental firm capacity. We also filed an application with the FERC to increase capacity by 250 Mdth/d by expanding our natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. (See Results of Operations – Segments, Gas Pipeline.)

 

   

In January 2012, we placed into service our Springville pipeline that will allow us to initially deliver approximately 300 MMcf/d into the Transco pipeline and full use of approximately 650 MMcf/d of capacity from various compression and dehydration expansion projects to our gathering business in Pennsylvania’s Marcellus Shale. (See Results of Operations – Segments, Gas Pipeline.)

 

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Discovery, an equity method investee in which we own 60 percent and operate, announced in January 2012 that it signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the central deepwater Gulf of Mexico. To provide these services Discovery plans to construct a new deepwater pipeline which will have the capacity to flow approximately 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. (See Results of Operations – Segments, Midstream Gas & Liquids.)

 

   

In January 2012, we completed an equity issuance of 7 million common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, the underwriters exercised their option to purchase an additional 1.05 million common units for $62.81 per unit, with expected settlement on February 28, 2012. The proceeds will be used to fund capital expenditures and for other general partnership purposes.

 

   

In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC for $325 million in cash, net of cash acquired in the transaction, and approximately 7.5 million of our common units. These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. (See Results of Operations – Segments, Midstream Gas & Liquids.)

 

   

In February 2012, we announced a new interstate gas pipeline joint venture with Cabot Oil & Gas Corporation. The new 120-mile Constitution Pipeline will connect Williams Partners’ gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We will own 75 percent of Constitution Pipeline. This project, along with the newly acquired Laser Gathering System and our Springville pipeline are key steps in Williams Partners’ strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania.

Outlook for 2012

We believe we are well-positioned to continue to execute on our 2012 business plan and to further realize our growth opportunities. Economic and commodity price indicators for 2012 and beyond reflect continued improvement in the economic environment. However, these measures can be volatile and it is reasonably possible that the economy could worsen and/or commodity prices could decline, negatively impacting our future operating results.

Our business plan for 2012 includes planned capital and investment expenditures of more than $2.7 billion, of which we expect to fund a significant portion through debt and equity issuances. Our structure is designed to drive lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. We expect to realize our growth opportunities through these continued investments in our businesses in a way that meets customer needs and enhances our competitive position by:

 

   

Continuing to invest in and grow our gathering and processing and interstate natural gas pipeline systems;

 

   

Retaining the flexibility to adjust, to some extent, our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

  Potential risks and obstacles that could impact the execution of our plan include:

 

   

Availability of capital;

 

   

General economic, financial markets, or industry downturn;

 

   

Lower than anticipated energy commodity margins;

 

   

Lower than expected levels of cash flow from operations;

 

   

Counterparty credit and performance risk;

 

   

Decreased volumes from third parties served by our midstream business;

 

   

Changes in the political and regulatory environments;

 

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Physical damages to facilities, especially damage to offshore facilities by named windstorms.

We continue to address these risks through disciplined investment strategies, commodity hedging strategies, and maintaining ample liquidity from cash and cash equivalents and unused revolving credit facility capacity.

Williams incurs certain corporate general and administrative costs which are charged to its business segments, including us. We expect an increase in our proportionate share of these costs in 2012, due in part to Williams’ spin-off of its former exploration and production business, which was completed on December 31, 2011.

Accounting Pronouncements Issued But Not Yet Adopted

Accounting pronouncements that have been issued but not yet adopted may have an effect on our Consolidated Financial Statements in the future.

See Accounting Standards Issued But Not Yet Adopted in Note 1 of Notes to Consolidated Financial Statements for further information on recently issued accounting standards.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions, which may involve subjectivity and judgment and/or are susceptible to change. We have reviewed the subjective and judgmental accounting estimates and assumptions used in the preparation of our financial statements and determined that we have no such critical accounting estimates. We have reviewed this determination with the Audit Committee of the Board of Directors of our general partner. We believe that none of these estimates and assumptions is material to our financial condition or results of operations.

 

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2011. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 

     Years Ended December 31,  
           $ Change      % Change           $ Change      % Change        
           from      from           from      from        
     2011     2010*      2010*     2010     2009*      2009*     2009  
     (Millions)  

Revenues

   $ 6,729       +1,014        +18   $ 5,715       +1,113        +24   $ 4,602  

Costs and expenses:

                

Costs and operating expenses

     4,672       -688        -17     3,984       -884        -29     3,100  

Selling, general and administrative expenses

     290       -9        -3     281       +19        +6     300  

Other (income) expense — net

     13       -28        NM        (15     -19        -56     (34

General corporate expenses

     112       +13        +10     125       -16        -15     109  
  

 

 

        

 

 

        

 

 

 

Total costs and expenses

     5,087            4,375            3,475  
  

 

 

        

 

 

        

 

 

 

Operating income

     1,642            1,340            1,127  

Equity earnings

     142       +33        +30     109       +28        +35     81  

Interest accrued — net

     (415     -51        -14     (364     -163        -81     (201

Interest income

     2       -2        -50     4       -16        -80     20  

Other income (expense) — net

     7       -5        -42     12       +3        +33     9  
  

 

 

        

 

 

        

 

 

 

Net income

     1,378            1,101            1,036  

Less: Net income attributable to noncontrolling interests

     —          +16        +100     16       +11        +41     27  
  

 

 

        

 

 

        

 

 

 

Net income attributable to controlling interests

   $ 1,378          $ 1,085          $ 1,009  
  

 

 

        

 

 

        

 

 

 

 

* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

2011 vs. 2010

The increase in revenues is primarily due to higher marketing and NGL production revenues at Midstream resulting from higher average energy commodity prices, partially offset by lower equity NGL volumes. Additionally, fee revenues increased at Midstream primarily due to higher gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired in late 2010 and the Piceance basin as a result of an agreement executed in November 2010. Gas Pipeline transportation revenues increased primarily due to expansion projects placed in service in 2010 and 2011.

The increase in costs and operating expenses is primarily due to increased marketing purchases at Midstream primarily resulting from higher average energy commodity prices. Additionally, operating costs increased primarily due to higher maintenance and higher depreciation costs. These increases are partially offset by decreased costs associated with production of NGLs reflecting lower average natural gas prices and lower equity NGL volumes at Midstream.

 

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The unfavorable change in other (income) expense – net within operating income primarily reflects:

 

   

$15 million of lower involuntary conversion gains in 2011 as compared to 2010 at Midstream due to insurance recoveries that are in excess of the carrying value of assets;

 

   

The absence of a $12 million gain in 2010 on the sale of part of our ownership interest in certain Piceance gathering assets at Midstream;

 

   

$4 million lower sales of base gas from Hester Storage Field in 2011 compared to 2010 at Gas Pipeline.

Partially offsetting the unfavorable change is $10 million related to the reversal of project feasibility costs from expense to capital in 2011 at Gas Pipeline (see Note 5 of Notes to Consolidated Financial Statements).

The decrease in general corporate expenses is primarily due to the absence of $12 million of outside services incurred in 2010 related to certain businesses acquired from our general partner.

The increase in operating income generally reflects an improved energy commodity price environment in 2011 compared to 2010 and increased fee revenues, partially offset by higher operating costs and an unfavorable change in other (income) expense – net as previously discussed.

Equity earnings increased primarily due to a $21 million increase from Gulfstream as a result of an increased ownership interest at Gas Pipeline and a $14 million increase from the 2010 acquisition of an additional interest in Overland Pass Pipeline Company LLC (OPPL) at Midstream.

The increase in interest accrued – net is primarily due to the $3.5 billion of senior notes issued in February 2010 and $600 million of senior notes issued in November 2010. In addition, 2010 project completions at Midstream contributed to a decrease in interest capitalized.

Net income attributable to noncontrolling interest decreased due to the merger with Williams Pipeline Partners L.P. (WMZ), which was completed in the third quarter of 2010.

2010 vs. 2009

The increase in revenues is primarily due to higher marketing and NGL production revenues resulting from higher average energy commodity prices and higher fee revenues primarily due to higher gathering revenue in the Piceance basin at Midstream.

The increase in costs and operating expenses is primarily due to increased marketing purchases and NGL production costs from higher average energy commodity prices at Midstream.

Other (income) expense – net within operating income in 2009 includes a $40 million gain on the sale of our Cameron Meadows NGL processing plant at Midstream.

General corporate expenses in 2010 include $12 million of outside services as discussed above.

The increase in operating income generally reflects an improved energy commodity margin environment in 2010 compared to 2009 and increased gathering-related fee revenues. The favorable change is partially offset by outside services incurred related to certain businesses acquired from our general partner and an unfavorable change in other (income) expense – net.

The increase in equity earnings is primarily due to a $10 million increase from Discovery, a $10 million increase from Aux Sable Liquid Products LP (Aux Sable) and equity earnings of $5 million from our increased investment in OPPL in 2010 at Midstream.

Interest accrued – net increased primarily due to the $3.5 billion of senior notes that were issued in February 2010 in conjunction with certain businesses acquired from our general partner.

Interest income decreased due primarily to reduced advances to affiliates and lower average interest rates in 2010 compared to 2009.

Net income attributable to noncontrolling interests decreased due to the merger with WMZ, which was completed in the third quarter of 2010.

 

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Results of Operations — Segments

Gas Pipeline

Overview

Gas Pipeline’s strategy to create value focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.

Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

Significant events of 2011 include:

Completed Expansion Projects

85 North

In September 2009, we received approval from the FERC to construct an expansion of our existing natural gas transmission system from Alabama to various delivery points as far north as North Carolina. Phase I was placed into service in July 2010 and it provides 90 thousand dekatherms per day (Mdth/d) of incremental firm capacity. Phase II was placed into service in May 2011 and it provides 219 Mdth/d of incremental firm capacity.

Mobile Bay South II

In July 2010, we received approval from the FERC to construct additional compression facilities and modifications to existing Mobile Bay line facilities in Alabama allowing transportation service to various southbound delivery points. The project was placed into service in May 2011 and provides incremental firm capacity of 380 Mdth/d.

In-progress Expansion Projects

Mid-South

In August 2011, we received approval from the FERC to upgrade compressor facilities and expand our existing natural gas transmission system from Alabama to markets as far north as North Carolina. The cost of the project is estimated to be $217 million. The project is expected to be phased into service in September 2012 and June 2013, with an expected increase in capacity of 225 Mdth/d.

Mid-Atlantic Connector

In July 2011, we received approval from the FERC to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The cost of the project is estimated to be $55 million and is expected to increase capacity by 142 Mdth/d. We plan to place the project into service in November 2012.

Northeast Supply Link

In December 2011, we filed an application with the FERC to expand our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The cost of the project is estimated to be $341 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in November 2013.

 

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Gulfstream acquisition

In May 2011, we acquired from Williams an additional 24.5 percent interest in Gulfstream in exchange for aggregate consideration of $297 million of cash, 632,584 limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. We funded the cash consideration for this transaction through our credit facility.

Eminence Storage Field Leak

On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers.

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. We estimate the total abandonment costs, which will be capital in nature, will be approximately $76 million which is expected to be spent through the first half of 2013. Through December 31, 2011 we have incurred approximately $38 million in abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note 14 of Notes to Consolidated Financial Statements.)

For the year ended December 31, 2011, we incurred approximately $15 million of expense related primarily to assessment and monitoring costs to ensure the safety of the surrounding area.

Outlook for 2012

In addition to the various in-progress expansion projects previously discussed, we have several other proposed projects to meet customer demands. Subject to regulatory approvals, construction of some of these projects could begin as early as 2012. We have planned capital and investment expenditures of $600 million to $700 million in 2012 mainly due to various in-progress expansion projects discussed above, as well as maintenance of existing facilities, primarily due to pipeline integrity costs and U. S. Department of Transportation mandatory requirements.

Filing of rate cases

During 2012, we expect to file rate cases for both Transco and Northwest Pipeline, which are expected to result in new transportation and storage rates beginning in 2013.

Year-Over-Year Operating Results

 

     Year ended December 31,  
     2011      2010      2009  
     (Millions)  

Segment revenues

   $ 1,678      $ 1,605      $ 1,591  
  

 

 

    

 

 

    

 

 

 

Segment profit

   $ 673      $ 637      $ 635  
  

 

 

    

 

 

    

 

 

 

2011 vs. 2010

Segment revenues increased $73 million, or 5 percent, primarily due to a $68 million increase in transportation revenues associated with expansion projects placed in service during 2010 and 2011, and $17 million higher system management gas sales (offset in costs and operating expenses). These increases are partially offset by $4 million lower sales of base gas from Hester Storage Field.

 

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Costs and operating expenses increased $55 million, or 7 percent, primarily due to $17 million higher system management gas costs (offset in segment revenues), $17 million increased pipeline maintenance costs, $10 million higher depreciation expense resulting from additional assets placed in service in 2010 and 2011, and $10 million increased operations and maintenance expense related to the Eminence Storage Field leak.

Equity earnings improved $20 million primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

Segment profit increased primarily due to the previously described changes.

2010 vs. 2009

Segment revenues increased primarily due to a $20 million increase in transportation revenues associated with expansion projects placed in service by Transco during 2010 and 2009 and a $9 million sale of base gas from Hester Storage Field (offset in costs and operating expenses.) Offsetting these increases is a $20 million decrease in other service revenues associated with reduced customer usage of our temporary natural gas loan and storage services.

Costs and operating expenses increased $25 million, or 3 percent, reflecting the absence of $11 million of income from an adjustment of state franchise taxes in 2009, a $9 million increase associated with the cost of selling base gas from Hester Storage Field (offset in segment revenues) and higher depreciation expense of $7 million.

Selling, general and administrative expenses decreased $13 million, or 8 percent, primarily due to lower employee-related expenses, including pension and other postretirement benefits.

Other (income) expense — net reflects increased expense of $10 million related to the over collection of certain employee-related expenses (offset in segment revenues) that will be returned to customers, partially offset by a $8 million gain on the sale of base gas from Hester Storage Field.

Segment profit increased primarily due to the previously described changes.

Midstream Gas & Liquids

Overview of 2011

Midstream’s ongoing strategy is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers.

Significant events during 2011 include the following:

Laser Northeast Gathering System Acquisition

In February 2012, we acquired the Laser Northeast Gathering System and other midstream businesses from Delphi Midstream Partners, LLC for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and approximately 7.5 million of our common units. The Laser Gathering System is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments. As production in the Marcellus increases, the Laser system is expected to reach a capacity of 1.3 Bcf/d.

Marcellus Shale Gathering Asset Transition and Expansion

Our Springville pipeline was placed into service in January 2012, allowing us to deliver approximately 300 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 650 MMcf/d of capacity from various compression and dehydration expansion projects to our gathering business in northeastern

 

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Pennsylvania’s Marcellus Shale which we acquired at the end of 2010. In conjunction with a long-term agreement with a significant producer, we are operating the 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline. Expansions to the Springville compression facilities in 2012 are expected to increase the capacity to approximately 625 MMcf/d.

Construction of a new noncontiguous gathering system is complete and was placed into service in October 2011. This system currently has the capacity to deliver approximately 50 MMcf/d into a third-party interstate pipeline via the newly acquired Laser gathering system.

In early 2011, we assumed the operational activities for these gathering systems in northeastern Pennsylvania’s Marcellus Shale which we acquired at the end of 2010. The acquired business included 75 miles of gathering pipelines and two compressor stations. We expect to expand this gathering system to a planned capacity of 1.7 Bcf/d by 2015.

Keathley Canyon ConnectorTM

Our equity investee, Discovery, plans to construct, own, and operate a new 215-mile 20-inch deepwater lateral pipeline for production from the Keathley Canyon Connector™, Walker Ridge, and Green Canyon areas in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from those fields. The Keathley Canyon ConnectorTM lateral will originate from a third party floating production facility in the southeast portion of the Keathley Canyon Connector™ area and will connect to Discovery’s existing 30-inch offshore gas transmission system. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. Construction is expected to begin in 2013, with a mid-2014 in-service date.

Gulfstar FPS™ Deepwater Project

In October 2011, we executed agreements with two significant producers to provide production handling services for the Tubular Bells discovery located in the eastern deepwater Gulf of Mexico. The operator of the Tubular Bells field will utilize our proprietary floating-production system, Gulfstar FPS™. We expect Gulfstar FPS to be capable of serving as a central host facility for other deepwater prospects in the area. We will design, construct, and install our Gulfstar FPS with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services. The facility is a spar-based floating production system that utilizes a standard design approach that will allow customers to reduce their cycle time from discovery to first production. Construction is underway and the project is expected to be in service in 2014.

Eagle Ford Shale

We have completed construction on a pipeline segment and related modifications necessary to reverse the flow of an existing Transco pipeline segment in southwest Texas, which began to gather south Texas gas to our Markham gas processing facility in the second quarter of 2011. In addition, we connected a third-party pipeline to our Markham plant during the third quarter that is delivering Eagle Ford Shale gas to the plant. We have executed both fee-based and keep whole processing agreements which we expect will increase utilization of our Markham facility to the full gas processing capacity. Markham is subject to limited NGL take-away capacity until third-party pipeline connections are completed in early 2013.

Perdido Norte

During the fourth quarter of 2010, both oil and gas production began to flow on a sustained basis through our Perdido Norte expansion, located in the western deepwater of the Gulf of Mexico. The project included a 200 MMcf/d expansion of our Markham gas processing facility and a total of 179 miles of deepwater oil and gas lines that expand the scale of our existing infrastructure. While 2011 production volumes were significantly lower than originally expected, they have increased each quarter of 2011, as producers have resolved several technical issues. With these improvements and with the addition of a new well, we anticipate volumes in 2012 to be higher than in 2011.

 

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Overland Pass Pipeline

We became the operator of OPPL effective April 1, 2011. We own a 50 percent interest in OPPL which includes a 760-mile NGL pipeline from Opal, Wyoming, to the Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the Piceance and Denver-Julesburg basins in Colorado, respectively. Our equity NGL volumes from our two Wyoming plants and our Willow Creek plant in Colorado are dedicated for transport on OPPL under a long-term shipping agreement. We plan to participate in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, to increase the pipeline’s capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.

Laurel Mountain

The initial phases of the Shamrock compressor station are in service, providing 60 MMcf/d of additional capacity, with further expansions planned in 2012. This compressor station is expandable to 350 MMcf/d and will likely be the largest central delivery point out of the Laurel Mountain system. Our equity investee continues to progress on further additions to the gathering infrastructure.

Volatile commodity prices

Average per-unit NGL margins in 2011 were significantly higher than in 2010, benefiting from a strong demand for NGLs resulting in higher NGL prices and slightly lower natural gas prices driven by abundant natural gas supplies.

NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

 

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LOGO

Outlook for 2012

The following factors could impact our business in 2012.

Commodity price changes

 

   

We expect our average per-unit NGL margins in 2012 to be comparable to 2011 and higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets.

 

   

As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices in 2012, we have entered into NGL swap agreements to fix the prices of approximately 5 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink gas requirements for 2012. The combined impact of these energy commodity derivatives will provide a margin on the hedged volumes of $106 million. The following table presents our energy commodity hedging instruments as of February 15, 2012.

 

                 Weighted  
      Period    Volumes
Hedged
     Average  Hedge
Price
 
        

Designated as hedging instruments:

           (per gallon)   

NGL sales - isobutane (million gallons)

   Feb - Dec 2012      12.8      $ 1.89   

NGL sales - normal butane (million gallons)

   Feb - Dec 2012      19.3      $ 1.79   

NGL sales - natural gasoline (million gallons)

   Feb - Dec 2012      29.0      $ 2.27   
                  (per MMbtu)  

Natural gas purchases (Tbtu)

   Feb - Dec 2012      6.5      $ 2.76   

Gathering, processing, and NGL sales volumes

 

   

The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities, which are influenced by natural gas prices.

 

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In our onshore businesses, we anticipate significant growth in our gas gathering volumes as our infrastructure grows to support drilling activities in northeast Pennsylvania. We anticipate slight increases in gas gathering volumes in the Piceance basin and no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. We anticipate equity NGL volumes in 2012 to be comparable to 2011, as we expect little change in the volume of gas processed in the western onshore businesses. Sustained low gas prices could discourage producer drilling activities in our onshore areas and unfavorably impact the supply of natural gas available to gather and process in the long term.

 

   

In our gulf coast businesses, we expect higher gas gathering, processing, and crude transportation volumes as production flowing through our Perdido Norte pipelines becomes consistent and other in-process drilling is completed. Increases in permitting, subsequent to the 2010 drilling moratorium, give us reason to expect gradual increased drilling activities in the Gulf of Mexico. In the Gulf Coast, our customers’ drilling activities are primarily focused on crude oil economics, rather than natural gas. We have not experienced, and do not anticipate an overall significant decline in volumes due to reduced drilling activities.

 

   

The operator of the third-party fractionator serving our NGL production transported on Overland Pass Pipeline has notified us of an expected 20- to 25-day outage in the second quarter of 2012 to accommodate their expansion efforts. The outage could result in a reduction to our equity volumes of up to approximately 20 million to 25 million gallons, along with price impacts; however we are evaluating methods to mitigate the impact.

 

   

We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in northeast Pennsylvania, Piceance basin, and western Gulf of Mexico.

Expansion Projects

We have planned growth capital and investment expenditures of $2,035 million to $2,215 million in 2012. We plan to pursue expansion and growth opportunities in the Marcellus Shale region, Gulf of Mexico, and Piceance basin.

As previously discussed, our ongoing major expansion projects include expansions to our gathering infrastructure in the Marcellus Shale region in northeastern Pennsylvania, including the acquisition of the Laser gathering system and related planned additions, expansions within our Laurel Mountain equity investment, also in the Marcellus Shale region, as well as our Gulfstar FPS floating production system and Discovery’s Keathley Canyon ConnectorTM pipeline, both located in the Gulf of Mexico.

In addition, we plan to construct a 350 MMcf/d cryogenic gas processing plant in conjunction with a new basin-wide agreement for all gathering and processing services provided by us to a customer in the Piceance basin. The Parachute TXP I plant is expected to be in service in 2014.

Year-Over-Year Operating Results

 

      Years ended December 31,  
     2011      2010      2009  
     (Millions)  

Segment revenues

   $  5,051      $ 4,110      $ 3,011  
  

 

 

    

 

 

    

 

 

 

Segment profit

   $  1,223      $ 937      $ 682  
  

 

 

    

 

 

    

 

 

 

 

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2011 vs. 2010

The increase in segment revenues includes:

 

   

A $589 million increase in marketing revenues primarily due to higher average NGL and crude prices. These changes are substantially offset by similar changes in marketing purchases.

 

   

A $244 million increase in revenues from our equity NGLs reflecting an increase of $272 million associated with a 25 percent increase in average NGL per-unit sales prices, partially offset by a decrease of $28 million associated with a 3 percent decrease in equity NGL volumes.

 

   

A $103 million increase in fee revenues primarily due to higher gathering and processing fee revenues. We have fees from new volumes on our gathering assets in the Marcellus Shale in northeastern Pennsylvania, which we acquired at the end of 2010, and on our Perdido Norte gas and oil pipelines in the western deepwater Gulf of Mexico, which went into service in late 2010. In addition, higher fees in the Piceance basin are primarily a result of an agreement executed in November 2010. These increases are partially offset by a decline in gathering and transportation fees in the eastern deepwater Gulf of Mexico primarily due to natural field declines.

Segment costs and expenses increased $669 million, or 21 percent, including:

 

   

A $574 million increase in marketing purchases primarily due to higher average NGL and crude prices. These changes are offset by similar changes in marketing revenues.

 

   

A $99 million increase in operating costs reflecting $57 million, or 17 percent, higher maintenance expenses, including maintenance expenses for our gathering assets in northeastern Pennsylvania acquired at the end of 2010, more maintenance performed on our assets in the western onshore businesses, and higher property insurance expense. In addition, depreciation expense is $33 million higher primarily due to our new Perdido Norte pipelines and our Echo Springs expansion, both of which went into service in late 2010, along with accelerated depreciation of our Lybrook plant which was idled in January 2012 when the gas was redirected to our Ignacio plant.

 

   

The absence of $30 million in gains recognized in 2010 associated with sale of certain assets in Colorado’s Piceance basin and involuntary conversion gains due to insurance recoveries in excess of the carrying value.

 

   

A $42 million decrease in costs associated with our equity NGLs reflecting a decrease of $21 million associated with a 5 percent decrease in average natural gas prices and a $21 million decrease reflecting lower equity NGL volumes.

The increase in Midstream’s segment profit reflects the previously described changes in segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.

The increase in Midstream’s segment profit includes:

 

   

A $286 million increase in NGL margins reflecting:

 

   

A $278 million increase in the onshore businesses’ NGL margins reflecting a $249 million increase from favorable commodity price changes due primarily to a 25 percent increase in average NGL prices. NGL equity volumes sold are 5 percent higher reflecting new capacity at our Echo Springs plant.

 

   

An $8 million increase in the gulf coast business’s NGL margins related to a $39 million increase from favorable commodity price changes, partially offset by 39 percent lower NGL equity volumes sold primarily due to a change in a major contract from “keep-whole” to “percent-of-liquids” processing.

 

   

A $103 million increase in fee revenues as previously discussed.

 

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A $15 million increase in margins related to the marketing of NGLs and crude.

 

   

A $13 million increase in equity earnings primarily due to higher OPPL equity earnings as a result of our purchase of an increased ownership interest in September 2010.

 

   

A $99 million increase in operating costs as previously discussed.

 

   

A $30 million unfavorable change primarily related to gains recognized in 2010 as previously discussed.

2010 vs. 2009

The increase in segment revenues includes:

 

   

A $699 million increase in marketing revenues primarily due to higher average NGL and crude prices. These changes are more than offset by similar changes in marketing purchases.

 

   

A $330 million increase in revenues associated with the production of NGLs reflecting an increase of $335 million associated with a 41 percent increase in average NGL per-unit sales prices.

 

   

A $56 million increase in fee revenues primarily due to higher gathering revenue in the Piceance basin as a result of permitted increases in the cost-of-service gathering rate in 2010 and to new fees for processing natural gas production at Willow Creek. These increases are partially offset by reduced fees from lower deepwater gathering and transportation volumes and lower gathering rates and volumes in the Four Corners area.

Segment costs and expenses increased $861 million, or 36 percent, including:

 

   

A $721 million increase in marketing purchases primarily due to higher average NGL and crude prices. These changes are offset by similar changes in marketing revenues.

 

   

A $107 million increase in costs associated with the production of NGLs reflecting an increase of $101 million associated with a 30 percent increase in average natural gas prices.

 

   

A $19 million increase in operating costs including $12 million higher depreciation primarily due to our new Perdido Norte pipelines and a full year of depreciation on our Willow Creek facility which was placed into service in the latter part of 2009.

 

   

The absence of a $40 million gain on the sale of our Cameron Meadows processing plant in 2009, partially offset by smaller gains in 2010 including involuntary conversion gains due to insurance recoveries in excess of the carrying value of our gulf assets which were damaged by Hurricane Ike in 2008 and our Ignacio plant, which was damaged by a fire in 2007 and gains associated with sales of certain assets in Colorado’s Piceance basin.

The increase in Midstream’s segment profit reflects the previously described changes in segment revenues and segment costs and expenses and higher equity earnings. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.

The increase in Midstream’s segment profit includes:

 

   

A $223 million increase in NGL margins reflecting:

 

   

A $194 million increase in the onshore businesses’ NGL margins reflecting a 43 percent increase in average NGL prices, partially offset by an increase in production costs reflecting a 31 percent increase in average natural gas prices. NGL equity volumes were slightly higher due primarily to a full year of production at Willow Creek in 2010 and new production capacity at Echo Springs in the fourth quarter of 2010, partially offset by the absence of favorable customer contractual changes in 2009 and decreasing inventory levels in 2009.

 

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A $30 million increase in the gulf coast businesses’ NGL margins reflecting a $40 million increase related to commodity price changes including a 34 percent increase in average NGL prices, partially offset by a 27 percent increase in average natural gas prices. NGL equity volumes sold were slightly lower driven by a 15 percent decrease in non-ethane volumes sold. Unfavorable impacts include natural field declines and an isolated sub-sea mechanical issue that reduced the Boomvang gas production flow, partially offset by low recoveries, primarily of ethane, in the first quarter of 2009 driven by unfavorable NGL economics.

 

   

A $25 million increase in equity earnings, primarily due to

 

   

A $10 million increase from Discovery due primarily to higher processing margins and new volumes from the Tahiti pipeline lateral expansion completed in 2009.

 

   

A $10 million increase from Aux Sable primarily due to higher processing margins.

 

   

A $5 million increase from our new investment in Overland Pass Pipeline.

 

   

A $56 million increase in fee revenues as previously discussed.

 

   

A $19 million increase in operating costs as previously discussed.

 

   

A $14 million unfavorable change related to the disposal of assets as previously discussed.

 

   

A $22 million decrease in margins related to the marketing of NGLs and crude primarily due to lower favorable changes in pricing while product was in transit in 2010 as compared to 2009.

 

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2011, we continued to focus upon growth through disciplined investments in our natural gas businesses. Examples of this growth included:

 

   

Expansion of Gas Pipeline’s interstate natural gas pipeline system and increased ownership in Gulfstream to meet the demand of growth markets.

 

   

Continued investment in Midstream’s gathering and processing capacity and infrastructure in the Marcellus Shale area, western United States, and deepwater Gulf of Mexico.

These investments were primarily funded through cash flow from operations and debt offerings.

Outlook

For 2012, we expect continued strong operating results and cash flows due to the combination of continued strong energy commodity margins and the start-up of certain expansion capital projects. However, energy commodity prices are volatile and difficult to predict. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, as follows:

 

   

Firm demand and capacity reservation transportation revenues under long-term contracts at Gas Pipeline;

 

   

Fee-based revenues from certain gathering and processing services at Midstream.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following for 2012:

 

   

We increased our per-unit quarterly distribution with respect to the fourth quarter of 2011 from $0.7475 to $0.7625. We expect to increase quarterly limited partner cash distributions by approximately 6 percent to 10 percent annually.

 

   

We have $325 million of debt maturing in 2012. We anticipate funding this maturity with a new debt issuance.

 

   

We expect to fund capital and investment expenditures, debt service payments, distributions to unitholders and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or long-term debt issuances and utilization of our revolving credit facility as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.775 billion and $2.25 billion in 2012.

 

   

In January 2012, we completed an equity issuance of 7 million common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, the underwriters exercised their option to purchase an additional 1.05 million common units for $62.81 per unit, with expected settlement on February 28, 2012.

 

   

As previously discussed, on February 17, 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC in exchange for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and approximately 7.5 million common units.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2012. Our internal and external sources of liquidity include:

 

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Cash and cash equivalents on hand;

 

   

Cash generated from operations, including cash distributions from our equity-method investees;

 

   

Cash proceeds from offerings of our common units and/or long-term debt;

 

   

Use of our credit facility, as needed and available.

We anticipate our more significant uses of cash to be:

 

   

Maintenance and expansion capital expenditures;

 

   

Payment of debt maturities (pursuant to expected issuances of new long-term debt);

 

   

Contributions to our equity-method investees to fund their expansion capital expenditures;

 

   

Interest on our long-term debt;

 

   

Quarterly distributions to our unitholders and/or general partner.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:

 

   

Lower than expected levels of cash flow from operations;

 

   

Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;

 

   

Sustained reductions in energy commodity margins from expected 2012 levels;

 

   

Physical damages to facilities, especially damage to offshore facilities by named windstorms.

 

Available Liquidity    December 31, 2011  
     (Millions)  

Cash and cash equivalents

   $ 163  

Capacity available under our $2 billion five-year senior unsecured revolving credit facility (expires June 3, 2016) (1)

     2,000  
  

 

 

 
   $ 2,163  
  

 

 

 

 

(1) In June 2011, we replaced our existing $1.75 billion unsecured revolving credit facility agreement with a new $2 billion five-year senior unsecured revolving credit facility agreement. The full amount of the new credit facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be increased by up to an additional $400 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the credit facility to the extent not otherwise utilized by the other co-borrowers. At December 31, 2011, we are in compliance with the financial covenants associated with this new credit facility agreement. (See 10 of Notes to Consolidated Financial Statements.)

Shelf Registration

In February 2012, we filed a shelf registration statement as a well-known seasoned issuer that allows us to issue an unlimited amount of registered debt and limited partnership unit securities.

 

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Distributions from Equity Method Investees

Our equity method investees’ organizational documents 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. Our more significant equity method investees include: Aux Sable, Discovery, Gulfstream, Laurel Mountain, and OPPL.

Debt Offerings

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. A portion of the proceeds were used to retire Transco’s $300 million 7 percent senior unsecured notes that matured on August 15, 2011.

In November 2011, we completed a public offering of $500 million of our 4 percent senior notes due 2021. We used the net proceeds primarily to repay outstanding borrowings on our senior unsecured revolving credit facility.

Credit Ratings

The table below presents our current credit ratings and outlook on our senior unsecured long-term debt.

 

               Senior Unsecured

Rating Agency

  

Date of Last Change

  

Outlook

  

Debt Rating

Standard & Poor’s    January 12, 2010    Positive    BBB-
Moody’s Investor Service    February 27, 2012    Stable    Baa2
Fitch Ratings    February 9, 2012    Positive    BBB-

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 Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. 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 Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. 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 continue to 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 and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2011, we estimate that a downgrade to a rating below investment grade could require us to post up to $134 million in additional collateral with third parties.

Capital Expenditures

Each of our businesses is capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of:

 

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Maintenance capital expenditures, which are generally not discretionary, including (1) capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives, (2) expenditures which are mandatory and/or essential to comply with laws and regulations and maintain the reliability of our operations, and (3) certain well connection expenditures.

 

   

Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, including (1) 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 and (2) well connection expenditures which are not classified as maintenance expenditures.

The following table provides summary information related to our expected capital expenditures for 2012:

 

     Maintenance      Expansion  

Segment

   Low      Midpoint      High      Low      Midpoint      High  
     (Millions)  

Gas Pipeline

   $ 330      $ 355      $ 380      $ 270      $ 295      $ 320  

Midstream

     115        125        135        2,035         2,125         2,215   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 445      $ 480      $ 515      $ 2,305      $ 2,420      $ 2,535  

See Results of Operations – Segments, Gas Pipeline and Midstream for discussions describing the general nature of these expenditures.

Cash Distributions to Unitholders

We have paid quarterly distributions to unitholders and our general partner after every quarter since our initial public offering on August 23, 2005. However, Williams waived its incentive distribution rights related to the 2009 distribution periods. We have increased our quarterly distribution from $0.7475 to $ 0.7625 per unit, which resulted in a fourth- quarter 2011 distribution of approximately $311 million that was paid on February 10, 2012, to the general and limited partners of record at the close of business on February 3, 2012.

Sources (Uses) of Cash

 

     Years Ended December 31,  
     2011     2010     2009  
     (Millions)  

Net cash provided (used) by:

      

Operating activities

   $ 2,166     $ 1,816     $ 1,483  

Financing activities

     (818     3,517       (544

Investing activities

     (1,372     (5,299     (919
  

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

   $ (24   $ 34     $ 20  
  

 

 

   

 

 

   

 

 

 

Operating activities

Net cash provided by operating activities increased $350 million in 2011 as compared to 2010 primarily due to higher operating income.

Net cash provided by operating activities increased $333 million in 2010 as compared to 2009 primarily due to higher operating income and changes in working capital.

 

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Financing activities

Significant transactions include:

2011

 

   

$1.1 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner;

 

   

$500 million received from our public offering of senior unsecured notes in November 2011 primarily used to repay borrowings on our revolving credit facility mentioned below;

 

   

$375 million received from Transco’s issuance of senior unsecured notes in August 2011;

 

   

$300 million paid to retire Transco’s senior unsecured notes that matured in August 2011;

 

   

$300 million received in revolver borrowings from our $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011. This obligation was transferred to our new $2 billion unsecured credit facility at its inception in June 2011;

 

   

$150 million paid to retire senior unsecured notes that matured in June 2011;

 

   

$123 million distributed to Williams related to the excess purchase price over the contributed basis of Gulfstream in May 2011;

 

   

$425 million in net borrowings and payments related to our revolving credit facility in 2011.

2010

 

   

$3.5 billion of net proceeds from the issuance of senior unsecured notes;

 

   

$660 million related to quarterly cash distributions paid to limited partner unitholders and our general partner;

 

   

$600 million received from our public offering of senior notes in November 2010 primarily used to fund a portion of the cash consideration paid for our Piceance acquisition;

 

   

$437 million received from our September and October 2010 equity offering primarily used to reduce revolver borrowings;

 

   

$430 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used to fund our increased ownership in OPPL, a transaction that closed in September 2010;

 

   

$369 million received from our December 2010 equity offering used to reduce revolver borrowings and to fund a portion of our acquisition of certain midstream assets in Pennsylvania’s Marcellus Shale in December 2010;

 

   

$250 million received from revolver borrowings on our $1.75 billion unsecured credit facility in February 2010 to repay a term loan outstanding under our credit agreement which expired at the closing of certain businesses we acquired from Williams;

 

   

$244 million distributed to Williams related to the excess purchase price over the contributed basis of the gathering and processing assets acquired in Colorado’s Piceance basin;

 

   

$200 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used for general partnership purposes and to fund a portion of the cash consideration paid for our acquisition of certain gathering and processing assets in Colorado’s Piceance basin;

 

   

$152 million in distributions to Williams primarily related to the Contributed Entities prior to the closing of certain businesses we acquired from Williams.

 

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2009

 

   

$384 million in distributions to Williams related to the Contributed Entities prior to the closing of certain businesses we acquired from Williams;

 

   

$144 million related to quarterly cash distributions paid to limited partner unitholders and our general partner.

Investing activities

Significant transactions include:

2011

 

   

$991 million in capital expenditures;

 

   

$174 million related to our acquisition of a 24.5 percent interest in Gulfstream from Williams in May 2011 (see Results of Operations – Segments, Gas Pipeline);

 

   

$137 million contribution to our Laurel Mountain equity investment.

2010

 

   

$3.4 billion related to the cash consideration paid for certain businesses we acquired from Williams;

 

   

$837 million in capital expenditures;

 

   

$458 million related to our Piceance acquisition;

 

   

$424 million cash payment for our September 2010 acquisition of an increased interest in OPPL;

 

   

$150 million paid for the purchase of a business in December 2010, consisting primarily of midstream assets in Pennsylvania’s Marcellus Shale.

2009

 

   

$907 million in capital expenditures;

 

   

$108 million cash payment for our 51 percent ownership interest in our Laurel Mountain equity investment;

 

   

$73 million of cash received as a distribution from Gulfstream following its debt offering.

Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments

We have various other guarantees and commitments which are disclosed in Notes 8, 10, 14, and 15 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.

 

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Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2011:

 

            2013 -      2015 -                
     2012      2014      2016      Thereafter      Total  
     (Millions)  

Long-term debt, including current portion:

           

Principal

   $ 325      $ —         $ 1,125      $ 5,803      $ 7,253  

Interest

     411        764        698        3,045        4,918  

Operating leases (1)

     33        49        44        145        271  

Purchase obligations (2)

     1,340        441        381        1,292        3,454  

Other long-term obligations

     —           1        1        —           2  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 2,109      $ 1,255      $ 2,249      $ 10,285      $ 15,898  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Includes a right-of-way agreement with the Jicarilla Apache Nation, which is considered an operating lease. We are required to make a fixed annual payment of $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 right-of-way agreement. The table above for years 2013 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable.

 

(2) Includes an estimated $2.2 billion long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31,2011 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator in Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or resold at comparable prices in the Mont Belvieu market.

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 63 percent of our gross property, plant, and equipment is at Gas Pipeline. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For Midstream, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the Organization of the Petroleum Exporting Countries (OPEC) production levels and/or the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to these price changes is reduced through the fee-based nature of certain of our services.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own (see Note 15 of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $18 million, all of which are included in other accrued liabilities and regulatory liabilities, deferred income and other on the Consolidated Balance Sheet at December 31, 2011. We will seek recovery of approximately $10 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2011, we paid approximately $4 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $4 million in 2012 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2011, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

 

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We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Act. Pursuant to requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone, we have installed air pollution controls on existing sources at certain facilities in order to reduce ozone emissions.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced it would not move forward with the proposed 2010 ozone NAAQS. Instead, the EPA will implement the 2008 ozone NAAQS that was stayed during the reconsideration process. The EPA is expected to designate ozone nonattainment areas under the 2008 NAAQS in second quarter 2012 and we are unable at this time to estimate the cost of additions that may be required to meet this new regulation. However, designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment net on the Consolidated Balance Sheet.

Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the NESHAP regulations are estimated to include capital costs in the range of $24 million to $32 million through 2013, the compliance date.

In June 2010, the EPA promulgated a final rule establishing a new one-hour sulfur dioxide (SO2) NAAQS. The effective date of the new SO2 standard was August 23, 2010. This new standard is subject to challenge in federal court. EPA has not adopted final modeling guidance. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.

 

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit facilities could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 10 of Notes to Consolidated Financial Statements.)

The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2011 and 2010. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings.

 

     2012      2013      2014      2015      2016      Thereafter(1)      Total      Fair Value
December 31,
2011
 
     (Millions)  

Long-term debt, including current portion:

                       

Fixed rate

   $ 325      $ —         $ —         $ 750      $ 375      $ 5,787      $ 7,237      $ 8,170  

Interest rate

     5.6%         5.5%         5.5%         5.6%         5.7%         5.9%         
     2011      2012      2013      2014      2015      Thereafter(1)      Total      Fair Value
December 31,
2010
 
     (Millions)  

Long-term debt, including current portion:

                       

Fixed rate

   $ 458      $ 325      $ —         $ —         $ 750      $ 5,290      $ 6,823      $ 7,283  

Interest rate

     5.9%         5.7%         5.7%         5.7%         5.8%         6.1%         

 

(1) Includes unamortized discount and premium.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of natural gas and NGLs, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets and our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining a conservative capital structure and significant liquidity, as well as using various derivatives and non derivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. (See Note 14 of Notes to Consolidated Financial Statements.)

We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio. Value-at-risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolio will not exceed the value-at-risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that

 

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changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value-at-risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value-at-risk.

Trading

Our limited trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net asset of less than $0.1 million at December 31, 2011. The value-at-risk for contracts held for trading purposes was less than $0.1 million at December 31, 2011 and zero at December 31, 2010.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from natural gas purchase and NGL sale activities.

The fair value of our nontrading derivatives was a net asset of $1 million at December 31, 2011.

The value at risk for derivative contracts held for nontrading purposes was zero at December 31, 2011 and 2010. During the year ended December 31, 2011, our value-at-risk for these contracts ranged from a high of $1 million to a low of zero.

Certain of the derivative contracts held for nontrading purposes in 2011 were accounted for as cash flow hedges but realized during the year. Of the total fair value on nontrading derivatives, cash flow hedges had a net asset value of zero as of December 31, 2011. Though these contracts would be included in our value-at-risk calculation, any changes in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

Trading Policy

We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations.

 

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING

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, 2011, 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 concluded that, as of December 31, 2011, 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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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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 (the Partnership) internal control over financial reporting as of December 31, 2011, 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 Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’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, 2011, 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, 2011 and 2010, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011, and our report dated February 27, 2012 expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP        
Tulsa, Oklahoma
February 27, 2012

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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. (the Partnership) as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (Gulfstream) (a limited liability corporation in which the Partnership has a 49 percent interest). The Partnership’s investment in Gulfstream constituted three percent of the Partnership’s assets as of December 31, 2011 and the Partnership’s equity in the net income of Gulfstream constituted four percent of the Partnership’s net income for the year ended December 31, 2011. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion on the 2011 consolidated financial statements, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of the other auditors.

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 and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, 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 27, 2012 expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP        
Tulsa, Oklahoma
February 27, 2012

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Gulfstream Natural Gas System, L.L.C.

We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C., (the “Company”), as of December 31, 2011, and the related statements of operations, cash flows, and members’ equity and comprehensive income for the year then ended. 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 audit.

We conducted our audit in accordance with the auditing 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2011, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 23, 2011

 

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WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF INCOME

 

     Years Ended December 31,  
     2011     2010     2009  
     (Millions, except per-unit amounts)  

Revenues:

      

Gas Pipeline

   $ 1,678     $ 1,605     $ 1,591  

Midstream Gas & Liquids

     5,051       4,110       3,011  
  

 

 

   

 

 

   

 

 

 

Total revenues

     6,729       5,715       4,602  

Segment costs and expenses:

      

Costs and operating expenses

     4,672       3,984       3,100  

Selling, general, and administrative expenses

     290       281       300  

Other (income) expense — net

     13       (15     (34
  

 

 

   

 

 

   

 

 

 

Segment costs and expenses

     4,975       4,250       3,366  

General corporate expenses

     112       125       109  
  

 

 

   

 

 

   

 

 

 

Operating income:

      

Gas Pipeline

     615       599       600  

Midstream Gas & Liquids

     1,139       866       636  

General corporate expenses

     (112     (125     (109
  

 

 

   

 

 

   

 

 

 

Total operating income

     1,642       1,340       1,127  

Equity earnings

     142       109       81  

Interest accrued — third-party

     (425     (392     (207

Interest accrued — affiliate

     (1     (1     (52

Interest capitalized

     11       29       58  

Interest income — third-party

     2       1       1  

Interest income — affiliate

     —          3       19  

Other income (expense) — net

     7       12       9  
  

 

 

   

 

 

   

 

 

 

Net income

     1,378       1,101       1,036  

Less: Net income attributable to noncontrolling interests

     —          16       27  
  

 

 

   

 

 

   

 

 

 

Net income attributable to controlling interests

   $ 1,378     $ 1,085     $ 1,009  
  

 

 

   

 

 

   

 

 

 

Allocation of net income for calculation of earnings per common unit:

      

Net income attributable to controlling interests

   $ 1,378     $ 1,085     $ 1,009  

Allocation of net income to general partner and Class C units (a)

     308       517       857  
  

 

 

   

 

 

   

 

 

 

Allocation of net income to common units

   $ 1,070     $ 568     $ 152  
  

 

 

   

 

 

   

 

 

 

Basic and diluted net income per common unit

   $ 3.69     $ 2.66     $ 2.88  

Weighted average number of common units outstanding (thousands) (a)

     290,255       213,539       52,777  

Cash distributions per common unit

   $ 2.96     $ 2.72     $ 2.54  

  

 

(a) Calculated as discussed in Note 2.

See accompanying notes.

 

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WILLIAMS PARTNERS L.P.

CONSOLIDATED BALANCE SHEET

 

     December 31,
2011
    December 31,
2010
 
     (Millions)  

ASSETS

  

Current assets:

    

Cash and cash equivalents

   $ 163     $ 187  

Accounts and notes receivable:

    

Trade

     484       404  

Affiliate

     9       8  

Inventories

     148       195  

Regulatory assets

     40       51  

Other current assets

     70       53  
  

 

 

   

 

 

 

Total current assets

     914       898  

Investments

     1,383       1,045  

Property, plant, and equipment – net

     11,627       11,001  

Regulatory assets, deferred charges, and other

     456       460  
  

 

 

   

 

 

 

Total assets

   $ 14,380     $ 13,404  
  

 

 

   

 

 

 

LIABILITIES AND EQUITY

    

Current liabilities:

    

Accounts payable:

    

Trade

   $ 554     $ 322  

Affiliate

     57       154  

Accrued interest

     105       105  

Asset retirement obligations

     66       35  

Other accrued liabilities

     166       139  

Long-term debt due within one year

     324       458  
  

 

 

   

 

 

 

Total current liabilities

     1,272       1,213  

Long-term debt

     6,913       6,365  

Asset retirement obligations

     503       460  

Regulatory liabilities, deferred income, and other

     464       290  

Contingent liabilities and commitments (Note 15)

    

Equity:

    

Common units (290,477,159 units outstanding at December 31, 2011 and 289,844,575 units outstanding at December 31, 2010)

     6,810       6,564  

General partner

     (1,580     (1,485

Accumulated other comprehensive income (loss)

     (2     (3
  

 

 

   

 

 

 

Total equity

     5,228       5,076  
  

 

 

   

 

 

 

Total liabilities and equity

   $ 14,380     $ 13,404  
  

 

 

   

 

 

 

See accompanying notes.

 

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WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

 

     Williams Partners L.P.              
                       Accumulated Other              
     Limited Partners     General     Comprehensive     Noncontrolling     Total  
     Common     Class C     Partner     Income (Loss)     Interests     Equity  
     (Millions)  

Balance – December 31, 2008

   $ 1,620     $ —        $ 5,901     $ 4     $ 342     $ 7,867  

Comprehensive income:

            

Net income

     145       —          864       —          27       1,036  

Other comprehensive income (loss):

            

Net unrealized change in cash flow hedges, net of reclassification adjustments

     —          —          —          (2     —          (2
            

 

 

 

Total other comprehensive income (loss)

               (2
            

 

 

 

Total comprehensive income

               1,034  

Cash distributions

     (134     —          (10     —          —          (144

Dividends paid to noncontrolling interests

     —          —          —          —          (23     (23

Distributions to The Williams Companies, Inc. – net

     —          —          (384     —          —          (384

Reclassification of notes receivable

     —          —          (253     —          —          (253

Other

     —          —          5       —          1       6  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance – December 31, 2009

   $ 1,631     $ —        $ 6,123     $ 2     $ 347     $ 8,103  

Comprehensive income:

            

Net income

     558       156       371       —          16       1,101  

Other comprehensive income (loss):

            

Net unrealized change in cash flow hedges, net of reclassification adjustments

     —          —          —          (5     —          (5
            

 

 

 

Total other comprehensive income (loss)

               (5
            

 

 

 

Total comprehensive income

               1,096  

Cash distributions

     (432     (87     (141     —          —          (660

Dividends paid to noncontrolling interests

     —          —          —          —          (18     (18

Issuance of units (203,000,000 Class C units)

     —          6,946       (6,946     —          —          —     

Distributions to The Williams Companies, Inc. – net

     —          (3,357     (679     —          —          (4,036

Excess of purchase price over contributed basis of business purchase from affiliate

     —          —          (244     —          —          (244

Conversion of Class C units to Common (203,000,000 units)

     3,658       (3,658     —          —          —          —     

Issuance of units due to Williams Pipeline Partners L.P. merger (13,580,485 common units)

     343       —          —          —          (343     —     

Issuance of units to public (18,637,500 common units)

     806       —          —          —          —          806  

Contributions from general partner

     —          —          29       —          —          29  

Other

     —          —          2       —          (2     —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance – December 31, 2010

   $ 6,564     $ —        $ (1,485   $ (3   $ —        $ 5,076  

Comprehensive income:

            

Net income

     1,088       —          290       —          —          1,378  

Other comprehensive income (loss):

            

Net unrealized change in cash flow hedges, net of reclassification adjustments

     —          —          —          1       —          1  
            

 

 

 

Total other comprehensive income (loss)

               1  
            

 

 

 

Total comprehensive income

               1,379  

Cash distributions

     (842     —          (282     —          —          (1,124

Excess of purchase price over contributed basis of investment purchase from affiliate

     —          —          (123     —          —          (123

Contributions from general partner

     —          —          31       —          —          31  

Other

     —          —          (11     —          —          (11
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance – December 31, 2011

   $ 6,810     $ —        $ (1,580   $ (2   $ —        $ 5,228  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes.

 

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WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF CASH FLOWS

 

      Years Ended December 31,  
     2011     2010     2009   
     (Millions)  

OPERATING ACTIVITIES:

      

Net income

   $ 1,378     $ 1,101     $ 1,036    

Adjustments to reconcile to net cash provided by operations:

      

Depreciation and amortization

     611       568       553    

Cash provided (used) by changes in current assets and liabilities:

      

Accounts and notes receivable

     (80     (23     (93 )  

Inventories

     47       (66     17    

Other assets and deferred charges

     (8     37         

Accounts payable

     163       28         

Accrued liabilities

     56       72       (73 )  

Affiliate accounts receivable and payable – net

     (98     72       16    

Other, including changes in noncurrent assets and liabilities

     97       27       17    
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     2,166       1,816       1,483    
  

 

 

   

 

 

   

 

 

 

FINANCING ACTIVITIES:

      

Proceeds from long-term debt

     1,596       5,029       —     

Payments of long-term debt

     (1,184     (1,203     (2 )  

Payment of debt issuance costs

     (16     (66     —     

Proceeds from sales of common units

     —          806       —     

General partner contributions

     31       29       —     

Dividends paid to noncontrolling interests

     —          (18     (23 )  

Distributions to limited partners and general partner

     (1,124     (660     (144 )  

Excess of purchase price over contributed basis of business and investment

     (123     (244     —     

Distributions to The Williams Companies, Inc. – net

     —          (152     (384 )  

Other – net

     2       (4       
  

 

 

   

 

 

   

 

 

 

Net cash provided (used) by financing activities

     (818     3,517       (544 )  
  

 

 

   

 

 

   

 

 

 

INVESTING ACTIVITIES:

      

Purchase of business and investments from affiliates

     (174     (3,884     —     

Property, plant and equipment:

      

Capital expenditures

     (991     (837     (907 )  

Net proceeds from dispositions

     5       64       46    

Purchases of business and investments

     (228     (626     (131 )  

Purchase of ARO trust investments

     (41     (47     (46 )  

Proceeds from sale of ARO trust investments

     56       31       41    

Other – net

     1       —          78    
  

 

 

   

 

 

   

 

 

 

Net cash used by investing activities

     (1,372     (5,299     (919 )  
  

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     (24     34       20    

Cash and cash equivalents at beginning of period

     187       153       133    
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 163     $ 187     $ 153    
  

 

 

   

 

 

   

 

 

 

See accompanying notes.

 

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Note 1. Organization, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

Organization

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us,” or similar language refer to Williams Partners L.P. and its subsidiaries.

We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of December 31, 2011, Williams owns an approximate 73 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us).

Description of Business

Our operations are located in the United States and are organized into the following reporting segments: Gas Pipeline and Midstream Gas & Liquids (Midstream).

Gas Pipeline is comprised primarily of the following interstate natural gas pipeline assets:

 

   

Transcontinental Gas Pipe Line Company, LLC (Transco), an interstate natural gas pipeline extending from the Gulf of Mexico region to the northeastern United States;

 

   

Northwest Pipeline GP (Northwest Pipeline), an interstate natural gas pipeline extending from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington;

 

   

A 49 percent equity interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream), an interstate natural gas pipeline extending from the Mobile Bay area in Alabama to markets in Florida.

Midstream is comprised primarily of:

 

   

Large-scale natural gas gathering, processing, and treating facilities in the Rocky Mountain, Four Corners, Piceance basin, and Pennsylvania’s Marcellus Shale regions;

 

   

Offshore deepwater oil and natural gas production platforms, gathering, and transportation facilities in the Gulf of Mexico, as well as significant natural gas gathering, processing, and treating facilities on the Gulf Coast;

 

   

A natural gas liquid (NGL) fractionator and storage facilities near Conway, Kansas;

 

   

Various equity investments in domestic natural gas gathering and processing assets and NGL fractionation and transportation assets.

Basis of Presentation

In May 2011, we closed the acquisition of a 24.5 percent interest in Gulfstream from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. As the acquired equity interest was purchased from a subsidiary of Williams, the transaction was accounted for as a combination of entities under common control whereby the investment acquired is combined with ours at its

 

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

historical amount as of the date of transfer. The excess of the cash purchase price over the historical carrying amount is recognized as a reduction of general partner equity. This investment is reported in our Gas Pipeline segment.

In February 2010, we closed a transaction (the Dropdown) with our general partner, our operating company, Williams and certain of its subsidiaries, pursuant to which Williams contributed to us the ownership interests in the entities that made up its gas pipeline and midstream businesses to the extent not already owned by us, including Williams’ limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding its Canadian, Venezuelan, and olefins operations, and 25.5 percent of Gulfstream, collectively defined as the Contributed Entities.

Accounting standards issued but not yet adopted

In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5). ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. ASU 2011-5 requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income. The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. We currently report net income in the Consolidated Statement of Operations and report other comprehensive income in the Consolidated Statement of Changes in Equity. In December 2011, The FASB issued Accounting Standards Update No. 2011-12, “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12). ASU 2011-12 defers the effective date for only the presentation requirements related to reclassifications in ASU 2011-5. During this deferral period, ASU 2011-12 states that we should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Both standards are effective beginning the first quarter of 2012, with retrospective application to prior periods. We will apply the new guidance for both standards beginning in 2012.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of Williams Partners L.P., OLLC, and our other wholly owned subsidiaries. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20 percent to 50 percent of the voting interest or otherwise exercise significant influence over operating and financial policies of the company. We also apply the equity method of accounting for investments where our majority ownership does not provide us with control due to the significant participatory rights of other owners.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

 

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Significant estimates and assumptions include:

 

   

Impairment assessments of investments and long-lived assets;

 

   

Litigation-related contingencies;

 

   

Environmental remediation obligations;

 

   

Asset retirement obligations.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates established by the FERC are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these businesses that are regulated can differ from the accounting requirements for non-regulated businesses. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits.

Cash and cash equivalents

Cash and cash equivalents includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have maturities of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The allowance for doubtful accounts at December 31, 2011 and 2010 was insignificant.

Inventory valuation

All inventories are stated at the lower of cost or market. We determine the cost of certain natural gas inventories held by Transco using the last-in, first-out (LIFO) cost method. We determine the cost of the remaining inventories primarily using the average-cost method. There was no LIFO inventory at December 31, 2011. LIFO inventory at December 31, 2010 was $9 million.

Property, plant, and equipment

Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (See Note 8.)

 

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Gains or losses from the ordinary sale or retirement of property, plant and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in other (income) expense — net included in operating income.