10-K 1 wpz-10k_20141231.htm 10-K

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X]    Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2014

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 No. 1-34831

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 Representing Limited Partner Interests

 

New York Stock Exchange

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    YES [X]    NO [  ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

YES [  ]    NO [X]

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 [X]    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 [X]    NO [  ]

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

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.

Large Accelerated Filer [X]   Accelerated Filer [  ]   Non-accelerated Filer [  ]   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 [X]

The aggregate market value of our common units held by non-affiliates on June 30, 2014 was approximately $12,066,283,239.

As of February 13, 2015, there were 586,694,683 common units outstanding.

 

 

 

 

 

 


WILLIAMS PARTNERS L.P.

2014 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

 

PART I

Page

Item 1.

 

Business

1

Item 1A.

 

Risk Factors

18

Item 1B.

 

Unresolved Staff Comments

39

Item 2.

 

Properties

39

Item 3.

 

Legal Proceedings

39

Item 4.

 

Mine Safety Disclosures

40

 

PART II

 

Item 5.

 

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

41

Item 6.

 

Selected Financial Data

43

Item 7.

 

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

45

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

73

Item 8.

 

Financial Statements and Supplementary Data

74

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

106

Item 9A.

 

Controls and Procedures

106

Item 9B.

 

Other Information

108

 

PART III

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

109

Item 11.

 

Executive Compensation

117

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

134

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

137

Item 14.

 

Principal Accountant Fees and Services

142

 

PART IV

 

Item 15.

 

Exhibits and Financial Statement Schedules

143

 


 


 

 

 

PART I

Item 1. Business

This filing includes information for the registrant formerly named Access Midstream Partners, L.P. As further described below, following the completion of a merger on February 2, 2015, the name of the registrant was changed to Williams Partners L.P. Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. (NYSE: WPZ) and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” also include the operations of our entities in which we own interests accounted for as equity investments that are not consolidated in our financial statements (“Partially Owned Entities”). 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 Securities and Exchange Commission (“SEC”) under the Exchange Act. These reports include, among other disclosures, information on any transactions we may engage in with our general partner and its affiliates and on fees and other amounts paid or accrued to our general partner and its affiliates. 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 http://investor.williams.com/williams-partners-lp. We make available free of charge through our 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. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent press releases. Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charters of our Audit Committee and Conflicts Committee of our general partner’s Board of Directors are also available on our website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s Corporate Secretary at One Williams Center, Suite 4700, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000.

GENERAL

We are a growth-oriented publicly traded Delaware limited partnership. Prior to the Merger discussed below, we were principally focused on natural gas and natural gas liquids (“NGLs”) gathering, the first segment of midstream energy infrastructure that connects natural gas and NGL’s produced at the well head to third party takeaway pipelines. The following diagram illustrates this area of focus in the natural gas value chain:

 

 

As of December 31, 2014, The Williams Companies, Inc. (“Williams”) owned an approximate 49 percent limited partnership interest in us and all of our 2 percent general partner interest and incentive distribution rights (“IDRs”). Williams is an energy infrastructure company that trades on the NYSE under the symbol “WMB.”

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MERGER WITH WILLIAMS PARTNERS L.P.

Pursuant to an Agreement and Plan of Merger dated as of October 24, 2014, the general partners of Williams Partners L.P. and Access Midstream Partners, L.P. agreed to combine those businesses and their general partners, with Williams Partners L.P. merging with and into Access Midstream Partners, L.P. and the Access Midstream Partners, L.P. general partner being the surviving general partner (the “Merger”). As further described below, following the consummation of the Merger on February 2, 2015, the name of the registrant was changed to Williams Partners L.P., and the name of its general partner was changed to WPZ GP LLC. For purposes of this Annual Report on Form 10-K and the financial statements included herein, references to Williams Partners L.P. (the “Partnership” or “Pre-merger ACMP”) pertain to ACMP as it existed prior to the consummation of the Merger, the “Merged Partnership” pertains to the entity as it exists after the consummation of the Merger, and “Pre-merger WPZ” pertains to the entity originally named Williams Partners L.P. prior to the consummation of the Merger.

In accordance with the terms of the Merger, each Pre-merger ACMP unitholder received 1.06152 Pre-merger ACMP units for each Pre-merger ACMP unit owned immediately prior to the Merger (“Pre-merger Unit Split”).  In conjunction with the Merger, each Pre-merger WPZ common unit held by the public was exchanged for 0.86672 common units of Pre-merger ACMP (“Merger Exchange”).   Each Pre-merger WPZ common unit held by Williams was exchanged for 0.80036 common units of Pre-merger ACMP.  Prior to the closing of the Merger, the Class D limited partner units of Pre-merger WPZ, all of which were held by Williams, were converted into Pre-merger WPZ common units on a one-for-one basis pursuant to the terms of the partnership agreement of Pre-merger WPZ.  All of the general partner interests of Pre-merger WPZ were converted into general partner interests of Pre-merger ACMP such that the general partner interest of Pre-merger ACMP represents 2.0 percent of the outstanding partnership interest.  Following the Merger on February 2, 2015, Williams owned approximately 60 percent of the Merged Partnership, including the general partner interest and IDRs.  Unless otherwise noted, all units discussed throughout this report are Pre-merger ACMP units before the Pre-merger Unit Split.  

Prior to the Merger, Williams owned certain limited partnership interests in both Pre-merger WPZ and Pre-merger ACMP, as well as 100 percent of the general partners of both partnerships.  As a result of its ownership of the general partners, Williams controlled both partnerships.  Williams’ control of Pre-merger WPZ began with Pre-merger WPZ’s inception in 2005, while control of Pre-merger ACMP was achieved upon obtaining an additional 50 percent interest in its general partner effective July 1, 2014.  Williams previously acquired 50 percent of the Pre-merger ACMP general partner in a separate transaction in 2012.

FINANCIAL INFORMATION ABOUT SEGMENTS

Part II, Item 8 — Financial Statements and Supplementary Data as well as Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations present information solely for Pre-merger ACMP.

BUSINESS SEGMENTS

Operations of our businesses are located in North America. We manage our business and analyze our results of operations on a segment basis. Subsequent to the Merger, our operations are divided into five business segments:

Access Midstream — this segment includes Pre-merger ACMP, which provides gathering, treating, and compression services to producers in the Marcellus and Utica shale plays, as well as the Eagle Ford, Haynesville, Barnett, Mid-Continent, and Niobrara areas. This segment also includes a 49 percent equity-method investment in Utica East Ohio Midstream, LLC (“UEOM”), and Appalachia Midstream Services, LLC (“Appalachia Midstream”), which owns an approximate average 45 percent interest in 11 gathering systems in the Marcellus Shale.

Northeast G&P — this segment includes natural gas gathering and processing and NGL fractionation businesses in the Marcellus and Utica shale regions, as well as a 69 percent equity investment in Laurel Mountain Midstream, LLC (“Laurel Mountain”) and a 58 percent equity investment in Caiman Energy II, LLC (“Caiman II”).

Atlantic-Gulf — this segment includes our interstate natural gas pipeline, Transcontinental Gas Pipeline Company, LLC (“Transco”), and significant natural gas gathering and processing and crude oil production handling and transportation in the Gulf Coast region, as well as a 50 percent equity investment in Gulfstream Natural Gas System, LLC (“Gulfstream”), a 41 percent interest in Constitution Pipeline Company, LLC (“Constitution”) (a consolidated entity), and a 60 percent equity investment in Discovery Producer Services, LLC (“Discovery”).

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West — this segment includes our natural gas gathering, processing and treating operations in New Mexico, Colorado, and Wyoming and our interstate natural gas pipeline, Northwest Pipeline.

NGL & Petchem Services — this segment includes our 88.5 percent interest in an olefins production facility in Geismar, Louisiana, along with an RGP Splitter and various petrochemical and feedstock pipelines in the Gulf Coast region. Our Canadian assets include an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and Butylene/Butane splitter (“B/B Splitter”) facility at Redwater, Alberta. This segment also includes an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in Overland Pass Pipeline Company LLC (“OPPL”).

Detailed discussion of each of our business segments follows. For a discussion of our ongoing expansion projects related to Pre-merger ACMP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Access Midstream

Our Access Midstream segment provides gathering, treating, and compression services to producers under long-term, fee-based contracts in Pennsylvania, West Virginia, Ohio, Louisiana, Texas, Arkansas, Oklahoma, Kansas, and Wyoming.

Prior to the Merger, Pre-merger ACMP segments were organized by region. The following table summarizes Pre-merger ACMP’s average daily throughput and assets for these regions as of and for the year ended December 31, 2014:

 

 

Location

 

Average Throughput (Bcf/d) (1)

 

Approximate Length of Pipeline (Miles)

 

Gas Compression (Horsepower)

Barnett Shale

Texas

 

0.907

 

860

 

134,660

Eagle Ford Shale

Texas

 

0.321

 

947

 

104,157

Haynesville Shale

Louisiana

 

0.672

 

585

 

20,195

Marcellus Shale

Pennsylvania & West Virginia

 

1.214

 

940

 

136,090

Niobrara Shale

Wyoming

 

0.028

 

168

 

51,345

Utica Shale

Ohio

 

0.364

 

375

 

135,010

Mid-Continent

Texas, Oklahoma, Kansas, & Arkansas

 

0.555

 

2,865

 

108,284

Total

 

 

4.061

 

6,740

 

689,741

__________

(1)

Throughput in all regions represents net throughput allocated to our interest.

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

Utica East Ohio Midstream

UEOM is a joint project to develop infrastructure for the gathering, processing and fractionation of natural gas and NGLs in the Utica Shale play in Eastern Ohio. We, along with other equity owners, operate the infrastructure complex which consists of natural gas gathering and compression facilities, four processing plants with a total capacity of 800 MMcf per day, a 135,000 barrel per day NGL fractionation facility, approximately 600,000 barrels of NGL storage capacity and other ancillary assets, including loading and terminal facilities that are operated by our partner. These assets earn a fixed fee that escalates annually within a specified range. We own a 49 percent interest and UEOM is accounted for as an equity-method investment.

Appalachia Midstream

Through our wholly owned subsidiary Appalachia Midstream, we operate 100 percent of and own an approximate average 45 percent interest in 11 natural gas gathering systems that consist of approximately 906 miles of gathering pipeline in the Marcellus Shale region. The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania and the northwestern panhandle of West Virginia, in core areas of the Marcellus Shale. Appalachia Midstream operates the assets under long-term, 100 percent fixed fee gathering agreements

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that include significant acreage dedications and cost of service mechanisms. The 11 gathering systems are separate investments with ownership percentages ranging from 33.75 percent to 67.5 percent and each gathering system is accounted for as an equity-method investment.

Northeast G&P

This segment includes our natural gas gathering and processing and NGL fractionation business in the Marcellus and Utica shale regions in Pennsylvania, West Virginia, New York, and Ohio that relate to Pre-merger WPZ operations.

The following tables summarize the significant operated assets of this segment as of December 31, 2014:

 

 

 

Natural Gas Gathering Assets

 

 

 

 

 

Inlet

 

 

 

 

 

 

 

Pipeline

 

Capacity

 

Ownership

 

 

 

Location

 

Miles

 

(Bcf/d)

 

Interest

 

Supply Basins

 

 

 

 

 

 

 

 

 

 

Ohio Valley

 

West Virginia

 

209

 

0.8

 

100%

 

Appalachian

Susquehanna Supply Hub

 

Pennsylvania & New York

 

325

 

2.5

 

100%

 

Appalachian

Laurel Mountain(1)

 

Pennsylvania

 

2,049

 

0.7

 

69%

 

Appalachian

_________

(1)

Statistics reflect 100 percent of the assets from the jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

 

 

 

Natural Gas Processing Facilities

 

 

 

 

 

NGL

 

 

 

 

 

 

 

Inlet

 

Production

 

 

 

 

 

 

 

Capacity

 

Capacity

 

Ownership

 

 

 

Location

 

(Bcf/d)

 

(Mbbls/d)

 

Interest

 

Supply Basins

 

 

 

 

 

 

 

 

 

 

Fort Beeler

 

Marshall County, WV

 

0.5

 

62

 

100%

 

Appalachian

Oak Grove

 

Marshall County, WV

 

0.2

 

25

 

100%

 

Appalachian

 

In addition, we own and operate condensate stabilization, de-ethanization and fractionation facilities near our Oak Grove processing plant and an ethane transportation pipeline.  Our two condensate stabilizers are capable of extracting more than 14 Mbbls/d of condensate from the natural gas stream.  After natural gas liquids (NGLs) are extracted from the natural gas stream in our cryogenic processing plants, our Oak Grove de-ethanizer is capable of handling approximately 80 Mbbls/d of mixed NGLs to extract approximately 40 Mbbls/d of ethane.  The residual mixed NGL stream from the de-ethanizer is then fractionated at our Moundsville fractionators, which are capable of handling more than 42 Mbbls/d per day of mixed NGLs.  Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania.

Laurel Mountain

We own a 69 percent equity interest in a joint venture, Laurel Mountain, that includes a gathering system that we operate in western Pennsylvania. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale.

Caiman II

We own a 58 percent equity interest in Caiman II. We, along with Caiman Energy, LLC and others are working to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. Caiman II is engaged in the construction of the Blue Racer Midstream project, a joint project between Caiman II and Dominion to serve oil and gas producers in the Utica Shale, primarily in Ohio and Northwest Pennsylvania. Caiman II owns a 50 percent interest in the Blue Racer Midstream project whose assets include nearly 600 miles of large-diameter gathering pipelines that span the Utica Shale,

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the Natrium complex in Marshall County, West Virginia, and a transmission pipeline connecting Natrium to the gathering system.  The Natrium complex currently includes a 200 MMcf/d cryogenic processing plant and a 46,000 Bbls/d fractionator.  

Operating Statistics

 

 

 

2014

 

 

2013

 

 

2012

 

Volumes: (1)

 

 

 

 

 

 

 

 

 

Gathering (Tbtu)

 

788

 

 

606

 

 

340

 

Plant inlet natural gas volumes (Tbtu)

 

118

 

 

105

 

 

55

 

NGL production volumes (Mbbls/d) (2)

 

12

 

 

9

 

 

7

 

__________

(1)

Excludes volumes associated with Partially Owned Entities.

(2)

Annual average Mbbls/d.

Atlantic-Gulf

This segment includes the Transco interstate natural gas pipeline that extends from the Gulf of Mexico to the eastern seaboard, as well as natural gas gathering, processing and treating, production handling, and NGL fractionation assets within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,600-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, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey and Pennsylvania.

At December 31, 2014, Transco’s system had a mainline delivery capacity of approximately 6.2 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 4.5 MMdth of natural gas per day for a system-wide delivery capacity total of approximately 10.7 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 1.7 million horsepower.

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, 2014, our customers had stored in our facilities approximately 140 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.

Gulfstream

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

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. In 2014, Discovery

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completed construction of the Keathley Canyon Connector, a deepwater lateral pipeline in the central deepwater Gulf of Mexico. 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.

Gathering & Processing Assets

The following tables summarize the significant operated assets of this segment as of December 31, 2014:

 

 

 

Natural Gas Gathering Assets

 

 

 

 

 

 

Inlet

 

 

 

 

 

 

 

 

Pipeline

 

Capacity

 

Ownership

 

 

 

 

Location

 

Miles

 

(Bcf/d)

 

Interest

 

Supply Basins

Canyon Chief & Blind Faith

 

Deepwater Gulf of Mexico

 

156

 

0.5

 

100%

 

Eastern Gulf of Mexico

Seahawk

 

Deepwater Gulf of Mexico

 

115

 

0.4

 

100%

 

Western Gulf of Mexico

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

 

134

 

0.9

 

100%

 

Western Gulf of Mexico

Discovery (1)

 

Gulf of Mexico

 

573

 

1.0

 

60%

 

Central Gulf of Mexico

 

 

 

Natural Gas Processing Facilities

 

 

 

 

 

 

NGL

 

 

 

 

 

 

 

 

Inlet

 

Production

 

 

 

 

 

 

 

 

Capacity

 

Capacity

 

Ownership

 

 

 

 

Location

 

(Bcf/d)

 

(Mbbls/d)

 

Interest

 

Supply Basins

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 jointly owned investment that we operate; however, our financial statements report equity-method income from this investment based on our equity ownership percentage.

 

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 offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings.

6


 

The following tables summarize our significant crude oil transportation pipelines and production handling platforms as of December 31, 2014:

 

 

 

Crude Oil Pipelines

 

 

 

 

 

 

 

 

 

Pipeline

 

Capacity

 

Ownership

 

 

 

Miles

 

(Mbbls/d)

 

Interest

 

Supply Basins

 

 

 

 

 

 

 

 

Mountaineer & Blind Faith

 

172

 

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

 

 

Production Handling Platforms

 

 

 

 

 

 

 

 

 

 

 

Crude/NGL

 

 

 

 

 

Gas Inlet

 

Handling

 

 

 

 

 

Capacity

 

Capacity

 

Ownership

 

 

 

(MMcf/d)

 

(Mbbls/d)

 

Interest

 

Supply Basins

 

 

 

 

 

 

 

 

Devils Tower

 

210

 

60

 

100%

 

Eastern Gulf of Mexico

Gulfstar I FPS

 

172

 

80

 

51%

 

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 jointly owned investment that we operate; however, our financial statements report equity method income from this investment based on our equity ownership percentage.

 

Operating Statistics

 

 

2014

 

 

2013

 

 

2012

 

Volumes: (1)

 

 

 

 

 

 

 

 

Interstate natural gas pipeline throughput (Tbtu)

3,455

 

 

3,153

 

 

2,774

 

Gathering (Tbtu)

59

 

 

137

 

 

163

 

Plant inlet natural gas (Tbtu)

243

 

 

270

 

 

303

 

NGL production (Mbbls/d)(2)

37

 

 

34

 

 

42

 

NGL equity sales (Mbbls/d)(2)

5

 

 

7

 

 

9

 

Crude oil transportation (Mbbls/d)(2)

105

 

 

117

 

 

126

 

_____________

(1)

Excludes volumes associated with Partially Owned Entities.

(2)

Annual average Mbbls/d.

West

This segment includes the Northwest Pipeline interstate natural gas pipeline, as well as natural gas gathering and processing assets in Colorado, New Mexico, and Wyoming.

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Northwest Pipeline

Northwest Pipeline LLC (“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 Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona directly or indirectly through interconnections with other pipelines.

At December 31, 2014, Northwest Pipeline’s system, having long-term firm transportation and storage redelivery agreements of approximately 3.9 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 472,000 horsepower.

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 14.2 MMdth of natural gas, which is substantially utilized for third-party natural gas.  These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to certain customers.

Gas Gathering & Processing Assets

The following tables summarize the significant operated assets of this segment as of December 31, 2014:

 

 

 

Natural Gas Gathering Assets

 

 

 

 

 

 

Inlet

 

 

 

 

 

 

 

 

Pipeline

 

Capacity

 

Ownership

 

 

 

 

Location

 

Miles

 

(Bcf/d)

 

Interest

 

Supply Basins

Rocky Mountain

 

Wyoming

 

3,587

 

1.1

 

100%

 

Wamsutter & SW Wyoming

Four Corners

 

Colorado & New Mexico

 

3,739

 

1.8

 

100%

 

San Juan

Piceance

 

Colorado

 

328

 

1.4

 

(1)

 

Piceance

__________

(1)

We own 60 percent of a gathering system in the Ryan Gulch area, which we operate, with 140 miles of pipeline and 200 MMcf/d of inlet capacity. We own and operate 100 percent of the balance of the Piceance gathering system.

 

 

 

Natural Gas Processing Facilities

 

 

 

 

 

NGL

 

 

 

 

 

 

 

Inlet

 

Production

 

 

 

 

 

 

 

Capacity

 

Capacity

 

Ownership

 

 

 

Location

 

(Bcf/d)

 

(Mbbls/d)

 

Interest

 

Supply Basins

Echo Springs

 

Echo Springs, WY

 

0.7

 

58

 

100%

 

Wamsutter

Opal

 

Opal, WY

 

1.1

 

43

 

100%

 

SW Wyoming

Willow Creek

 

Rio Blanco County, CO

 

0.5

 

30

 

100%

 

Piceance

Ignacio

 

Ignacio, CO

 

0.5

 

29

 

100%

 

San Juan

Parachute

 

Garfield County, CO

 

1.3

 

7

 

100%

 

Piceance

Kutz

 

Bloomfield, NM

 

0.2

 

12

 

100%

 

San Juan

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

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Operating Statistics

 

 

 

2014

 

 

2013

 

 

2012

 

Volumes:

 

 

Interstate natural gas pipeline throughput (Tbtu)

 

687

 

 

717

 

 

658

 

Gathering volumes (Tbtu)

 

931

 

 

988

 

 

1,111

 

Plant inlet natural gas volumes (Tbtu)

 

1,023

 

 

1,174

 

 

1,281

 

NGL production volumes (Mbbls/d) (1)

 

79

 

 

100

 

 

160

 

NGL equity sales volumes (Mbbls/d) (1)

 

22

 

 

33

 

 

68

 

__________

(1)

Annual average Mbbls/d.

NGL & Petchem Services

Gulf Olefins

We have an 88.5 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.

Our olefins production facility has a total production capacity of 1.95 billion pounds of ethylene and 114 million pounds of propylene per year. Our feedstocks for the cracker are ethane and propane; as a result, these assets are primarily exposed to the price spread between ethane and propane, and ethylene and propylene, respectively. Ethane and propane are available for purchase from third parties and from affiliates.  We own ethane and propane pipeline systems in Louisiana that provide feedstock transportation to the Geismar plant and other third-party crackers. We also own a pipeline that has the capacity to supply 12 Mbbls/d of ethane from Discovery’s Paradis fractionator to the Geismar plant.

The Geismar plant restarted in February 2015, following an explosion and fire that occurred in 2013.  An expansion of the plant has also been completed and is planned to increase the facility’s ethylene production capacity by 600 million pounds per year.  The plant is expected to continue to ramp up to the expanded capacity through March.  Production during February and March is expected to be intermittent, resulting in limited financial contribution for the first quarter.

Our refinery grade propylene splitter has a production capacity of approximately 500 million pounds per year of propylene. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result this asset is exposed to the price spread between those commodities.

As a merchant producer of ethylene and propylene, our product sales are to customers for use in making plastics and other downstream petrochemical products destined for both domestic and export markets.

Canadian Operations

Our Canadian operations include an oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility and B/B Splitter facility, both of which are located at Redwater, Alberta, which is near Edmonton, Alberta, and the Boreal Pipeline which transports NGLs and olefins from our Fort McMurray plant to our Redwater fractionation facility.  We operate the Fort McMurray area processing plant and the Boreal Pipeline, while another party operates the Redwater facilities on our behalf.  Our Fort McMurray area facilities extract liquids from the offgas produced by a third-party oil sands bitumen upgrader. Our arrangement with the third-party upgrader is a “keep-whole” type where we remove a mix of NGLs and olefins from the offgas and return the equivalent heating value to the third-party upgrader in the form of natural gas, as well as a profit share whereby a portion of the profit above a threshold is shared with the third party. We extract, fractionate, treat, store, terminal and sell the ethane/ethylene, propane, propylene, normal butane (“butane”), isobutane/butylene (“butylene”) and condensate recovered from this process. The commodity price exposure of this asset is the spread between the price for natural gas and the NGL and olefin products we produce. We continue to be the only NGL/olefins fractionator in western Canada and the only processor of oil sands upgrader offgas. Our extraction of liquids from upgrader offgas streams allows the upgraders to burn cleaner natural gas streams and reduces their overall air emissions.

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The Fort McMurray extraction plant has processing capacity of 121 MMcf/d with the ability to recover 26 Mbbls/d of olefin and NGL products. Our Redwater fractionator has a liquids handling capacity of 26 Mbbls/d.  The B/B Splitter, which has a production capacity of 3.7 Mbbls/d of butylene and 3.7 Mbbls/d of butane, further fractionates the butylene/butane mix produced at our Redwater fractionators into separate butylene and butane products, which receive higher values and are in greater demand.  We also purchase small volumes of olefin/NGLs mixes from third-party gas processors, fractionate the olefins and NGLs at our Redwater plant and sell the resulting products. The Boreal Pipeline is a 261-mile pipeline in Canada that transports recovered NGLs and olefins from our extraction plant in Fort McMurray to our Redwater fractionation facility. The pipeline has an initial capacity of 43 Mbbls/d that can be increased to an ultimate capacity of 125 Mbbls/d with additional pump stations. Our products are sold within Canada and the United States.

Marketing Services

We market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets our 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. 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 OPPL 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 5 percent, 9 percent, and 14 percent of Pre-merger WPZ’s consolidated revenues in 2014, 2013, and 2012, respectively.

In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.

We also market olefin products to a wide range of users in the energy and petrochemical industries.  In order to meet sales contract obligations, we may purchase olefin products for resale.

Other NGL & Petchem 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 31.5 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.

We own approximately 115 miles of pipelines in the Houston Ship Channel area which transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol, and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel.  A portion of these pipelines are leased to third parties.

In addition, the first phase of the roughly 270-mile Bayou Ethane Pipeline, which operates between Texas and Louisiana, went into service in December 2014.    The pipeline connects a 57-mile pipeline segment from Mount Belvieu to Port Arthur, Texas, and a 50-mile pipeline segment from Lake Charles, Louisiana, to Port Arthur. The pipeline provides ethane transportation capacity from fractionation and storage facilities in Mont Belvieu, Texas, to the WPZ Geismar olefins plant in south Louisiana and serves customers along the way.  Phases 2 and 3 are planned to be brought into service in the second and fourth quarters of 2015, respectively.

We also own a 14.6 percent equity interest in 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, Aux Sable owns 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.

We also operate and own a 50 percent interest in OPPL. OPPL is capable of transporting 255 Mbbls/d and includes approximately 1,096 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado.  In 2013, a pipeline connection and capacity expansions were installed to accommodate volumes coming from the Bakken Shale in the Williston basin in North Dakota. 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.

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Operating Statistics

 

 

2014

 

 

2013

 

 

2012

 

Geismar ethylene sales (millions of pounds)

 

 

467

 

 

1,058

 

Canadian propylene sales (millions of pounds)

143

 

 

118

 

 

153

 

Canadian NGL sales (millions of gallons)

218

 

 

123

 

 

118

 

Service Assets, Customers, and Contracts

Pre-Merger ACMP Business

These gathering systems collect natural gas and NGLs from unconventional plays. Revenues are generated through long-term, fixed-fee gas gathering, treating, compression and processing contracts, all of which limit our direct commodity price exposure. These contracts provide us with extensive acreage dedications and generally contain the following terms:

opportunity to connect drilling pads and wells of the counterparties to these agreements within our acreage dedications to our gathering systems in each applicable region;

fee redetermination or cost of service mechanisms in the majority of our regions that are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, compression and other expenses;

minimum volume commitments (“MVC”) in the Barnett Shale region and on the Mansfield system in the Haynesville Shale region which mitigate throughput volume variability; and

price escalators in certain regions that annually increase our gathering rates.

Our contract structure creates cash flow stability across all of our basins as reflected below:

 

 

Barnett

Eagle Ford

Haynesville

Marcellus

Mid-Continent

Niobrara

Utica

Direct Commodity Price Exposure

100% Fixed Fee

100% Fixed Fee

 

100% Fixed Fee

100% Fixed Fee

100% Fixed Fee

100% Fixed Fee

100% Fixed Fee

Contract Structure

MVC & Fee Redetermina-tion

Cost of Service & Fee Tiers

Annual Fee Redetermina-tion / Fixed Fee with MVC & Fee Tiers

Cost of Service

Annual Fee Redetermina-tion

Cost of Service

Cost of Service (gathering) / Fixed Fee (processing)

Re-Contracting

20 Year Acreage Dedication

20 Year Acreage Dedication

10-20 Year Acreage Dedication

15 Year Acreage Dedication

20 Year Acreage Dedication

20 Year Acreage Dedication

15-20 Year Acreage Dedication

Volume Protection

10 Year MVC and Fee Redetermina-tions

Two Year Fee Tiers & Cost of Service

Annual Fee Redetermina-tion / 5 Year MVC & Fee Tiers

Cost of Service

Annual Fee Redetermina-tion

Cost of Service

Cost of Service (gathering only)

Inflation Protection

2.0% Fee Escalation

Cost of Service

2.5% Fee Escalation

Cost of Service

2.5% Fee Escalation

Cost of Service

Cost of Service (gathering); 1.5% Fee Escalation (processing)

Capital Protection

Fee Redetermina-tions

Cost of Service

Annual Fee Redetermina-tion (Springridge Only)

Cost of Service

Annual Fee Redetermina-tion

Cost of Service

Cost of Service (gathering only)

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We continue to see a trend by our producer customers of shifting drilling activity from dry gas shale plays, such as those in the Barnett Shale region, to NGL-rich plays, such as the Eagle Ford, Marcellus, Niobrara, Utica and Mid-Continent regions. We believe this trend is likely to continue for the foreseeable future. Our contractual protections, of minimum volume commitments and rate redetermination, work to support our financial performance in the Barnett Shale and Haynesville Shale relative to decreases in production.

The expansion of our services into the Eagle Ford, Niobrara and Utica Shale regions expanded our opportunity to serve producer customers in liquids-rich areas, including entering the business line of processing natural gas and fractionation to produce NGLs. We expect that continued construction activity in 2015 will generate significant increased gathering, processing and fractionation capacity.

The natural gas price environment has generally resulted in lower drilling activity in our dry gas shale plays, resulting in fewer new well connections in certain of the areas in which we operate. We have no control over this activity. In addition, commodity price movements will affect production rates and the level of capital invested by our producer customers in the exploration for and development of new natural gas reserves. Our opportunity to connect new wells to our systems is dependent on natural gas producers and shippers.

For the years ended December 31, 2014, 2013 and 2012, Chesapeake Energy Corporation (“Chesapeake”) accounted for approximately 82 percent, 84 percent and 81 percent, respectively, of Pre-merger ACMP’s revenues.

Pre-merger WPZ Businesses

The assets acquired in the Merger primarily provide services for interstate natural gas transportation; gathering, processing, and treating; and crude oil transportation, production handling, and olefins production.

Interstate Natural Gas Pipeline Assets

Our interstate natural gas pipelines are subject to regulation by the FERC, and as such, our rates and charges for the transportation of natural gas in interstate commerce are subject to regulation. The rates are established through the FERC’s ratemaking process.

Our interstate natural gas pipelines transport and store 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. We have firm transportation and storage contracts that are generally long-term contracts with various expiration dates and account for the major portion of our regulated businesses. Additionally, we offer storage services and interruptible firm transportation services under short-term agreements.

Gathering, Processing and Treating Assets

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

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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. Beginning in 2013, a portion of our fee-based processing revenues includes a share of the margins on the NGLs produced. For the year ended December 31, 2014, 79 percent of the Pre-merger WPZ 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 price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2014, 19 percent of the Pre-merger WPZ NGL production volumes were under keep-whole contracts.

Percent-of-Liquids:  Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the Btu content of the retained NGLs that were extracted during processing, 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, 2014, 2 percent of the Pre-merger WPZ 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 2014, our facilities gathered and processed gas for approximately 220 customers. Our top five 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.

 

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;

Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;

Prices impacting our commodity-based activities.

Crude Oil Transportation and Production Handling Assets

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. 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.  Fixed fees associated with the resident production at our Gulfstar One facility are recognized as the guaranteed capacity is made available.

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Significant Service Revenues

Subsequent to the Merger, we expect revenues from regulated natural gas transportation and storage and gathering and processing to each exceed 10 percent of our consolidated revenues.

REGULATORY MATTERS

Gas Pipeline and Midstream Gathering

FERC

Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (“NGA”) and under the Natural Gas Policy Act of 1978, 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. 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.

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. 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.

We also own interests in and operate 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. In addition, we own a 50 percent interest, and operate 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.

Pipeline Safety

Our gas pipelines are 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 Jobs Creation Act of 2011 (“Pipeline Safety Act”), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The United States Department of Transportation (“USDOT”) administers federal pipeline safety laws.

Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.

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Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations. A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal law. However, USDOT is completing a congressionally-mandated review of the adequacy of the existing federal and state regulations for gathering lines and has indicated that it may apply additional safety standards to rural gas gathering lines in the future.

States are preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by USDOT to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety.

On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.

Pipeline integrity regulations

We have developed an enterprise wide Gas 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 gas 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 time frames. In meeting the integrity regulations, we have identified high consequence areas and developed baseline assessment plans. We completed the assessments within the required time frames, with two exceptions which were reported to PHMSA. Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames required by the rule. We estimate that the cost to be incurred in 2015 associated with this program to be approximately $57 million, most of which we expect to be capital expenditures. 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 Northwest Pipeline’s and Transco’s rates.

We developed a Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002.  The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect high consequence areas (whether onshore or offshore) in the event of pipeline failure.  The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames.  In meeting the integrity regulations, we utilized government defined high consequence areas and developed baseline assessment plans.  We completed assessments within the required time frames. We estimate that the cost to be incurred in 2015 associated with this program to be approximately $2 million, most of which we expect to be included in 2015 operating expenses.  Ongoing periodic reassessments and initial assessments of any new high consequence areas are expected to be completed within the time frames 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.

State Gathering Regulation

Our onshore midstream gathering operations are subject to regulation by states in which we operate. Of the states where our midstream business gathers gas, currently only Texas and New York actively regulate gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement.  New York has specific regulations pertaining to the design, construction and operations of gathering lines in New York.  

OCSLA

Our offshore midstream gathering is subject to the Outer Continental Shelf Lands Act (“OCSLA”). 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

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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.”

Olefins

Our olefins assets are regulated by the Louisiana Department of Environmental Quality, the Texas Railroad Commission, and various other state and federal entities regarding our liquids pipelines.

Our olefins assets are also subject to the liquid pipeline safety and integrity regulations previously discussed above since both Louisiana and Texas have adopted the integrity management regulations defined by PHMSA.

See Note 13 – Commitments and Contingencies of our Notes to Consolidated Financial Statements for further details on our regulatory matters. For additional information regarding regulatory matters, please also refer to “Risk Factors — "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."

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 – Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures and could exceed expectations” and “Item 3. Legal Proceedings - Environmental” and “Environmental obligations” in Note 13 – Commitments and Contingencies of our Notes to Consolidated Financial Statements.

COMPETITION

Gathering and Processing

Generally, our gathering and processing agreements are long-term agreements and many include acreage dedication. We primarily face competition to the extent these agreements approach renewal or new volume opportunities arise. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. 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.

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Interstate Natural Gas Pipelines

The natural gas industry has a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity.  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 connect growing supply to market has increased.

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. The state plans have, in some cases, discouraged LDCs from signing long-term contracts for new capacity.

States have developed new 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.

Olefins Production

Ethylene and propylene markets, and therefore our olefins business, compete in a worldwide marketplace. Due to our NGL feedstock position at Geismar, we expect to benefit from the lower cost position in North America versus other crude based feedstocks worldwide. The majority of North American olefins producers have significant downstream petrochemical manufacturing for plastics and other products. As such, they buy or sell ethylene and propylene as required. We operate as a merchant seller of olefins with no downstream manufacturing, and therefore can be either a supplier or a competitor at any given time to these other companies. We compete on the basis of service, price and availability of the products we produce.

For additional information regarding competition for our services or otherwise affecting our business, please refer to “Risk Factors - 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 and demand for those supplies in our traditional markets, “-Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results,” and “- We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay distributions, and our ability to grow.”

EMPLOYEES

We do not have any employees. We are managed and operated by the directors and officers of our general partner. At February 1, 2015, our general partner or its affiliates employed approximately 6,742 full-time employees, a substantial portion of which support our operations and provide services to us. Additionally, our general partner and its affiliates provide general and administrative services to us. For further information, please read “Item 10. Directors, Executive Officers and Corporate Governance” and “Item 13. Certain Relationships and Related Transactions, and Director Independence — Reimbursement of Expenses of our General Partner.”

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

As of December 31, 2014, Pre-merger ACMP had 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. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

 

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,” “assumes,” “guidance,” “outlook,” “in service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

 

the levels of cash distributions to unitholders;

our and Williams’ (as defined below) future credit ratings;

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;

seasonality of certain business components;

natural gas, natural gas liquids and olefins prices, supply and demand; and

demand for our services.

 

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 pay current and expected levels of cash distributions, if any, following establishment of cash reserves and payment of fees and expenses, including payments to our general partner;

availability of supplies, market demand, and volatility of prices;

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 and the effects of competition;

whether we are able to successfully identify, evaluate and execute investment opportunities;

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

development of alternative energy sources;

the impact of operational and development hazards and unforeseen interruptions;

our ability to recover expected insurance proceeds related to the Geismar plant;

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costs of, changes in, or the results of laws, government regulations (including safety and environmental regulations), 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 financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital;

the amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

risks associated with weather and natural phenomena, including climate conditions;

acts of terrorism, including cybersecurity threats and related disruptions;

additional risks described in our filings with the Securities and Exchange Commission.

 

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

 

In addition to causing our actual results to differ, the factors 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.

Prices for NGLs, olefins, natural gas, oil and other commodities, are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our 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, olefins, natural gas, oil, or other commodities, and the differences between prices of these commodities and could be materially adversely affected by an extended period of current low commodity prices, or a further decline in commodity prices. 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. Price volatility can also have an adverse effect on our business, results of operations, financial condition and cash flows and our ability to make cash distributions to unitholders.

 

The markets for NGLs, olefins, natural gas, oil and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:

 

worldwide and domestic supplies of and demand for natural gas, NGLs, olefins, oil, and related commodities;

turmoil in the Middle East and other producing regions;

the activities of the Organization of Petroleum Exporting Countries;

the level of consumer demand;

the price and availability of other types of fuels or feedstocks;

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; and

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

 

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 and demand for those supplies in our traditional markets.

 

Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas and NGL reserves connected to our systems and processing facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, or the lack of available capital could adversely affect the development and production of additional natural gas reserves, the installation of gathering, storage, and pipeline transportation facilities and the import and export of natural gas supplies. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation and processing facilities.

 

Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils or nuclear energy could reduce demand for natural gas in our markets and have an adverse effect on our business.

A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition and results of operations.

 

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

 

As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We have both a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner. Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines and facilities, NGL transportation, fractionation or storage facilities or olefins processing facilities, as well as the expansion of existing facilities. We also face all the risks associated with construction. These risks include the inability to obtain skilled labor, equipment, materials, permits, rights-of-way and other required inputs in a timely manner such that projects are completed on time and the risk that construction cost overruns could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:

 

changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated;

we could be required to contribute additional capital to support acquired businesses or assets;

we may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;

acquisitions could disrupt our ongoing business, distract management,  divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls and procedures; and

acquisitions and capital projects may require substantial new capital, either by the issuance of debt or equity, and we may not be able to access capital markets or obtain acceptable terms.

 

If realized, any of these risks could have an adverse impact on our results of operations, including the possible impairment of our assets, and could also have an adverse impact on our financial position, cash flows and our ability to

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make cash distributions to unitholders.

 

We do not own all of the interests in the 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 generally 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. Following the closing of the Merger, our investments in the Partially Owned Entities accounted for approximately 8 percent of our total consolidated assets. Conflicts of interest may arise in the future between us, on the one hand, and our Partially Owned Entities, on the other hand, with regard to our Partially Owned Entities’ governance, business, and operations. If a conflict of interest arises between us and a Partially Owned Entity, other owners may control the Partially Owned Entity’s actions with respect to such matter (subject to certain limitations), which could be detrimental to our business. 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, financial condition, results of operations and cash flows and our ability to make cash distributions to unitholders.

 

We may not have sufficient cash from operations to enable us to pay cash distributions or to maintain current or expected levels of cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

 

We may not have sufficient cash each quarter to pay cash distributions or maintain current or expected levels of cash distributions. The actual 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 amount of cash that our subsidiaries and the Partially Owned Entities distribute to us;

the amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;

the restrictions contained in our indentures and credit facility and our debt service requirements; and

the cost of acquisitions, if any.

 

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. A failure to pay distributions or to pay distributions at expected levels could result in a loss of investor confidence, reputational damage and a decrease in the value of our unit price.

 

We are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our conflicts committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.

 

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

 

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

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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 strategic investments or acquisitions. Our competitors 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. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition and cash flows and our ability to make cash distributions to unitholders.

 

We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay distributions, and our ability to grow.

 

We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers, or otherwise increase the contracted volumes of natural gas provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay distributions could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:

 

the level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy;

natural gas, NGL, and olefins prices, demand, availability and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;

general economic, financial markets and industry conditions;

the effects of regulation on us, our customers and our contracting practices; and

our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.

 

Some of our businesses, including our Access Midstream business, are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers.

 

Some of our businesses may be dependent on a small number of suppliers for delivery of critical goods or services.  For instance, pursuant to a compression services agreement, our Access Midstream business receives a substantial portion of its compression capacity on certain gathering systems from EXLP Operating LLC (“Exterran Operating”). Exterran Operating has, until December 31, 2020, the exclusive right to provide our Access Midstream business with compression services on certain gas gathering systems located in Wyoming, Texas, Oklahoma, Louisiana, Kansas and Arkansas, in return for the payment of specified monthly rates for the services provided, subject to an annual escalation provision. If a supplier on which we depend were to fail to timely supply required goods and services we may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If we are unable to adequately diversify or otherwise mitigate such supplier concentration risks and such risks were realized, we could be subject to reduced revenues, increased expenses, which could have a material adverse effect on our financial condition, results of operation and cash flows and our ability to make cash distributions to unitholders.  

 

We conduct certain operations through joint ventures that may limit our operational flexibility or require us to make additional capital contributions.

 

Some of our operations are conducted through joint venture arrangements, and we may enter additional joint ventures in the future. In a joint venture arrangement, we have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases:

 

we have limited ability to influence or control certain day to day activities affecting the operations;

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we cannot control the amount of capital expenditures that we are required to fund with respect to these operations;

we are dependent on third parties to fund their required share of capital expenditures;

we may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; and

we may be forced to offer rights of participation to other joint venture participants in the area of mutual interest.

 

In addition, our joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance and ability of third parties to satisfy their obligations under joint venture arrangements is outside our control. If these third parties do not satisfy their obligations under these arrangements, our business may be adversely affected. Our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

 

If we fail to make a required capital contribution under the applicable governing provisions of our joint venture arrangements, we could be deemed to be in default under the joint venture agreement. Our joint venture partners may be permitted to fund any deficiency resulting from our failure to make such capital contribution, which would result in a dilution of our ownership interest, or our joint venture partners may have the option to purchase all of our existing interest in the subject joint venture.

 

The risks described above or the failure to continue our joint ventures, or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct our operation that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.

 

Our operations are subject to operational hazards and unforeseen interruptions.

 

There are operational risks associated with the gathering, transporting, storage, processing and treating of natural gas, the fractionation, transportation and storage of NGLs, the processing of olefins, and crude oil transportation and production handling, including:

 

aging infrastructure and mechanical problems;

damages to pipelines and pipeline blockages or other pipeline interruptions;

uncontrolled releases of natural gas (including sour gas), NGLs, olefins products, 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;

truck and rail loading and unloading; and

operating in a marine environment.

 

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage and substantial losses to us. 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. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

 

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

 

In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. Williams currently maintains excess liability insurance with limits of $695 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.

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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 be 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, but 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.

 

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

 

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

The time required to return our Geismar plant to full expanded production following the explosion and fire at the facility on June 13, 2013, and the amount and timing of insurance recoveries related such incident could be materially different than we anticipate and could cause our financial results and levels of distributions to be materially different than we project.

 

Our projections of financial results and expected levels of distributions are based on numerous assumptions and estimates including, but not limited to, the time required to return the Geismar plant to full expanded production and the amount and timing of insurance recoveries related to the June 13, 2013 explosion and fire at our Geismar plant. Our insurers continue to evaluate our claims and have raised questions around key assumptions involving our business interruption claim; as a result, the insurers have elected to make a partial payment pending further assessment of these issues. Although we currently expect to recover most of the limits under a $500 million insurance program related to the Geismar incident, there can be no assurance that we will recover the full policy limits. Our total receipts from our insurers to date are $296.25 million. Our financial results and levels of distributions could be materially different than we project if our assumptions and estimates related to the incident are materially different than actual outcomes.

 

Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.

 

Our assets and operations, especially those located offshore and our customers’ assets and operations, can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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

 

Given the volatile nature of the commodities we transport, process, store and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets 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 business, 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, practices and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems 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 to physical locations or information.

 

Breaches in our information technology infrastructure or physical facilities, or other disruptions including those arising from theft, vandalism, fraud or unethical conduct, could result in damage to our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

 

The natural gas sales, transportation and storage operations of our gas pipelines are subject to regulation by the 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.

 

In addition to regulation by other federal, state and local regulatory authorities, under the Natural Gas Act of 1938, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:

 

transportation and sale for resale of natural gas in interstate commerce;

rates, operating terms, types of services and conditions of service;

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; and

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

 

Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, 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.

 

Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities and expenditures that could exceed expectations.

 

Our operations are subject to extensive federal, state, tribal and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities. 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, fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling as well as waste disposal practices and construction activities. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations and delays in granting permits.

 

Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, 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

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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.

 

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.

 

In addition, climate change regulations and the costs associated with the regulation of emissions of greenhouse gases (“GHGs”) have the potential to affect our business. Regulatory actions by the Environmental Protection Agency or the passage of new 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 our GHG compliance 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. Climate change and GHG regulation could also reduce demand for our services.

 

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, financial condition and cash flows and our ability to make cash distributions to unitholders.

 

The operation of our businesses might 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 the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations and court proceedings, including litigation of energy industry matters. 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 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 and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be

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material and may not be covered fully or at all by insurance.

 

In addition, existing regulations might be revised or reinterpreted, and new laws and regulations, including those pertaining to oil and gas hedging and cash collateral requirements, might be adopted or become applicable to us, our customers or our business activities. If new laws or regulations are imposed relating to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are required or imposed, including those 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.

 

Certain of our gas pipeline 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.

 

Our gas pipelines 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 our pipelines 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 operating results for certain components of our business might fluctuate on a seasonal 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 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, financial condition and cash flows and our ability to make cash distributions to unitholders.

 

Difficult conditions in the global financial 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 global financial markets. Included among these potential negative impacts are industrial or economic contraction leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. 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. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above.

 

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.

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

 

A downgrade of our credit ratings might increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition our ability to access capital markets could be limited by a downgrade of our credit ratings.

 

Credit rating agencies perform independent analysis when assigning credit ratings. This analysis includes a number of criteria such as 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 subject to revision or withdrawal at any time by the ratings agencies.

 

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. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. 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.

 

Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.

 

Following the closing of the Merger, our total outstanding long-term debt (which does not include commercial paper notes), was $16.3 billion, representing approximately 36 percent of our total book capitalization.  

The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ debt agreements contain similar covenants with respect to Williams and its subsidiaries, including in some cases us.

 

Our debt service obligations and the covenants described above could have important consequences. For example, they could:

 

make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general partnership purposes or other purposes;

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, the payment of distributions, general partnership purposes or other purposes; and

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.

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Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. 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<