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 comply with these covenants, meet our debt service obligations or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

 

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources.”

 

Our ability to obtain credit in the future could be affected by Williams’ credit ratings.

 

Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans, dividends and distributions paid to it by its subsidiaries. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as loans or contributions to capital. Due to our relationship with Williams, our ability to obtain credit will be affected by Williams’ credit ratings. Williams has been assigned investment-grade credit ratings at two of the three ratings agencies and sub-investment-grade at the third rating agency. If Williams were to experience a deterioration in its credit standing or financial condition, our access to credit and our ratings could be adversely affected. Any future downgrading of a Williams credit rating could also result in a downgrading of our credit rating. A downgrading of a Williams credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

 

Institutional knowledge residing with current employees nearing retirement eligibility or with our former employees might not be adequately preserved.

 

We expect that a significant percentage of employees will become eligible for retirement over the next several years. In certain areas of our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age or their services are no longer available to Williams, Williams may not be able to replace them with employees of comparable knowledge and experience. In addition, Williams may not be able to retain or recruit other qualified individuals, and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.

 

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

 

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter, into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.

 

Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.

 

We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic, political and legal conditions and regulatory environment in the countries in which we have interests or in which we might pursue acquisition or investment opportunities present risks that are different

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from or greater than those in the United States. These risks include, among others, delays in construction and interruption of business, as well as risks of renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, including with respect to the prices we realize for the commodities we produce and sell. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.

 

Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.

 

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

 

We rely on Williams for certain services necessary for us to be able to conduct our business. Certain of Williams’ accounting and information technology functions that we rely on are currently provided by third party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.

 

The execution of the integration strategy following the Merger may not be successful.

 

The ultimate success of the Merger will depend, in part, on the ability of the combined company to realize the anticipated benefits from combining these formerly separate businesses. Realizing the benefits of the Merger will depend in part on the effective integration of assets, operations, functions and personnel while maintaining adequate focus on our core businesses. Any expected cost savings, economies of scale, enhanced liquidity or other operational efficiencies, as well as revenue enhancement opportunities, or other synergies, may not occur.

 

Our management team expects to face challenges inherent in integrating certain Pre-merger Access Midstream operations into the West and Northeast G&P operating areas as well as integrating certain functions that support our business such as environmental, health and safety, engineering and construction and business development. If management is unable to minimize the potential disruption of our ongoing business and the distraction of management during the integration process, the anticipated benefits of the Merger may not be realized or may only be realized to a lesser extent than expected. In addition, the inability to successfully manage the integration could have an adverse effect on us.

 

The integration process could result in the loss of key employees, as well as the disruption of each of our ongoing businesses or the creation of inconsistencies in standards, controls, procedures and policies. Any or all of those occurrences could adversely affect our ability to maintain relationships with service providers, customers and employees or to achieve the anticipated benefits of the Merger.

 

Integration may also result in additional and unforeseen expenses, which could reduce the anticipated benefits of the Merger and materially and adversely affect our business, operating results and financial condition.

 

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

 

As we have no employees, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs in defined benefit pension plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of the costs of other postretirement benefit plans covering certain eligible participants providing services to us. The timing and amount of our allocations under the

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defined benefit pension plans depend upon a number of factors that Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition and results of operations.

 

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

 

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.

 

Risks Inherent in an Investment in Us

 

Williams, through its ownership of Access Midstream Ventures, L.L.C. (“Access Midstream Ventures”), indirectly owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner has limited duties to us and it and its affiliates, including Williams and Access Midstream Ventures, and may have conflicts of interest with us and may favor their own interests to the detriment of us and our common unitholders.

 

Access Midstream Ventures, which is owned and controlled by Williams, owns and controls our general partner and appoints all of the officers and directors of our general partner, some of whom are also officers and directors of Williams and Access Midstream Ventures. Although our general partner has a contractual duty when acting in its capacity as our general partner to act in a way that it believes is in our best interest, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its sole member, Access Midstream Ventures, and Williams. Conflicts of interest may arise between Williams, Access Midstream Ventures and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Williams and/or Access Midstream Ventures over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

 

Neither our partnership agreement nor any other agreement requires Williams or Access Midstream Ventures to pursue a business strategy that favors us. For example, Williams’ directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Williams, which may be contrary to our best interests and the interests of our unitholders.  Further, Williams is not a party to any agreement that prohibits it from competing against us in our gas gathering and processing operations and for gathering, processing and acquisition opportunities. It is possible that Williams could preclude us from pursuing opportunities in which Williams has a competitive interest.

Our general partner is allowed to take into account the interests of parties other than us, such as Williams or Access Midstream Ventures, in resolving conflicts of interest.

Our partnership agreement limits the liability of and reduces the duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Williams owns units representing approximately 59 percent of the limited partner interest in us.  If a vote of our limited partners is required in which Williams is entitled to vote, Williams will be able to vote its units in accordance with its own interests, which may be contrary to our interests or the interests of our unitholders.

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

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

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Our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances and, in some instances, with the concurrence of the conflicts committee of its board of directors, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner with respect to its incentive distribution right.

Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

Our partnership agreement permits us to classify up to $120 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of its general partner interest or the incentive distribution rights.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our general partner, in certain circumstances, has limited liability regarding our contractual and other obligations and in some circumstances is required to be indemnified by us.

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80 percent of the common units.

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

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

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

 

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

 

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

 

Permits our general partner to make a number of decisions in its individual capacity as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include whether to exercise of its limited call right, how to exercise its voting rights with respect to the units it owns, whether to exercise its registration rights, its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement, whether to elect to reset target distribution levels and how to allocate business opportunities among us and its affiliates;

Provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

Generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

Provides that our general partner, its affiliates and their respective officers and directors will not be liable for monetary damages to us or our limited partners or assignees for any acts or omissions unless there has been a final and nonappealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was criminal;

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Provides that in resolving conflicts of interest, if Special Approval (as defined in our partnership agreement) is sought or if neither Special Approval nor unitholder approval is sought and the board of directors of our general partner determines that the resolution or course of action taken with respect to a conflict of interest satisfies certain standards set forth in our partnership agreement, it will be presumed that in making its decision our general partner or the conflicts committee of its board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

 

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

 

Affiliates of our general partner, including Williams, are not limited in their ability to compete with us and may exclude us from opportunities with which they are involved. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams, and these persons will owe fiduciary duties to Williams.

 

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

 

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

 

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

 

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

 

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

 

Even if public unitholders are dissatisfied, they have little ability to remove our general partner without the consent of Williams.

 

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

 

33


 

Furthermore, if our public unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding limited partner units is required to remove our general partner. Following the closing of the Merger, Williams and its affiliates own approximately 59 percent of our outstanding limited partner units and, as a result, our public unitholders cannot remove our general partner without the consent of Williams.

 

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

 

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement effectively permits a change of control without unitholder consent.  The new owner of our general partner would then be in a position to replace our general partner’s board of directors and officers with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

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

 

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

 

our unitholders’ proportionate ownership interest in us will decrease;

the amount of cash available to pay distributions on each unit may decrease;

the ratio of taxable income to distributions may decrease;

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

the market price of the common units may decline.

 

The existence and eventual sale of common units or securities convertible into common units, whether held by Williams or which may be issued in acquisitions and eligible for future sale, may adversely affect the price of our common units.

Williams holds 339,664,088 common units, representing approximately 58 percent of our common units outstanding. Williams may, from time to time, sell all or a portion of its common units. We may issue additional common units to unaffiliated third parties in connection with future acquisitions. Sales of substantial amounts of common units by Williams or third parties, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48 percent) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner’s general partner interest in us (currently two percent) will be maintained at the percentage that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset

34


 

election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.

 

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

 

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. Our general partner may assign this right to any of its affiliates or to us. As a result, nonaffiliated unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered under the Exchange Act, we would no longer be subject to the reporting requirements of such Act.

 

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

 

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings, to acquire information about our operations and to influence the manner or direction of management.

 

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

 

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

 

we were conducting business in a state but had not complied with that particular state’s partnership statute; or

your rights to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

 

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

 

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

 

35


 

Tax Risks

 

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

 

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes.

 

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

 

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35 percent, and would likely pay state and local income tax at varying rates. Distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distributions to unitholders would be reduced. Therefore, if we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to unitholders, likely causing a substantial reduction in the value of the common units.

 

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

 

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

 

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021.  From time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect certain publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of the common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing United States Department of the Treasury (“Treasury”) regulations, and although the Treasury issued proposed regulations allowing a similar monthly simplifying convention, such regulations are not final and do not

36


 

specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

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

 

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

 

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

 

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

 

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

 

If a unitholder sells its common units, it will recognize gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income that was allocated to a unitholder for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its common units, the unitholder may incur a U.S. federal income tax liability in excess of the amount of cash it received from the sale.

 

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

 

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

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

 

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

 

37


 

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

 

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the unitholder does not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax. It is the unitholder’s responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

 

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

 

We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all partners, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to its partners for the tax years in the fiscal year during which the termination occurs.

 

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

 

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

 

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

 

A unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

 

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, items of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as

38


 

ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller to effect a short sale of common units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Please read “Item 1. Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others.

Item 3. Legal Proceedings

Environmental

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

In November 2013, we became aware of deficiencies with the air permit for the Ft. Beeler gas processing facility located in West Virginia.  We notified the EPA and the West Virginia Department of Environmental Protection and are working to bring the Ft. Beeler facility into full compliance.

On November 7, 2014, the New Mexico Environment Department’s Air Quality Bureau (“Bureau”) issued a Notice of Violation (“NOV”) to Williams Four Corners LLC (“Williams”) for the El Cedro Gas Treating Plant alleging a failure by Williams to limit emissions to the allowable emission rates in violation of permit requirements, and for the failure to timely file initial and excess emission reports.  The NOV followed an April 2014 inspection at the plant.  Williams is providing Corrective Action Verification information to the Bureau and has entered into a Tolling Agreement to allow for additional time – until May 31, 2015 – for the parties to resolve the alleged violations.   

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (“EPA”), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2014, Pre-merger WPZ had accrued liabilities totaling $19 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, one hour nitrogen dioxide emission limits, and new air quality standards impacting storage vessels, pressure valves, and compressors. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

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Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2014, Pre-merger WPZ had accrued liabilities of $11 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2014, Pre-merger WPZ had accrued liabilities totaling $8 million for these costs.

Geismar Incident  

On June 13, 2013, an explosion and fire occurred at our Geismar olefins plant. The incident (“Geismar Incident”) rendered the facility temporarily inoperable and resulted in significant human, financial, and operational effects. As a result of the Geismar Incident, there were two fatalities and numerous individuals (including employees and contractors) reported injuries, which varied from minor to serious.  We are addressing the following matters in connection with the Geismar Incident.

On June 28, 2013, the Louisiana Department of Environmental Quality (“LDEQ”) issued a Consolidated Compliance Order & Notice of Potential Penalty that consolidates claims of unpermitted emissions and other deviations under the Clean Air Act that the parties had been negotiating since 2010 and alleged unpermitted emissions arising from the Geismar Incident.  On November 12, 2014, the LDEQ issued a Notice of Potential Penalty for the alleged violations.  LDEQ then issued a Penalty Assessment on November 21, 2014.  We paid a penalty of $194,306 on December 1, 2014.

On October 21, 2013, the EPA issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through 28, 2013.  The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters.  On June 16, 2014, we received a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014.  The EPA could issue penalties pertaining to final determinations.

On December 11, 2013, the Occupational Safety and Health Administration (“OSHA”) issued citations in connection with its investigation of the June 13, 2013 incident, which included a Notice of Penalty for $99,000.  We settled the citations with OSHA on September 12, 2014 for a penalty of $36,000.  The settlement was judicially approved on September 23, 2014, and the order approving settlement became a final order on November 10, 2014.  On June 25, 2013, OSHA commenced a second inspection pursuant to its Refinery and Chemical National Emphasis Program (“NEP”).  OSHA did not issue a citation in connection with this NEP inspection and there is a six month statute of limitations for violation of the Occupational Safety and Health Act of 1970 or regulations promulgated under such act.

Additionally, multiple lawsuits, including class actions for alleged offsite impacts, property damage, customer claims, and personal injury, have been filed against various of our subsidiaries.  Due to ongoing litigation concerning defenses to liability and limited information as to the nature and extent of plaintiffs’ damages, we cannot reasonably estimate a range of potential loss related to these contingencies at this time.

Other

The additional information called for by this item is provided in Note 13 – Commitments and Contingencies to the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements and Supplementary Data of this report, which information is incorporated by reference into this item.

Item 4. Mine Safety Disclosures

Not applicable.

 

 

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Part II

 

ITEM  5.

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

Market Information

On February 3, 2015, following completion of the Merger, the ticker symbol for our common units listed on the NYSE was changed from “ACMP” to “WPZ”. The following table sets forth the high and low sales prices of the common units as well as the amount of cash distributions declared and paid on the common units during each quarter over the last two fiscal years.

 

 

Common Units

 

  

 

 

 

High

 

  

Low

 

  

Distribution per
common unit

 

Year ended December 31, 2014

 

 

 

  

 

 

 

  

 

 

 

Fourth Quarter

$

66.79

  

  

$

49.01

  

  

$

0.8500

  

Third Quarter

 

65.90

  

  

 

57.78

  

  

 

0.6150

  

Second Quarter

 

66.71

  

  

 

56.31

  

  

 

0.5950

  

First Quarter

 

59.19

  

  

 

53.63

  

  

 

0.5750

  

Year ended December 31, 2013

 

 

 

  

 

 

 

  

 

 

 

Fourth Quarter

$

57.48

  

  

$

46.66

  

  

$

0.5550

  

Third Quarter

 

49.29

  

  

 

44.75

  

  

 

0.5350

  

Second Quarter

 

48.74

  

  

 

38.00

  

  

 

0.4850

  

First Quarter

 

41.68

  

  

 

33.76

  

  

 

0.4675

  

Following the Merger on February 2, 2015, the last reported sale price of our common units on the NYSE under the symbol “WPZ” on February 13, 2015 was $47.43. As of February 13, 2015, there were approximately 108 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We have also issued 13,948,171 Class B units and ownership interests in the general partner, for which there is no established public trading market. All of the Class B units and general partner interests are held by affiliates of our general partner. Class B units are entitled to paid-in-kind distributions.

Selected Information from our Partnership Agreement

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions, paid-in-kind distributions and incentive distribution rights.

Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter less the amount of cash reserves established by our general partner to provide for the proper conduct of our business, including reserves to fund future capital expenditures, to comply with applicable laws, or our debt instruments and other agreements, or to provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.

Conversion of Subordinated Units

Upon payment of the cash distribution for the second quarter of 2013, the subordination period with respect to our 69,076,122 subordinated units expired and all outstanding subordinated units converted into common units on a one-for-one basis on August 15, 2013.  Prior to the conversion date, the subordinated units were not entitled to receive any distributions until the common units received the minimum quarterly distribution of $0.3375 per common unit plus any arrearages from prior quarters. The conversion did not impact the total number of our outstanding units representing limited partner interests.

41


 

Class B Units

The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit is the quotient of the quarterly distribution paid to our common units by the volume-weighted average price of the common units for the 30-day period prior to the declaration of the quarterly distribution to common units. Effective on the business day after the record date for the distribution on common units for the fiscal quarter ending December 31, 2014, each Class B unit became convertible at the election of either us or the holder of such Class B unit into a common unit on a one-for-one basis. In the event of our liquidation, the holder of Class B units will be entitled to receive out of our assets available for distribution to the partners the positive balance in each such holder’s capital account in respect of such Class B units, determined after allocating our net income or net loss among the partners. All Class B units are held indirectly by an affiliate of our general partner.

Class C Units

Under our partnership agreement, the Class C units became convertible into common units on a one-for-one basis at the election of either us or the holders of the Class C units on February 10, 2014 (the first business day following the record date for the Partnership’s 2013 fourth quarter cash distribution).  After February 10, 2014, we received notice from certain of the GIP II Entities and Williams, as holders of the Class C units, of their election to convert all of the Class C units.  All of the outstanding Class C units were converted into common units on a one-for-one basis effective February 19, 2014.  The common units resulting from this conversion will participate pro rata with the other common units in quarterly distributions.  The conversion did not impact the total number of our outstanding units representing limited partner interests.

General Partner Interest and Incentive Distribution Rights

Our general partner is entitled to two percent of all quarterly distributions that we make after inception and prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its two percent general partner interest. Our general partner’s initial two percent interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding Class B units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its two percent general partner interest.

Other Securities Matters

Securities Authorized for Issuance Under Equity Compensation Plans.

Our general partner has adopted the Access Midstream Long-Term Incentive Plan, or “LTIP,” which permits the issuance of up to 3,649,927 units, as adjusted to reflect the Pre-merger Unit Split, subject to adjustment for certain events. Phantom unit grants were made to each of the independent directors of our general partner in 2014 under the LTIP. Please read the information under Item 12 of this annual report, which is incorporated by reference into this Item 5.

In addition, as a result of the Merger we assumed the Williams Partners GP LLC Long-Term Incentive Plan which was maintained by the general partner of Pre-merger WPZ (“Pre-merger WPZ LTIP”).  Prior to the Merger, the Pre-merger WPZ LTIP initially permitted the issuance of up to 700,000 Pre-merger WPZ common units.  The number of awards that may be issued under this plan in the future is subject to conversion to our securities by our general partner’s Board of Directors consistent with the ratio of the Merger Exchange.  No awards were outstanding under the Pre-merger WPZ LTIP in 2014 and no awards are currently outstanding.

Unregistered Securities

On December 20, 2012, we sold (i) 5,929,025 Class B Units to each of Williams and the GIP II Entities and (ii) 5,599,634 Class C Units to each of Williams and the GIP II Entities, in each case pursuant to that certain Subscription Agreement described and included in our Current Report on Form 8-K filed December 12, 2012. We received aggregate proceeds of approximately $700.0 million in exchange for the sale of the Class B Units and the Class C Units, inclusive of the capital contribution made by the general partner to maintain its two percent interest in us.

In connection with public offerings of our common units in March 2013 and December 2012, the general partner made additional capital contributions to us of $8.4 million and $12.1 million, respectively, to maintain its two percent

42


 

interest in us. These issuances were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

On August 15, 2013, all of our existing subordinated units were converted into common units on a one-for-one basis.  On February 19, 2014, all of our existing Class C units were converted into common units on a one-for-one basis.  

In connection with public offerings under our Equity Distribution Agreement during the fourth quarter of 2013, the first quarter of 2014 and the second quarter of 2014, our general partner made additional capital contributions to us of $1.0 million on February 14, 2014, $0.1 million on May 15, 2014 and $0.9 million on August 14, 2014, respectively, to maintain its two percent interest in us. These issuances were exempt from registration under Section 4(2) of the Securities Act of 1933, as amended.

During the fiscal year ended December 31, 2014, we did not sell or issue any other equity securities without the registration of these securities under the Securities Act of 1933, as amended, in reliance on exemptions from such registration requirements, that have not been previously disclosed in a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.

 

ITEM 6. Selected Financial Data

The following table shows our selected financial and operating data for Pre-merger ACMP for the periods and as of the dates indicated, which is derived from our consolidated financial statements.

The table should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this Annual Report.

 

 

Year Ended
December 31,
2014

 

 

Year Ended
December 31,
2013

 

 

Year Ended
December 31,
2012

 

 

Year Ended
December 31,
2011

 

 

Year Ended
December 31,
2010

 

 

 

 

($ in thousands) 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues(1)

$

1,378,939

 

 

$

1,073,222

 

 

$

608,447

 

 

$

565,929

 

 

$

459,153

 

 

Operating expenses

 

427,589

 

 

 

338,716

 

 

 

197,639

 

 

 

176,851

 

 

 

133,293

 

 

Depreciation and amortization expense

 

314,758

 

 

 

296,179

 

 

 

165,517

 

 

 

136,169

 

 

 

88,601

 

 

General and administrative expense

 

202,796

 

 

 

104,332

 

 

 

67,579

 

 

 

40,380

 

 

 

31,992

 

 

Other operating (income) expense

 

24,123

 

 

 

2,092

 

 

 

(766

)

 

 

739

 

 

 

285

 

 

Total operating expenses

 

969,266

 

 

 

741,319

 

 

 

429,969

 

 

 

354,139

 

 

 

254,171

 

 

Operating income (loss)

 

409,673

 

 

 

331,903

 

 

 

178,478

 

 

 

211,790

 

 

 

204,982

 

 

Income from unconsolidated affiliates

 

205,082

 

 

 

130,420

 

 

 

67,542

 

 

 

433

 

 

 

 

 

Interest expense

 

(185,680

)

 

 

(116,778

)

 

 

(64,739

)

 

 

(14,884

)

 

 

(7,426

)

 

Other income

 

872

 

 

 

827

 

 

 

320

 

 

 

287

 

 

 

102

 

 

Income (loss) before income taxes

 

429,947

 

 

 

346,372

 

 

 

181,601

 

 

 

197,626

 

 

 

197,658

 

 

Income tax expense

 

576

 

 

 

5,223

 

 

 

3,214

 

 

 

3,289

 

 

 

2,431

 

 

Net income (loss)

 

429,371

 

 

 

341,149

 

 

 

178,387

 

 

 

194,337

 

 

 

195,227

 

 

Net income (loss) attributable to  noncontrolling interests

 

31,311

 

 

 

5,124

 

 

 

(68

)

 

 

 

 

 

 

 

Net income (loss) attributable to Williams Partners L.P. (formerly Access Midstream Partners, L.P.)

$

398,060

 

 

$

336,025

 

 

$

178,455

 

 

$

194,337

 

 

$

195,227

 

 

Net income per common unit – basic and diluted(2)

$

1.01

 

 

$

0.98

 

 

$

1.05

 

 

$

1.29

 

 

$

0.73

 

 

Net income per subordinated unit – basic and  diluted(2)

 

 

 

 

0.88

 

 

 

1.07

 

 

 

1.29

 

 

 

0.73

 

 

Distribution per unit

 

2.64

 

 

 

2.04

 

 

 

1.71

 

 

 

1.48

 

 

 

0.55

 

 

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net property, plant and equipment

$

6,052,469

 

 

$

5,290,800

 

 

$

4,632,048

 

 

$

2,527,924

 

 

$

2,226,909

 

 

Total assets

 

9,143,577

 

 

 

7,917,446

 

 

 

6,561,100

 

 

 

3,683,238

 

 

 

2,545,916

 

 

Total debt

 

4,296,370

 

 

 

3,253,664

 

 

 

2,500,000

 

 

 

1,062,900

 

 

 

249,100

 

 

Total partners’ capital

 

4,512,317

 

 

 

4,352,790

 

 

 

3,796,506

 

 

 

2,473,145

 

 

 

2,194,568

 

 

Cash Flow Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

$

770,973

 

 

$

563,962

 

 

$

318,130

 

 

$

399,016

 

 

$

317,091

 

 

Investing activities

 

(1,487,658

)

 

 

(1,556,418

)

 

 

(2,685,965

)

 

 

(1,017,104

)

 

 

(711,480

)

 

Financing activities

 

741,327

 

 

 

944,691

 

 

 

2,432,807

 

 

 

600,294

 

 

 

412,202

 

 

Key Performance Metrics:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjusted EBITDA(3)

$

1,161,213

 

 

$

858,633

 

 

$

477,882

 

 

$

349,473

 

 

$

293,970

 

 

Distributable cash flow(3)

 

724,805

 

 

 

635,125

 

 

 

340,073

 

 

 

261,960

 

 

 

218,989

 

 

Capital expenditures

 

999,211

 

 

 

1,058,599

 

 

 

350,500

 

 

 

418,834

 

 

 

216,303

 

 

Operational Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Throughput, Bcf/d (4)

 

4.061

 

 

 

3.699

 

 

 

2.845

 

 

 

2.176

 

 

 

1.595

 

 

43


 

(1) 

If Chesapeake or Total does not meet its minimum volume commitments to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitments in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each one thousand cubic feet (“Mcf”) by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. The Partnership recognizes any associated revenue in the fourth quarter. For the years ended December 31, 2014, 2013, 2012, 2011 and 2010, we recognized revenue related to volume shortfall of $167.2 million, $64.9 million, $0.0 million, $17.4 million and $56.8 million, respectively.  

(2) 

The 2010 amounts are reflective of general and limited partner interests in net income after the closing our IPO on August 3, 2010. All years were adjusted to reflect the unit split that occurred immediately prior to the Merger.

(3) 

Adjusted EBITDA and distributable cash flow are defined under the heading Adjusted EBITDA and Distributable Cash Flow in Item 7 of this annual report. For reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles, see How We Evaluate Our Operations in Item 7 of this annual report.

(4) 

Throughput represents the net throughput allocated to the Partnership’s interest.

 

 

 

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ITEM  7.

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

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 item to Williams Partners L.P. (NYSE: WPZ) and its subsidiaries (the “Partnership,” “Pre-merger ACMP,” “we,” “our,” “us” or like terms) 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 and subsequent name change.  The “GIP I Entities” refers to, collectively, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P., the “GIP II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, and “GIP” refers to the GIP I Entities and their affiliates and the GIP II Entities, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB).  Unless otherwise noted, the remainder of this Management’s Discussion and Analysis focuses on the registrant prior to completion of the merger.  For further discussion of the businesses acquired in the merger, see Part 1 of this report.

Overview

We are a growth-oriented publicly traded Delaware limited partnership formed in 2010 to own, operate, develop and acquire natural gas, natural gas liquids (“NGLs”) and oil gathering systems and other midstream energy assets. We are principally focused on natural gas and NGL gathering, the first segment of midstream energy infrastructure that connects natural gas and NGLs produced at the wellhead to third-party takeaway pipelines.

We provide our midstream services to Chesapeake Energy Corporation (“Chesapeake”); Total Gas and Power North America, Inc. and Total E&P USA, Inc., each wholly owned subsidiaries of Total S.A. (“Total”); Mitsui & Co. (“Mitsui”); Anadarko Petroleum Corporation (“Anadarko”); Statoil ASA (“Statoil”) and other leading producers under long-term, fixed-fee contracts. We operate assets in the Barnett Shale region in north-central Texas; the Eagle Ford Shale region in South Texas; the Haynesville Shale region in northwest Louisiana; the Marcellus Shale region primarily in Pennsylvania and West Virginia; the Niobrara Shale region in eastern Wyoming; the Utica Shale region in eastern Ohio; and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins.  

Williams Acquisition

On July 1, 2014, Williams acquired all of the interests in the Partnership and Access Midstream Ventures, L.L.C., the sole member of Access Midstream Partners GP, L.L.C. (“Access Midstream Ventures” or the “General Partner”), that were owned by the GIP II Entities (the “Williams Acquisition”).  As a result of the closing of the Williams Acquisition, Williams owns 100% of the General Partner, and the GIP II Entities no longer have any ownership interest in the Partnership or the General Partner.  All of the equity awards previously outstanding under the Partnership’s Long-Term Incentive Plan vested on July 1, 2014 upon closing of the Williams Acquisition, resulting in compensation expense of $38.5 million.  Additionally, both components of the Management Incentive Compensation Plan (“MICP”) vested on July 1, 2014, resulting in total cash payments to MICP participants of $88.8 million during the 2014 third quarter and compensation expense of $41.1 million in the 2014 third quarter.  On July 16, 2014, we issued to certain key employees cash and equity retention awards that have various vesting periods between one and four years.  

Merger with Pre-merger WPZ

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”).  Following the completion of the Merger on February 2, 2015, the surviving Access Midstream Partners, L.P. changed its name to Williams Partners L.P. and the surviving general partner changed its name to WPZ GP LLC.

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-

45


 

merger ACMP represents 2.0 percent of the outstanding partnership interest.  Following the Merger, Williams owns approximately 60 percent of the Merged Partnership, including the general partner interest and IDRs.

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.  Due to the 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.

Our Compression Acquisition

On March 31, 2014, we acquired certain midstream compression assets from MidCon Compression, L.L.C. (“MidCon”), a wholly owned subsidiary of Chesapeake, for approximately $160 million. The acquisition adds natural gas compression assets, historically leased from MidCon, in the rapidly growing Utica Shale and Marcellus Shale regions. This transaction provides the opportunity to insource a key cost element of our business model and adds the potential for additional future organic growth to the portfolio. The acquired assets include more than 100 compression units with a combined capacity of approximately 200,000 horsepower.

Our CMO Acquisition and Williams’ Acquisition of 50 Percent of Our General Partner

On December 20, 2012, we acquired from Chesapeake Midstream Development, L.P. (“CMD”), a wholly owned subsidiary of Chesapeake, and certain of CMD’s affiliates, 100 percent of the issued and outstanding equity interests in Chesapeake Midstream Operating, L.L.C. (“CMO”) for total consideration of $2.16 billion (the “CMO Acquisition”). As a result of the CMO Acquisition, we own certain midstream assets in the Eagle Ford, Utica and Niobrara regions. The CMO Acquisition also extended our existing assets and operations in the Haynesville, Marcellus and Mid-Continent regions. The acquired assets included, in the aggregate, approximately 1,675 miles of pipeline and 4.3 million (gross) dedicated acres as of the date of the acquisition. We also assumed various gas gathering and processing agreements associated with the assets that have terms ranging from 10 to 20 years and that, in certain cases, include cost of service or fee redetermination mechanisms.

The results of operations presented and discussed in this annual report include results of operations from the CMO assets for the full year of operations in 2014, 2013 and for the twelve-day period from closing of the CMO Acquisition on December 20, 2012 through December 31, 2012.

Concurrently with the CMO Acquisition, the GIP I Entities sold to Williams 34,538,061 of our subordinated units and 50 percent of the outstanding equity interests in Access Midstream Ventures, the sole member of our general partner, for cash consideration of approximately $1.82 billion.  As a result, the GIP I Entities did not have any ownership interest in us or our general partner.

Our Marcellus Acquisition

On December 29, 2011, we acquired from CMD all of the issued and outstanding equity interests in Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash. Through Appalachia Midstream, we currently operate 100 percent of and own an average 45 percent interest in 11 gas gathering systems that consist of approximately 906 miles of gas gathering pipeline in the Marcellus Shale. The remaining 55 percent interest in these assets is owned primarily by Statoil, Anadarko and Mitsui. Appalachia Midstream operates the assets under long-term, 100 percent fixed fee gathering agreements that include significant acreage dedications and cost of service mechanisms.

Our Operations

We operate assets in the Barnett Shale region in north-central Texas, the Eagle Ford Shale region in southwest Texas, the Haynesville Shale region in northwest Louisiana, the Marcellus Shale region primarily in Pennsylvania and West Virginia, the Niobrara Shale region in Wyoming, the Utica Shale region in northeast Ohio, and the Mid-Continent region, which includes the Anadarko, Arkoma, Delaware and Permian Basins.

46


 

For the year ended December 31, 2014, we generated approximately 28 percent of our fees from our gathering systems in the Barnett Shale region, approximately 21 percent of our fees from our gathering systems in the Eagle Ford Shale region, approximately 10 percent of our fees from our gathering systems in the Haynesville Shale region, approximately 17 percent of our fees from our gathering systems in the Marcellus Shale region, approximately two percent of our fees from our gathering systems in the Niobrara Shale region, approximately nine percent of our fees from our gathering systems and processing facilities in the Utica Shale region and approximately 13 percent of our fees from our gathering systems and processing facilities in the Mid-Continent region.

The results of our operations are primarily driven by the volumes of natural gas and NGLs we gather, treat, compress and process across our gathering systems and processing facilities. We currently provide all of our midstream services pursuant to fixed fee contracts, which limit our direct commodity price exposure, and we generally do not take title to the natural gas or NGLs we gather. We have entered into long-term gas gathering and processing agreements with Chesapeake, Total, Statoil, Anadarko, Mitsui, and other producers. Pursuant to our commercial agreements, our producer customers have agreed to dedicate extensive acreage in our operating regions.

Our Commercial Agreements with Producers

We generate substantially all of our fees through long-term, fixed-fee natural gas gathering, treating, compression and processing contracts, all of which limit our direct commodity price exposure.

Future fees under our commercial agreements with producers will be derived pursuant to terms that will vary depending on the applicable operating region. The following outlines the key economic provisions of our commercial agreements by region.

Barnett Shale Region.  Under our gas gathering agreements with Chesapeake and Total, we have agreed to provide the following services in the Barnett Shale region for the fees and obligations outlined below:

Gathering, Treating and Compression Services.  We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per thousand cubic feet (“Mcf”) for natural gas gathered on our gathering systems that are based on the pressure at the various points where our gathering systems received our customers’ natural gas. We refer to these fees collectively as the Barnett Shale fee. The Barnett Shale fee is subject to an annual rate escalation of two percent at the beginning of each year.

Acreage Dedication.  Pursuant to our gas gathering agreements, subject to certain exceptions, each of Chesapeake and Total has agreed to dedicate all of the natural gas owned or controlled by them and produced from or attributable to existing and future wells located on natural gas and oil leases covering lands within an acreage dedication in the Barnett Shale region.

47


 

Minimum Volume Commitments.  Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments for each year through December 31, 2018 and for the six-month period ending June 30, 2019. Approximately 75 percent of the aggregate minimum volume commitment is attributed to Chesapeake, and approximately 25 percent is attributed to Total. The minimum volume commitments increase, on average, approximately three percent per year. The following table outlines the approximate aggregate minimum volume commitments for each year during the minimum volume commitment period:

(1)

Indicated volumes relate to the six months ending June 30, 2019.  Included in this amount is an overage of 2.8 Bcf related to 2012 production.  

 

If either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total, as applicable, during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total, as applicable, will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the six months ending June 30, 2019, and then against the minimum volume commitments of each preceding year. If the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.

Fee Redetermination.  In May 2012, we entered into an agreement with Chesapeake and Total relating to the initial redetermination period. The agreement called for an upward adjustment of the Barnett Shale fee and was effective July 1, 2012. We and each of Chesapeake and Total, as applicable, have the right to request an additional redetermination of the Barnett Shale fee during a two-year period beginning on September 30, 2014. The fee redetermination mechanism is intended to support a return on our invested capital. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to the Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment

48


 

period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. The cumulative upward or downward adjustment for the Barnett Shale region is capped at 27.5 percent of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. If we and Chesapeake or Total, as applicable, do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee.

Well Connection Requirement.  Subject to required notice by Chesapeake and Total and certain exceptions, we have generally agreed to connect new operated drilling pads and new operated wells within the Barnett Shale region acreage dedications as requested by Chesapeake and Total during the minimum volume commitment period. During the minimum volume commitment period, if we fail to complete a connection in the acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for natural gas volumes that would have been produced from the delayed connection.

Fuel and Lost and Unaccounted For Gas.  We have agreed with Chesapeake and Total on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s and Total’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

Eagle Ford Shale Region.  Under our gas gathering agreement with Chesapeake, we have agreed to provide the following services for the fees and obligations outlined below:

Gathering, Compression, Dehydration and Treating Services.  We gather, compress, dehydrate and treat natural gas and liquids for Chesapeake within the Eagle Ford Shale region in exchange for a cost of service based fee for natural gas and liquids gathered and treated on our gathering systems. The cost of service components include revenue, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We refer to these fees collectively as the Eagle Ford fee.

Acreage Dedication.  Subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas and liquids owned or controlled by it and produced from the Eagle Ford Shale formation through existing and future wells with a surface location within the dedicated area in the Eagle Ford Shale region.

Fee Redetermination.  During 2013 and 2014, the Eagle Ford fee is determined by a fee tiering mechanism that calculates the Eagle Ford fee on a monthly basis according to the quantity of natural gas delivered to us by Chesapeake relative to its scheduled deliveries. Effective on January 1, 2015 and January 1 of each year thereafter for a period of 18 years, the Eagle Ford fee will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these adjustments.

Well Connection Requirement.  Subject to required notice by Chesapeake, we have the option to connect new operated wells within the Eagle Ford Shale region acreage dedications as requested by Chesapeake. If we elect not to connect a new operated well, Chesapeake will be provided alternative forms of release. Subject to certain conditions specified in the applicable gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer customer’s acreage dedication in certain circumstances.

Fuel and Lost and Unaccounted For Gas.  We have agreed with Chesapeake to a cap on fuel and lost and unaccounted for gas on our systems with respect to the producer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then-current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

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Haynesville Shale Region.  Under our gas gathering agreements with Chesapeake, we have agreed to provide the following services for the fees and obligations outlined below:

Springridge Gathering System

Gathering, Treating and Compression Services.  We gather, treat and compress natural gas in exchange for fees per Mcf for natural gas gathered and per Mcf for natural gas compressed, which we refer to as the Springridge fees. The Springridge fees for these systems are subject to an annual specified rate escalation at the beginning of each year.

Acreage Dedication.  Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases within the Springridge acreage dedication.

Fee Redetermination.  The Springridge fees are subject to a redetermination mechanism. The first redetermination period included December 1, 2010 through December 31, 2012, and subsequent redetermination periods will be the calendar years 2013 through 2020. We determine adjustments to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending December 31, 2020, referred to as the redetermination period, made as of November 30, 2010. The annual upward or downward fee adjustment for the Springridge region is capped at 15 percent of the then-current fees at the time of redetermination.

Well Connection Requirement.  We have certain connection obligations for new operated drilling pads and operated wells of Chesapeake in the acreage dedications. Chesapeake is required to provide us notice of new drilling pads and wells operated by Chesapeake in the acreage dedications. Subject to certain conditions specified in the gas gathering agreement, we are generally required to connect new operated drilling pads in the acreage dedication by the later of 30 days after the date the wells commence production and six months after the date of the connection notice. If we fail to complete a connection in the Springridge acreage dedication by the required date, we are subject to a daily penalty for such delayed connections, up to a specified cap per delayed connection. Chesapeake is also required to notify us of its wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, Chesapeake has certain rights to have the well released from the dedication under the gas gathering agreement.

Fuel and Lost and Unaccounted For Gas.  We have agreed with Chesapeake on caps on fuel and lost and unaccounted for gas on our systems with respect to its volumes. These caps do not apply to one of our compressor stations due to its historical performance relative to the caps. This station will be reviewed periodically to determine whether changes have occurred that would make it suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Mansfield Gathering System

Gathering, Treating, Compression and Dehydration Services.  We gather, treat, compress and dehydrate natural gas in exchange for a fixed fee per million British thermal units (“MMBtu”) for natural gas gathered. We refer to this fee as the Mansfield fee. The Mansfield fee is subject to an annual 2.5 percent rate escalation at the beginning of each year.

Acreage Dedication.  Subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from the Bossier and Haynesville formations through existing and future wells with a surface location within the dedicated area in the Mansfield acreage dedication.

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Minimum Volume Commitments.  Pursuant to our gas gathering agreement, Chesapeake has agreed to minimum volume commitments for each year through December 31, 2017. If Chesapeake does not meet its minimum volume commitments to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, it is obligated to pay us the Mansfield fee for each MMBtu by which the minimum volume commitment exceeded the actual volumes of natural gas delivered to us.

Fixed Fee/Tiered Fees.  During the minimum volume commitment period, the Mansfield fee is a fixed fee on all monthly volumes. Subsequent to that period, our producer customer will pay a tiered fee that calculates the Mansfield fee on a monthly basis according to the quantity of natural gas delivered to us from Chesapeake’s wells relative to its scheduled deliveries.

Well Connection Requirement.  We have certain connection obligations for new operated wells in our acreage dedications. Chesapeake is required to provide us notice of new wells that it operates in the acreage dedications. Subject to certain conditions specified in the applicable gas gathering agreement, we are generally required to connect new wells within specified timelines subject to minimum volume commitment delays for volumes that would have been received from the new wells during the minimum volume commitment period and penalties up to a specified cap after the minimum volume commitment period.

Fuel and Lost and Unaccounted For Gas.  We have agreed with Chesapeake on percentage-based caps on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Marcellus Shale Region.  Under our gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon Energy Ltd. (“Epsilon”), Mitsui and Chief Oil & Gas LLC (“Chief”), we have agreed to provide the following services in our Marcellus Shale region for our proportionate share (based on our ownership interest in the applicable systems) of the fees and obligations outlined below:

Gathering and Compression Services. In systems operated by Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”), we gather and compress natural gas in exchange for fees per MMBtu of natural gas gathered and per MMBtu of natural gas compressed. The gathering fees are redetermined annually based on a cost of service mechanism, as described below. The compression fees escalate on January 1 of each year based on the consumer price index.

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Acreage Dedication.  Pursuant to our gas gathering agreements, subject to certain exceptions, the shippers and producers have agreed to dedicate all of the natural gas owned or controlled by them and produced from or attributable to existing and future wells with a surface location within the designated dedicated areas.

Fee Redetermination.  Each January 1, gathering fees for each gathering system under the gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui will be redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital for a period of 15 years. There is no cap on these fee adjustments. Each January 1, gathering fees for each gathering system under the gas gathering agreement with Chief are adjusted based on the applicable consumer price index. The change in the amount of the gathering fees under the Chief agreement is not to exceed three percent in any one year.

Well Connections.  We have the option to connect to new wells within the dedicated acreage. If we elect not to connect to any new well within the dedicated acreage, the shipper for such well may elect to have such well, and any subsequent wells within a two-mile radius (in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui) or a one-mile radius (in the case of Chief) of the surface location of such well, permanently released from the dedication area, or the shipper may elect to construct, at the shipper’s expense, a gathering system to connect to such well (and wells within a one-mile radius of such well in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui), in which case the shipper would pay us a reduced gathering fee for natural gas we receive through the shipper-installed asset. Alternatively, the shipper may require us to enter into an agreement pursuant to which we would construct the gathering system to connect to the well in exchange for a reimbursement by the shipper of the costs we incur in connection therewith. The shipper may elect to connect wells outside the dedicated area at its sole expense and pay us a reduced gathering fee for natural gas we receive from such wells, but natural gas from such outside wells will not be afforded the same priority as natural gas produced from wells located within the dedicated area.

Fuel and Lost and Unaccounted For Gas.  Under our gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui, we have agreed on caps on fuel and lost and unaccounted for gas on the systems. If we exceed the permitted cap, we must provide a cost estimate for a remedy that is reasonably expected to prevent exceeding the permitted cap in the future. At the election of the shippers we may pay such costs (which costs would then be included in the gathering fee redetermination) or the shippers may pay the costs. If we exceed the permitted cap and do not provide a proposal to the shippers to prevent exceeding the cap in the future within the required time period, we may incur our proportionate share (based on our ownership interest in the applicable system) of significant expenses in connection with the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this may subject us to direct commodity price risk.

 

Under gas gathering agreements between Appalachia Midstream and certain subsidiaries of Chief, the shipper on each system is to furnish to us, at the shipper’s sole cost and expense, all necessary fuel gas to operate the system. Natural gas volumes lost solely due to our actions or inactions constituting gross negligence or willful misconduct are our sole responsibility. Additionally, we will bear the cost of natural gas lost in excess of one percent due to our failure to maintain adequate corrosion protection. If we lose natural gas due to our gross negligence or willful misconduct or our failure to maintain an adequate corrosion protection system, we may incur significant expenses in connection with the cost of the lost natural gas. Our responsibility for the cost of the lost gas may subject us to direct commodity price risk.

Niobrara Shale Region.  Under our gas gathering and processing agreements with Chesapeake and RKI Exploration & Production, LLC (“RKI”), we have agreed to provide the following services for the fees and obligations outlined below:

Gathering, Compression, Dehydration and Processing Services. We will gather, compress, dehydrate and process natural gas and liquids within the Niobrara region in exchange for a cost of service based fee for natural gas and liquids gathered on our gathering systems and for natural gas and liquids processed at our processing facility. The cost of service components will include revenues, compression expense, deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We refer to these fees collectively as the Niobrara fee.

Acreage Dedication.  Subject to certain exceptions, each of Chesapeake and RKI have agreed to dedicate all of the natural gas and liquids owned or controlled by it and produced from the Frontier Sand and the Niobrara Shale through existing and future wells with a surface location within the dedicated areas in the Niobrara Shale region.

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Fee Redetermination.  The Niobrara fees are redetermined on January 1 of each year through 2032 based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments.

Well Connections.  Subject to required notice by Chesapeake and RKI, we will have the option to connect new operated wells within our Niobrara region acreage dedications as requested by our producer customers. If we elect not to connect a new operated well, Chesapeake and RKI, as applicable will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreements, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections up to a specified cap, and the potential for a well pad release from the producer customer’s acreage dedication in certain circumstances.

Fuel and Lost and Unaccounted For Gas. We have agreed with each Chesapeake and RKI to a cap on fuel and lost and unaccounted for gas on our systems with respect to the producer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period and do not respond in a timely manner with a proposed solution, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Utica Shale Region. Under our commercial agreements with Chesapeake, Total and Enervest, we have agreed to provide the following services for the fees and obligations outlined below:

Gathering, Compression, Dehydration, Processing and Fractionation Services.  We gather, compress and dehydrate natural gas and liquids in exchange for a cost of service based fee for natural gas and liquids gathered on our gathering systems. The cost of service components (i) for our 66 percent operating interest in a joint venture that owns a wet gas gathering system (the “Cardinal Joint Venture”), and (ii) in the area covered by our 100 percent ownership interest in four dry gas gathering systems (the “Utica Dry”) include revenues, compression expense (in the case of the Utica Dry only), deemed general and administrative expense, capital expenditures, fixed and variable operating expenses and other metrics. We also process and fractionate natural gas and NGLs through our 49 percent non-operating interest in a joint venture (the “UEO Joint Venture”) that operates processing facilities with a total capacity of 800 MMcf per day and planned incremental capacity of 200 MMcf per day to be placed in service in 2016.  The UEO Joint Venture operates 135,000 barrel per day fractionation facilities.  The UEO Joint Venture also operates approximately 600,000 barrels of NGL storage capacity with an additional 350,000 barrels of NGL storage expected by the end of 2015 and other ancillary assets for a fixed fee that escalates annually within a specified range. We refer to these fees collectively as the Utica fee.

Acreage Dedication.  Subject to certain exceptions, our producer customers have agreed to dedicate natural gas and liquids owned or controlled by them and produced from the Utica Shale formation through existing and future wells with a surface location within the dedicated areas in the Utica Shale region. The UEO Joint Venture has processing and fractionation dedications from Chesapeake, Total, Enervest and American Energy – Utica, LLC in support of 1.0 bcf/d of capacity.

Fee Redetermination.  Beginning on October 1, 2013, for the Cardinal Joint Venture and January 1, 2014, for the Utica Dry and annually thereafter, for a period of 20.75 years from January 1, 2012 (Cardinal Joint Venture) and 15 years from July 1, 2012 (Utica Dry), the gathering fee portion of the Utica fee is redetermined based on a cost of service calculation that targets a specified pre-income tax rate of return on invested capital. There is no cap on these fee adjustments.

Well Connections.  In the Cardinal Joint Venture, we are generally required to connect new wells within specified timelines subject to penalties for delayed connections in the form of a temporary reduction in the gathering fee for the new well. In the Utica Dry, subject to required notice by the producer customer, we will have the option to connect new operated wells within our dedicated acreage as requested by the producer customer. If we elect not to connect a new operated well, the producer customer will be provided alternative forms of release. Subject to certain conditions specified in the gas gathering agreement, if we elect to connect a new well to our gathering systems, we are generally required to connect the new wells within specified timelines subject to penalties for delayed connections, up to a specified cap, and the potential for a well pad release from the producer’s acreage dedication in certain circumstances.

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Processing and Fractionation Performance Standards.  We have agreed with our producer customers to certain performance standards for the UEO Joint Venture, including guaranteed in-service dates, minimum facility run-time standards, minimum propane recovery standards, and fuel caps. If the UEO Joint Venture fails to achieve any of these performance standards as specified, the fees associated with these services will be temporarily reduced.

Fuel and Lost and Unaccounted For Gas.  We have agreed with the producer customers to a cap on fuel and lost and unaccounted for gas on our systems with respect to each producer’s volumes. The cap is based on a percentage per deemed compression stage and a percentage for lost and unaccounted for gas. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk. In the Utica Dry, exceeding the permitted cap does not result in a reimbursement to the Utica producers if we respond in a timely manner with a proposed solution.

Mid-Continent Region. Under our gas gathering agreements with our producer customers, we have agreed to provide the following services for the fees and obligations outlined below:

Gathering, Treating and Compression and Processing Services.  We gather, treat, compress and process natural gas and NGLs in exchange for system-based services fees per Mcf for natural gas gathered and per Mcf for natural gas compressed. We refer to the fees collectively as the Mid-Continent fee. The Mid-Continent fees for these systems are subject to an annual two and a half percent rate escalation at the beginning of each year.

Acreage Dedication.  Pursuant to our gas gathering agreement, subject to certain exceptions, our producer customers have agreed to dedicate all of the natural gas and liquids owned or controlled by them and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within the acreage dedication.

Fee Redetermination.  The Mid-Continent fees are redetermined at the beginning of each year through 2019. We and our producer customers determine adjustments to fees for the gathering systems in the region with our producer customers based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15 percent of the then current fees at the time of redetermination.

Well Connection Requirement.  Subject to required notice by our producer customers and certain exceptions, we have generally agreed to use our commercially reasonable efforts to connect new operated drilling pads and new operated wells in our Mid-Continent region acreage dedications as requested by our producer customers through June 30, 2019.

Fuel and Lost and Unaccounted For Gas.  We have agreed with our producer customers on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to our producer customers volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems are reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

As part of the CMO Acquisition, we acquired a 33.33 percent equity interest in Ranch Westex JV LLC, which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC. Under a gas processing agreement with Chesapeake and Anadarko, Ranch Westex JV LLC provides natural gas processing services under a cost of service fee arrangement.

All Regions.  If one of the counterparties to these gas gathering and processing agreements sells, transfers or otherwise disposes of properties within the our acreage dedications to a third party, it does so subject to the terms of the gas gathering and processing agreements, including our dedication, and it will be required to cause the third party to acknowledge and take assignment of the counterparty’s obligations under the existing gas gathering and processing agreements with us, subject to our consent. Our producer customers’ dedication of the natural gas produced from applicable properties under our gas gathering and processing agreements will run with the land in order to bind

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successors to the producer customers’ interest, as well as any interests in the dedicated properties subsequently acquired by the producer customer.

On October 14, 2014, Chesapeake announced that its wholly owned subsidiary, Chesapeake Appalachia, L.L.C. (“CHK Appalachia”), had entered into a Purchase and Sale Agreement with a subsidiary of Southwestern Energy Company (“Southwestern”), pursuant to which Southwestern has agreed to purchase CHK Appalachia’s interests in approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus and Utica formations (collectively, the “Designated Properties”) and are subject to certain of our existing gas gathering agreements with Chesapeake. The closing of this transaction occurred in December 2014.  Upon the closing of this transaction, Southwestern is contractually obligated to assume Chesapeake’s obligations with respect to the Designated Properties under certain of our existing gas gathering agreements with Chesapeake.  As a result of this transaction, we expect to further decrease our dependence on Chesapeake as a customer.

Other Arrangements

On June 15, 2012, in connection with the closing of the first portion of the acquisition by the GIP II Entities of Chesapeake’s ownership interest in us (the “GIP Acquisition”), we entered into a letter agreement with Chesapeake regarding the terms on which Chesapeake provides certain transition services to us and our general partner. Among other things, the letter agreement provided for the continuation of our services agreement with Chesapeake until December 31, 2013. On June 29, 2012, we entered into an amendment to the letter agreement amending certain terms relating to the insurance coverage to be provided under our services agreement. On December 20, 2012, in connection with the CMO Acquisition, we entered into an amendment to the letter agreement amending certain terms relating primarily to the extension of transition services for technology related services through September 2014 for certain field communication support services.

How We Evaluate Our Operations

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput volumes, (ii) revenues, (iii) operating expenses, (iv) segment operating income, (v) Adjusted EBITDA and (vi) distributable cash flow.

Throughput Volumes

Our management analyzes our performance based on the aggregate amount of throughput volumes on our gathering systems in our operating regions in order to maintain or increase throughput volumes on our gathering systems as a whole. Our success in connecting additional wells is impacted by successful drilling activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, our ability to attract natural gas and liquids volumes currently gathered by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.

Revenues

Our revenues are driven primarily by our contractual terms with our customers and the actual volumes of natural gas we gather, treat, compress and process. Our revenues will be supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total in the case of our Barnett Shale and Chesapeake in the case of our Haynesville Shale as well as fee redetermination and cost of service provisions in our other regions. We contract with producers to gather or process natural gas or liquids from individual wells located near our gathering systems or processing facilities. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas and liquids that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the years ended December 31, 2014, 2013 and 2012, Chesapeake accounted for approximately 71 percent, 74 percent and 81 percent, respectively, of the natural gas volumes on our gathering systems and 82 percent, 84 percent and 81 percent, respectively, of our revenues.  The Partnership’s revenues exclude revenue attributable to the Partnership’s equity investments as those revenues are accounted for as part of the Partnership’s investments in unconsolidated affiliates.  

Our revenues are also impacted by other aspects of our contractual agreements, including rate redetermination, cost of service and other contractual provisions and our management constantly evaluates capital spending and its impact on future revenue generation.

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Operating Expenses

Our management seeks to maximize the profitability of our operations by minimizing operating expenses without compromising environmental protection and employee safety. Operating expenses are comprised primarily of field operating costs (which include labor, treating and chemicals, and measurements services among other items), compression expense, ad valorem and taxes and other operating costs, some of which are independent of the volumes that flow through our systems but fluctuate depending on the scale of our operations during a specific period.

Segment Operating Income

Prior to the CMO Acquisition, our operations were organized into a single business segment. As a result of the CMO Acquisition, we added assets in three new operating regions. Our chief operating decision maker measures performance and allocates resources based on geographic segments.  Our operations are divided into eight operating segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent and Corporate.

Adjusted EBITDA

We define Adjusted EBITDA as net income (loss) before income tax expense (benefit), interest expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results.

Adjusted EBITDA is a non-GAAP supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

·

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to capital structure, historical cost basis, or financing methods;

·

our ability to incur and service debt and fund capital expenditures;

·

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

·

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe it is appropriate to exclude certain items from EBITDA because we believe these items affect the comparability of operating results. We believe that the presentation of Adjusted EBITDA in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA is net income.

Distributable Cash Flow

Our Partnership defines Distributable Cash Flow (“DCF”) as Adjusted EBITDA attributable to the Partnership adjusted for:

·

addition of interest income;

·

subtraction of net cash paid for interest expense;

·

subtraction of maintenance capital expenditures; and

·

subtraction of income taxes.

DCF is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is in part measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. The GAAP measure most directly comparable to DCF is net cash provided by operating activities.

Reconciliation to GAAP measures

We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. Adjusted EBITDA and distributable cash flow are

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presented because they are helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider either Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

The following table presents a reconciliation of the non-GAAP financial measures of Adjusted EBITDA and distributable cash flow to the GAAP financial measures of net income and net cash provided by operating activities:

 

 

Year Ended
December 31,
2014

 

  

Year Ended
December 31,
2013

 

 

Year Ended
December 31,
2012

 

 

($ in thousands)

 

Reconciliation of Adjusted EBITDA and Distributable cash flow to net income:

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to Williams Partners L.P. (formerly Access Midstream Partners, L.P.)

$

398,060

 

 

$

336,025

 

 

$

178,455

 

Interest expense

 

185,680

 

 

 

116,778

 

 

 

64,739

 

Income tax expense

 

576

 

 

 

5,223

 

 

 

3,214

 

Depreciation and amortization expense

 

314,758

 

 

 

296,179

 

 

 

165,517

 

Other

 

(6,555

)

 

 

(2,615

)

 

 

(820

)

Income from unconsolidated affiliates

 

(205,082

)

 

 

(130,420

)

 

 

(67,542

)

EBITDA from unconsolidated affiliates(1)

 

298,668

 

 

 

202,453

 

 

 

116,887

 

Transaction related costs

 

123,137

 

 

 

 

 

 

17,432

 

Loss on impairments and disposals of assets

 

23,783

 

 

 

 

 

 

 

Expense for non-cash equity awards

 

28,188

 

 

 

35,010

 

 

 

 

Adjusted EBITDA

$

1,161,213

 

 

$

858,633

 

 

$

477,882

 

Maintenance capital expenditures

 

(130,000

)

 

 

(110,000

)

 

 

(75,184

)

Cash portion of interest expense

 

(177,248

)

 

 

(108,285

)

 

 

(59,411

)

Income tax expense

 

(576

)

 

 

(5,223

)

 

 

(3,214

)

Cash impact of transaction related costs

 

(128,584

)

 

 

 

 

 

 

Distributable cash flow

$

724,805

 

 

$

635,125

 

 

$

340,073

 

57


 

 

 

Year Ended
December 31,
2014

 

  

Year Ended
December 31,
2013

 

 

Year Ended
December 31,
2012

 

 

($ in thousands)

 

Reconciliation of Adjusted EBITDA and Distributable cash flow to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

$

770,973

 

 

$

563,962

 

 

$

318,130

 

Changes in assets and liabilities

 

109,211

 

 

 

46,394

 

 

 

(33,472

)

Distribution of earnings received from unconsolidated affiliates

 

(281,733

)

 

 

(82,871

)

 

 

 

Interest expense

 

185,680

 

 

 

116,778

 

 

 

64,739

 

Income tax expense

 

576

 

 

 

5,223

 

 

 

3,214

 

Other non-cash items

 

(97,270

)

 

 

(28,316

)

 

 

(9,048

)

Transaction related costs

 

123,137

 

 

 

 

 

 

17,432

 

EBITDA from unconsolidated affiliates(1)

 

298,668

 

 

 

202,453

 

 

 

116,887

 

Loss on impairments and disposals of assets

 

23,783

 

 

 

 

 

 

 

Expense for non-cash equity awards

 

28,188

 

 

 

35,010

 

 

 

 

Adjusted EBITDA

$

1,161,213

 

 

$

858,633

 

 

$

477,882

 

Maintenance capital expenditures

 

(130,000

)

 

 

(110,000

)

 

 

(75,184

)

Cash portion of interest expense

 

(177,248

)

 

 

(108,285

)

 

 

(59,411

)

Income tax expense

 

(576

)

 

 

(5,223

)

 

 

(3,214

)

Cash impact of transaction related costs

 

(128,584

)

 

 

 

 

 

 

Distributable cash flow

$

724,805

 

 

$

635,125

 

 

$

340,073

 

 

 

Year Ended
December 31,
2014

 

  

Year Ended
December 31,
2013

 

 

Year Ended
December 31,
2012

 

 

($ in thousands)

 

(1) EBITDA from unconsolidated affiliates is calculated as follows:

 

 

 

 

 

 

 

 

 

 

 

Net income

$

205,082

 

 

$

130,420

 

 

$

67,542

 

Depreciation and amortization expense

 

93,695

 

 

 

72,053

 

 

 

49,458

 

Other

 

(109

)

 

 

(20

)

 

 

(113

)

EBITDA from unconsolidated affiliates

$

298,668

 

 

$

202,453

 

 

$

116,887

 

 

 

Year Ended
December 31,
2014

 

  

Year Ended
December 31,
2013

 

  

Year Ended
December 31,
2012

 

 

($ in thousands)

 

GAAP Capital Expenditures

$

999,211

 

 

$

1,058,599

 

 

$

350,500

 

Adjusted for:

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures included in unconsolidated affiliates

 

385,236

 

 

 

671,394

 

 

 

384,403

 

Capital expenditures attributable to noncontrolling interest

 

(211,494

)

 

 

(151,584

)

 

 

 

Net capital expenditures

$

1,172,953

 

 

$

1,578,409

 

 

$

734,903

 

58


 

Results of Operations

We have provided a detailed comparison for the years ended December 31, 2014, 2013 and 2012 in the chart and discussion below.

 

 

Year Ended
December 31,
2014

 

  

Year Ended
December 31,
2013

 

 

Year Ended
December 31,
2012

 

 

($ in thousands, except per unit data)

 

Revenues (1)

$

1,378,939

 

 

$

1,073,222

 

 

$

608,447

 

Operating expenses

 

427,589

 

 

 

338,716

 

 

 

197,639

 

Depreciation and amortization expense

 

314,758

 

 

 

296,179

 

 

 

165,517

 

General and administrative expense

 

202,796

 

 

 

104,332

 

 

 

67,579

 

Other operating expense (income)

 

24,123

 

 

 

2,092

 

 

 

(766

)

Total operating expenses

 

969,266

 

 

 

741,319

 

 

 

429,969

 

Operating income

 

409,673

 

 

 

331,903

 

 

 

178,478

 

Income from unconsolidated affiliates

 

205,082

 

 

 

130,420

 

 

 

67,542

 

Interest expense

 

(185,680

)

 

 

(116,778

)

 

 

(64,739

)

Other income

 

872

 

 

 

827

 

 

 

320

 

Income before income tax expense

 

429,947

 

 

 

346,372

 

 

 

181,601

 

Income tax expense

 

576

 

 

 

5,223

 

 

 

3,214

 

Net income

 

429,371

 

 

 

341,149

 

 

 

178,387

 

Net income (loss) attributable to noncontrolling interests

 

31,311

 

 

 

5,124

 

 

 

(68

)

Net income attributable to Williams Partners L.P. (formerly Access Midstream Partners, L.P.)

$

398,060

 

 

$

336,025

 

 

$

178,455

 

Operational Data:

 

 

 

 

 

 

 

 

 

 

 

Throughput, Bcf/d(2)

 

4.061

 

 

 

3.699

 

 

 

2.845

 

(1) 

If either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each Mcf by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. The Partnership recognizes any associated revenue in the fourth quarter. For the years ended December 31, 2014 and 2013, we recognized revenue related to volume shortfall of $167.2 million and $64.9 million.

(2) 

Throughput represents the net throughput allocated to the Partnership’s interest.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet financing activities.

Segment Reporting

We present information in this Management’s Discussion and Analysis of Financial Condition and Results of Operations by segment. The segment information appearing in Note 14 of the accompanying Notes to the Consolidated Financial Statements is presented on a basis consistent with how our chief operating decision maker measured performance and allocated resources as of December 31, 2014. We conduct our operations in the following segments: Barnett Shale, Eagle Ford Shale, Haynesville Shale, Marcellus Shale, Niobrara Shale, Utica Shale, Mid-Continent region and Corporate.

59


 

Year Ended December 31, 2014 vs. Year Ended December 31, 2013

The following tables reflect our revenues, throughput, operating expenses and operating expenses per Mcf of throughput by segment for the years ended December 31, 2014 and 2013 (please note that revenue, throughput and operating expenses related to our equity investments (primarily in the Marcellus Shale) are excluded from the tables below as the financial results for our equity investments are reported separately. Please read “Income from Unconsolidated Affiliates” in this Results of Operations section of Management’s Discussion and Analysis of Financial Condition and Results of Operations):

 

 

Years Ended December 31,

 

  

 

 

 

2014

 

  

2013

 

  

% Change(1)

 

 

(In thousands, except percentages and throughput data)

 

Revenue:

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

$

463,645

 

 

$

433,709

 

 

 

6.9

%

Eagle Ford Shale

 

348,904

 

 

 

278,282

 

 

 

25.4

 

Haynesville Shale

 

160,138

 

 

 

119,209

 

 

 

34.3

 

Marcellus Shale

 

15,136

 

 

 

10,989

 

 

 

37.7

 

Niobrara Shale

 

28,329

 

 

 

15,095

 

 

 

87.7

 

Utica Shale

 

153,963

 

 

 

44,063

 

 

 

N.M.

 

Mid-Continent

 

208,819

 

 

 

171,875

 

 

 

21.5

 

Corporate

 

5

 

 

 

 

 

 

N.M.

 

 

$

1,378,939

 

 

$

1,073,222

 

 

 

28.5

%

Throughput (Bcf)(2):

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

330.9

 

 

 

381.3

 

 

 

(13.2

)%

Eagle Ford Shale

 

117.2

 

 

 

96.0

 

 

 

22.1

 

Haynesville Shale

 

245.1

 

 

 

244.3

 

 

 

0.3

 

Marcellus Shale

 

443.2

 

 

 

372.1

 

 

 

19.1

 

Niobrara Shale

 

10.3

 

 

 

5.5

 

 

 

87.3

 

Utica Shale

 

133.0

 

 

 

39.0

 

 

 

N.M.

 

Mid-Continent

 

202.5

 

 

 

212.2

 

 

 

(4.6

)

 

 

1,482.2

 

 

 

1,350.4

 

 

 

9.8

%

(1) 

N.M. - not meaningful

(2) 

Throughput in all regions represents the net throughput allocable to our interest.

 

 

Years Ended December 31,

 

  

 

 

  

2014

 

  

2013

 

  

% Change(1)

 

 

(In thousands, except percentages and per Mcf data)

 

Operating Expenses:

 

 

 

  

 

 

 

  

 

 

 

Barnett Shale

$

95,744

 

 

$

96,926

 

 

 

(1.2

)%

Eagle Ford Shale

 

74,962

 

 

 

59,059

 

 

 

26.9

 

Haynesville Shale

 

46,171

 

 

 

41,176

 

 

 

12.1

 

Marcellus Shale

 

12,526

 

 

 

4,834

 

 

 

N.M.

 

Niobrara Shale

 

14,568

 

 

 

9,090

 

 

 

60.3

 

Utica Shale

 

38,348

 

 

 

19,065

 

 

 

N.M.

 

Mid-Continent

 

78,150

 

 

 

70,609

 

 

 

10.7

 

Corporate

 

67,120

 

 

 

37,957

 

 

 

76.8

 

 

$

427,589

 

 

$

338,716

 

 

 

26.2

%

Expenses ($ per Mcf):

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

$

0.29

 

 

$

0.25

 

 

 

16.0

%

Eagle Ford Shale

 

0.64

 

 

 

0.62

 

 

 

3.2

 

Haynesville Shale

 

0.19

 

 

 

0.17

 

 

 

11.8

 

Marcellus Shale

 

1.99

 

 

 

1.01

 

 

 

97.0

 

Niobrara Shale

 

0.71

 

 

 

1.65

 

 

 

(57.0

)

Utica Shale

 

0.19

 

 

 

0.49

 

 

 

(61.2

)

Mid-Continent

 

0.39

 

 

 

0.33

 

 

 

18.2

 

 

$

0.38

 

 

$

0.34

 

 

 

11.8

%

(1) 

N.M. - not meaningful

60


 

Barnett Shale

Revenues. For the years ended December 31, 2014 and 2013, revenues totaled $463.6 million and $433.7 million, respectively. Revenues increased despite a decrease in throughput of 13 percent in the region.  The increase in revenues was primarily the result of increasing volumes under our minimum volume commitment and an annual fixed fee rate escalation of two percent effective January 1, 2014.  Total revenue includes $134.0 million and $64.9 million of revenues associated with the contractual minimum volume commitment in 2014 and 2013, respectively.  

Operating Expenses.  For the years ended December 31, 2014 and 2013, operating expenses were $95.7 million, or $0.29 per Mcf, compared to $96.9 million, or $0.25 per Mcf, respectively. While operating costs remained consistent, operating expenses per Mcf has increased due to both decreased drilling activity in the region caused by the low natural gas price environment and the natural decline of existing wells. The most significant operating expenses in the Barnett Shale region are compression costs.

Depreciation and Amortization Expenses. For the years ended December 31, 2014 and 2013, depreciation expense was $81.8 million and $97.9 million, respectively. The decrease was due to an increase in the estimated useful lives of gathering systems in this region during 2014.

Eagle Ford Shale

Revenues. For the years ended December 31, 2014 and 2013, revenues totaled $348.9 million and $278.3 million, respectively.  The increase was primarily attributable to a 22.1 percent increase in throughput, a contractual increase in fees and additional services provided in this region in 2014.

Operating Expenses. For the year ended December 31, 2014, operating expenses totaled $75.0 million or $0.64 per Mcf, compared to $59.1 million, or $0.62 per Mcf for the year ended December 31, 2013. The most significant operating expenses in this region are employee compensation and compression costs, which both increased from 2013 due to increased activity in this region.

Depreciation and Amortization Expenses. Depreciation and amortization expense for the years ended December 31, 2014 and 2013, was $57.0 million and $51.4 million, respectively.  Additional depreciation as a result of increased capital expenditures made in this region during 2014 and 2013 was partially offset by an increase in the estimated useful lives of gathering systems in this region during 2014.

Haynesville Shale

Revenues. For the years ended December 31, 2014 and 2013, revenues were $160.1 million and $119.2 million, respectively. Haynesville revenues were positively impacted by an annual rate escalation of 2.5 percent and rate redetermination of 15 percent on the Springridge gathering system, both effective January 1, 2014. Additionally, we have contractual minimum volume commitments from Chesapeake in the Haynesville Shale. Total revenue for 2014 included $33.2 million of revenues associated with the contractual minimum volume commitment. Throughput for the year ended December 31, 2013 was above the minimum volume commitment level.

Operating Expenses. For the years ended December 31, 2014 and 2013, operating expenses were $46.2 million, or $0.19 per Mcf, compared to $41.2 million, or $0.17 per Mcf, respectively.  The increase in operating expenses is primarily a result of increased ad valorem taxes due to reassessments on the properties for 2014.

Depreciation and Amortization Expenses. Depreciation and amortization expense for the years ended December 31, 2014 and 2013, was $69.5 million and $80.8 million, respectively.  The decrease was due to an increase in the estimated useful lives of gathering systems in this region during 2014.

Marcellus Shale

On September 4, 2013, we sold Mid-Atlantic Gas Services, L.L.C. (“Mid-Atlantic”) to Chesapeake for net proceeds of $32.9 million. Mid-Atlantic was acquired in December 2012 and consisted of midstream assets in the Marcellus region.  These assets were not part of our equity method investment in Appalachia Midstream. The net proceeds equaled our basis in the assets; thus, no gain or loss was recognized as a result of the sale.

61


 

The large majority of our assets in the Marcellus Shale are accounted for as equity investments and included in Income from unconsolidated affiliates. See further discussion below under “Income from unconsolidated affiliates” in this section of Marcellus Shale results of operations.

Income from unconsolidated affiliates. We own an average 45 percent interest in 11 gas gathering systems in the Marcellus Shale in Pennsylvania and West Virginia. The remaining average 55 percent interests in these assets are owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates was $170.2 million and $133.0 million reflecting activity for the years ended December 31, 2014 and 2013, respectively.  Revenues (net to our interest) for the years ended December 31, 2014 and 2013 were $279.1 million and $234.8 million, respectively.  The net increase was due to throughput growth and increased construction activity in the Marcellus region where we invested $147.0 million of capital in 2014.  Operating expenses on a per unit basis for the years ended December 31, 2014 and 2013 were $0.10 Mcf in each year.  The increase in operating expenses is consistent with the increase in revenues in the Marcellus region.  The margin for these assets is strong as a result of lower operating expenses than in many other regions of the United States. These lower operating expenses are primarily due to high reservoir pressures that reduce the need for compression in the transportation of commodities.  We expect our margin in the Marcellus Shale to remain strong; however, we could experience a slight decrease in our margin over time as the need for additional compression increases. The following table summarizes the results of the Appalachia Midstream assets (net to our interest) for the years ended December 31, 2014 and 2013.

 

 

Year Ended
December 31,
2014

 

  

Year Ended
December 31,
2013

 

Revenue ($ in thousands)

$

279,108

  

  

$

234,801

  

Throughput (Bcf)

 

436.9

  

  

 

367.3

  

Operating Expenses ($ in thousands)

$

42,714

  

  

$

35,999

  

Expenses ($ per Mcf)

 

0.10

  

  

 

0.10

  

Niobrara Shale

We acquired our ownership interest in the Niobrara Shale assets in December 2012 and own that interest through our 50 percent ownership interest in Jackalope Gas Gathering, L.L.C., in which Crestwood Niobrara LLC owns the remaining 50 percent interest. Because we operate the assets and have contractual discretion to make operating decisions for the assets, we are deemed to control the assets and thus, we consolidated 100 percent of the assets and results of operation in our financial results. We present the noncontrolling interest for these assets in Noncontrolling Interests on the condensed consolidated balance sheet and in Net Income Attributable to Noncontrolling Interests on the condensed consolidated statement of operations.

Revenues.  For the years ended December 31, 2014 and 2013, revenues in the Niobrara Shale region were $28.3 million and $15.1 million, respectively. An increase in throughput was partially offset by a fee redetermination decrease effective January 1, 2014.  We continue to invest significant capital in this region and expect to connect a significant number of wells to our gathering systems that will drive additional volume growth in future periods.

Operating Expenses. For the years ended December 31, 2014 and 2013, operating expenses in the Niobrara Shale region were $14.6 million and $9.1 million, respectively. Expenses are expected to continue to increase in 2015 as construction activity continues and we prepare to provide additional gathering and processing services in this region in future periods. The most significant expenses in this region are employee compensation and compression costs.  Operating expenses per Mcf have decreased in 2014 as a result of the volume growth in this region.

Depreciation and Amortization Expenses. Depreciation and amortization expense for the years ended December 31, 2014 and 2013, was $5.4 million and $4.3 million, respectively, which was due to capital expenditures made in this region during 2014 and 2013, partially offset by an increase in the estimated useful lives of gathering systems in this region during 2014.

Utica Shale

In the CMO Acquisition, we acquired a 100 percent ownership interest in four natural gas gathering systems, a 66 percent operating interest in the Cardinal Joint Venture and a 49 percent interest in the UEO Joint Venture. Because we operate the four wholly-owned natural gas gathering systems and Cardinal Joint Venture and have contractual discretion to make operating decisions for the Cardinal Joint Venture, we are deemed to control the assets and, as a result, we consolidate 100 percent of the assets and results of operations in our financial results and reflect the ownership of the

62


 

other interest owners through a noncontrolling interest in the income and equity of the investment. The UEO Joint Venture is accounted for as an equity investment because we have significant influence over but do not control the entity.

Revenues.  For the years ended December 31, 2014 and 2013, revenues in the Utica Shale region were $154.0 million and $44.1 million, respectively.  The growth is primarily the result of increased throughput due to increased drilling and compression activity.  We continue to invest significant capital in this region that is expected to drive additional volume and revenue growth in future periods.

Operating expenses.  For the years ended December 31, 2014 and 2013, operating expenses in the Utica Shale region were $38.3 million, or $0.19 per Mcf and $19.1 million, or $0.49 per Mcf, respectively. The increase in operating expenses is primarily a result of the increase in operating activity in the Utica Shale region.  The most significant operating expenses in this region are compensation and compression costs.

Depreciation and Amortization Expenses. Depreciation and amortization expense for the years ended December 31, 2014 and 2013, was $25.5 million and $9.5 million, respectively, which was due to capital expenditures made in this region during 2014 and 2013, partially offset by an increase in the estimated useful lives of gathering systems in this region during 2014.

Income from unconsolidated affiliates.  For the years ended December 31, 2014 and 2013, income (loss) from unconsolidated affiliates was $24.8 million and $(3.8) million, respectively.  Income from the UEO Joint Venture increased primarily as a result of a plant that became operational in early 2014 causing an increase in volumes and revenue.  

Mid-Continent

Revenues.  For the years ended December 31, 2014 and 2013, revenues were $208.8 million and $171.9 million, respectively. This increase was caused primarily by a 2.5 percent annual rate increase and a 15 percent fee increase due to annual contractual fee redetermination, both effective January 1, 2014, offset by a 4.6 percent decrease in throughput.

Operating Expenses.  For the years ended December 31, 2014 and 2013, operating expenses were $78.2 million, or $0.39 per Mcf and $70.6 million, or $0.33 per Mcf, respectively. The increase occurred across all operating costs in this region as we continue to experience increased drilling activity in this liquids-rich region by our producer customers.

Depreciation and Amortization Expenses. Depreciation and amortization expense for the years ended December 31, 2014 and 2013, was $35.4 million and $36.4 million, respectively, which was due to an increase in the estimated useful lives of gathering systems in this region during 2014, partially offset by capital expenditures made in this region during 2014 and 2013.

Income from unconsolidated affiliates.  As part of the CMO Acquisition, we acquired a 33.33 percent equity interest in Ranch Westex JV LLC (“Ranch Westex”), which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC.  For the years ended December 31, 2014 and 2013, income from unconsolidated affiliates was $10.0 million and $1.2 million, respectively. Income from Ranch Westex increased during 2014 as a result of an increase in volumes during 2014, along with a fee redetermination that increased revenues.  

Corporate

Operating Expenses.  For the years ended December 31, 2014 and 2013, operating expenses were $67.1 million and $38.0 million, respectively. The increase in operating expenses is largely attributable to an increase in payroll compensation of $23.8 million, which included the accelerated vesting of the Long-Term Incentive Plan equity awards upon completion of the Williams acquisition.

General and Administrative Expense.  For the years ended December 31, 2014 and 2013, general and administrative expenses were $202.8 million and $104.3 million, respectively, representing an increase of 94.4 percent. This increase is attributable to an increase in payroll compensation of $76.9 million, primarily due to accelerated vesting of awards under the MICP and Long-Term Incentive Plan, upon completion of the Williams acquisition. Additionally, there was a $21.4 million increase in other general and administrative costs, primarily related to software licensing and maintenance, legal and audit costs.

Interest Expense. Interest expense for the year ended December 31, 2014 was $185.7 million, which was net of $25.6 million of capitalized interest. Interest expense was $116.8 million for the year ended December 31, 2013, which was net of $43.9 million of capitalized interest. The increase is related to interest expense on the additional senior notes

63


 

issued August 2013 and 2024 Notes, issued in March 2014. We also incurred interest expenses on borrowings under our revolving credit facility and our outstanding senior notes. Interest expense also includes commitment fees on the unused portion of our credit facility and amortization of debt issuance costs.

Income Tax Expense. Income tax expense for the years ended December 31, 2014 and 2013 was $0.6 million and $5.2 million, respectively, and was attributable to franchise taxes in the state of Texas. We and our subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements, other than Texas franchise tax.

Year Ended December 31, 2013 vs. Year Ended December 31, 2012

The following tables reflect our revenues, throughput, operating expenses and operating expenses per Mcf of throughput by segment for the years ended December 31, 2013 and 2012 (please note that revenue, throughput and operating expenses related to our equity investments (primarily in the Marcellus Shale) are excluded from the tables below as the financial results for our equity investments are reported separately. Please read “Income from Unconsolidated Affiliates” in this Results of Operations section of Management’s Discussion and Analysis of Financial Condition and Results of Operations):

 

 

Years Ended December 31,

 

  

 

 

 

2013

 

  

2012

 

  

% Change(1)

 

 

(In thousands, except percentages and throughput data)

 

Revenue:

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

$

433,709

 

 

$

395,467

 

 

 

9.7

%

Eagle Ford Shale(2)

 

278,282

 

 

 

7,232

 

 

 

N.M.

 

Haynesville Shale(2)

 

119,209

 

 

 

68,184

 

 

 

74.8

 

Marcellus Shale(2)

 

10,989

 

 

 

783

 

 

 

N.M.

 

Niobrara Shale(2)

 

15,095

 

 

 

116

 

 

 

N.M.

 

Utica Shale(2)

 

44,063

 

 

 

353

 

 

 

N.M.

 

Mid-Continent

 

171,875

 

 

 

136,312

 

 

 

26.1

 

 

$

1,073,222

 

 

$

608,447

 

 

 

76.4

%

Throughput (Bcf):

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

 

381.3

 

 

 

437.3

 

 

 

(12.8

)%

Eagle Ford Shale

 

96.0

 

 

 

2.2

 

 

 

N.M.

 

Haynesville Shale

 

244.3

 

 

 

138.4

 

 

 

76.5

 

Marcellus Shale

 

372.1

 

 

 

256.7

 

 

 

45.0

 

Niobrara Shale

 

5.5

 

 

 

0.1

 

 

 

N.M.

 

Utica Shale

 

39.0

 

 

 

0.5

 

 

 

N.M.

 

Mid-Continent

 

212.2

 

 

 

206.5

 

 

 

2.8

 

 

 

1,350.4

 

 

 

1,041.7

 

 

 

29.6

%

(1) 

N.M. - not meaningful

(2) 

Reflective of revenue after completion of the CMO Acquisition on December 20, 2012.

64


 

 

 

Years Ended December 31,

 

  

 

 

 

2013

 

  

2012

 

  

% Change(1)

 

 

(In thousands, except percentages and per Mcf data)

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

$

96,926

 

 

$

101,703

 

 

 

(4.7

)%

Eagle Ford Shale(2)

 

59,059

 

 

 

1,604

 

 

 

N.M.

 

Haynesville Shale(2)

 

41,176

 

 

 

15,642

 

 

 

163.2

 

Marcellus Shale(2)

 

4,834

 

 

 

188

 

 

 

N.M.

 

Niobrara Shale(2)

 

9,090

 

 

 

85

 

 

 

N.M.

 

Utica Shale(2)

 

19,065

 

 

 

159

 

 

 

N.M.

 

Mid-Continent

 

70,609

 

 

 

52,979

 

 

 

33.3

 

Corporate

 

37,957

 

 

 

25,279

 

 

 

50.2

 

 

$

338,716

 

 

$

197,639

 

 

 

71.4

%

Expenses ($ per Mcf):

 

 

 

 

 

 

 

 

 

 

 

Barnett Shale

$

0.25

 

 

$

0.23

 

 

 

8.7

%

Eagle Ford Shale

 

0.62

 

 

 

0.73

 

 

 

(15.1

)

Haynesville Shale

 

0.17

 

 

 

0.11

 

 

 

54.5

 

Marcellus Shale

 

1.01

 

 

 

0.63

 

 

 

60.3

 

Niobrara Shale

 

1.65

 

 

 

0.85

 

 

 

94.1

 

Utica Shale

 

0.49

 

 

 

0.31

 

 

 

58.1

 

Mid-Continent

 

0.33

 

 

 

0.26

 

 

 

26.9

 

 

$

0.34

 

 

$

0.19

 

 

 

78.9

%

(1) 

N.M. - not meaningful

(2) 

Reflective of operating expenses after completion of the CMO Acquisition on December 20, 2012.

Barnett Shale

Revenues. For the years ended December 31, 2013 and 2012, revenues totaled $433.7 million and $395.5 million, respectively. The increase was primarily the result of increasing volumes under our minimum volume commitment and the full year impact of the five cents per mcf fee redetermination which was effective on July 1, 2012.  Total revenue for 2013 includes $64.9 million of revenues associated with the contractual minimum volume commitment.  The minimum volume revenue offset a decrease in throughput of 12.8 percent due to decreased drilling activity by Chesapeake in 2013.

Operating Expenses.  For the years ended December 31, 2013 and 2012, operating expenses were $96.9 million, or $0.25 per Mcf, compared to $101.7 million, or $0.23 per Mcf, respectively. Total operating expenses decreased 4.7% consistent with the decrease in throughput. The most significant operating expenses in the Barnett Shale region are compression costs.

Depreciation and Amortization Expenses. For the years ended December 31, 2013 and 2012, depreciation expenses were $97.9 million and $93.3 million, respectively. The increase was due to capital expenditures made in this region during 2013 and 2012.

Eagle Ford Shale

We acquired the Eagle Ford Shale assets in December 2012.

Revenues. For the year ended December 31, 2013, revenues in the Eagle Ford totaled $278.3 million and were primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput.  We invested $316.0 million of capital in this region in 2013 and as a result, we experienced increased revenues in 2014.

Operating Expenses. For the year ended December 31, 2013, operating expenses totaled $59.1 million, or $0.62 per Mcf. The most significant operating expenses in this region are employee compensation and compression costs.

Depreciation and Amortization Expenses. Depreciation and amortization expense for the year ended December 31, 2013, was $51.4 million.

65


 

Haynesville Shale

Revenues. For the years ended December 31, 2013 and 2012, revenues were $119.2 million and $68.2 million, respectively. An overall increase in throughput of 76.5 percent resulted from production from the Mansfield gathering system acquired in December 2012, offset by a volume decrease for the Springridge gathering system of 16.1 percent.  Haynesville revenues were positively impacted by an annual rate escalation of 2.5 percent and rate redetermination of 15 percent on the Springridge gathering system, both effective January 1, 2013. Additionally, we have contractual minimum volume commitments from Chesapeake in the Haynesville Shale. Throughput for each of the years ended December 31, 2013 and 2012 was above the minimum volume commitment levels.

Operating Expenses. For the years ended December 31, 2013 and 2012, operating expenses were $41.2 million and $15.6 million, respectively.  All of our operating expenses in this region increased significantly as a result of the acquisition of the Mansfield gathering system in December 2012.  Operating expenses per Mcf increased primarily due to the need for additional treating services for the natural gas gathered in our Mansfield gathering system.

Marcellus Shale

On September 4, 2013, we sold Mid-Atlantic to Chesapeake for net proceeds of $32.9 million. Mid-Atlantic was acquired in December 2012 and consisted of midstream assets in the Marcellus region.  These assets were not part of our equity method investment in Appalachia Midstream. The net proceeds equaled our basis in the assets; thus, no gain or loss was recognized as a result of the sale.

The large majority of our assets in the Marcellus Shale are accounted for as equity investments and included in Income from Unconsolidated Affiliates. See further discussion below under “Income from Unconsolidated Affiliates” in this section of Marcellus Shale results of operations.

Income from unconsolidated affiliates. On December 29, 2011, we acquired all of the issued and outstanding equity interest in Appalachia Midstream, which owns an average 45 percent interest in 11 gas gathering systems in the Marcellus Shale in Pennsylvania and West Virginia. The remaining average 55 percent interests in these assets are owned primarily by Statoil, Anadarko, Epsilon and Mitsui. Income from unconsolidated affiliates was $133.0 million and $67.6 million reflecting activity for the years ended December 31, 2013 and 2012, respectively.  Revenues (net to our interest) for the years ended December 31, 2013 and 2012 were $234.8 million and $140.5 million, respectively.  The net increase was due to throughput growth and increased construction activity in the Marcellus region where we invested $289.7 million of capital in 2013.  Operating expenses on a per unit basis for the years ended December 31, 2013 and 2012 were $0.10 Mcf and $0.06 Mcf, respectively.  The increase in operating expenses is consistent with the increase in revenues in the Marcellus region.  The margin for these assets is strong as a result of lower operating expenses than in many other regions of the United States. These lower operating expenses are primarily due to high reservoir pressures that reduce the need for compression in the transportation of commodities.  We expect our margin in the Marcellus Shale to remain strong; however, we could experience a slight decrease in our margin over time as the need for additional compression increases. The following table summarizes the results of the Appalachia Midstream assets (net to our interest) for the year ended December 31, 2013.  

 

 

Year Ended
December 31,
2013

 

  

Year Ended
December 31,
2012

 

Revenue ($ in thousands)

$

234,801

  

  

$

140,541

  

Throughput (Bcf)

 

367.3

  

  

 

256.7

  

Operating Expenses ($ in thousands)

$

35,999

  

  

$

15,782

  

Expenses ($ per Mcf)

 

0.10

  

  

 

0.06

  

Niobrara Shale

Revenues.  For the year ended December 31, 2013, revenues in the Niobrara Shale region were $15.1 million and were primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput.  

Operating Expenses. For the year ended December 31, 2013, operating expenses in the Niobrara Shale region were $9.1 million. The most significant expenses in this region are employee compensation and compression costs.

66


 

Utica Shale

Revenues.  For the year ended December 31, 2013, revenues in the Utica Shale region were $44.1 million and were primarily attributable to the amount of throughput and rates charged for such throughput on our gathering systems and gathering systems included in the Cardinal Joint Venture.  We continue to invest significant capital in this region that is expected to drive volume and revenue growth in future periods.

Operating expenses.  For the year ended December 31, 2013, operating expenses in the Utica Shale region were $19.1 million. The most significant operating expenses in this region are compensation and compression costs.

Income from unconsolidated affiliates.  For the year ended December 31, 2013, loss from unconsolidated affiliates was $3.8 million.    

Mid-Continent

Revenues.  For the years ended December 31, 2013 and 2012, revenues were $171.9 million and $136.3 million, respectively. This increase was due to increased throughput of 2.8 percent as drilling activity increased in this liquids-rich region, a 2.5 percent annual fee escalation and a 15 percent fee increase due to annual contractual fee redetermination.

Operating Expenses.  For the years ended December 31, 2013 and 2012, operating expenses were $70.6 million and $53.0 million, respectively. Operating expenses increased primarily due to added compression in anticipation of additional future throughput.

Income from unconsolidated affiliates.  As part of the CMO Acquisition, we acquired a 33.33 percent equity interest in Ranch Westex JV LLC, which we own jointly with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC.  For the year ended December 31, 2013, income from unconsolidated affiliates was $1.2 million.    

Corporate

Operating Expenses.  For the years ended December 31, 2013 and 2012, operating expenses were $38.0 million and $25.3 million, respectively. The increase in operating expenses resulted from additional technical resources to support the assets acquired in 2012.

General and Administrative Expense.  For the years ended December 31, 2013 and 2012, general and administrative expenses were $104.3 million and $67.6 million, respectively, representing an increase of 54.3 percent. This increase is primarily attributable to additional overhead expenses resulting from the increased scale of our operations following the CMO Acquisition, additional expense from equity-based, long-term incentive compensation influenced by the increase in our unit price, as well as transition costs as we developed an independent back office infrastructure.

Interest Expense. Interest expense for the year ended December 31, 2013 was $116.8 million, which was net of $43.9 million of capitalized interest. Interest expense was $64.7 million for the year ended December 31, 2012, which was net of $14.6 million of capitalized interest. The increase is related to interest expense on the 2023 Notes, issued in December 2012 and the additional senior notes issued August 2013. We also incurred interest expenses on borrowings under our revolving credit facility and our outstanding senior notes. Interest expense also includes commitment fees on the unused portion of our credit facility and amortization of debt issuance costs.

Income Tax Expense. Income tax expense for the years ended December 31, 2013 and 2012 was $5.2 million and $3.2 million, respectively, and was attributable to franchise taxes in the state of Texas. We and our subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements, other than Texas franchise tax.  

Liquidity and Capital Resources

Following the Merger, our ability to finance operations, fund capital expenditures and pay distributions will largely depend on our ability to generate sufficient cash flow from operations as well as the availability of borrowings under our revolving credit facility and our access to the capital markets. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. See Risk Factors in Item 1A of this annual report.

67


 

Historically, our sources of liquidity included cash generated from operations and borrowings under our revolving credit facility.

Working Capital (Deficit).  Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of liquidity and the potential need for short-term funding. As of December 31, 2014, we had working capital of $217.6 million, and as of December 31, 2013, we had a working capital deficit of $48.5 million due to our capital intensive business that requires significant investment in new midstream operating assets and to maintain and improve existing facilities.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of the Partnership for the year ended December 31, 2014 and 2013 were as follows:

 

 

Years Ended
December 31,

 

 

2014

 

  

2013

 

 

($ in thousands)

 

Cash Flow Data:

 

 

 

  

 

 

 

Net cash provided by (used in):

 

 

 

  

 

 

 

Operating activities

$

770,973

  

  

$

563,962

  

Investing activities

(1,487,658

)  

  

(1,556,418

Financing activities

741,327

  

  

944,691

  

Operating Activities.  Net cash provided by operating activities was $771.0 million for the year ended December 31, 2014 compared to $564.0 million during the year ended December 31, 2013. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, amortization and gains or losses on the sales of fixed assets. The increase was primarily attributable to distributions of earnings received from our unconsolidated affiliates and the timing impacts on our working capital accounts.  Please read “Results of Operations” above in this Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Investing Activities.  Net cash used in investing activities for the year ended December 31, 2014 decreased $68.8 million compared to the prior year. Approximately $1.5 billion of cash was used in investing activities during 2014. This amount included approximately $999.2 million in additions to property, plant, and equipment, $159.2 million in the purchase of compression assets and $351.3 million in additions to our investments in unconsolidated affiliates.

Financing Activities.  Net cash provided by financing activities was $741.3 million for the year ended December 31, 2014 compared to $944.7 million for the year ended December 31, 2013. This decrease was primarily attributable to the issuance of senior notes during 2014, offset by an increase in payments on long-term borrowings.

Sources of Liquidity.  At December 31, 2014, our sources of liquidity included:

cash on hand;

cash generated from operations;

borrowings availability under our revolving credit facility; and

capital raised through debt and equity markets.

Following the Merger, we now have a new $3.5 billion long-term unsecured credit facility, a $3.0 billion commercial paper program, and a $1.5 billion short-term unsecured credit facility, all as further described below.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to fund our quarterly cash distributions to unitholders.

Cash flow from operations is a significant source of liquidity we use to fund capital expenditures, pay distributions and service debt. We have historically and expect in the future to use capacity on our credit facility and the capital markets to fund growth capital and acquire natural gas, natural gas liquids and oil gathering systems and other midstream energy assets, allowing us to execute our growth strategy.

68


 

Revolving Credit Facility.  As of December 31, 2014 and 2013, we had approximately $640.0 million and $343.5 million, respectively, of borrowings outstanding under our revolving credit facility.  On February 2, 2015, the revolving credit facility loans outstanding were paid and the revolving credit facility was terminated in connection with the Merger.

Credit Facilities Post-Merger. On February 2, 2015, we along with Transco and Northwest Pipeline, the lenders named therein and an administrative agent, entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020.  However, the co-borrowers may request an extension of the maturity date for an additional one year period, up to two times, to allow a maturity date as late as February 2, 2022 under certain conditions. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments of $1.125 billion. As of February 2, 2015, the total amount of outstanding letters of credit under the credit facility was approximately $2.0 million.  Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.  As measured at December 31, 2014, we were in compliance with the financial covenants applicable to the revolving credit facility then in effect.

The agreement governing our credit facility contains the following terms and conditions:

Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.

Other than swingline loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing.  If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus ½ of 1% and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1%, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin.  Interest on swingline loans is calculated as the sum of the alternate base rate plus an applicable margin.  The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

Our significant financial covenants require:

The ratio of debt to EBITDA (each as defined in the credit facility) to be no greater than 5 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.

The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline.

 

On February 3, 2015, we entered into a Credit Agreement providing for a $1.5 billion short-term credit facility with a maturity date of August 3, 2015 with an option to extend the maturity date to February 2, 2016 subject to certain circumstances.  Our short-term credit facility has substantially the same covenants as our $3.5 billion credit facility.  Under our short-term credit facility any time funds are borrowed, we must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing.  Interest is calculated on each of these types of borrowings in the same manner as under our $3.5 billion credit facility. We are required to pay a commitment fee based on the unused portion of the short-term credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on our senior unsecured long-term debt ratings.  In the event of certain debt incurrences, issuances of equity, and certain asset sales, the Merged Partnership will be required to repay any outstanding borrowings and the commitments under the Short-Term Facility will be reduced on a dollar-for-dollar basis with the net cash proceeds of such events.

69


 

On February 2, 2015, the commercial paper program of Pre-merger WPZ was amended and restated for the merger and to allow a maximum outstanding amount of $3 billion.  The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance.  The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis.

Equity Issuances.  On August 2, 2013, we entered into an Equity Distribution Agreement (“ATM”) under which we may offer and sell common units, in amounts, at prices and on terms to be determined by market conditions and other factors, having an aggregate market value of up to $300 million. We are under no obligation to issue equity under the ATM. For the year ended December 31, 2014, we sold an aggregate of 0.9 million common units under the ATM for net proceeds of approximately $52.2 million, net of approximately $0.5 million in commissions, plus an approximate $1.0 million capital contribution from our general partner to maintain its two percent general partner interest.  For the year ended December 31, 2013, we sold an aggregate of 0.9 million common units under the ATM for aggregate gross proceeds of approximately $50.1 million and an approximate $1.0 million capital contribution from our general partner to maintain its two percent general partner interest. We used the proceeds for general partnership purposes. On February 24, 2015 we filed a post-effective amendment to terminate the effectiveness of the registration statement pertaining to sales of securities under the ATM and to deregister the offer and sale of all unsold securities thereunder.  We anticipate filing a new registration statement on Form S-3 concerning the sale, on a continuous offering basis, by the Merged Partnership of common units.

On April 2, 2013, we completed an equity offering of 10.35 million common units, including 1.35 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $39.86 per common unit. We received offering proceeds (net of underwriting discounts and commissions) of $399.8 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units and an approximate $8.4 million capital contribution from our general partner to maintain its two percent general partner interest. The proceeds were used for general partnership purposes, including repayment of amounts outstanding under our revolving credit facility.

On December 18, 2012, we completed an equity offering of 18.4 million common units, including 2.4 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $32.15 per common unit. We received offering proceeds (net of underwriting discounts, commissions and offering expenses) of approximately $569.3 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units. We used the net proceeds to pay a portion of the purchase price for the CMO Acquisition.

Subscription Agreement.  On December 20, 2012, we sold 5.9 million Class B units to each of the GIP II Entities and Williams and 5.6 million Class C units to each of the GIP II Entities and Williams, in each case pursuant to the subscription agreement. We received aggregate proceeds of approximately $712.1 million in exchange for the sale of Class B units and Class C units, inclusive of the capital contribution made by our general partner to maintain its two percent interest in us following the issuance of the Class B and Class C units.

Capital Requirements.  Our business is capital-intensive, requiring significant investment to grow our business as well as to maintain and improve existing assets. We categorize capital expenditures as either:

maintenance capital expenditures, which include those expenditures required to maintain our long-term operating capacity and/or operating income and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or

growth capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, expand and upgrade our systems and facilities, extend the useful lives of our assets, increase gathering, treating, compression and processing throughput from current levels and reduce costs or increase revenues.

For the years ended December 31, 2014 and 2013, growth capital expenditures totaled $1.1 billion and $1.5 billion, respectively. The 2014 and 2013 amounts include $385.2 million and $671.4 million, respectively, of capital expenditures made as part of our unconsolidated affiliates that are accounted for as equity investments. Maintenance capital expenditures totaled $130.0 million and $110.0 million for the years ended December 31, 2014 and 2013, respectively, an

70


 

increase of 18.2 percent. Our future capital expenditures may vary significantly from budgeted amounts and from period to period based on the investment opportunities that become available to us.

We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because our partnership agreement requires us to distribute most of the cash generated from operations to our unitholders and our general partner, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations that is not distributed to our unitholders and general partner, borrowings under our revolving credit facility and future issuances of equity and debt securities.

Distributions. We intend to pay a minimum quarterly distribution of $0.3375 per unit per quarter. We do not have a legal obligation to pay this distribution. Our distribution for the fourth quarter 2014 was a distribution from the Merged Partnership and was calculated based on the Merged Partnership’s units at the record date.

The following table represents a summary of our quarterly distributions for the years ended December 31, 2014 and 2013:

 

 

Declaration
Date

 

  

Record
Date

 

  

Distribution
Date

 

  

Distribution
Declared

 

2014

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Fourth quarter

 

January 26, 2015

  

  

 

February 9, 2015

  

  

 

February 13, 2015

  

  

$

0.8500

  

Third quarter

 

October 23, 2014

  

  

 

November 7, 2014

  

  

 

November 14, 2014

  

  

0.6150

  

Second quarter

 

July 18, 2014

  

  

 

August 7, 2014

  

  

 

August 14, 2014

  

  

0.5950

  

First quarter

 

April 24, 2014

  

  

 

May 8, 2014

  

  

 

May 15, 2014

  

  

0.5750

  

2013

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Fourth quarter

 

January 24, 2014

  

  

 

February 7, 2014

  

  

 

February 14, 2014

  

  

$

0.5550

  

Third quarter

 

October 25, 2013

  

  

 

November 7, 2013

  

  

 

November 14, 2013

  

  

0.5350

  

Second quarter

 

July 24, 2013

  

  

 

August 7, 2013

  

  

 

August 14, 2013

  

  

0.4850

  

First quarter

 

April 24, 2013

  

  

 

May 8, 2013

  

  

 

May 15, 2013

  

  

0.4675

  

Contractual Obligations.  At December 31, 2014, and not reflecting the Merger, our contractual obligations included:

 

 

Payments Due By Period

 

 

Total

 

  

Less than
1 year

 

  

1-3 years

 

  

3-5 years

 

  

More than
5 years

 

 

(in thousands)

 

Long-term debt (including interest)(1)(2)

$

5,787,147

  

  

$

839,263

  

  

$

398,526

  

  

$

389,896

  

  

$

4,159,462

  

Other long-term liabilities

 

71,700

 

 

 

 

 

 

 

 

 

71,700

 

 

 

 

Purchase obligations

 

326,628

 

 

 

326,628

 

 

 

 

 

 

 

 

 

 

Capital leases

 

4,602

 

 

 

3,287

 

 

 

1,315

 

 

 

 

 

 

 

Operating leases

 

114,049

  

  

 

38,889

  

  

 

47,034

  

  

 

12,338

  

  

 

15,788

  

Total

$

6,304,126

  

  

$

1,208,067

  

  

$

446,875

  

  

$

473,934

  

  

$

4,175,250

  

(1)

Assumes a commitment fee of 0.375 percent on the unused portion of the credit facility.

(2)

In conjunction with the Merger, we assumed long-term debt of $16.3 billion as of December 31, 2014, with maturities ranging from 2015 to 2045, not included in this table.

Off-Balance Sheet Arrangements of Debt or Other Commitments

We have various other commitments which are disclosed in Note 2 (Summary of Significant Accounting Policies – Fair Value) and Note 13 (Commitments and Contingencies) of Notes to Condensed Consolidated Financial Statements.  We do not believe these commitments will prevent us from meeting our liquidity needs.

Critical Accounting Policies and Estimates

Readers of this report and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The policies we consider to be the most significant are discussed below. The Partnership’s management has discussed each critical accounting policy with the Audit Committee of the Partnership’s general partner’s board of directors.

71


 

The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business.

Depreciation and amortization

Depreciation associated with our property, plant and equipment and other assets is calculated using the straight-line method, based on the estimated useful lives of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we make estimates with respect to useful lives and salvage values that we believe are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation. The estimated service lives of our functional asset groups are as follows:

 

Asset Group

  

Estimated Useful Lives
(In years)

Gathering systems

  

30

Other fixed assets

  

2 to 39

Intangible assets are generally amortized on a straight-line basis over their estimated useful lives, unless the assets’ economic benefits are consumed on an other than straight-line basis. The estimated useful life is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows.

Impairment of long-lived assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized. Fair value is typically determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.

Variable Interest Entities (“VIEs”)

An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. We consolidate a VIE when we have both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. We continually monitor both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change.

 

72


 

ITEM  7A.

Quantitative and Qualitative Disclosures About Market Risk

As of December 31, 2014, we are dependent on Chesapeake, Total and other producers for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake, Total or other producers of gathering, treating and compression fees. Chesapeake’s debt ratings for its senior notes are below investment grade, and they may remain below investment grade for the foreseeable future. Additionally, we are also subject to the risk that one or more of these customers default on its obligations under its gas gathering agreements with us. Not all of our counterparties under our gas gathering agreements are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with an investment grade or otherwise rated contract counterparty or with a more diversified group of customers, and unless and until we significantly increase our customer base, we expect to continue to be subject to significant and non-diversified risk of nonpayment or late payment of our fees.

Interest Rate Risk

If interest rates rise, our financing costs would increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. For the year ended December 31, 2014, a 125 basis point increase in the interest rate would have resulted in a $50.1 million decrease in net income.

Commodity Price Risk

We attempt to mitigate commodity price risk by contracting our operations on a long-term fixed-fee basis and through various provisions in our gas gathering and processing agreements that are intended to support the stability of our cash flows. Natural gas prices are historically impacted by changes in the supply and demand of natural gas, as well as market uncertainty. However, an actual or anticipated prolonged reduction in natural gas prices or disparity in oil and natural gas pricing could result in reduced drilling in our areas of operations and, accordingly, in volumes of natural gas gathered by our systems. Notwithstanding any minimum volume commitments, fee redetermination provisions and cost of service provisions in our commercial agreements with producers, a reduction in volumes of natural gas gathered by our systems could adversely affect both our profitability and our cash flows. Adverse effects on our cash flows from reductions in natural gas prices could adversely affect our ability to make cash distributions to our unitholders.

We have agreed with our producer customers on caps on fuel and lost and unaccounted for gas on certain of our gathering systems in our operating regions. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

Additionally, an increase in commodity prices could result in increased costs of steel and other products that we use in the operation of our business, as well as the cost of obtaining rights-of-way for property on which our assets are located. Accordingly, our operating expenses and capital expenditures could increase as a result of an increase in commodity prices.

 

 

 

73


 

PART II

 

ITEM  8.

Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS

WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

 

 

 

 

74


 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

 

The Board of Directors of WPZ GP LLC,

General Partner of Williams Partners L.P.

and the Limited Partners of Williams Partners L.P.

 

We have audited the accompanying consolidated balance sheet of Williams Partners L.P. (formerly named Access Midstream Partners, L.P.) (the “Partnership”) as of December 31, 2014, and the related consolidated statements of income, changes in partners’ capital, and cash flows for the year then ended.  These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit. 

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2014, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 25, 2015 expressed an unqualified opinion thereon.

 

/s/ Ernst & Young LLP

 

Tulsa, Oklahoma

February 25, 2015

 

 


75


 

Report of Independent Registered Public Accounting Firm

 

To the Board of Directors of Access Midstream Partners GP, L.L.C., as General Partner of

Williams Partners, L.P. formerly known as Access Midstream Partners, L.P. and the Unitholders

 

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of changes in partners’ capital and of cash flows present fairly, in all material respects, the financial position of Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.) and its subsidiaries (the “Partnership”) at December 31, 2013 and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

Prior to December 2012, as discussed in Notes 5 and 6 to the accompanying consolidated financial statements, Williams Partners L.P. (formerly known as Access Midstream Partners, L.P.) earned substantially all of its revenues and had other significant transactions with affiliated entities.

 

 

/s/ PricewaterhouseCoopers LLP

 

Tulsa, Oklahoma

February 21, 2014, except for Note 16 to the consolidated financial statements appearing under Item 8 of the Partnership’s 2013 Annual Report on Form 10-K/A (not presented herein), as to which the date is March 3, 2014, and except for the effects of the capital structure change described in Note 1, as to which the date is February 25, 2015

 

 

 

 

 

76


 

WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

CONSOLIDATED BALANCE SHEETS

 

 

December 31,

 

 

December 31,

 

 

2014

 

 

2013

 

 

($ in thousands)

 

ASSETS

 

 

 

 

 

 

 

Current assets

 

 

 

 

 

 

 

Cash and cash equivalents

$

41,871

 

 

$

17,229

 

Accounts receivable

 

377,078

 

 

 

222,409

 

Prepaid expenses

 

24,531

 

 

 

10,182

 

Other current assets

 

19,924

 

 

 

8,111

 

Total current assets

 

463,404

 

 

 

257,931

 

 

 

 

 

 

 

 

 

Property, plant and equipment

 

 

 

 

 

 

 

Gathering systems

 

6,700,092

 

 

 

5,974,940

 

Other fixed assets

 

469,482

 

 

 

175,411

 

Less: Accumulated depreciation

 

(1,117,105

)

 

 

(859,551

)

Total property, plant and equipment, net

 

6,052,469

 

 

 

5,290,800

 

Investments in unconsolidated affiliates

 

2,229,986

 

 

 

1,936,603

 

Intangible customer relationships, net

 

348,683

 

 

 

372,391

 

Deferred loan costs, net

 

49,035

 

 

 

59,721

 

Total assets

$

9,143,577

 

 

$

7,917,446

 

LIABILITIES AND PARTNERS' CAPITAL

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

 

Accounts payable

$

32,575

 

 

$

37,520

 

Accrued gathering liabilities

 

54,490

 

 

 

108,934

 

Accrued interest

 

50,197

 

 

 

39,422

 

Accrued compensation and benefits

 

23,165

 

 

 

48,745

 

Due to affiliate

 

17,988

 

 

 

-

 

Accrued taxes

 

22,643

 

 

 

25,273

 

Other accrued liabilities

 

44,761

 

 

 

46,578

 

Total current liabilities

 

245,819

 

 

 

306,472

 

 

 

 

 

 

 

 

 

Long-term liabilities

 

 

 

 

 

 

 

Long-term debt

 

4,295,055

 

 

 

3,249,230

 

Other liabilities

 

90,386

 

 

 

8,954

 

Total long-term liabilities

 

4,385,441

 

 

 

3,258,184

 

 

 

 

 

 

 

 

 

Commitments and contingencies (Note 13)

 

 

 

 

 

 

 

Partners' capital

 

 

 

 

 

 

 

Common units (202,532,920 and 188,739,474 issued and outstanding at

   December 31, 2014 and December 31, 2013, respectively) (Note 1)

 

3,501,613

 

 

 

3,343,145

 

Class B units (13,725,843 and 13,188,705 issued and outstanding at

   December 31, 2014 and December 31, 2013) (Note 1)

 

360,190

 

 

 

318,472

 

Class C units (zero and 11,888,247 issued and outstanding at

   December 31, 2014 and December 31, 2013) (Note 1)

 

-

 

 

 

322,896

 

General partner interest

 

172,824

 

 

 

114,393

 

Total partners' capital attributable to Williams Partners L.P. (formerly

   Access Midstream Partners, L.P.)

 

4,034,627

 

 

 

4,098,906

 

Noncontrolling interest

 

477,690

 

 

 

253,884

 

Total partners' capital

 

4,512,317

 

 

 

4,352,790

 

Total liabilities and partners' capital

$

9,143,577

 

 

$

7,917,446

 

    

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

77


 

WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

CONSOLIDATED STATEMENTS OF INCOME

 

 

 

 

Year Ended

 

 

Year Ended

 

 

Year Ended

 

 

December 31,

 

 

December 31,

 

 

December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

($ in thousands, except per unit data)

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

1,378,939

 

 

$

1,073,222

 

 

$

608,447

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

427,589

 

 

 

338,716

 

 

 

197,639

 

Depreciation and amortization expense

 

314,758

 

 

 

296,179

 

 

 

165,517

 

General and administrative expense

 

202,796

 

 

 

104,332

 

 

 

67,579

 

Other operating expense (income)

 

24,123

 

 

 

2,092

 

 

 

(766

)

 

 

 

 

 

 

 

 

 

 

 

 

Total operating expenses

 

969,266

 

 

 

741,319

 

 

 

429,969

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

409,673

 

 

 

331,903

 

 

 

178,478

 

 

 

 

 

 

 

 

 

 

 

 

 

Other income (expense)

 

 

 

 

 

 

 

 

 

 

 

Income from unconsolidated affiliates

 

205,082

 

 

 

130,420

 

 

 

67,542

 

Interest expense

 

(185,680

)

 

 

(116,778

)

 

 

(64,739

)

Other income

 

872

 

 

 

827

 

 

 

320

 

 

 

 

 

 

 

 

 

 

 

 

 

Income before income tax expense

 

429,947

 

 

 

346,372

 

 

 

181,601

 

Income tax expense

 

576

 

 

 

5,223

 

 

 

3,214

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income

 

429,371

 

 

 

341,149

 

 

 

178,387

 

Net income (loss) attributable to noncontrolling interests

 

31,311

 

 

 

5,124

 

 

 

(68

)

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to Williams Partners L.P. (formerly

   Access Midstream Partners, L.P.)

$

398,060

 

 

$

336,025

 

 

$

178,455

 

 

 

 

 

 

 

 

 

 

 

 

 

Limited partner interest in net income

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to Williams Partners L.P. (formerly

   Access Midstream Partners, L.P.)

$

398,060

 

 

$

336,025

 

 

$

178,455

 

Less general partner interest in net income (Note 4)

 

(147,507

)

 

 

(40,681

)

 

 

(8,481

)

Limited partner interest in net income

$

250,553

 

 

$

295,344

 

 

$

169,974

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income per limited partner unit - basic and diluted (Note 4)

 

 

 

 

 

 

 

 

 

 

 

Common units

$

1.01

 

 

$

0.95

 

 

$

1.05

 

Subordinated units (Note 3)

$

-

 

 

$

0.88

 

 

$

1.07

 

    

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

78


 

WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

 

Year Ended

 

 

Year Ended

 

 

Year Ended

 

 

December 31,

 

 

December 31,

 

 

December 31,

 

 

2014

 

 

2013

 

 

2012

 

 

($ in thousands)

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

 

 

Net income

$

429,371

 

 

$

341,149

 

 

$

178,387

 

Adjustments to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

314,758

 

 

 

296,179

 

 

 

165,517

 

Income from unconsolidated affiliates

 

(205,082

)

 

 

(130,420

)

 

 

(67,542

)

Loss on impairments and disposals of assets

 

23,783

 

 

 

-

 

 

 

-

 

Other non-cash items

 

35,621

 

 

 

20,577

 

 

 

8,296

 

Distribution of earnings received from unconsolidated affiliates

 

281,733

 

 

 

82,871

 

 

 

-

 

Changes in assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

(Increase) decrease in accounts receivable

 

(143,810

)

 

 

(97,507

)

 

 

18,484

 

(Increase) decrease in other assets

 

(13,270

)

 

 

2,244

 

 

 

(9,925

)

Increase (decrease) in accounts payable

 

(4,286

)

 

 

(10,492

)

 

 

8,800

 

Increase (decrease) in accrued liabilities

 

(19,545

)

 

 

59,361

 

 

 

16,113

 

Increase (decrease) in other long-term liabilities

 

71,700

 

 

 

-

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

770,973

 

 

 

563,962

 

 

 

318,130

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

 

 

 

 

 

 

Additions to property, plant and equipment

 

(999,211

)

 

 

(1,058,599

)

 

 

(350,500

)

Purchase of compression assets

 

(159,210

)

 

 

-

 

 

 

-

 

Acquisition of gathering system assets

 

-

 

 

 

-

 

 

 

(2,160,000

)

Investments in unconsolidated affiliates

 

(351,331

)

 

 

(572,370

)

 

 

(185,039

)

Proceeds from sale of assets

 

22,094

 

 

 

74,551

 

 

 

9,574

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash used in investing activities

 

(1,487,658

)

 

 

(1,556,418

)

 

 

(2,685,965

)

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

 

 

Proceeds from long-term debt borrowings

 

2,699,371

 

 

 

2,015,700

 

 

 

1,387,800

 

Payments on long-term debt borrowings

 

(2,402,871

)

 

 

(1,672,200

)

 

 

(2,100,700

)

Proceeds from issuance of common units

 

52,155

 

 

 

449,312

 

 

 

569,255

 

Proceeds from issuance of Class B units

 

-

 

 

 

-

 

 

 

343,000

 

Proceeds from issuance of Class C units

 

-

 

 

 

-

 

 

 

343,000

 

Proceeds from issuance of senior notes

 

750,000

 

 

 

414,094

 

 

 

2,150,000

 

Distributions to unitholders

 

(536,716

)

 

 

(389,128

)

 

 

(251,720

)

Capital contributions from noncontrolling interests

 

192,495

 

 

 

151,976

 

 

 

-

 

Payments on capital lease obligations

 

(3,479

)

 

 

(3,552

)

 

 

-

 

Payments on leasehold improvement financing

 

-

 

 

 

(17,798

)

 

 

-

 

Debt issuance costs

 

(8,929

)

 

 

(12,414

)

 

 

(39,626

)

Other

 

(699

)

 

 

8,701

 

 

 

31,798

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by financing activities

 

741,327

 

 

 

944,691

 

 

 

2,432,807

 

 

 

 

 

 

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

24,642

 

 

 

(47,765

)

 

 

64,972

 

Cash and cash equivalents, beginning of period

 

17,229

 

 

 

64,994

 

 

 

22

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents, end of period

$

41,871

 

 

$

17,229

 

 

$

64,994

 

 

 

 

 

 

 

 

 

 

 

 

 

Supplemental disclosure of non-cash investing activities:

 

 

 

 

 

 

 

 

 

 

 

Changes in accounts payable and other liabilities related to purchases of property,

   plant and equipment

$

36,603

 

 

$

7,434

 

 

$

60,427

 

Changes in other liabilities related to asset retirement obligations

$

8,494

 

 

$

(1,314

)

 

$

(133

)

Property, plant and equipment acquired under capital lease

$

-

 

 

$

(9,370

)

 

$

-

 

Property, plant and equipment acquired through leasehold improvement financing

$

-

 

 

$

(17,798

)

 

$

-

 

 

 

 

 

 

 

 

 

 

 

 

 

Supplemental disclosure of cash payments for interest, net of capitalized interest

$

151,786

 

 

$

39,939

 

 

$

30,292

 

Supplemental disclosure of cash payments for taxes

$

2,000

 

 

$

3,300

 

 

$

2,900

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

79


 

WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

 

 

Partners' Equity

 

 

 

 

 

 

Limited Partners

 

 

 

 

 

 

Non-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General

 

 

controlling

 

 

 

 

 

 

Common

 

 

Subordinated

 

 

Class B

 

 

Class C

 

 

Partner

 

 

interest

 

 

Total

 

($ in thousands)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2011

$

1,561,504

 

 

$

869,241

 

 

$

-

 

 

$

-

 

 

$

42,400

 

 

$

-

 

 

$

2,473,145

 

Net income

 

90,822

 

 

 

78,736

 

 

 

214

 

 

 

202

 

 

 

8,481

 

 

 

(68

)

 

 

178,387

 

Distribution to unitholders

 

(130,204

)

 

 

(113,976

)

 

 

-

 

 

 

-

 

 

 

(7,540

)

 

 

-

 

 

 

(251,720

)

Contributions from noncontrolling interest

   owners

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

111,741

 

 

 

111,741

 

Non-cash equity based compensation

 

3,695

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

3,695

 

Issuance of common units

 

569,255

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

569,255

 

Issuance of Class B units

 

-

 

 

 

-

 

 

 

331,148

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

331,148

 

Issuance of Class C units

 

-

 

 

 

-

 

 

 

-

 

 

 

331,115

 

 

 

-

 

 

 

-

 

 

 

331,115

 

Issuance of general partner units

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

49,841

 

 

 

-

 

 

 

49,841

 

Beneficial conversion feature of Class B

   and Class C units

 

95,073

 

 

 

-

 

 

 

(58,328

)

 

 

(36,745

)

 

 

-

 

 

 

-

 

 

 

-

 

Amortization of beneficial conversion

   feature of Class B and Class C units

 

(1,803

)

 

 

-

 

 

 

824

 

 

 

979

 

 

 

-

 

 

 

-

 

 

 

-

 

Other adjustments

 

(101

)

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

(101

)

Balance at December 31, 2012

$

2,188,241

 

 

$

834,001

 

 

$

273,858

 

 

$

295,551

 

 

$

93,182

 

 

$

111,673

 

 

$

3,796,506

 

Net income

 

206,236

 

 

 

54,479

 

 

 

18,055

 

 

 

16,574

 

 

 

40,681

 

 

 

5,124

 

 

 

341,149

 

Distribution to unitholders

 

(241,080

)

 

 

(96,879

)

 

 

-

 

 

 

(21,699

)

 

 

(29,470

)

 

 

-

 

 

 

(389,128

)

Conversion of subordinated units to

   common units

 

791,601

 

 

 

(791,601

)

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Contributions from noncontrolling interest

   owners

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

137,087

 

 

 

137,087

 

Non-cash equity based compensation

 

7,864

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

7,864

 

Issuance of common units

 

449,312

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

449,312

 

Issuance of general partner interests

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

10,000

 

 

 

-

 

 

 

10,000

 

Beneficial conversion feature of Class B

   units

 

1,317

 

 

 

-

 

 

 

(1,317

)

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Amortization of beneficial conversion

   feature of Class B and Class C units

 

(60,346

)

 

 

-

 

 

 

27,876

 

 

 

32,470

 

 

 

-

 

 

 

-

 

 

 

-

 

Balance at December 31, 2013

$

3,343,145

 

 

$

-

 

 

$

318,472

 

 

$

322,896

 

 

$

114,393

 

 

$

253,884

 

 

$

4,352,790

 

Net income

 

235,828

 

 

 

-

 

 

 

13,550

 

 

 

1,175

 

 

 

147,507

 

 

 

31,311

 

 

 

429,371

 

Distribution to unitholders

 

(438,635

)

 

 

-

 

 

 

-

 

 

 

(6,215

)

 

 

(91,866

)

 

 

-

 

 

 

(536,716

)

Conversion of Class C units to common

   units

 

321,151

 

 

 

-

 

 

 

-

 

 

 

(321,151

)

 

 

-

 

 

 

-

 

 

 

-

 

Contributions from noncontrolling interest

   owners

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

192,495

 

 

 

192,495

 

Non-cash equity based compensation

 

19,432

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

19,432

 

Issuance of general partner interests

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

2,790

 

 

 

-

 

 

 

2,790

 

Issuance of common units

 

52,155

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

52,155

 

Beneficial conversion feature of Class B

   units

 

(1,317

)

 

 

-

 

 

 

1,317

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

Amortization of beneficial conversion

   feature of Class B and Class C units

 

(30,146

)

 

 

-

 

 

 

26,851

 

 

 

3,295

 

 

 

-

 

 

 

-

 

 

 

-

 

Balance at December 31, 2014

$

3,501,613

 

 

$

-

 

 

$

360,190

 

 

$

-

 

 

$

172,824

 

 

$

477,690

 

 

$

4,512,317

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

80


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.

Description of Business and Basis of Presentation

Basis of presentation. These financial statements pertain to the entity formerly named Access Midstream Partners, L.P. (“ACMP”).  As further described below, following the consummation of a merger on February 2, 2015, the name of the entity was changed to Williams Partners L.P.  For purposes of these financial statements, 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.  WPZ, a Delaware limited partnership formed in January 2010, is principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. The Partnership’s assets are located in Arkansas, Kansas, Louisiana, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation (“Chesapeake”), Total Gas and Power North America, Inc. and Total E&P USA, Inc., a wholly owned subsidiary of Total, S.A. (collectively, “Total”), Statoil ASA (“Statoil”), Anadarko Petroleum Corporation (“Anadarko”), Mitsui & Co., Ltd. (“Mitsui”) and other producers under long-term, fixed-fee contracts.

For purposes of these financial statements, the “GIP I Entities” refers to, collectively, GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P. and GIP-C Holding (CHK), L.P., the “GIP II Entities” refers to certain entities affiliated with Global Infrastructure Investors II, LLC, and “GIP” refers to the GIP I Entities and their affiliates and the GIP II Entities, collectively. “Williams” refers to The Williams Companies, Inc. (NYSE: WMB).

The accompanying consolidated financial statements of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). To conform to these accounting principles, management makes estimates and assumptions that affect the amounts reported in the consolidated financial statements and the notes thereto. These estimates are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known.

Williams Acquisition. On July 1, 2014, Williams acquired all of the interests in the Partnership and Access Midstream Ventures, L.L.C. (“Access Midstream Ventures”), the sole member of Access Midstream Partners GP, L.L.C. (the “General Partner”), that were owned by the GIP II Entities (the “Williams Acquisition”).  As a result of the Williams Acquisition, Williams wholly owns the General Partner.  The GIP II Entities no longer have any ownership interest in the Partnership or the General Partner.  At December 31, 2014, Williams held 4,157,665 notional general partner units representing a 2.0 percent general partner interest in the Partnership, all of the Partnership’s incentive distribution rights, 88,940,056 common units and 12,930,367 Class B units.  At December 31, 2014, Williams’ ownership represented an aggregate 49.0 percent limited partner interest in the Partnership. The public held 101,855,143 common units, representing a 49.0 percent limited partner interest in the Partnership.

 

As a result of the Williams Acquisition, both components of the Management Incentive Compensation Plan and all of the equity awards previously outstanding under the Long-Term Incentive Plan vested on July 1, 2014.  In addition, on July 16, 2014, the Partnership issued cash and equity retention awards to certain key employees that have various vesting periods between one and four years.  As a result of these transaction related costs, total compensation expense for the year ended December 31, 2014 was approximately $96.0 million.

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.

81


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 percent of the outstanding partnership interest.  Following the Merger, Williams owns an approximate 60 percent interest in 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.  Due to the ownership of the general partners, Williams controlled both partnerships.  Williams’ control of Pre-merger WPZ began with its 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.

Midcon Acquisition. On March 31, 2014, the Partnership acquired certain midstream compression assets from MidCon Compression, L.L.C. (“MidCon”), a wholly owned subsidiary of Chesapeake, for approximately $160 million. The acquisition added natural gas compression assets, historically leased from MidCon, in the rapidly growing Utica Shale and Marcellus Shale regions. The acquired assets include more than 100 compression units with a combined capacity of approximately 200,000 horsepower.

GIP II Entities acquisition. During the second quarter of 2012, the GIP II Entities acquired Chesapeake’s 50 percent interest in the Partnership’s general partner and all of the common units and subordinated units in the Partnership that were previously held by Chesapeake. The remaining 50 percent interest in the Partnership’s general partner continued to be owned by the GIP I Entities.

Williams 2012 Acquisition. Concurrently with the CMO Acquisition, the GIP I Entities sold to Williams 34,538,061 of the Partnership’s subordinated units and 50% of the outstanding equity interests in the General Partner, for cash consideration of approximately $1.8 billion (the “Williams 2012 Acquisition”). The Partnership did not receive any cash proceeds from the Williams 2012 Acquisition. As a result of the closing of the Williams 2012 Acquisition, the GIP I Entities no longer had any ownership interest in the Partnership or its general partner and the GIP II Entities and Williams together owned and controlled the Partnership’s general partner until the Williams Acquisition in 2014.

 

Equity Issuance. On August 2, 2013, the Partnership entered into an Equity Distribution Agreement (“ATM”) under which it may offer and sell common units, in amounts, at prices and on terms to be determined by market conditions and other factors, having an aggregate market value of up to $300 million. The Partnership is under no obligation to issue equity under the ATM. For the year ended December 31, 2014, the Partnership sold an aggregate of 0.9 million common units under the ATM for net proceeds of approximately $52.2 million, net of approximately $0.5 million in commissions, plus an approximate $1.0 million capital contribution from the Partnership’s general partner to maintain its two percent general partner interest. For the year ended December 31, 2013, the Partnership sold an aggregate of 0.9 million common units under the ATM for aggregate gross proceeds of approximately $50.1 million and an approximate $1.0 million capital contribution from the Partnership’s general partner to maintain its two percent general partner interest. The Partnership used the proceeds for general partnership purposes. On February 24, 2015 management filed a post-effective amendment to terminate the effectiveness of the registration statement pertaining to sales of securities under the ATM and to deregister the offer and sale of all unsold securities thereunder.  Management anticipates filing a new registration statement on Form S-3 concerning the sale, on a continuous offering basis, by the Merged Partnership of common units.

On April 2, 2013, the Partnership completed an equity offering of 10.35 million common units, including 1.35 million common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, at a price of $39.86 per common unit. The Partnership received offering proceeds (net of underwriting discounts and commissions) of $399.8 million from the equity offering, including proceeds from the underwriters’ exercise of their option to purchase additional common units, plus an approximate $8.4 million capital contribution from the General Partner to maintain its two percent general partner interest. The proceeds were used for general partnership purposes, including repayment of amounts outstanding under the Partnership’s revolving credit facility.

82


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

On December 18, 2012, the Partnership completed an equity offering of 18.4 million common units (such amount includes 2.4 million common units issued pursuant to the exercise of the underwriters’ over-allotment option) representing limited partner interest in the Partnership, at a price of $32.15 per common unit. The Partnership received gross offering proceeds (net of underwriting discounts, commissions and offering expenses) from the equity offering of approximately $569.3 million, including the exercise of the option to purchase additional units. The Partnership used the net proceeds to pay a portion of the purchase price for the CMO Acquisition.

Subscription Agreement. On December 20, 2012, the Partnership sold 5.9 million Class B units to each of the GIP II Entities and Williams and 5.6 million Class C units to each of the GIP II Entities and Williams, in each case pursuant to the subscription agreement. The Partnership received aggregate proceeds of approximately $712.1 million in exchange for the sale of Class B units and Class C units, inclusive of the capital contribution made by its general partner to maintain its 2.0 percent interest in the Partnership following the issuance of common, Class B and Class C units.

Limited partner and general partner units.  The following table summarizes common, subordinated, Class B, Class C and general partner units issued during the years ended December 31, 2014, 2013 and 2012:

 

 

Limited Partner Units

 

  

 

 

  

 

 

 

Common

 

  

Subordinated

 

 

Class B

 

  

Class C

 

  

General
Partner
Interests

 

  

Total

 

Balance at December 31,
2011

 

78,876,643

 

 

 

69,076,122

 

 

 

 

 

 

 

 

 

3,019,444

 

 

 

150,972,209

 

Long-term incentive plan awards

 

47,810

 

 

 

 

 

 

 

 

 

 

 

 

976

 

 

 

48,786

 

December 2012 equity issuances

 

18,400,000

 

 

 

 

 

 

11,858,050

 

 

 

11,199,268

 

 

 

846,068

 

 

 

42,303,386

 

Balance at December 31,
2012

 

97,324,453

 

 

 

69,076,122

 

 

 

11,858,050

 

 

 

11,199,268

 

 

 

3,866,488

 

 

 

193,324,381

 

Long-term incentive plan awards

 

98,242

 

 

 

 

 

 

 

 

 

 

 

 

2,006

 

 

 

100,248

 

April 2013 equity issuance

 

10,350,000

 

 

 

 

 

 

 

 

 

 

 

 

211,224

 

 

 

10,561,224

 

Conversion of subordinated units to common units

 

69,076,122

 

 

 

(69,076,122

)

 

 

 

 

 

 

 

 

 

 

 

 

ATM equity issuances

 

952,330

 

 

 

 

 

 

 

 

 

 

 

 

19,435

 

 

 

971,765

 

Paid-in-kind Class B unit distributions

 

 

 

 

 

 

 

566,308

 

 

 

 

 

 

11,557

 

 

 

577,865

 

Balance at December 31,
2013

 

177,801,147

 

 

 

 

 

 

12,424,358

 

 

 

11,199,268

 

 

 

4,110,710

 

 

 

205,535,483

 

Long-term incentive plan awards

 

885,565

 

 

 

 

 

 

 

 

 

 

 

 

18,073

 

 

 

903,638

 

Conversion of Class C units to common units

 

11,199,268

 

 

 

 

 

 

 

 

 

(11,199,268

)

 

 

 

 

 

 

ATM equity issuances

 

909,219

 

 

 

 

 

 

 

 

 

 

 

 

18,555

 

 

 

927,774

 

Paid-in kind Class B unit distributions

 

 

 

 

 

 

 

506,009

 

 

 

 

 

 

10,327

 

 

 

516,336

 

Balance at December 31,
2014

 

190,795,199

 

 

 

 

 

 

12,930,367

 

 

 

 

 

 

4,157,665

 

 

 

207,883,231

 

Pre-merger unit split rate

 

1.06152

 

 

 

 

 

 

 

1.06152

 

 

 

 

 

 

 

1.06152

 

 

 

1.06152

 

Balance at December 31,
2014

 

202,532,920

 

 

 

 

 

 

13,725,843

 

 

 

 

 

 

4,413,445

 

 

 

220,672,208

 

Accounting standards issued but not yet adopted.  On May 28, 2014, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers.  The standard will eliminate the transaction and industry specific revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach for determining revenue recognition.  The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services.  In doing so, companies will need to

83


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

use more judgment and make more estimates than under today’s guidance.  This guidance will be effective for the Partnership beginning January 1, 2017.  The Partnership is currently evaluating the impact of this new standard on its consolidated financial statements.

 

2.

Summary of Significant Accounting Policies

Principles of consolidation.  The consolidated financial statements include the accounts of all entities that the Partnership controls and the Partnership’s proportionate interest in the accounts of certain ventures in which we own an undivided interest.  Management judgment is required to evaluate whether the Partnership controls an entity.  Key areas of that evaluation include (i) determining whether an entity is a variable interest entity (“VIE”); (ii) determining whether the Partnership is the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that the Partnership and its related parties have over those activities through variable interests; (iii) identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether the Partnership is a VIE’s primary beneficiary; and (iv) evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that the Partnership does not have the power to control such entities.

The Partnership applies the equity method of accounting to investments in entities over which the Partnership exercises significant influence but does not control.  

Use of estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. Significant estimates include: (1) estimated useful lives of assets, which impacts depreciation and amortization; (2) accruals related to revenues, expenses and capital costs; (3) litigation-related contingencies; and (4) cost allocations. Although management believes these estimates are reasonable, actual results could differ from the Partnership’s estimates.

Cash and cash equivalents. For purposes of the consolidated financial statements, investments in all highly liquid instruments with original maturities of three months or less at date of purchase are considered to be cash equivalents. The Partnership had approximately $41.9 million and $17.2 million of cash and cash equivalents as of December 31, 2014 and 2013, respectively.

Accounts receivable. The majority of accounts receivable relate to gathering and treating activities. Accounts receivable are carried on a gross basis, with no discounting, less the allowance for doubtful accounts.  The Partnership estimates the allowance for doubtful accounts based on existing economic conditions, the financial condition of the Partnership’s customers, and the amount and age of past due accounts.  Receivables are considered past due if full payment is not received by the contractual due date.  Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. At December 31, 2014 and 2013, the Partnership had no allowance for doubtful accounts.

Property, plant and equipment and depreciation. Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in operating expenses in the statements of income.

Depreciation is calculated using the straight-line method, based on the assets’ estimated useful lives. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets.  Amortization of assets recorded under capital leases is included in depreciation expense.

In July 2014, the Partnership reassessed the estimated useful lives of its gathering systems and related customer relationships, as well as the gathering systems of the investees which it operates.  Following this assessment, the Partnership increased the useful lives of its gathering systems from 20 years to 30 years.  Given the limited history of the assets at the Partnership’s inception, a 20 year useful life was deemed appropriate at the time based on the Partnership’s maintenance and pipeline integrity program in addition to the expectation that commercial quantities of oil and natural gas would continue to be produced in each operating area for that time period.  As the Partnership’s experience in operating

84


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

the assets and confidence in the operating basins and its maintenance and pipeline integrity program grew, it was determined that a 30 year useful life is a more appropriate measure of the investment recovery period.  The Partnership also reassessed the estimated useful lives of its other fixed assets and increased or decreased lives where appropriate depending on the type of other fixed asset.

In accordance with FASB ASC 250, the Partnership determined that the change in depreciation method is a change in accounting estimate, and accordingly, the change will be applied on a prospective basis.  The effect of this change in estimate resulted in a decrease in depreciation expense for the year ended December 31, 2014, of approximately $58.3 million, or approximately $0.29 per common unit. The effect of this change in estimate also resulted in an increase in income from unconsolidated affiliates for the year ended December 31, 2014, of approximately $9.4 million, or approximately $0.05 per common unit, for a total increase in net income for the year ended December 31, 2014, of approximately $67.7 million, or approximately $0.34 per common unit.

Impairment of long-lived assets. Long-lived assets, including property, plant and equipment and intangible assets, with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. Assets are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount that the carrying value exceeds the fair value of the asset is recognized.  $11.7 million of impairment charges were recognized in 2014 related to certain materials and equipment held for sale.  See Note 8 – Property, Plant and Equipment for more information.

Equity method investments. The equity method of accounting is used to account for the Partnership’s interest in Utica East Ohio Midstream LLC and Ranch Westex JV, LLC, which the Partnership acquired as part of the CMO Acquisition. The equity method is also used to account for the Partnership’s various ownership interests in 11 gas gathering systems in the Marcellus Shale. See Note 1 – Description of Business and Basis of Presentation for more information on the acquisitions.

Asset retirement obligations. Management recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at fair value measured using expected discounted future cash outflows of the asset retirement obligation when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Accretion expense is recognized over time as the discounted liability is accreted to the Partnership’s expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected timing or amount of the retirement obligation (with a corresponding adjustment to property, plant and equipment) and for accretion of the liability due to the passage of time, until the obligation is settled.

Fair value. The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities.

Level 2 — inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 — inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations (see Note 9 – Acquisitions and Divestitures) and initial recognition of asset retirement obligations.

85


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. See Note 12 — Long-Term Debt and Interest Expense for disclosures regarding the fair value of debt.

 

 

December 31, 2014

 

  

December 31, 2013

 

 

Carrying
amount

 

  

Fair Value

 

  

Carrying
amount

 

  

Fair Value

 

 

 

 

  

($ in thousands)

 

  

 

 

Financial liabilities

 

 

 

  

 

(Level 2)

 

  

 

 

 

  

 

(Level 2)

 

Revolving credit facility

$

640,000

 

  

$

640,000

 

  

$

343,500

 

  

$

343,500

 

2021 Notes

 

750,000

 

  

 

772,725

 

  

 

750,000

 

  

 

801,098

 

2022 Notes

 

750,000

 

  

 

798,833

 

  

 

750,000

 

  

 

804,848

 

2023 Notes

 

1,400,000

 

  

 

1,423,870

 

  

 

1,400,000

 

  

 

1,355,382

 

2024 Notes

 

750,000

 

  

 

760,181

 

  

 

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Additional disclosure

 

 

 

 

 

(Level 3)

 

 

 

 

 

 

 

(Level 3)

 

Assets held for sale

 

1,092

 

 

 

1,092

 

 

 

 

 

 

 

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value.

As of December 31, 2014, certain materials and equipment was classified as held for sale, included in other current assets on the consolidated balance sheet.  The estimated fair value (less cost to sell) of the equipment at December 31, 2014 was $1.1 million.  The estimated fair value was determined by a market approach based on the Partnership’s analysis of information related to sales of similar pre-owned equipment in the principal market.  This analysis resulted in an impairment charge of $11.7 million, which is included in the total loss on impairments and disposals of assets of $23.7 million, recorded in other operating expense (income) in the consolidated statement of income.  This nonrecurring fair value measurement is classified within Level 3 of the fair value hierarchy.

Segments.  The Partnership’s chief operating decision maker measures performance and allocates resources based on geographic segments. The Partnership’s operations are divided into eight operating segments: Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, Utica, Mid-Continent and Corporate.

Revenue Recognition. Revenues consist of fees recognized for the gathering, treating, compression and processing of natural gas. Revenues are recognized when the service is performed and is based upon non-regulated rates and the related gathering, treating, compression and processing volumes. Certain contracts include minimum volume commitments.  Under such contracts, the customer is obligated to pay a fee equal to the applicable fee for each thousand cubic feet (“Mcf”) by which the applicable party’s minimum volume commitment exceeds the actual volumes gathered from such party’s production.  Revenue associated with minimum volume commitments is recognized in the period in which the amount is fixed and no longer subject to future reduction or offset.

Deferred Loan Costs. External costs incurred in connection with the revolving credit facility and senior notes are capitalized as deferred loan costs and amortized over the life of the related agreement. Amortization is included in interest expense in the statement of income.

Environmental Expenditures. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. There are no liabilities reflected in the accompanying financial statements at December 31, 2014 and 2013.

Equity Based Compensation. Certain employees of the Partnership’s general partner receive equity-based compensation through the Partnership’s equity-based compensation programs. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is generally four years from the date of grant.

86


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

Certain key members of management have been designated as participants in the Management Incentive Compensation Plan (“MICP”) which is made up of two components. The first component is an annual cash bonus based on “excess” cash distributions made by the Partnership above a specified target amount with respect to each fiscal quarter during which the award is outstanding. The second component is based on an increase in value of the Partnership’s common units at the end of a specified five-year period beginning on the award commencement date.  As a result of the Williams Acquisition, both components of the MICP vested on July 1, 2014, resulting in total cash payments to MICP participants of $88.8 million and compensation expense of $41.1 million during 2014.

Included in operating expense, general and administrative expense, and income from unconsolidated affiliates is MICP compensation and LTIP equity-based compensation of $113.8 million, $35.0 million and $9.0 million for the Partnership during the years ended December 31, 2014, 2013 and 2012, respectively.

The Long-Term Incentive Plan (“LTIP”) provides for an aggregate of 3.5 million common units to be awarded to employees, directors and consultants of the Partnership’s general partner and its affiliates through various award types, including unit awards, restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards. The LTIP has been designed to promote the interests of the Partnership and its unitholders by strengthening its ability to attract, retain and motivate qualified individuals to serve as employees, directors and consultants. As a result of the Williams Acquisition, all unit awards outstanding under the LTIP at June 30, 2014, vested on July 1, 2014, resulting in total compensation expense of $38.5 million.  On July 16, 2014, the Partnership issued to certain key employees, equity retention awards that have various vesting periods between one and four years.  As of December 31, 2014, measured but unrecognized unit-based compensation was $65.2 million, which does not include the effect of estimated forfeitures of $6.0 million. These amounts are expected to be recognized over a weighted-average period of 2.3 years.

The following table summarizes LTIP award activity for the year ended December 31, 2014:

 

 

Units

 

  

Value
per Unit

 

Restricted units unvested at beginning of period

 

1,182,288

 

  

$

36.11

 

Granted

 

1,621,910

 

  

58.67

 

Vested

 

(882,784

)

  

39.69

 

Forfeited

 

(614,954

)

  

41.09

 

Restricted units unvested at end of period

 

1,306,460

 

  

$

59.35

 

Intangible Assets. Intangible assets are amortized on a straight-line basis over their estimated useful lives. The estimated useful life is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful life of the customer relationship acquired with the Springridge gathering system and Appalachia Midstream is 15 years and 20 years, respectively. As of December 31, 2014, the carrying value of the Partnership’s intangible assets was $348.7 million, net of $69.7 million of accumulated amortization.  The Partnership estimates that it will record $23.6 million of intangible asset amortization for each of the next five years.  As of December 31, 2013, the carrying value of the Partnership’s intangible assets was $372.4 million, net of $46.0 million of accumulated amortization.  Amortization expense was $23.7 million, $24.0 million and $11.3 million for the years ended December 31, 2014, 2013 and 2012, respectively, for the Partnership.

Business Combinations. The Partnership makes various assumptions in developing models for determining the fair values of assets and liabilities associated with business acquisitions. These fair value models, developed with the assistance of outside consultants, apply discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions to arrive at an economic value for the business acquired. The Partnership then determines the fair value of the tangible assets based on estimates of replacement costs less obsolescence. Identifiable intangible assets acquired consist primarily of customer contracts, customer relationships, trade names, and licenses and permits. The Partnership values customer relationships using a discounted cash flow model.

Income taxes. As a master limited partnership, the Partnership is a pass-through entity and also not subject to federal income taxes and most state income taxes with the exception of Texas Franchise Tax. The tax on net income is generally borne by individual partners.  Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.  The aggregated difference in the basis

87


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

of the Partnership’s net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in the Partnership is not available to the Partnership.  

 

3.

Partnership Distributions

The Partnership’s partnership agreement, as amended, requires that, within 45 days subsequent to the end of each quarter, the Partnership distributes all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. During the years ended December 31, 2014, 2013 and 2012, the Partnership paid cash distributions to its unitholders of approximately $536.7 million, $389.1 million and $251.7 million, respectively, representing the four quarterly distributions in 2014, 2013 and 2012. See also Note 15 — Subsequent Events concerning distributions approved in January 2015 for the quarter ended December 31, 2014.

Available cash. The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of its business, including reserves to fund future capital expenditures, to comply with applicable laws, or its debt instruments and other agreements, or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement.

Conversion of Subordinated Units. Upon payment of the cash distribution for the second quarter of 2013, the subordination period with respect to the Partnership’s 69,076,122 subordinated units expired and all outstanding subordinated units converted into common units on a one-for-one basis on August 15, 2013. The conversion did not impact the amount of the cash distribution paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Conversion of Class C Units.  Under the partnership agreement, the Class C units became convertible into common units on a one-for-one basis at the election of either the Partnership or the holders of the Class C units on February 10, 2014 (the first business day following the record date for the Partnership’s 2013 fourth quarter cash distribution). After February 10, 2014, the Partnership received notice from certain of the GIP II Entities and Williams, as holders of the Class C units, of their election to convert all of the Class C units. All of the outstanding Class C units were converted into common units on a one-for-one basis effective February 19, 2014. The common units resulting from this conversion participate pro rata with the other common units in quarterly distributions. The conversion did not impact the amount of cash distributions paid or the total number of the Partnership’s outstanding units representing limited partner interests.

Class B Units. The Class B units are not entitled to cash distributions. Instead, prior to conversion into common units, the Class B units receive quarterly distributions of additional paid-in-kind Class B units. The amount of each quarterly distribution per Class B unit is the quotient of the quarterly distribution paid to the Partnership’s common units divided by the volume-weighted average price of the common units for the 30-day period prior to the declaration of the quarterly distribution to common units. Effective on the business day after the record date for the distribution on common units for the fiscal quarter ending December 31, 2014, each Class B unit will become convertible at the election of either the Partnership or the holders of such Class B unit into a common unit on a one-for-one basis. In the event of the Partnership’s liquidation, the holders of Class B units will be entitled to receive out of the Partnership’s assets available for distribution to the partners the positive balance in each such holder’s capital account in respect of such Class B units, determined after allocating the Partnership’s net income or net loss among the partners. All Class B units are held indirectly by affiliates of the Partnership’s general partner. The Class B units were issued at a discount to the market price of the common units into which they are convertible. This discount totaled $58.3 million and represents a beneficial conversion feature which was reflected as an increase in common unitholders’ capital and a decrease in Class B unitholders’ capital to reflect the fair value of the Class B units at issuance on the Partnership’s consolidated statement of changes in partners’ capital for the year ended December 31, 2012. The beneficial conversion feature is considered a non-cash distribution recognized ratably from the issuance date of December 20, 2012, through the conversion date, resulting in an increase in Class B unitholders’ capital and a decrease in common unitholders’ capital.

General Partner Interest and Incentive Distribution Rights. The Partnership’s general partner is entitled to two percent of all quarterly distributions that the Partnership makes prior to its liquidation. When capital contributions are made to the Partnership, the general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s initial two percent interest in the

88


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

Partnership’s distributions may be reduced if the Partnership issues additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding Class B units or the issuance of common units upon a reset of the incentive distribution rights) and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its two percent general partner interest. After distributing amounts equal to the minimum quarterly distribution to common unitholders (and Class B unitholders, upon conversion of Class B units to common units) and distributing amounts to eliminate any arrearages to common unitholders, the Partnership’s general partner is entitled to incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds specified target levels shown below:

 

 

  

Total quarterly distribution per unit

  

Unitholders

 

 

General partner

 

Minimum Quarterly Distribution

  

$0.3375

  

 

98.0

%

 

 

2.0

%

First Target Distribution

  

up to $0.388125

  

 

98.0

%

 

 

2.0

%

Second Target Distribution

  

above $0.388125 up to $0.421875

  

 

85.0

%

 

 

15.0

%

Third Target Distribution

  

above $0.421875 up to $0.50625

  

 

75.0

%

 

 

25.0

%

Thereafter

  

above $0.50625

  

 

50.0

%

 

 

50.0

%

The table above assumes that the Partnership’s general partner maintains its two percent general partner interest, that there are no arrearages on common units and the general partner continues to own the incentive distribution rights. The maximum distribution sharing percentage of 50.0 percent includes distributions paid to the general partner on its two percent general partner interest and does not include any distributions that the general partner may receive on limited partner units that it owns or may acquire.

 

4.

Net Income per Limited Partner Unit

The Partnership’s net income is allocated to the General Partner and the limited partners, including any subordinated, Class B and Class C unitholders, in accordance with the distributions made based on their respective ownership percentages. The allocation of undistributed earnings, or net income in excess of distributions, to the IDRs is limited to available cash (as defined by the partnership agreement) for the period. The Partnership’s net income allocable to the limited partners is allocated between the common, subordinated, Class B and Class C unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed. Accordingly, for any quarterly period, if current net income allocable to the limited partners is less than the minimum quarterly distribution, or if cumulative net income allocable to the limited partners since August 3, 2010 is less than the cumulative minimum quarterly distributions, more income is allocated to the common unitholders than the subordinated, Class B and Class C unitholders for that quarterly period. Following the consummation of the Merger, the Merged Partnership paid a cash distribution of $0.85 per unit on February 13, 2015, on the outstanding common units to unitholders of record at the close of business on February 9, 2015.  For the purpose of determining general partner interest in net income and the net income per limited partner common unit, the IDRs for the fourth quarter of 2014 and the weighted average limited partner units outstanding for common units reflect Pre-merger ACMP only.  

Basic and diluted net income per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. Any common units issued during the period are included on a weighted-average basis for the days in which they were outstanding.

89


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):

 

 

Years Ended

 

 

December 31,
2014

 

  

December 31,
2013

 

 

December 31,
2012

 

Net income attributable to Williams Partners L.P. (formerly Access Midstream Partners, L.P.)

$

398,060

 

 

$

336,025

 

 

$

178,455

 

Less general partner interest in net income

 

(147,507

)

 

 

(40,681

)

 

 

(8,481

)

Limited partner interest in net income

$

250,553

 

 

$

295,344

 

 

$

169,974

 

Net income allocable to common units(1)

 

203,543

 

 

 

147,706

 

 

 

89,019

 

Net income allocable to subordinated units

 

 

 

 

52,564

 

 

 

78,736

 

Net income allocable to Class B units(1)

 

42,540

 

 

 

45,987

 

 

 

1,038

 

Net income allocable to Class C units(1)

 

4,470

 

 

 

49,087

 

 

 

1,181

 

Limited partner interest in net income

$

250,553

 

 

$

295,344

 

 

$

169,974

 

Net income per limited partner unit – basic and diluted(2)

 

 

 

 

 

 

 

 

 

 

 

Common units

$

1.01

 

 

$

0.95

 

 

$

1.05

 

Subordinated units

$

 

 

$

0.88

 

 

$

1.07

 

Weighted average limited partner units outstanding – basic and diluted(2)

 

 

 

 

 

 

 

 

 

 

 

Common units

 

201,273,800

 

 

 

140,872,913

 

 

 

84,983,892

 

Subordinated units

 

 

 

 

45,401,657

 

 

 

73,325,685

 

Total

 

201,273,800

 

 

 

186,274,570

 

 

 

158,309,577

 

(1)

Adjusted to reflect amortization for the beneficial conversion feature

(2)

The net income per limited partner unit – basic and diluted for common units and subordinated units and the weighted average limited partner units outstanding – basic and diluted for common units and subordinated units for the years ended December 31, 2014, 2013 and 2012 were adjusted to reflect the Pre-merger Unit Split.

 

5.Variable Interest Entities

As of December 31, 2014, the Partnership consolidates the following VIEs:

 

Cardinal Venture.  The Partnership owns a 66 percent interest in Cardinal Gas Services, L.L.C (“Cardinal Venture”), a subsidiary that, due to certain risks shared with customers, is a VIE. The Partnership is the primary beneficiary because it has the power to direct the activities that most significantly impact Cardinal Venture’s economic performance. The Partnership, as operator for Cardinal Venture, designed, constructed, and installed associated pipelines which will initially provide production handling and gathering services for the Utica region. The Partnership has received certain advance payments from the equity partners during the construction process.

 

Jackalope Venture.  The Partnership owns a 50 percent interest in Jackalope Gas Gathering Services, L.L.C (“Jackalope Venture”), a subsidiary that, due to certain risks shared with customers, is a VIE. The Partnership is the primary beneficiary because it has the power to direct the activities that most significantly impact Jackalope Venture’s economic performance. The Partnership, as operator for Jackalope Venture, designed, constructed, and installed associated pipelines which will initially provide production handling and gathering services for the Niobrara region. The Partnership has received certain advance payments from the equity partners during the construction process.

 

90


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table presents amounts included in the accompanying consolidated balance sheet that are for the use or obligation of these VIEs ($ in thousands):

 

Assets (liabilities):

 

December 31, 2014

 

 

 

December 31, 2013

 

 

 

Classification

 

Cash

$

41,868

 

 

$

16,830

 

 

 

Cash and cash equivalents

 

Trade accounts receivable

 

42,638

 

 

 

20,402

 

 

 

Accounts receivable

 

Prepaid expenses

 

101

 

 

 

32

 

 

 

Prepaid expenses

 

Other current assets

 

610

 

 

 

509

 

 

 

Prepaid expenses

 

Gathering system

 

1,160,480

 

 

 

665,510

 

 

 

Gathering systems

 

Other fixed assets

 

762

 

 

 

14

 

 

 

Other fixed assets

 

Trade accounts payable

 

(4,177

)

 

 

(3,987

)

 

 

Accounts payable

 

Accrued liabilities

 

(52,282

)

 

 

(65,853

)

 

 

Accrued gathering liabilities

 

Asset retirement obligation

 

(1,036

)

 

 

(187

)

 

 

Other liabilities, long-term

 

 

 

 

6.

Related Party Transactions

In June 2012, Chesapeake sold all of its ownership interests in the Partnership and its general partner; however, Mr. Dell’Osso, Executive Vice President and Chief Financial Officer of Chesapeake, remained on the Partnership’s board of directors until July 1, 2014. See Note 9 – Acquisitions and Divestitures for further transactions with Chesapeake. Because Chesapeake was the Partnership’s affiliate for a portion of 2012, set forth below is a description of the Partnership’s transactions with Chesapeake prior to 2013.

On July 1, 2014, Williams acquired all of the interests in the Partnership and the General Partner, and as a result, Williams now owns all of the General Partner.  Therefore, the Partnership considers Williams an affiliate as of that date.  The Partnership had a payable to Williams for $18.0 million at December 31, 2014.      

Affiliate transactions. In the normal course of business, natural gas gathering, treating and other midstream services were provided to Chesapeake and its affiliates. Revenues were derived primarily from Chesapeake, which included volumes attributable to third-party interest owners that participated in Chesapeake’s operated wells.

Omnibus Agreement. The Partnership entered into an omnibus agreement with Access Midstream Ventures and Chesapeake Midstream Holdings that addressed the Partnership’s right to indemnification for certain liabilities and its obligation to indemnify Access Midstream Ventures and affiliated parties for certain liabilities.

General and Administrative Services and Reimbursement. Pursuant to a services agreement, Chesapeake and its affiliates provided certain services including legal, accounting, treasury, human resources, information technology and administration. The employees supporting these operations were employees of Chesapeake Energy Marketing Inc. (“CEMI”) or Chesapeake. The consolidated financial statements for the Partnership included costs allocated from Chesapeake and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Chesapeake’s centralized general and administrative functions. Effective October 1, 2009, the Partnership was charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicated corporate overhead costs were charged to the Partnership based on actual cost of the services provided, subject to a fee per Mcf cap based on volumes of natural gas gathered. The fee was calculated as the lesser of $0.0310/Mcf gathered or actual corporate overhead costs. General and administrative charges were $22.3 million for the year ended December 31, 2012 for the Partnership.

Additional Services and Reimbursement. At the Partnership’s request, Chesapeake also provided the Partnership with certain additional services under the services agreement, including engineering, construction, procurement, business analysis, commercial, cartographic and other similar services to the extent they were not already provided by the seconded employees. In return for such additional services, the general partner reimbursed Chesapeake on a monthly basis an amount equal to the time and materials actually spent in performing the additional services. The reimbursement for additional services was not subject to the general and administrative services reimbursement cap.

Chesapeake agreed to perform all services under the relevant provisions of the services agreement, as amended effective through 2013 using at least the same level of care, quality, timeliness and skill as it did for itself and its affiliates and with no less than the same degree of care, quality, timeliness and skill as its past practice in performing the services

91


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

for itself and the Partnership’s business. In any event, Chesapeake agreed to perform such services using no less than a reasonable level of care in accordance with industry standards.

In connection with the services arrangement, the Partnership reimbursed GIP for certain costs incurred by GIP in connection with assisting the Partnership in the operation of its business. The cost for these support services was $1.0 million, $0.4 million and $1.7 million for the years ended December 31, 2014, 2013 and 2012, respectively.

Employee Secondment Agreement. Chesapeake, certain of its affiliates and the Partnership’s general partner entered into an amended and restated employee secondment agreement pursuant to which specified employees of Chesapeake were seconded to the general partner and provided operating, routine maintenance and other services with respect to the Partnership’s business under the direction, supervision and control of the general partner. Additionally, all of the Partnership’s executive officers other than its chief executive officer, Mr. Stice, were seconded to the general partner pursuant to this agreement. The general partner, subject to specified exceptions and limitations, reimbursed Chesapeake on a monthly basis for substantially all costs and expenses Chesapeake incurred relating to such seconded employees, including the cost of their salaries, bonuses and employee benefits, including 401(k), restricted stock grants and health insurance and certain severance benefits. Charges to the Partnership for the services rendered by such seconded employees were $49.4 million for the year ended December 31, 2012. These charges included $37.7 million in operating expenses and $11.7 million in general and administrative expenses for the year end December 31, 2012 in the accompanying consolidated statements of operations.

Shared Services Agreement. In return for the services of Mr. Stice as the chief executive officer of the Partnership’s general partner during the year ended December 2012, its general partner entered into a shared services agreement with Chesapeake pursuant to which its general partner reimbursed certain of the costs and expenses incurred by Chesapeake in connection with Mr. Stice’s employment. The general partner was generally expected, subject to certain exceptions, to reimburse Chesapeake for 50 percent of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation was determined based on the amount of time Mr. Stice actually spent working for the Partnership.

Gas Compressor Master Rental and Servicing Agreement. The Partnership entered into a gas compressor master rental and servicing agreement with MidCon, pursuant to which MidCon agreed to provide the Partnership certain compression equipment that the Partnership uses to compress gas gathered on its gathering systems outside the Marcellus Shale and provide certain related services. In return for providing such equipment, the Partnership paid specified monthly rates per specified compression units, subject to an annual escalator to be applied on October 1st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. As noted in Note 1 – Description of Business and Basis of Presentation, on March 31, 2014, the Partnership acquired certain midstream compression assets from MidCon and no longer leases any compression equipment or services from MidCon.  Compressor charges from affiliates were $65.3 million for the year ended December 31, 2012. These charges are included in operating expenses in the accompanying consolidated statements of operations.

 

7.

Concentration of Credit Risk

Chesapeake is the only customer from whom revenues exceeded 10 percent of consolidated revenues for the years ended December 31, 2014 and 2013 for the Partnership. Chesapeake and Total are the only customers from whom revenues exceeded 10 percent of consolidated revenues for the year ended December 31, 2012 for the Partnership. The percentage of revenues from Chesapeake, Total and other customers are as follows:

 

 

Years Ended December 31,

 

 

2014

 

 

2013

 

 

2012

 

Chesapeake

 

82.4

 

 

84.4

 

 

80.7

Total

 

9.9

  

 

 

9.6

  

 

 

14.1

  

Other

 

7.7

  

 

 

6.0

  

 

 

5.2

  

Total(a)

 

100

 

 

100

 

 

100

(a)

Revenues from Appalachia Midstream are accounted for as part of the Partnership’s equity method investment.

92


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

Revenue from Chesapeake accounted for $1.1 billion of the Partnership’s revenue for the year ended December 31, 2014.  Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2014 and 2013, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings. On December 31, 2014 and 2013, respectively, Chesapeake accounted for $308.1 million and $176.5 million of the Partnership’s accounts receivable balance.

 

8.

Property, Plant and Equipment

A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:

 

 

Estimated
Useful Lives
(Years)

 

  

December 31,
2014

 

  

December 31,
2013

 

 

($ in thousands)

 

Gathering systems

 

30

 

 

$

6,700,092

 

 

$

5,974,940

 

Other fixed assets

 

2 through 39

 

 

 

469,482

 

 

 

175,411

 

Total property, plant and equipment

 

 

 

 

 

7,169,574

 

 

 

6,150,351

 

Accumulated depreciation

 

 

 

 

 

(1,117,105

)

 

 

(859,551

)

Total net, property, plant and equipment

 

 

 

 

$

6,052,469

 

 

$

5,290,800

 

Included in gathering systems and other fixed assets is $650.0 million and $620.5 million at December 31, 2014 and 2013, respectively, that is not subject to depreciation as the systems were under construction and had not been put into service.

As of December 31, 2014, certain materials and equipment within the Partnership’s Corporate segment was reclassified from property, plant and equipment to a held for sale account, included in other current assets on the consolidated balance sheet.  The estimated fair value (less cost to sell) of the equipment at December 31, 2014 was $1.1 million.  The estimated fair value was determined by a market approach based on the Partnership’s analysis of information related to sales of similar pre-owned equipment in the principal market.  This analysis resulted in an impairment charge of $11.7 million, which is included in the total loss on disposal of assets of $23.7 million, recorded in other operating expense (income) in the consolidated statement of income.

Depreciation expense, including capital lease amortization, was $288.5 million, $271.7 million and $153.8 million for the years ended December 31, 2014, 2013 and 2012, respectively, for the Partnership.

 

9.

Acquisitions and Divestitures

Acquisitions

CMO. On December 20, 2012, the Partnership acquired from CMD all of the issued and outstanding equity interests in CMO for total consideration of $2.16 billion. Through the acquisition of CMO, the Partnership owns certain midstream assets in the Eagle Ford, Utica, Niobrara, Haynesville, Marcellus and Mid-Continent regions. These assets include, in aggregate, approximately 1,675 miles of pipeline and 4.3 million gross dedicated acres as of the date of the acquisition. See Note 1 to the consolidated financial statements for additional information.

The results of operations presented and discussed in this annual report include results of operations from the CMO acquisition for the twelve-day period from closing of the acquisition on December 20, 2012 through December 31, 2012. The purchase price in excess of the value underlying the gas gathering system assets and working capital is approximately $263.3 million and is attributable to customer relationships acquired. This intangible asset is being amortized over a 20 year period on a straight-line basis.

93


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The table below reflects the final allocation of the purchase price to the assets acquired and the liabilities assumed in the CMO Acquisition (in thousands).

 

Property, plant and equipment

$

1,890,036

 

Intangible asset

 

263,262

 

Other

 

6,702

 

Total purchase price

$

2,160,000

 

The initial purchase price allocation was based on an assessment of the fair value of the assets acquired and liabilities assumed in the CMO Acquisition. The fair values of the gathering assets, related equipment, and intangible assets acquired were based on the market, cost and income approaches. All fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs.  

Marcellus. On December 29, 2011, the Partnership acquired from CMD all of the issued and outstanding common units of Appalachia Midstream for total consideration of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on the Partnership’s revolving credit facility. The base purchase price of $879.3 million was increased by $7.3 million due to initial working capital adjustments through December 31, 2011. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an approximate average 45 percent interest in 11 gas gathering systems that consist of approximately 906 miles of gas gathering pipeline in the Marcellus Shale.

The results of operations presented and discussed in this annual report include results of operations from the Appalachia Midstream for the full year of operations in 2012 and the three-day period from closing of the acquisition on December 29, 2011, through December 31, 2011. The Partnership’s interest in the gas gathering systems is accounted for as an equity investment and is included in income from unconsolidated affiliate. For the three-day period ended December 31, 2011, income from unconsolidated affiliate attributable to Marcellus operations was $0.4 million. The purchase price in excess of the value underlying the gas gathering system assets and working capital is approximately $461.2 million and is attributable to customer relationships acquired. This intangible asset is being amortized over a 15 year period on a straight-line basis.

The following table presents the pro forma condensed financial information of the Partnership as if the CMO Acquisition and our acquisition of Appalachia Midstream each occurred on January 1, 2011. The pro forma adjustments reflected in the pro forma condensed consolidated financial statements are based upon currently available information and certain assumptions and estimates; therefore, the actual effects of these transactions will differ from the pro forma adjustments. However, the Partnership’s management considers the applied estimates and assumptions to provide a reasonable basis for the presentation of the significant effects of certain transactions that are expected to have a continuing impact on the Partnership. In addition, the Partnership’s management considers the pro forma adjustments to be factually supportable and to appropriately represent the expected impact of items that are directly attributable to the transfer of CMO and Appalachia Midstream to the Partnership.

 

 

 

  

Year Ended
December 31,

 

 

 

  

2012

 

 

 

 

(in thousands)

Revenues, including revenue from affiliates

 

 

$

670,702

 

Net income

 

 

$

117,334

 

Net income attributable to Access Midstream Partners, L.P.

 

 

$

117,861

 

Net income per common unit – basic and diluted

 

 

$

0.72

 

Net income per subordinated unit – basic and diluted

 

 

$

0.74

 

Divestitures

On September 4, 2013, the Partnership sold Mid-Atlantic Gas Services, L.L.C. (“Mid-Atlantic”) to Chesapeake for net proceeds of $32.9 million.  Mid-Atlantic was acquired by the Partnership in December 2012 as part of the CMO Acquisition and consisted of midstream assets in the Marcellus Shale region.  These assets were not part of the Partnership’s equity investment in Appalachia Midstream.  The net proceeds equaled the Partnership’s basis in the assets. Consequently, the Partnership did not recognize any gain or loss as a result of the sale.

94


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

 

10.

Unconsolidated Affiliates

At December 31, 2014 and 2013, the Partnership had the following investments:

 

 

Net
Ownership
Interest

 

 

December 31,
2014

 

  

December 31,
2013

 

 

($ in thousands)

 

Utica East Ohio Midstream LLC

 

49.00

%

 

$

707,080

 

 

$

471,891

 

Liberty gas gathering system

 

33.75

%

 

 

353,243

 

 

 

354,316

 

Panhandle gas gathering system

 

67.50

 

 

 

258,349

 

 

 

237,656

 

Rome gas gathering system

 

33.75

 

 

 

197,703

 

 

 

181,147

 

Victory gas gathering system

 

67.50

 

 

 

195,243

 

 

 

190,353

 

Overfield gas gathering system

 

67.50

 

 

 

119,909

 

 

 

125,959

 

Smithfield gas gathering system

 

67.50

 

 

 

119,308

 

 

 

107,009

 

Selbyville gas gathering system

 

67.50

 

 

 

74,418

 

 

 

73,463

 

Ranch Westex JV, LLC

 

33.33

 

 

 

38,060

 

 

 

36,060

 

Pecan Hill Water Solutions, LLC

 

49.00

 

 

 

3,469

 

 

 

-

 

Other gas gathering systems

 

various

 

 

 

163,204

 

 

 

158,749

 

Total investments in unconsolidated affiliates

 

 

 

 

$

2,229,986

 

 

$

1,936,603

 

Marcellus. The Partnership operates all and owns an average 45 percent interest in 11 gas gathering systems that consist of approximately 906 miles of gas gathering pipeline in the Marcellus Shale in Pennsylvania and West Virginia. These 11 gathering systems consist of the Liberty, Panhandle, Rome, Victory, Overfield, Smithfield and Selbyville gas gathering systems and four other smaller gas gathering systems. The remaining 55 percent interest in these assets is owned primarily by Statoil, Anadarko, Epsilon and Mitsui. The Partnership operates the assets under 15-year fixed fee gathering agreements. The 11 gathering systems are separate investments with varying ownership percentages and each gathering system is accounted for as an equity investment because the Partnership has significant influence over but does not control each venture.

Utica East Ohio Midstream, LLC. The Partnership acquired Utica East Ohio Midstream LLC (“UEOM”) as part of the CMO Acquisition in December 2012. In March 2012, CMO entered into an agreement to form UEOM with M3 Midstream, L.L.C. and EV Energy Partners, L.P. to develop necessary infrastructure for the gathering, processing and fractionation of natural gas and NGLs in the Utica Shale play in Eastern Ohio. The infrastructure complex consists of natural gas gathering and compression facilities constructed and operated by the Partnership, as well as processing, NGL fractionation, loading and terminal facilities constructed and operated by M3 Midstream, L.L.C. The Partnership owns a 49 percent interest and UEOM is accounted for as an equity investment because the Partnership has significant influence over but does not control the entity.

Ranch Westex JV, LLC. The Partnership acquired Ranch Westex JV, LLC (“Ranch Westex”) as part of the CMO Acquisition in December 2012. On December 1, 2011, CMO entered into a joint venture to form Ranch Westex with Regency Energy Partners, LP and Anadarko Pecos Midstream LLC to build a processing facility in Ward County, Texas, to process natural gas delivered from the liquids-rich Bone Springs and Avalon Shale formations. The Partnership owns a 33.33 percent interest and Ranch Westex is accounted for as an equity method investment because the Partnership has significant influence over but does not control the entity.  The project consists of two plants, a refrigeration plant and a cryogenic processing plant.

Pecan Hill Water Solutions, LLC.  On May 1, 2014, the Partnership entered into a joint venture to form Pecan Hill Water Solutions, LLC (“Pecan Hill”) with Select Energy Services, LLC to operate a water treatment facility in Grady County, Oklahoma, to process water used in fractionation and gathering processes of natural gas within the Granite Wash formation.  The Partnership owns 49 percent interest and Pecan Hill is accounted for as an equity method investment because the Partnership has significant influence over but does not control the entity.  The project consists of a freshwater system and a saltwater disposal facility.

95


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

Unconsolidated Affiliates Financial Information.

The following tables sets forth summarized financial information of the investments in which the Partnership owned an interest in December 2014 and 2013, as follows:

 

 

December 31,
2014

 

  

December 31,
2013

 

 

($ in thousands)

 

Balance Sheet

 

 

 

Current assets

$

232,610

 

 

$

196,567

 

Property, plant, and equipment

 

3,837,260

 

 

 

3,249,371

 

Other assets

 

6,174

 

 

 

6,166

 

Total assets

$

4,076,044

 

 

$

3,452,104

 

Current liabilities

$

52,826

 

 

$

96,275

 

Other liabilities

 

30,796

 

 

 

87,886

 

Partner’s capital

 

3,992,422

 

 

 

3,267,943

 

Total liabilities and partner’s capital

$

4,076,044

 

 

$

3,452,104

 

 

 

Years Ended

 

 

December 31,
2014

 

  

December 31,
2013

 

  

December 31,
2012

 

 

($ in thousands)

 

Income Statement

 

 

 

Revenue

$

771,003

 

 

$

520,388

 

 

$

308,845

 

Operating expenses

$

236,257

 

 

$

230,974

 

 

$

97,594

 

Net income

$

534,770

 

 

$

289,441

 

 

$

211,361

 

 

 

11.

Asset Retirement Obligations

The following table provides a summary of changes in asset retirement obligations, which are included in other liabilities in the accompanying consolidated balance sheets. Revisions in estimates for the periods presented relate primarily to revisions of current cost estimates, inflation rates and/or discount rates.

 

 

Years Ended December 31,

 

 

2014

 

  

2013

 

 

2012

 

 

(in thousands)

 

Asset retirement obligations, beginning of period

$

4,521

 

 

$

5,335

 

 

$

3,409

 

Additions

 

1,789

 

 

 

 

 

 

1,816

 

Revisions

 

6,705

 

 

 

(1,314

)

 

 

(133

)

Accretion expense

 

2,058

 

 

 

500

 

 

 

243

 

Deletions

 

 

 

 

 

 

 

 

Asset retirement obligations, end of period

$

15,073

 

 

$

4,521

 

 

$

5,335

 

 

 

96


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

 

12.

Long-Term Debt and Interest Expense

The following table presents the Partnership’s outstanding debt as of December 31, 2014 and 2013 (in thousands):

 

 

December 31,
2014

 

  

December 31,
2013

 

Revolving credit facility

$

640,000

 

 

$

343,500

 

5.875 percent senior notes due April 2021

 

750,000

 

 

 

750,000

 

6.125 percent senior notes due July 2022

 

750,000

 

 

 

750,000

 

4.875 percent senior notes due May 2023

 

1,400,000

 

 

 

1,400,000

 

4.875 percent senior notes due March 2024

 

750,000

 

 

 

 

Premium on 5.875 percent senior notes due April  2021

 

5,055

 

 

 

5,730

 

Total long-term debt

$

4,295,055

 

 

$

3,249,230

 

Revolving Credit Facility.  As of December 31, 2014 and 2013, we had approximately $640.0 million and $343.5 million, respectively, of borrowings outstanding under our revolving credit facility.  The revolving credit facility bears interest at the Partnership’s option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (“LIBOR”) (LIBOR ranged from 2.16 percent to 2.42 percent during 2014), plus 1.00 percent, each of which is subject to a margin that varies from 0.50 percent to 1.50 percent per annum, according to the Partnership’s leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.50 percent to 2.50 percent per annum, according to the Partnership’s leverage ratio. On February 2, 2015, the revolving credit facility loans outstanding were paid and the revolving credit facility was terminated in connection with the Merger.

Credit Facilities Post-Merger. On February 2, 2015, the Merged Partnership along with Transcontinental Gas Pipeline Company, LLC (“Transco”) and Northwest Pipeline LLC (“Northwest Pipeline”), the lenders named therein and an administrative agent, entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The maturity date of the facility is February 2, 2020.  However, the co-borrowers my request an extension of the maturity date for an additional one year period, up to two times, to allow a maturity date as late as February 2, 2022 under certain conditions. The agreement allows for swing line loans up to an aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments of $1.125 billion. As of February 2, 2015, the total amount of outstanding letters of credit under the credit facility was $2.31 million.  Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.  As measured at December 31, 2014, the Partnership was in compliance with the financial covenants applicable to the revolving credit facility then in effect.

The agreements governing the Merged Partnership’s credit facilities contain the following terms and conditions:

Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business.

If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies.

Each time funds are borrowed under the credit facility, the borrower may choose from two methods of calculating interest: a fluctuating base rate equal to an alternate base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings.

97


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

Significant financial covenants require:

The ratio of debt to EBITDA (each as defined in the credit facility) to be no greater than 5 to 1, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed, in which case the ratio of debt to EBITDA is to be no greater than 5.5 to 1.

The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline.

 

On February 3, 2015, the Merged Partnership entered into a Credit Agreement providing for a $1.5 billion short-term credit facility with a maturity date of August 3, 2015 with an option to extend the maturity date to February 2, 2016 subject to certain circumstances.  The short-term credit facility has substantially the same financial covenants as the $3.5 billion credit facility.  Under the short-term credit facility any time funds are borrowed, the Merged Partnership must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing.  Interest is calculated on each of these types of borrowings in the same manner as under our $3.5 billion credit facility. The Merged Partnership is required to pay a commitment fee based on the unused portion of the short-term credit facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on the senior unsecured long-term debt ratings.  In the event of certain debt incurrences, issuances of equity, and certain asset sales, the Merged Partnership will be required to repay any outstanding borrowings and the commitments under the short-term facility will be reduced on a dollar-for-dollar basis with the net cash proceeds of such events.

On February 2, 2015, the commercial paper program of Pre-merger WPZ was amended and restated for the merger and to allow a maximum outstanding amount of $3 billion.  The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance.  The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis

Senior Notes. On March 7, 2014, the Partnership and ACMP Finance Corp., a wholly owned subsidiary of Access MLP Operating, L.L.C., completed a public offering of $750 million in aggregate principal amount of 4.875 percent senior notes due 2024 (the “2024 Notes”). The Partnership used a portion of the net proceeds to repay borrowings outstanding under the Partnership’s revolving credit facility, including amounts incurred to fund the purchase price of and certain expenses relating to the Partnership’s purchase of compression assets from MidCon and the balance for general partnership purposes. Debt issuance costs of $8.9 million are being amortized over the life of the 2024 Notes.

On August 14, 2013, the Partnership issued $400 million in aggregate principal amount of additional 5.875 percent senior notes due 2021 (the “Additional Notes”). The Additional Notes are additional to the $350 million of 2021 Notes initially issued on April 19, 2011 and are fully fungible with, rank equally with and form a single series with the 2021 Notes.  The Additional Notes were issued at a price of 101.5 percent of the principal amount plus accrued interest from April 15, 2013, resulting in net proceeds of $400.8 million, which was used for general partnership purposes, including funding working capital, repayment of indebtedness and funding the Partnership’s capital expenditure program.  Debt issuance costs of $5.8 million are being amortized over the life of the Additional Notes.

On December 19, 2012, the Partnership and ACMP Finance Corp. completed a public offering of $1.4 billion in aggregate principal amount of 4.875 percent senior notes due 2023 (the “2023 Notes”). The Partnership used a portion of the net proceeds to fund a portion of the purchase price for the CMO Acquisition, and the balance to repay borrowings outstanding under the Partnership’s revolving credit facility. Debt issuance costs of $25.9 million are being amortized over the life of the 2023 Notes.

On January 11, 2012, the Partnership and ACMP Finance Corp. completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). The Partnership used a portion of the net proceeds to repay all borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $13.8 million are being amortized over the life of the 2022 Notes.

On April 19, 2011, the Partnership and ACMP Finance Corp. completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 ( the “2021 Notes”). The Partnership used a portion of the net proceeds to repay borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $8.2 million are being amortized over the life of the 2021 Notes.

98


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The 2024 Notes will mature on March 15, 2024, and interest is payable on March 15 and September 15 of each year. The Partnership has the option to redeem all or a portion of the 2024 Notes at any time on or after March 15, 2019, at the redemption price specified in the indenture relating to the 2024 Notes, plus accrued and unpaid interest. The Partnership may also redeem the 2024 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to March 15, 2019. In addition, the Partnership may redeem up to 35 percent of the 2024 Notes prior to March 15, 2017 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2023 Notes will mature on May 15, 2023, and interest is payable on May 15 and November 15 of each year. The Partnership has the option to redeem all or a portion of the 2023 Notes at any time on or after December 15, 2017, at the redemption price specified in the indenture relating to the 2023 Notes, plus accrued and unpaid interest. The Partnership may also redeem the 2023 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to December 15, 2017. In addition, the Partnership may redeem up to 35 percent of the 2023 Notes prior to December 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. The Partnership has the option to redeem all or a portion of the 2022 Notes at any time on or after January 15, 2017, at the redemption price specified in the indenture relating to the 2022 Notes, plus accrued and unpaid interest. The Partnership may also redeem the 2022 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to January 15, 2017. In addition, the Partnership may redeem up to 35 percent of the 2022 Notes prior to January 15, 2015 under certain circumstances with the net cash proceeds from certain equity offerings.

The 2021 Notes and Additional Notes will mature on April 15, 2021 and interest is payable on the 2021 Notes and Additional Notes on April 15 and October 15 of each year, beginning on October 15, 2011. The Partnership has the option to redeem all or a portion of the 2021 Notes and Additional Notes at any time on or after April 15, 2015, at the redemption price specified in the indenture, plus accrued and unpaid interest. The Partnership may also redeem the 2021 Notes and Additional Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, the Partnership may redeem up to 35 percent of the 2021 Notes and Additional Notes prior to April 15, 2014 under certain circumstances with the net cash proceeds from certain equity offerings.

The indentures governing the 2024 Notes, the 2023 Notes, the 2022 Notes and the 2021 Notes contain covenants that, among other things, limit the Partnership’s ability and the ability of certain of the Partnership’s subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase the Partnership’s units, or redeem or purchase the Partnership’s subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to the Partnership; (7) consolidate, merge or transfer all or substantially all of the Partnership’s or certain of the Partnership’s subsidiaries’ assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2024 Notes, 2023 Notes, 2022 Notes or the 2021 Notes achieve an investment grade rating from either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default, as defined in the indentures, has occurred or is continuing, many of these covenants will terminate.  Following the Merger, the senior notes noted above achieved an investment grade rating and therefore many of the covenants terminated.  There were no other significant changes to these senior notes as a result of the Merger.

The Partnership, as the parent company, has no independent assets or operations. ACMP Finance Corp., an indirect 100 percent owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of any debt securities, has jointly and severally co-issued the Partnership’s senior notes. There are no significant restrictions on the ability of the Partnership to obtain funds from its subsidiaries by dividend or loan. None of the assets of the Partnership represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Capitalized Interest. Interest expense was net of capitalized interest of $25.6 million, $43.9 million, and $14.6 million for the years ended December 31, 2014, 2013 and 2012, respectively, for the Partnership.

 

99


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

13.

Commitments and Contingencies

Environmental obligations. The Partnership is subject to various environmental-remediation and reclamation obligations arising from federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are currently no such matters that will have a material effect on the Partnership’s results of operations, cash flows or financial position and has not recorded any liability in these financial statements.

Litigation and legal proceedings. From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceedings for which a final disposition could have a material effect on the Partnership’s results of operations, cash flows or financial position.

Certain of the Partnership’s customers, including one of its major customers, have been named in various lawsuits alleging underpayment of royalty.  In certain of these cases, the Partnership has also been named as a defendant based on allegations that it improperly participated with that major customer in causing the alleged royalty underpayments.  The Partnership has also received subpoenas from the United States Department of Justice and the Pennsylvania Attorney General requesting documents relating to the agreements between the Partnership and its major customer and calculations of the major customer’s royalty payments.  Management believes that the claims asserted to date are subject to indemnity obligations owed to the Partnership by that major customer.  Due to the preliminary status of the cases, we are unable to estimate a range of liability at this time.

Operating lease commitments. Certain property, equipment and operating facilities are leased under various operating leases. Costs are also incurred associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations.

Rental expense related to leases was $98.3 million, $104.5 million, $81.1 million for the years ended December 31, 2014, 2013 and 2012, respectively, for the Partnership and is reflected in operating expenses in the accompanying statements of income. The Partnership’s remaining contractual lease obligations as of December 31, 2014 include obligations for compression equipment as compression services are needed to support pipeline that is being placed in service in future periods. Contractual lease obligations also include remaining payments for the Partnership’s headquarter buildings and other lease agreements.

Future minimum rental payments due under operating leases as of December 31, 2014 are as follows:

 

 

(in thousands)

2015

$

38,889

  

2016

 

28,924

  

2017

 

18,111

  

2018

 

7,196

  

2019

 

5,141

  

Thereafter

 

15,788

 

Future minimum lease payments

$

114,049

 

 

Capital lease commitments.  The Partnership has entered into one and three year capital leases for certain computer equipment. Assets under capital leases as of December 31, 2014, which are reflected as other fixed assets in the accompanying balance sheet, are summarized as follows:

 

 

(in thousands)

 

Computer software

$

9,909

 

Less: Accumulated amortization

 

(5,321

)

Net assets under capital lease

$

4,588

 

 

100


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following are the minimum lease payments to be made in each of the following years indicated for the capital lease in effect as of December 31, 2014:

 

Fiscal Year

(in thousands)

2015

$

3,880

 

2016

 

1,294

 

2017

 

53

 

Less: Interest

 

(233

)

Net minimum lease payments under capital leases

 

4,994

 

Less: Current portion of net minimum lease payments

 

(3,679

)

Long-term portion of net minimum lease payments

$

1,315

 

 

14.

Segment Information

The Partnership’s chief operating decision maker measures performance and allocates resources based on geographic segments. The Partnership’s operations are divided into eight operating segments: Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, Utica, Mid-Continent and Corporate. Summarized financial information for the reportable segments is shown in the following tables, presented in thousands.

 


101


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the year ended December 31, 2014

 

 

 

Barnett

 

 

Eagle Ford

 

 

Haynesville

 

 

Marcellus

 

 

Niobrara

 

 

Revenues

$

463,645

 

 

$

348,904

 

 

$

160,138

 

 

$

15,136

 

 

$

28,329

 

 

Operating expenses

 

95,744

 

 

 

74,962

 

 

 

46,171

 

 

 

12,526

 

 

 

14,568

 

 

Depreciation and amortization expense

 

81,845

 

 

 

56,980

 

 

 

69,488

 

 

 

8,182

 

 

 

5,418

 

 

General and administrative expense

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Other operating expense

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Operating income (loss)

$

286,056

 

 

$

216,962

 

 

$

44,479

 

 

$

(5,572

)

 

$

8,343

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from unconsolidated

   affiliates

$

-

 

 

$

-

 

 

$

-

 

 

$

170,236

 

 

$

-

 

 

Capital expenditures

$

13,661

 

 

$

188,661

 

 

$

14,459

 

 

$

42,791

 

(1)

$

213,749

 

(2)

Total assets

$

1,438,080

 

 

$

1,277,910

 

 

$

1,220,301

 

 

$

1,662,655

 

 

$

367,132

 

 

 

 

 

 

 

 

Mid-

 

 

 

 

 

 

 

 

 

 

Utica

 

 

Continent

 

 

Corporate

 

 

Consolidated

 

Revenues

$

153,963

 

 

$

208,819

 

 

$

5

 

 

$

1,378,939

 

Operating expenses

 

38,348

 

 

 

78,150

 

 

 

67,120

 

 

 

427,589

 

Depreciation and amortization expense

 

25,512

 

 

 

35,364

 

 

 

31,969

 

 

 

314,758

 

General and administrative expense

 

-

 

 

 

-

 

 

 

202,796

 

 

 

202,796

 

Other operating expense

 

-

 

 

 

-

 

 

 

24,123

 

 

 

24,123

 

Operating income (loss)

$

90,103

 

 

$

95,305

 

 

$

(326,003

)

 

$

409,673

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from unconsolidated

   affiliates

$

24,832

 

 

$

10,014

 

 

$

-

 

 

$

205,082

 

Capital expenditures

$

317,638

 

(3)

$

100,889

 

(4)

$

107,363

 

 

$

999,211

 

Total assets

$

1,596,504

 

 

$

820,576

 

 

$

760,419

 

 

$

9,143,577

 

 

(1) 

Amount excludes $147.0 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

 

(2) 

Amount includes $107.6 million of capital expenditures attributable to noncontrolling interest owners.

 

(3) 

Amount excludes $237.2 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates and includes $103.9 million of capital expenditures attributable to noncontrolling interest owners.

 

(4) 

Amount excludes $1.0 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.


102


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the year ended December 31, 2013

 

 

Barnett

 

 

Eagle Ford

 

 

Haynesville

 

 

Marcellus

 

 

Niobrara

 

 

Revenues

$

433,709

 

 

$

278,282

 

 

$

119,209

 

 

$

10,989

 

 

$

15,095

 

 

Operating expenses

 

96,926

 

 

 

59,059

 

 

 

41,176

 

 

 

4,834

 

 

 

9,090

 

 

Depreciation and amortization expense

 

97,941

 

 

 

51,433

 

 

 

80,770

 

 

 

1,381

 

 

 

4,284

 

 

General and administrative expense

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Other operating expense

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Operating income (loss)

$

238,842

 

 

$

167,790

 

 

$

(2,737

)

 

$

4,774

 

 

$

1,721

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from unconsolidated

   affiliates

$

-

 

 

$

-

 

 

$

-

 

 

$

133,036

 

 

$

-

 

 

Capital expenditures

$

50,627

 

 

$

316,002

 

 

$

17,186

 

 

$

2,590

 

(1)

$

59,115

 

(2)

Total assets

$

1,511,405

 

 

$

1,172,022

 

 

$

1,276,795

 

 

$

1,452,797

 

 

$

137,319

 

 

 

 

 

 

 

 

 

Mid-

 

 

 

 

 

 

 

 

 

 

Utica

 

 

Continent

 

 

Corporate

 

 

Consolidated

 

Revenues

$

44,063

 

 

$

171,875

 

 

$

-

 

 

$

1,073,222

 

Operating expenses

 

19,065

 

 

 

70,609

 

 

 

37,957

 

 

 

338,716

 

Depreciation and amortization expense

 

9,451

 

 

 

36,435

 

 

 

14,484

 

 

 

296,179

 

General and administrative expense

 

-

 

 

 

-

 

 

 

104,332

 

 

 

104,332

 

Other operating expense

 

-

 

 

 

-

 

 

 

2,092

 

 

 

2,092

 

Operating income (loss)

$

15,547

 

 

$

64,831

 

 

$

(158,865

)

 

$

331,903

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from unconsolidated

   affiliates

$

(3,842

)

 

$

1,226

 

 

$

-

 

 

$

130,420

 

Capital expenditures

$

342,839

 

(3)

$

106,718

 

(4)

$

163,522

 

 

$

1,058,599

 

Total assets

$

1,040,199

 

 

$

773,104

 

 

$

553,805

 

 

$

7,917,446

 

(1) Amount excludes $289.7 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.

(2) 

Amount includes $29.6 million of capital expenditures attributable to noncontrolling interest owners.

 

(3) 

Amount excludes $376.8 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates and includes $122.0 million of capital expenditures attributable to noncontrolling interest owners.

(4) Amount excludes $4.9 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates.


103


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

For the year ended December 31, 2012

 

 

 

Barnett

 

 

Eagle Ford

 

 

Haynesville

 

 

Marcellus

 

 

Niobrara

 

 

Revenues

$

395,467

 

 

$

7,232

 

 

$

68,184

 

 

$

783

 

 

$

116

 

 

Operating expenses

 

101,703

 

 

 

1,604

 

 

 

15,642

 

 

 

188

 

 

 

85

 

 

Depreciation and amortization expense

 

93,343

 

 

 

968

 

 

 

33,210

 

 

 

6

 

 

 

79

 

 

General and administrative expense

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Other operating expense

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

 

-

 

 

Operating income (loss)

$

200,421

 

 

$

4,660

 

 

$

19,332

 

 

$

589

 

 

$

(48

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from unconsolidated

   affiliates

$

-

 

 

$

-

 

 

$

-

 

 

$

67,592

 

 

$

-

 

 

Capital expenditures

$

98,507

 

 

$

11,796

 

 

$

23,578

 

 

$

-

 

(1)

$

1,967

 

 

Total assets

$

1,573,789

 

 

$

925,694

 

 

$

1,324,599

 

 

$

1,142,550

 

 

$

91,236

 

 

 

 

 

 

 

Mid-

 

 

 

 

 

 

 

 

 

 

Utica

 

 

Continent

 

 

Corporate

 

 

Consolidated

 

Revenues

$

353

 

 

$

136,312

 

 

$

-

 

 

$

608,447

 

Operating expenses

 

159

 

 

 

52,979

 

 

 

25,279

 

 

 

197,639

 

Depreciation and amortization expense

 

48

 

 

 

32,042

 

 

 

5,821

 

 

 

165,517

 

General and administrative expense

 

-

 

 

 

-

 

 

 

67,579

 

 

 

67,579

 

Other operating expense

 

-

 

 

 

-

 

 

 

(766

)

 

 

(766

)

Operating income (loss)

$

146

 

 

$

51,291

 

 

$

(97,913

)

 

$

178,478

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from unconsolidated

   affiliates

$

(38

)

 

$

(12

)

 

$

-

 

 

$

67,542

 

Capital expenditures

$

126

 

 

$

184,285

 

 

$

30,241

 

 

$

350,500

 

Total assets

$

356,662

 

 

$

714,510

 

 

$

432,060

 

 

$

6,561,100

 

 

(1) Amount excludes $384.4 million for the Partnership’s share of capital expenditures included in investments in unconsolidated affiliates

 

 

 

104


WILLIAMS PARTNERS L.P. (FORMERLY ACCESS MIDSTREAM PARTNERS, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

15.

Subsequent Events

On January 26, 2015, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.85 per unit, or $725.0 million in aggregate. The cash distribution was paid by the Merged Partnership on February 13, 2015 to unitholders of record at the close of business on February 9, 2015, which was subsequent to the completion of the merger described below and the issuance of new partnership units.

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.  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.  Please read Note 1 – Description of Business and Basis of Presentation, to the consolidated financial statements, for more information on the Merger.  

Following the Merger, the Merged Partnership now has a new $3.5 billion long-term unsecured credit facility, a $3.0 billion commercial paper program, and a $1.5 billion short-term unsecured credit facility, all as further discussed in Note 12 – Long-Term Debt and Interest Expense.

 

Quarterly Financial Data (Unaudited)

 

Summarized unaudited quarterly financial data for 2014 and 2013 are as follows ($ in thousands except per share data):

 

 

Quarters Ended

 

 

March 31,
2014

 

  

June 30,
2014

 

  

September 30,
2014

 

  

December 31,
2014

 

Total revenues

$

277,078

 

 

$

292,934

 

 

$

313,849

 

 

$

495,078

 

Gross profit(a)

$

184,165

 

 

$

195,411

 

 

$

197,197

 

 

$

374,577

 

Net income

$

65,529

 

 

$

72,468

 

 

$

51,902

 

 

$

239,472

 

Net income attributable to Williams Partners L.P. (formerly Access Midstream Partners, L.P.)

$

61,078

 

 

$

67,454

 

 

$

41,218

 

 

$

228,310

 

Net income per common units

$

0.15

 

 

$

0.18

 

 

$

0.03

 

 

$

0.65

 

Net income per subordinated units

$

 

 

$

 

 

$

 

 

$

 

 

Quarters Ended

 

 

March 31,
2013

 

 

June 30,
2013

 

 

September 30,
2013

 

 

December 31,
2013

 

Total revenues

$

236,959

 

 

$

247,242

 

 

$

260,943

 

 

$

328,078

 

Gross profit(a)

$

154,196

 

 

$

164,398

 

 

$

177,410

 

 

$

238,502

 

Net income

$

60,696

 

 

$

70,427

 

 

$

79,211

 

 

$

130,815

 

Net income attributable to Williams Partners L.P. (formerly Access Midstream Partners, L.P.)

$

59,538

 

 

$

69,213

 

 

$

78,217

 

 

$

129,057

 

Net income per common units

$

0.13

 

 

$

0.17

 

 

$

0.21

 

 

$

0.44

 

Net income per subordinated units

$

0.29

 

 

$

0.31

 

 

$

0.33

 

 

$

 

(a)

Total revenue less operating costs.

 

 

 

 

 

 

105


 

ITEM 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

 

ITEM 9A.

Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at a reasonable level of assurance as of December 31, 2014.

Changes in Internal Control over Financial Reporting

There have been no changes in the Partnership’s internal control over financial reporting during the quarter ended December 31, 2014, that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

It is the responsibility of the management of Williams Partners L.P. to establish and maintain adequate internal control over financial reporting (as defined in Rules 13a — 15(f) and 15d — 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2014, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework, (2013). Based on our assessment, we concluded that, as of December 31, 2014, our internal control over financial reporting was effective.

The effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2014 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in its report which appears herein.


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Report of Independent Registered Public Accounting Firm

On Internal Control Over Financial Reporting

 

The Board of Directors of WPZ GP LLC,

General Partner of Williams Partners L.P.

and the Limited Partners of Williams Partners L.P.

 

We have audited Williams Partners L.P.’s (formerly named Access Midstream Partners, L.P.) (the “Partnership”) internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). The Partnership’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of the Partnership as of December 31, 2014, and the related consolidated statements of income, changes in partners’ capital, and cash flows for the year then ended, and our report dated February 25, 2015 expressed an unqualified opinion thereon. 

/s/Ernst & Young LLP

 

Tulsa, Oklahoma

February 25, 2015

 

 


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ITEM 9B.

Other Information  

None

 

 

 

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PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

As a limited partnership, we have no directors or officers. Instead, our general partner, WPZ GP LLC, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner’s directors are appointed by a wholly owned subsidiary of Williams.  Accordingly, we do not have a procedure by which our unitholders may recommend nominees to our general partner’s Board of Directors.

All of the senior officers of our general partner are also senior officers of Williams.

The following table shows information for the directors and executive officers of our general partner.

 

Name

 

Age

 

Position with WPZ GP LLC

Alan S. Armstrong

 

52

 

Chairman of the Board and Chief Executive Officer

Donald R. Chappel

 

63

 

Chief Financial Officer and Director

Frank E. Billings

 

52

 

Senior Vice President – Corporate Strategic Development and Director

Rory L. Miller

 

54

 

Senior Vice President - Atlantic-Gulf and Director

Robert S. Purgason

 

58

 

Senior Vice President – Access and Director

James E. Scheel

 

50

 

Senior Vice President - Northeast G&P and Director

H. Brent Austin

 

60

 

Director

David A. Daberko

 

69

 

Director

Philip L. Fredrickson

 

58

 

Director

Alice M. Peterson

 

62

 

Director

J. Michael Stice

 

55

 

Director

Walter J. Bennett

 

45

 

Senior Vice President – West

John R. Dearborn

 

57

 

Senior Vice President - NGL & Petchem Services

Fred E. Pace

 

53

 

Senior Vice President - E&C

Brian L. Perilloux

 

53

 

Senior Vice President - Operational Excellence

Craig L. Rainey

 

62

 

General Counsel

Ted T. Timmermans

 

58

 

Vice President, Controller, and Chief Accounting Officer

Officers serve at the discretion of the Board of Directors of our general partner. There are no family relationships among any of the directors or executive officers of our general partner.  The directors of our general partner are appointed for one-year terms. In addition to independence and financial literacy for members of our general partner’s Board of Directors who serve on the Audit Committee and Conflicts Committee, our general partner considers the following qualifications relevant to service on its Board of Directors in the context of our business and structure:

Industry Experience in the oil, natural gas, and petrochemicals business.

Engineering and Construction Experience.

Financial and Accounting Experience.

Corporate Governance Experience.

Securities and Capital Markets Experience.

Executive Leadership Experience.

Public Policy and Government Experience.

Strategy Development and Risk Management Experience.

Operating Experience.

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Knowledge of the marketplace and political and regulatory environments relevant to the energy sector in the locations where we operate currently or plan to in the future (“Marketplace Knowledge”).

Certain information about each of our general partner’s directors and executive officers is set forth below, including qualifications relevant to service on our general partner’s Board of Directors.

Alan S. Armstrong has served as a director of our general partner since 2012, as Chief Executive Officer of our general partner since December 31, 2014, and as Chairman of the Board of Directors of our general partner since February 2, 2015.  Mr. Armstrong has served as the Chief Executive Officer, President, and a director of Williams since 2011.  Mr. Armstrong served as a director of the general partner of Pre-merger WPZ (the Pre-merger WPZ Board) from 2005 until the Merger on February 2, 2015, as the Chairman of the Pre-merger WPZ Board and the Chief Executive Officer of the general partner of Pre-merger WPZ (the Pre-merger WPZ General Partner) from 2011 until the Merger. From 2010 to 2011, Mr. Armstrong served as Senior Vice President — Midstream of the Pre-merger WPZ General Partner. From 2005 until 2010, Mr. Armstrong served as the Chief Operating Officer of the Pre-merger WPZ General Partner. From 2002 to 2011, Mr. Armstrong served as Senior Vice President — Midstream of Williams and acted as President of Williams’ midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in Williams’ midstream business and from 1998 to 1999 was Vice President, Commercial Development, in Williams’ midstream business.  Mr. Armstrong has also served as a director of BOK Financial Corporation (a financial services company) since 2013.

Mr. Armstrong’s qualifications include Marketplace Knowledge and industry, engineering and construction, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, strategy development and risk management, and operating experience.

Donald R. Chappel has served as a director of our general partner since 2012 and as Chief Financial Officer of our general partner since December 31, 2014.  Mr. Chappel has served as Senior Vice President and Chief Financial Officer of Williams since 2003.  Mr. Chappel served as the Chief Financial Officer and a director of the Pre-merger WPZ General Partner from 2005 until the Merger.  Mr. Chappel served as Chief Financial Officer and a director of the general partner of Williams Pipeline Partners L.P. (“WMZ”) (a limited partnership formed by Williams to own and operate natural gas transportation and storage assets) from 2008 until WMZ merged with Pre-merger WPZ in 2010.  Mr. Chappel has served as a member of the Management Committee of Northwest Pipeline since 2007. Mr. Chappel also serves as a director of SUPERVALU Inc. (a grocery and pharmacy company).

Mr. Chappel’s qualifications include Marketplace Knowledge and industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, and strategy development, and risk management experience.

Frank E. Billings has served as a director of our general partner since February 2014 and as our general partner’s Senior Vice President – Corporate Strategic Development since the Merger.  Mr. Billings has served as Senior Vice President — Corporate Strategic Development of Williams since January 2014 and served in that role for the Pre-merger WPZ General Partner from January 2014 until the Merger.  From January 2013 to January 2014, he served as Senior Vice President — Northeast G&P of Williams and the Pre-merger WPZ General Partner. Mr. Billings served as a Vice President of Williams’ midstream business from 2011 until 2013 and as Vice President, Business Development of Williams from 2010 to 2011.  He served as President of Cumberland Plateau Pipeline Company (a privately held company developing an ethane pipeline to serve the Marcellus shale area) from 2009 until 2010. From 2008 to 2009, Mr. Billings served as Senior Vice President of Commercial for Crosstex Energy, Inc. and Crosstex Energy L.P. (an independent midstream energy services master limited partnership and its parent corporation). In 1988, Mr. Billings joined MAPCO Inc., which merged with a Williams subsidiary in 1998, serving in various management roles, including in 2008 as a Vice President in the midstream business.

Mr. Billings’ qualifications include industry, executive leadership, risk management, and operating experience.

Rory L. Miller has served as a director of our general partner and as Senior Vice-President – Atlantic-Gulf of our general partner since the Merger.  Mr. Miller has served as Senior Vice President – Atlantic Gulf of Williams since 2013 and served in that role for the Pre-merger WPZ General Partner from 2011 until the Merger. From 2011 until 2013, Mr. Miller was Senior Vice President — Midstream of Williams and the Pre-merger WPZ General Partner, acting as President of Williams’ midstream business. Mr. Miller was a Vice President of Williams’ midstream business from 2004 until 2011. Mr. Miller has served as a member of the Management Committee of Transco since 2013.

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Mr. Miller’s qualifications include Marketplace Knowledge and industry, engineering and construction, executive leadership, strategy development and risk management, and operating experience.

Robert S. Purgason has served as a director of our general partner since 2012 and as Senior Vice President-Access of our general partner since the Merger.  Mr. Purgason has served as Senior Vice President-Access of Williams since January 1, 2015.  Mr. Purgason served as Chief Operating Officer of our general partner from 2010 until the Merger. Prior to joining our general partner, Mr. Purgason spent five years at Crosstex Energy L.P. and was promoted to Senior Vice President — Chief Operating Officer in 2006.  Prior to Crosstex, Mr. Purgason spent 19 years with Williams in various senior business development and operational roles. Mr. Purgason began his career at Perry Gas Companies in Odessa, Texas working in all facets of the natural gas treating business.  Mr. Purgason has also served on the Board of Directors of L.B. Foster Company (a manufacturer, fabricator, and distributor of products and services for the rail, construction, energy, and utility markets) since December 2014.

Mr. Purgason’s qualifications include Marketplace Knowledge and industry, engineering and construction, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, strategy development and risk management, and operating experience.

James E. Scheel has served as a director of our general partner and as Senior Vice President – Northeast G&P since the Merger.  Mr. Scheel has served as Senior Vice President – Northeast G&P of Williams since January 2014 and served in that role for the Pre-merger WPZ General Partner from January 2014 until the Merger.  Mr. Scheel served as a director of the Pre-merger WPZ General Partner from 2012 until the Merger.  Mr. Scheel served as a director of the Pre-merger ACMP General Partner from 2012 to February 2014.  Mr. Scheel served as Senior Vice President — Corporate Strategic Development of Williams and the Pre-merger WPZ General Partner from 2012 to January 2014.  Mr. Scheel served as Vice President of Business Development of Williams’ midstream business from 2011 until 2012.  Mr. Scheel joined Williams in 1988 and has served in leadership roles in business strategic development, engineering and operations, the NGL business, and international operations.

Mr. Scheel’s qualifications include Marketplace Knowledge and industry, engineering and construction, executive leadership, strategy development and risk management, and operating experience.

H. Brent Austin has served as a director of our general partner since the Merger.  Mr. Austin served as a director of the Pre-merger WPZ General Partner from 2010 until the Merger. Mr. Austin has been Managing Director and Chief Investment Officer of Alsamora L.P., a Houston-based private limited partnership with real estate and diversified equity investments, since 2003. Mr. Austin served as a director of the general partner of WMZ from 2008 until WMZ merged with Pre-merger WPZ in 2010.  From 2002 to 2003, Mr. Austin was President and Chief Operating Officer of El Paso Corporation, an owner and operator of natural gas transportation pipelines, storage, and other midstream assets, where he managed all nonregulated operations as well as all financial functions.

Mr. Austin’s qualifications include Marketplace Knowledge and industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, strategy development and risk management, and operating experience.

David A. Daberko has served as a director of our general partner since 2010, having served as Chairman of the Board until the Merger.  Mr. Daberko is the retired Chairman and Chief Executive Officer of National City Corporation, a regional bank holding company, where he worked for 39 years.  Mr. Daberko joined National City Bank in 1968 as a management trainee and held a number of management positions within the company. Mr. Daberko was elected Deputy Chairman of National City Corporation and President of National City Bank in Cleveland in 1987. He served as President and Chief Operating Officer from 1993 until 1995 when he was named Chairman and Chief Executive Officer. He retired as Chief Executive Officer and Chairman in 2007. Mr. Daberko also serves on the board of directors of RPM International, Inc. (a manufacturer of specialty coatings, sealants, and building materials), Marathon Petroleum Corporation (an oil refining, marketing, and pipeline transport company) and MPLX LP (a master limited partnership formed by Marathon). He is a trustee of Case Western Reserve University, University Hospitals Health System and Hawken School. Mr. Daberko also previously served as a director of OMNOVA Solutions, Inc. (a provider of emulsion polymers, specialty chemicals and decorative and functional surfaces), a director of the Federal Reserve Bank of Cleveland, and a member and chairman of the Federal Advisory Council to the Board of Governors of the Federal Reserve System.

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Mr. Daberko’s qualifications include Marketplace Knowledge and industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, public policy and government, and strategy and risk management experience.  

Philip L. Frederickson has served as a director of our general partner since 2010. Mr. Frederickson retired from ConocoPhillips (then an international, integrated oil company) after 29 years of service.  At the time of his retirement, he was Executive Vice President Planning, Strategy and Corporate Affairs.  He also served as a board member for Chevron Phillips Chemical (a chemical producer) and DCP Midstream (a natural gas processor and marketer).  Mr. Frederickson joined Conoco in 1978 and held several senior positions in the United States and Europe, including General Manager, Strategy and Business Development; General Manager, Refining and Marketing Europe; Managing Director, Conoco Ireland; General Manager, Refining and Marketing; General Manager, Strategy and Portfolio Management, Upstream; and Vice President, Business Development. Mr. Frederickson was Senior Vice President of Corporate Strategy and Business Development for Conoco Inc. from 2001 to 2002.  Following the announcement of the merger of Conoco and Phillips in 2001, Mr. Frederickson was named integration lead to coordinate the merger transition and in 2002 was made Executive Vice President, Commercial, of ConocoPhillips. Mr. Frederickson serves as a board member for Rosetta Resources Inc., an independent natural gas exploration and production company, and as a director emeritus for the Yellowstone Park Foundation. Mr. Fredrickson previously served as a director of Sunoco Logistics Partners L.P.

Mr. Fredrickson’s qualifications include Marketplace Knowledge and industry, engineering and construction, financial and accounting, corporate governance, securities and capital markets, public policy and government, strategy and risk management, and operating experience.  

Alice M. Peterson has served as a director of our general partner since the Merger.  Ms. Peterson served as a director of the Pre-merger WPZ General Partner from 2005 until the Merger.  Ms. Peterson has served as Chief Operating Officer of PPL Group, a private equity firm since 2012. Ms. Peterson served as a director of RIM Finance, LLC, a wholly owned subsidiary of Research in Motion, Ltd., the maker of the Blackberry™ handheld device, from 2000 to 2013.  From 2009 to 2010, Ms. Peterson served as the Chief Ethics Officer of SAI Global, a provider of compliance and ethics services, and was a special advisor to SAI Global until 2012. Ms. Peterson served as a director of Patina Solutions, which provides professionals on a flexible basis to help companies achieve their business objectives from 2012 to 2013. Ms. Peterson founded and served as the president of Syrus Global, a provider of ethics, compliance, and reputation management solutions from 2002 to 2009, when it was acquired by SAI Global.  From 2000 to 2001, Ms. Peterson served as President and General Manager of RIM Finance, LLC. From 1998 to 2000, Ms. Peterson served as Vice President of Sears Online and from 1993 to 1998, as Vice President and Treasurer of Sears, Roebuck and Co. Ms. Peterson previously served as a director of Navistar Financial Corporation, a wholly owned subsidiary of Navistar International (a manufacturer of commercial and military trucks, diesel engines and parts), Hanesbrands Inc. (an apparel company), TBC Corporation (a marketer of private branded replacement tires), and Fleming Companies (a supplier of consumer package goods).  

Ms. Peterson’s qualifications include industry, financial and accounting, corporate governance, securities and capital markets, executive leadership, strategy development and risk management, and operating experience.

J. Michael Stice has served as a director of our general partner since 2012.  Mr. Stice served as the Chief Executive Officer of our general partner from 2010 until December 31, 2014.  Mr. Stice was Senior Vice President —Natural Gas Projects of Chesapeake and President and Chief Operating Officer of Chesapeake’s primary midstream subsidiaries from 2008 to 2012.  Prior to joining our general partner and Chesapeake, Mr. Stice spent 27 years with ConocoPhillips and its predecessor companies, where he most recently served as President of ConocoPhillips Qatar, responsible for the development, management and construction of natural gas liquefaction and regasification projects. While at ConocoPhillips, he also served as Vice President of Global Gas, as President of Gas and Power and as President of Energy Solutions in addition to other roles in ConocoPhillips’ upstream and midstream business units.  Mr. Stice also serves on the Board of Directors of U.S. Silica Holdings, Inc. (a producer of industrial silica and sand proppants) and SandRidge Energy, Inc. (an oil and natural gas company with a focus on exploration and production).

Mr. Stice’s qualifications include Marketplace Knowledge and industry, engineering and construction, corporate governance, executive leadership, public policy and government, strategy development and risk management, and operating experience.

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Walter J. Bennett has served as Senior Vice President — West of our general partner since December 2013.  Mr. Bennett has served as Senior Vice President-West of Williams since January 1, 2015 and served in that same role for the Pre-merger WPZ General Partner until the Merger.  He most recently was Vice President – Western Operations for our general partner.  Prior, he was Chief Operating Officer of Chesapeake Midstream Development. Before joining our general partner, Mr. Bennett served as Senior Vice President-Operations at Boardwalk Pipeline Partners. Previously, Mr. Bennett served in a variety of senior positions at Gulf South Pipeline Company that included operations and commercial responsibilities. Mr. Bennett began his career at a subsidiary of Koch Industries.

John R. Dearborn has served as Senior Vice President - NGL & Petchem Services of our general partner since the Merger.  Mr. Dearborn served as Senior Vice President - NGL & Petchem Services of Williams since 2013 and also served in that role for the Pre-merger WPZ General Partner from 2013 until the Merger.  Mr. Dearborn served as a senior leader for Saudi Basic Industries Corporation, a petrochemical company, from 2011 to 2013. From 2001 to 2011, Mr. Dearborn served in a variety of leadership positions with The Dow Chemical Company (“Dow”).  Mr. Dearborn also worked for Union Carbide Corporation (prior to its merger with Dow) from 1981 to 2001 where he served in several leadership roles.

Fred E. Pace has served as Senior Vice President – E&C (engineering and construction) of our general partner since the Merger.  Mr. Pace has served as Senior Vice President – E&C of Williams since 2013 and also served in that role for the Pre-merger WPZ General Partner from 2013 until the Merger.  From 2011 until 2013, Mr. Pace served Williams in project engineering and development roles, including service as Vice President, Engineering and Construction for Williams’ midstream business.  From 2009 to 2011, Mr. Pace was the managing member of PACE Consulting, LLC, an engineering and consulting firm serving the energy industry. In 2003, Mr. Pace co-founded Clear Creek Natural Gas, LLC, later known as Clear Creek Energy Services, LLC, a provider of engineering, construction, and operational services to the energy industry, where he served as Chief Executive Officer until 2009. Mr. Pace has over 30 years of experience in the engineering, construction, operation, and project management areas of the energy industry, including prior service with Williams from 1985 to 1990.

Brian L. Perilloux has served as Senior Vice President – Operational Excellence of our general partner since the Merger.  Mr. Perilloux has served as Senior Vice President – Operational Excellence of Williams since 2013 and served in that role for the Pre-merger WPZ General Partner from 2013 until the Merger.  Mr. Perilloux served as a Vice President of Williams’ midstream business from 2011 until 2013. Mr. Perilloux served in various roles in Williams’ midstream business, including engineering and construction roles from 2007 to 2011.  Prior to joining Williams, Mr. Perilloux was an officer of a private international engineering and construction company.

Craig L. Rainey has served as the General Counsel of our general partner since December 31, 2014.  Mr. Rainey has served as the Senior Vice President and General Counsel of Williams since 2012 and served as General Counsel for the Pre-merger WPZ General Partner from 2012 until the Merger.  From 2001 until 2012, Mr. Rainey served as an Assistant General Counsel of Williams, primarily supporting Williams’ midstream business and former exploration and production business during that time. He joined Williams in 1999 as a senior counsel and he has practiced law since 1977.

Ted T. Timmermans has served as Vice President, Controller, and Chief Accounting Officer of our general partner since the Merger.  Mr. Timmermans has served as Vice President, Controller, and Chief Accounting Officer of Williams since 2005 and served in those roles for the Pre-merger WPZ General Partner from 2005 until the Merger.  Mr. Timmermans served as an Assistant Controller of Williams from 1998 to 2005. Mr. Timmermans served as Chief Accounting Officer of the general partner of WMZ from 2008 until WMZ merged with Pre-merger WPZ in 2010.

Governance

Our general partner adopted governance guidelines that address, among other areas, director independence, policies on meeting attendance and preparation, executive sessions of nonmanagement directors, and communications with nonmanagement directors.

Director Independence

Because we are a limited partnership, the NYSE does not require our general partner’s Board of Directors to be composed of a majority of directors who meet the criteria for independence required by the NYSE or to maintain nominating/corporate governance and compensation committees composed entirely of independent directors.

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Our general partner’s Board of Directors has adopted governance guidelines which require at least three members of our general partner’s Board of Directors to be independent directors as defined by the rules of the NYSE and have no material relationship with us or our general partner. Our general partner’s Board of Directors at least annually reviews the independence of its members expected to be independent and affirmatively makes a determination that each director meets these independence standards.

Our general partner’s Board of Directors affirmatively determined that each of Mesdames Suedeen G. Kelly, Peterson and Laura A. Sugg, and Messrs. Austin, William B. Berry, and Fredrickson is an independent director.  Mesdames Kelly and Sugg served as directors of our general partner until the Merger and Mr. Berry served as a director until July 1, 2014.In determining independence, the Board of Directors determined that each of these individuals met the “bright line” independence standards of the NYSE. In addition, the Board considered any transaction and relationships between each director and any member of his or her immediate family on one hand, and us or any affiliate of us on the other, to confirm that those transactions do not vitiate the affected director’s independence.  Accordingly, the Board considered that Mr. Debarko is a director of Marathon Petroleum Corporation (“Marathon”) for whom we provide ordinary course services.  In determining that the relationship was not material, the Board considered these facts:  the relationship arises only because Mr. Debarko is a director of Marathon; he has no material interest in any transactions between Marathon and us or our general partner; and he had no role in any such transactions.  

Mesdames Peterson and Messrs. Austin, Daberko, and Fredrickson do not serve as an executive officer of any nonprofit organization to which we or our affiliates made contributions within any single year of the preceding three years that exceeded the greater of $1.0 million or 2 percent of such organization’s consolidated gross revenues.  Further, there were no discretionary contributions made by us or our affiliates to a nonprofit organization with which such director, or such director’s spouse, has a relationship that impact the director’s independence.

Meeting Attendance and Preparation

Members of the Board of Directors of our general partner are expected to attend at least 75 percent of regular Board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the Board by reviewing written materials distributed in advance.

Executive Sessions of NonManagement Directors

Our general partner’s nonmanagement Board members periodically meet outside the presence of our general partner’s executive officers. The Chair of the Audit Committee serves as the presiding director for executive sessions of nonmanagement Board members. The current Chair of the Audit Committee and the presiding director is Ms. Peterson.

Communications with Directors

Interested parties wishing to communicate with our general partner’s nonmanagement directors, individually or as a group, may do so by contacting our general partner’s Corporate Secretary or the presiding director. The contact information is maintained on our website at http://investor.williams.com/williams-partners-lp.

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The current contact information is as follows:

Williams Partners L.P.

c/o WPZ GP LLC

One Williams Center, Suite 4700

Tulsa, Oklahoma 74172

Attn: Presiding Director

Williams Partners L.P.

c/o WPZ GP LLC

One Williams Center, Suite 4700

Tulsa, Oklahoma 74172

Attn: Corporate Secretary

Board Committees

The Board of Directors of our general partner has a separately designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 and a Conflicts Committee. The following is a description of each of the committees and committee membership.

Board Committee Membership

 

 

Audit

 

Conflicts

 

Committee

 

Committee

H. Brent Austin

*

 

David A. Daberko

*

 

*

Phillip L. Fredrickson

*

 

*

Alice M. Peterson

 

*

__________________________

*  = committee member

•    = chairperson

Audit Committee

Our general partner’s Board of Directors has determined that all members of the Audit Committee meet the heightened independence requirements of the NYSE for audit committee members and that all members are financially literate as defined by the rules of the NYSE. The Board of Directors has further determined that Ms. Peterson and Messrs. Austin and Daberko qualify as “audit committee financial experts” as defined by the rules of the SEC. Biographical information for each of these persons is set forth above. The Audit Committee is governed by a written charter adopted by the Board of Directors. For further information about the Audit Committee, please read the “Report of the Audit Committee” below and “Principal Accountant Fees and Services.”

Conflicts Committee

The Conflicts Committee of our general partner’s Board of Directors reviews specific matters that the Board believes may involve conflicts of interest and which it determines to submit to the Conflicts Committee for review. The Conflicts Committee determines if the resolution of the conflict of interest is fair and reasonable to us. The members of the Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement.  Any matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

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Code of Business Conduct and Ethics.

Our general partner has adopted a Code of Business Conduct and Ethics for directors, officers and employees. We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our general partner’s Chief Executive Officer, Chief Financial Officer, Controller and persons performing similar functions on our website at http://investor.williams.com/williams-partners-lp under the Corporate Governance tab, promptly following the date of any such amendment or waiver.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our general partner’s executive officers and directors and persons who own more than 10 percent of a registered class of our equity securities to file with the SEC and the NYSE reports of ownership of our securities and changes in reported ownership. Executive officers and directors of our general partner and greater than 10 percent unitholders are required by SEC rules to furnish to us copies of all Section 16(a) reports that they file. Based solely on a review of reports furnished to our general partner, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2014 our general partner’s officers and directors and our greater than 10 percent common unitholders timely filed all reports they were required to file under Section 16(a), except that due to inadvertent reporting oversights (i) one report for Ms. Suedeen G. Kelley was filed one day late with respect to two transactions and (ii) an initial statement of ownership for Mr. Frank Billings reflecting no holdings was not timely filed.

Transfer Agent and Registrar

Computershare Trust Company, N.A. serves as registrar and transfer agent for our common units. Contact information for Computershare is as follows:

Computershare Trust Company, N.A.

P.O. Box 30170

College Station, Texas 77842-3170

Phone: (781) 575-2879 or toll-free, (877) 498-8861

Hearing impaired: (800) 952-9245

Internet: www.computershare.com/investor

Send overnight mail to:

Computershare Trust Company, N.A.

211 Quality Circle, Suite 210

College Station, Texas 77845

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REPORT OF THE AUDIT COMMITTEE

The Audit Committee oversees our financial reporting process on behalf of the Board of Directors of our general partner. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee operates under a written charter approved by the Board. The charter, among other things, provides that the Audit Committee has authority to appoint, oversee, compensate, evaluate, and terminate when appropriate the independent auditor. In this context, the Audit Committee:

 

Reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;

Reviewed with Ernst & Young LLP, the independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of Williams Partners L.P.’s accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards;

Received the written disclosures and the letter from Ernst & Young LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding Ernst & Young LLP’s communications with the audit committee concerning independence, and discussed with Ernst & Young LLP its independence;

Discussed with Ernst & Young LLP the matters required to be discussed by Auditing Standard No. 16, “Communications with Audit Committees” issued by the Public Company Accounting Oversight Board;

Discussed with Ernst & Young LLP the overall scope and plans for their respective audit. The Audit Committee meets with Ernst & Young LLP, with and without management present, to discuss the results of their examinations, their evaluations of Williams Partners L.P.’s internal controls and the overall quality of Williams Partners L.P.’s financial reporting; and

Based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2014, for filing with the SEC.

This report has been furnished by the members of the Audit Committee of the Board of Directors:

— Alice M. Peterson - Chair

— H. Brent Austin

— David A. Daberko

— Phillip L. Frederickson

The report of the Audit Committee in this report shall not be deemed incorporated by reference into any other filing by Williams Partners L.P. under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.

 

ITEM 11.

Executive Compensation

Compensation Discussion and Analysis

Named Executive Officers

This Compensation Discussion and Analysis describes the compensation system for our named executive officers for 2014 consisting of the following individuals: (1) J. Michael Stice, Chief Executive Officer; (2) Robert S. Purgason, Chief Operating Officer, (3) David C. Shiels, Chief Financial Officer, (4) Walter Bennett, Senior Vice President – Western Operations; and (5) John D. Seldenrust, Senior Vice President – Eastern Operations.  

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Effective December 31, 2014, Alan S. Armstrong was named Chief Executive Officer and Donald R. Chappel was named Chief Financial Officer. Both individuals were elected as officers as Mr. Stice and Mr. Shiels departed from their positions, effective December 31, 2014.  Messrs. Armstrong and Chappel will not be included as “named executive officers” throughout this section as they had no compensation from the Partnership or general partner during 2014.

Overview

Our general partner manages our operations and activities, and through its Board of Directors and officers, makes decisions on our behalf.

Compensation Design and Process

The Pre-merger ACMP compensation system was designed to:

attract, retain and motivate executive officers with the competence, knowledge, leadership skills and experience to grow the Partnership’s profitability;

align the interests of the executive officers with the interests of our unitholders by basing a significant majority of each executive officer’s total compensation on individual and Partnership performance; and

encourage both a short-term and long-term focus, while discouraging excessive risk taking.

Effective as of January 1, 2013, our general partner entered into an employment agreement with each of our named executive officers. The employment agreements are the primary basis for the 2014 compensation mix and levels for each of the named executive officers and reflect our comprehensive approach to executive compensation. In 2014, our general partner reviewed each named executive officer’s performance twice. These reviews consisted of a subjective assessment of the overall performance of the named executive officer and his role and relative contribution. In our assessment of the performance of each named executive officer, we considered the following:

 

Individual Performance

  

Partnership Performance

  

Intangibles

 

 

 

    Contributions to the development and execution of the Partnership’s business plans and strategies (including contributions that are expected to provide substantial benefit to the organization in future periods)

    Performance of the relevant department or functional unit

    Level of responsibility

    Longevity with the Partnership

  

    Overall performance of the Partnership, including progress made with respect to operational results, risk management activities, asset acquisitions and asset monetizations

    Financial performance as measured by Adjusted EBITDA, distributable cash flow, net income, cost of capital, general and administrative costs and common unit price performance

  

    Leadership ability

    Demonstrated commitment to the organization

    Motivational skills

    Attitude

    Work ethic

As part of this review, Mr. Stice provided recommendations to the Compensation Committee of the Board of Directors of our general partner with respect to the compensation levels of Messrs. Shiels, Purgason, Bennett and Seldenrust based on their respective employment agreements as well as a comprehensive, subjective evaluation of the Partnership’s performance and their individual performances. The Compensation Committee of the Board of Directors of our general partner reviewed and approved the total compensation for the named executive officers. Awards to the named executive officers under our LTIP and MICP were also expressly approved by the Board of Directors of our general partner.

Elements and Mix of Compensation

Pre-merger ACMP provided short-term compensation in the form of base salaries, cash bonuses, long-term compensation in the form of equity awards and 401(k) matching contributions and certain perquisites.

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Cash Salary and Bonuses

The base salary levels of the named executive officers were intended to reflect each named executive officer’s base level of responsibility, leadership, tenure and contribution to the success and profitability of the organization. Base salaries tend to be less variable over time and are intended to contribute less to total compensation than incentive awards. The base salaries did not increase in 2014 for the named executive officers. Cash bonuses paid during 2014 were intended to provide incentives based on a subjective performance assessment over a shorter period of time than the equity compensation listed below.  Our named executive officers’ cash bonuses were determined by the Compensation Committee of the Board of Directors of our general partner in its discretion, based on its subjective assessment of our performance and our named executive officers’ performance over the first half of calendar year 2014 and over the second half of calendar year 2014.  

Equity-Based Compensation

The equity-based compensation of the named executive officers was intended to provide incentives for long-term performance that increases unitholder value by aligning the interests of the unitholders and the named executive officers. Equity awards were granted to Messrs. Bennett and Seldenrust in January 2014.  In July 2014, each named executive officer received an equity award.  This award recognized that previously granted awards vested and distributed as a result of the Williams Acquisition and were intended to provide long-term incentives and ensure appropriate retention was in place to maintain continuity during this transition.  The named executive officers received phantom unit awards under our LTIP, which is described below under “Long-Term Incentive Plan”.

Management Incentive Compensation Plan

Our general partner maintained the amended and restated MICP, which provided incentive compensation awards consisting of two components, to key members of management who were designated as participants by our general partner. Mr. Stice was granted an MICP award in December 2012 and Messrs. Shiels and Purgason were each granted MICP awards in December 2012 and January 2010.  No additional MICP awards were granted to our named executive officers in 2014.  As a result of the Williams Acquisition, MICP cash payments were made in 2014, as defined by the Plan, to Messrs. Stice, Shiels and Purgason.

The first component of each award was an annual cash bonus based on “excess” cash distributions made by us above a specified target amount with respect to each fiscal quarter during which the award was outstanding, beginning with the fiscal quarter in which the grant date occurred (the “Excess Return Component”). A participant’s Excess Return Component was generally calculated by multiplying the “excess” distribution amount for an applicable quarter (the amount of distributions that were made over “target” for that quarter) by the participant’s participation percentage assigned to him at the time of grant, by the annual payment percentage that was set forth in the MICP (unless otherwise assigned to the participant at the time of the grant). The Excess Return Component determined to be payable to a participant with respect to the quarters within a specified fiscal year (if any) was paid in annual installments over the first five years following the award commencement date, provided the participant continued to be employed by us or an affiliate until the payment date.

The second component was based on an increase in value of our common units at the end of a specified five-year period beginning on the award commencement date and was measured and paid at the end of such period (the “Equity Uplift Component”), unless a change of control occurred prior to the expiration of the period, at which time the award would be paid upon that change of control, as described in more detail below under “Potential Payments Upon Termination or Change of Control.” The Equity Uplift Component was calculated by multiplying the “equity uplift value,” if any, by the participant’s “equity uplift value percentage.” The “equity uplift value” was defined as the excess of the value of our units on the payment date over the value of our units on a date specified at the time of grant ($25.07 for the 2012 awards and $21.00 for the 2010 awards), multiplied by the number of our outstanding units on the payment date. Each participant’s “equity uplift value percentage” was assigned pursuant to an award agreement. Awards that could become due under the Equity Uplift Component could be paid in the form of a single lump sum in cash or common units, at the discretion of the Board of Directors of our general partner.

As a result of Williams Acquisition, payments were made under the MICP to Messrs. Stice, Purgason and Shiels in 2014.  These payment amounts were consistent with the terms of the MICP and are disclosed in the Summary Compensation Table.

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Other Compensation Arrangements

Pre-merger ACMP also provided compensation in the form of personal benefits and perquisites to the named executive officers in 2014. Most of the benefits that Pre-merger ACMP provided to the named executive officers were the same benefits that were provided to all employees or large groups of senior-level employees of Pre-merger ACMP, including health and welfare insurance benefits, 401(k) benefits, which include matching contributions (up to 12 percent of an employee’s annual base salary and cash incentive bonus compensation).  We did not have a pension plan or any other retirement plan other than the 401(k) and retirement restoration plans.  

Employment Agreements

Each of the named executive officers is a party to an employment agreement with our general partner that became effective January 1, 2013, that governs the terms and conditions of their employment, including their duties and responsibilities, compensation and benefits, and applicable severance terms, which are described below under “Potential Payments Upon Termination or Change of Control.” The employment agreements are each described below.

Employment Agreement with J. Michael Stice

Mr. Stice’s employment agreement became effective January 1, 2013 and had an initial employment term ending on June 30, 2017, subject to automatic one-year renewals thereafter. Pursuant to the agreement, Mr. Stice served as the Chief Executive Officer of our general partner, with an initial annual base salary of $750,000, subject to review and increase by our general partner’s Board in its discretion. During the term of his employment, Mr. Stice was also eligible to participate in the employee benefit plans and arrangements, such as retirement, health and welfare plans and vacation programs, in accordance with the terms and conditions of such plans and arrangements. Mr. Stice also participated in the MICP and the LTIP.

Mr. Stice’s employment agreement provided for certain severance payments and benefits upon specified terminations of employment, as described in more detail below under “Potential Payments Upon Termination or Change in Control – J. Michael Stice Employment Agreement”. In addition, Mr. Stice was entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Potential Payments Upon Termination or Change in Control – Severance Program.”

As a result of Mr. Stice’s departure from our general partner effective December 31, 2014, he received a payment in 2015 consistent with the severance payment terms of the Employment Agreement.   The Williams Acquisition did not trigger the Change in Control provisions of this agreement.

Employment Agreement with Robert S. Purgason

The employment agreement for Mr. Purgason became effective on January 1, 2013 and had an initial employment term ending on November 30, 2014 subject to automatic one-year renewals thereafter. Pursuant to the agreement, Mr. Purgason will serve as an officer of our general partner or an affiliate, with an initial annual base salary of $450,000, subject to review and increase by the employer in its discretion. During the term of his employment, Mr. Purgason is eligible to participate in the employee benefit plans and arrangements, such as retirement, health and welfare plans and vacation programs, in accordance with the terms and conditions of such plans and arrangements. In addition, during his employment terms, discretionary bonuses may be paid to Mr. Purgason as determined by the employer. Mr. Purgason also participated in the MICP and the LTIP.

The employment agreement for Mr. Purgason provides for certain severance payments and benefits upon specified terminations of employment, as described in more detail below under “Potential Payments Upon Termination or Change in Control – David C. Shiels and Robert S. Purgason Employment Agreement”. In addition, Mr. Purgason may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Potential Payments Upon Termination or Change in Control – Severance Program.”

Employment Agreement with David C. Shiels

The employment agreement for Mr. Shiels became effective on January 1, 2013 and had an initial employment term ending on January 3, 2015 subject to automatic one-year renewals thereafter. Pursuant to the agreement, Mr. Shiels served as the Chief Financial Officer of our general partner, with an initial annual base salary of $400,000, subject to

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review and increase by our general partner’s Board in its discretion. During the term of his employment with our general partner, Mr. Shiels was eligible to participate in the employee benefit plans and arrangements, such as retirement, health and welfare plans and vacation programs, in accordance with the terms and conditions of such plans and arrangements. Mr. Shiels also participated in the MICP and the LTIP.

The employment agreement for Mr. Shiels provided for certain severance payments and benefits upon specified terminations of employment, as described in more detail below under “Potential Payments Upon Termination or Change in Control – David C. Shiels and Robert S. Purgason Employment Agreement”. In addition, Mr. Shiels was entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Potential Payments Upon Termination or Change in Control – Severance Program.”

As a result of Mr. Shiels’ departure from our general partner effective December 31, 2014, he received a payment in 2015 consistent with the severance payment terms of the Employment Agreement.  The Williams Acquisition did not trigger the Change in Control provisions of this agreement.

Employment Agreements with Walter Bennett and John D. Seldenrust

The employment agreements for each of Messrs. Bennett and Seldenrust became effective on January 1, 2013 and have initial employment terms ending on December 31, 2017. Pursuant to their respective agreements, Mr. Bennett will serve as an officer of our general partner or an affiliate, with an initial annual base salary of $300,000, subject to review and increase by the employer in its discretion, and Mr. Seldenrust will serve as an officer of our general partner or an affiliate, with an initial annual base salary of $370,000, subject to review and increase by the employer in its discretion. During the term of their employment with our general partner, Messrs. Bennett and Seldenrust are eligible to participate in the employee benefit plans and arrangements, such as retirement, health and welfare plans and vacation programs, in accordance with the terms and conditions of such plans and arrangements.

Mr. Bennett’s employment agreement provides that he is eligible to receive target annual bonuses equal to $150,000 and $175,000 with respect to calendar years 2014 and 2015, respectively.  Additionally, discretionary bonuses may be paid to Mr. Bennett as determined by our general partner.  Mr. Seldenrust’s employment agreement provides that discretionary bonuses may be paid to him as determined by our general partner.  

Messrs. Bennett and Seldenrust also participate in the LTIP. With respect to the 2014 and 2015 calendar years, Mr. Bennett is eligible to receive an equity unit award under the LTIP with a targeted value of $150,000 and $175,000, respectively.

The employment agreements for Messrs. Bennett and Seldenrust each provide for certain severance payments and benefits upon specified terminations of employment, as described in more detail below under “Potential Payments Upon Termination or Change in Control – Walter Bennett and John D. Seldenrust Employment Agreement”. In addition, Messrs. Bennett and Seldenrust may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Potential Payments Upon Termination or Change in Control – Severance Program.”

Williams Leveraged Restricted Stock Unit (“RSU”) Awards

       With a focus on strengthening the alignment between management and Williams stockholders while building important retention with select leaders during a time of tremendous growth and capital investment, Williams awarded Leveraged Restricted Stock Unit awards to Messrs. Purgason, Bennett and Seldenrust effective October 25, 2014.  This special award is not part of Williams’ annual targeted compensation.  The award incents the growth of Williams’ Total Shareholder Return (“TSR”) over a three-year period.  In order for the award to generate value for the recipient, the annualized absolute TSR over the three-year period must be at least 7%.    At the 7% annualized TSR result, the recipient would receive half of the units granted, regardless of the performance relative to Williams 2015 comparator company group.  A result below 7% annualized TSR will not generate any distribution to the award recipients.   For each full percentage point the annualized absolute TSR improves above 7% threshold, the number of units vesting will increase by a factor of the original unit award amount.  This factor amount will vary based on Williams TSR performance relative to its 2015 comparator company group.  When Williams TSR over the performance period meets or exceeds the median TSR of its comparator group of companies, the number of units earned will increase by a factor of 25% of the original unit award for each 1% above a 7% annualized rate of TSR and by 50% of the original unit award for each 1% above a 12% annualized TSR.    When Williams TSR over the performance period falls below the median TSR of its comparator group of companies, the number of units earned will increase by a factor of 10% of the original award for each 1% above a 7%

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annualized rate of TSR.  While the awards will vest at the end of three years, any vested units will be paid out in Williams’ stock on a one-for-one basis.  Any such shares will distribute one-third three years after the award date, one-third four years after the award date, and one-third five years after the award date, subject to certain retention and change of control provisions.  The award may not exceed five times the number of original units granted or eight times the target value of the award in dollars.

Compensation Programs in 2015

On January 1, 2015, all persons who were employed by our general partner and providing services to Pre-merger ACMP became employees of another affiliate of Williams, including our executive officers and our management directors.  Beginning on January 1, 2015, all of our general partner’s executive officers will be compensated directly by a subsidiary of Williams except to the extent that awards or other compensatory agreements under our Pre-merger compensation programs remain outstanding.  Because we no longer have a significant role in any policies or programs relating to compensation of the executive officers of our general partner and we will no longer make significant decisions relating to such compensation, our general partner’s Board of Directors dissolved its Compensation Committee in December 2014.  Beginning January 1, 2015, we will reimburse our general partner or an affiliate for direct and indirect general and administrative expenses attributable to our management (which expenses include the share of the compensation paid to the executive officers of our general partner attributable to the time they spend managing our business). Please read “Certain Relationships and Related Transactions, and Director Independence - Reimbursement of Expenses of Our General Partner”for more information regarding this arrangement.

Board Report on Compensation

Neither we nor our general partner have a compensation committee.  The Board of Directors of our general partner has reviewed and discussed with management the Compensation Discussion and Analysis set forth above and based on this review and discussion, has approved it for inclusion in this Form 10-K.

The Board of Directors of WPZ GP LLC:

Alan S. Armstrong, Chairman

H. Brent Austin

Frank E. Billings

Donald R. Chappel

David A. Daberko

Philip L. Frederickson

Rory L. Miller

Alice M. Peterson

Robert S. Purgason

James E. Scheel

J. Michael Stice

Long-Term Incentive Plan

General

Our general partner previously adopted the Access Midstream LTIP, for employees, consultants and directors of our general partner and its affiliates, who perform services for us. The summary of the LTIP contained herein does not purport to be complete and is qualified in its entirety by reference to the LTIP. The LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights with respect to phantom units, and other unit-based awards. Subject to adjustment for certain events, an aggregate of 3,649,927 common units, as adjusted to reflect the Pre-merger Unit Split, may be delivered pursuant to awards under the LTIP. Units from awards that are cancelled or forfeited are available for delivery pursuant to other awards. The LTIP is administered by our general partner’s Board of Directors. The LTIP was designed to promote the interests of the Partnership and its unitholders by strengthening the Partnership’s ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

We do not expect to grant additional awards pursuant to this plan in future years.

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Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture during the restricted period. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our general partner, cash equal to the fair market value of a common unit. The Board of Directors of our general partner may make grants of restricted units and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the Board may determine are appropriate, including the period over which restricted or phantom units will vest. Our general partner may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement. Upon the vesting of phantom units, common units equal to the number of phantom units then vesting, or cash equal to the fair market value thereof, is delivered to the grantee, less the number of units or amount of cash equal to the minimum income taxes withholding payable on the vesting of the phantom units.

Distributions made by us with respect to awards of phantom units may, in the discretion of the Board of Directors of our general partner, be subject to the same vesting requirements as the restricted units. Our general partner, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights are rights to receive an amount equal to all or a portion of the cash distributions made on units during the period a phantom unit remains “outstanding.” Restricted units and phantom units granted under the LTIP serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants do not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner receives remuneration for the units delivered with respect to these awards.

Unit Options and Unit Appreciation Rights

The LTIP also permits the grant of options and unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by the board. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as our general partner may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant.

Other Unit-Based Awards

The LTIP also permits the grant of other unit-based awards, which are awards that, in whole or in part, are valued or based on or related to the value of a unit. The vesting of any other unit-based award may be based on a participant’s length of service, the achievement of performance criteria or other measures. On vesting, any other unit-based award may be paid in cash and/or in units (including restricted units), as our general partner may determine.

Source of Common Units; Cost

Common units to be delivered with respect to awards may be newly issued units, common units acquired by our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner from any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement. With respect to unit options and unit appreciation rights, our general partner will be entitled to reimbursement from us for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise of an option. Thus, we will bear the cost of the unit options.

Amendment or Termination of Long-Term Incentive Plan

The Board of Directors of our general partner, in its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the earlier of the 10th anniversary of the date it was initially adopted by our general partner or when common units are no longer available for delivery pursuant to awards under the LTIP. The Board of Directors of our general partner will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the

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LTIP; provided, however, that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under Section 409A of the Internal Revenue Code (the “Code”).

Upon a change of control of us or our general partner, the Board of Directors of our general partner may, in its sole discretion:

provide for either (A) the termination of any award in exchange for an amount of cash, if any, equal to the amount that would have been then attained upon the exercise or vesting of the award or (B) the replacement of the award with other rights or property;

provide that the award be assumed by the successor or survivor entity or be exchanged for similar awards of the equity of the successor or survivor, with appropriate adjustments;

make adjustments in the number and type of common units subject to, and terms and conditions and any performance criteria of, the award;

provide that the award will be exercisable or payable, notwithstanding anything to the contrary in the LTIP or the award agreement; and

provide that the award will be terminated upon such event.

Pre-merger WPZ LTIP

As a result of the Merger, we assumed the Pre-merger WPZ LTIP. Prior to the Merger, the Pre-merger WPZ LTIP initially permitted the issuance of up to 700,000 Pre-merger WPZ common units in the form of options, restricted units, phantom units, or unit appreciation rights.  The number of awards that may be issued under this plan in the future is subject to conversion to our securities by our general partner consistent with the ratio of the Merger Exchange.  No awards were outstanding under the Pre-merger WPZ LTIP in 2014 and no awards are currently outstanding.  We do not expect to utilize this plan in future years.

 

 

 

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Summary Compensation Table

The following table summarizes the compensation amounts for each of the named executive officers for the fiscal years ended December 31, 2014, 2013 and 2012.

 

Name and
Principal Position

 

Year

 

 

Salary
($)(1)

 

 

Bonus
($)(2)

 

 

Stock
Awards
($)(3)

 

 

Option
Awards
($)(3)

 

 

Non-Equity
Incentive
Plan
Compen-
sation
($) (4)

 

 

Change in
Pension
Value and
Nonqualified
Deferred
Compen-
sation
Earnings
($)

 

 

All
Other
Compen-
sation
($)(6)

 

 

Total
($)

 

J. Michael Stice(5)

 

2014

 

 

 

804,822

 

 

 

1,465,743

 

 

 

1,000,006

 

 

 

 

 

 

44,094,284

 

 

 

 

 

 

816,079

 

 

 

48,180,934

 

Chief Executive Officer

 

2013

 

 

 

747,115

 

 

 

826,150

 

 

 

3,262,875

 

 

 

 

 

 

324,721

 

 

 

 

 

 

67,802

 

 

 

5,228,663

 

 

2012

 

 

 

342,308

 

 

 

1,562,875

 

 

 

881,062

 

 

 

 

 

 

29,848

 

 

 

 

 

 

299,403

 

 

 

3,115,496

 

 

Robert S. Purgason

 

2014

 

 

 

455,192

 

 

 

661,693

 

 

 

6,105,737

 

 

 

 

 

 

30,024,798

 

 

 

 

 

 

247,731

 

 

 

37,495,151

 

Chief Operating Officer

 

2013

 

 

 

448,269

 

 

 

581,050

 

 

 

250,221

 

 

 

 

 

 

263,899

 

 

 

 

 

 

40,700

 

 

 

1,584,139

 

 

2012

 

 

 

423,558

 

 

 

551,850

 

 

 

250,082

 

 

 

 

 

 

134,711

 

 

 

 

 

 

168,567

 

 

 

1,528,768

 

 

David C. Shiels

 

2014

 

 

 

431,776

 

 

 

608,550

 

 

 

600,055

 

 

 

 

 

 

15,012,398

 

 

 

 

 

 

210,908

 

 

 

16,863,687

 

Chief Financial Officer

 

2013

 

 

 

398,462

 

 

 

226,450

 

 

 

200,111

 

 

 

 

 

 

131,949

 

 

 

 

 

 

35,190

 

 

 

992,162

 

 

2012

 

 

 

373,750

 

 

 

200,750

 

 

 

200,138

 

 

 

 

 

 

67,355

 

 

 

 

 

 

119,351

 

 

 

961,344

 

 

John D. Seldenrust

 

2014

 

 

 

390,454

 

 

 

371,241

 

 

 

5,102,763

 

 

 

 

 

 

 

 

 

 

 

 

163,446

 

 

 

6,027,904

 

Senior Vice President – Eastern Operations

 

2013

 

 

 

371,077

 

 

 

351,650

 

 

 

315,180

 

 

 

 

 

 

 

 

 

 

 

 

24,906

 

 

 

1,062,813

 

Walter Bennett

 

2014

 

 

 

338,866

 

 

 

319,800

 

 

 

3,886,551

 

 

 

 

 

 

 

 

 

 

 

 

122,975

 

 

 

4,668,192

 

Senior Vice President -

 

2013

 

 

 

311,385

 

 

 

212,450

 

 

 

405,188

 

 

 

 

 

 

 

 

 

 

 

 

18,030

 

 

 

947,053

 

    Western Operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Alan S. Armstrong

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Chief Executive Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Donald R. Chappel

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Chief Financial Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

The amounts in this column reflect the base salary compensation earned by our named executive officers for the year indicated.

(2)

The amounts in this column reflect bonuses earned by the named executive officers in the year indicated. For each of the named executive officers, the bonus amounts include bonuses provided for in their respective employment agreements and routine holiday bonuses.

 

 

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(3)

The amounts shown in this column for 2014 and 2013 reflect the aggregate grant date fair value of phantom unit awards granted to our named executive officers in 2014 and 2013, determined in accordance with FASB ASC Topic 718 (Compensation – Stock Compensation). The value ultimately realized by the executives upon the actual vesting of the awards may or may not be equal to the grant date fair value. Refer to the Grants of Plan-Based Awards in 2014 table for additional information regarding phantom unit awards made to the named executive officers in the year ended December 31, 2014.  The amount also includes an October 25, 2014 award of Williams Leveraged RSR awards to Merres. Purgason, Seldenrust and Bennett. These awards were approved by Williams Compensation Committee subject to the terms of Williams 2007 Incentive Plan.  More information about the named executive officers’ outstanding phantom units as of December 31, 2014 is provided in the Outstanding Equity Awards at Fiscal Year-End 2014 table. Unvested phantom units accrue distributions which are paid out upon the vesting of such units. Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.

(4)

The amounts shown in this column reflect amounts earned from awards made in December 2012 for Mr. Stice and awards made in December 2012 and January 2010 for Messrs. Purgason and Shiels pursuant to the Excess Return Component of the MICP.  The amounts in this column were paid pro-rata to the named executive officers over the remaining years of the MICP, until July 1, 2014 when both components of the MICP vested with the Williams Acquisition.

(5)

The amounts for Mr. Stice, in 2014 and 2013, reflect compensation paid entirely by the Partnership. The amounts for Mr. Stice, reflect compensation paid for his time spent providing services to the Partnership in 2012, which was approximately 50 percent of his time with the exception of a $1.0 million bonus payment in December 2012 that was paid entirely by the Partnership.

(6)

The dollar amounts for each perquisite and each other item of compensation shown in the “All Other Compensation” column and in this footnote represent our incremental cost of providing the perquisite or other benefit to the named executive officer. Amounts include the following perquisites and other items of compensation provided to our named executive officers in 2014.

 

 

Name

 

 

401(k) Plan
Matching
Contributions
($)(a)

 

Deferred Compensation Plan
Matching
Contributions
($)(b)

 

 

Distribution
Equivalent
Rights

($)(c)

 

 

 

Supplemental
Life Insurance
($)(d)

 

 

 

Supplemental
Accidental
Death and
Dismemberment
Insurance

($)(e)

 

 

 

Perquisites

($)(f)

 

 

 

Total

($)

 

J. Michael Stice

 

 

23,000

 

297,538

 

 

468,443

 

 

 

12,642

 

 

 

1,170

 

 

 

13,286

 

 

 

816,079

 

Robert S. Purgason

 

 

23,000

 

147,213

 

 

64,546

 

 

 

10,062

 

 

 

936

 

 

 

1,974

 

 

 

247,731

 

David C. Shiels

 

 

17,500

 

120,715

 

 

66,551

 

 

 

2,124

 

 

 

576

 

 

 

3,442

 

 

 

210,908

 

John D. Seldenrust

 

 

23,000

 

91,864

 

 

41,708

 

 

 

4,017

 

 

 

705

 

 

 

2,152

 

 

 

163,446

 

Walter Bennett

 

 

17,500

 

76,354

 

 

25,626

 

 

 

1,920

 

 

 

523

 

 

 

1,052

 

 

 

122,975

 

(a)

Amounts represent matching contributions made on behalf of the named executive officers under Pre-Merger ACMP’s 401(k) plan.

(b)

Amounts represent matching contributions made on behalf of the named executive officers under Pre-Merger ACMP’s nonqualified deferred compensation plan.

(c)

This column represents distribution equivalent rights credited to the named executive officers with respect to their phantom units.

(d)

Amounts represent supplemental life insurance premiums paid on behalf of the named executive officers in 2014.

(e)

Amounts represent supplemental accidental death and dismemberment insurance premiums paid on behalf of the named executive officers in 2014.  

(f)

Our employees and our named executive officers receive tickets to certain sporting events for which there is no incremental cost to the Company. This column represents the tax gross-up payments made to our named executive officers with respect to such tickets during 2014.  Mr. Stice also received perquisites of $11,706 for personal use of airplane that Pre-Merger ACMP had a contract with for business purposes.    

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Grants of Plan-Based Awards in 2014

The following table sets forth information concerning grants of plan-based awards made to the named executive officers during 2014.  

 

Name

  

Grant Date

 

  

Approval Date (1)

 

  

Estimated
Future Payout
Under Non-
Equity
Incentive Plan
Awards –
Target ($)

 

 

All Other Stock
Awards: Number
of Shares of
Stock or Units
(#)(2)

 

  

Grant Date 

Fair Value
of Stock
Awards
($)

 

J. Michael Stice

 

 

July 16, 2014

 

 

 

July 2, 2014

 

 

$

 

 

 

15,652

 

 

$

1,000,006

(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Robert S. Purgason

 

 

July 16, 2014

 

 

 

July 2, 2014

 

 

 

 

 

 

78,260

 

 

$

5,000,031

(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

October 25, 2014

 

 

 

October 25, 2014

 

 

 

 

 

 

18,746

 

 

$

1,105,706

(4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

David C. Shiels

 

 

July 16, 2014

 

 

 

July 2, 2014

 

 

 

 

 

 

9,392

 

 

$

600,055

(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

John D. Seldenrust

 

 

January 10, 2014

 

 

 

December 12, 2013

 

 

 

 

 

 

3,685

 

 

$

200,059

(3)

 

 

 

July 16, 2014

 

 

 

June 30, 2014

 

 

 

 

 

 

62,608

 

 

 

4,000,025

(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

66,293

 

 

$

4,200,084

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

October 25, 2014

 

 

 

October 25, 2014

 

 

 

 

 

 

11,361

 

 

$

736,420

(4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Walter Bennett

 

 

January 10, 2014

 

 

 

December 12, 2013

 

 

 

 

 

 

2,765

 

 

$

150,112

(3)

 

 

 

July 16, 2014

 

 

 

June 30, 2014

 

 

 

 

 

 

46,956

 

 

 

3,000,019

(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

49,721

 

 

$

3,150,131

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

October 25, 2014

 

 

 

October 25, 2014

 

 

 

 

 

 

14,202

 

 

$

902,679

(4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Alan S. Armstrong

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Donald R. Chappel

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

Our general partner approved the phantom unit awards to the named executive officers at regularly scheduled meetings. The general partner’s approval on December 12, 2013 provided for the phantom unit grant dates to be on January 10, 2014. The general partner’s approval on June 30, 2014 and July 2, 2014 provided for the phantom unit grant dates to be on July 16, 2014.

(2)

The phantom unit awards granted in January 2014 vested on July 1, 2014 due to the Williams Acquisition. The phantom unit awards granted on July 16, 2014 vest as follows: 25% granted to Mr. Purgason will vest on the second and third anniversaries of the grant date, and the remaining granted will vest on the fourth anniversary of the grant date; 18.75% granted to Mr. Seldenrust will vest on each of the second and third anniversaries of the grant date, and the remaining granted will vest on the fourth anniversary of the grant date; and 16.67% granted to Mr. Bennett will vest on each of the second and third anniversaries of the grant date, and the remaining granted will vest on the fourth anniversary of the grant date.  The phantom unit awards granted to Mr. Stice and Mr. Shiels were originally granted with time-based vesting periods but were accelerated due to their departure on December 31, 2014.  Unvested phantom units accrue distributions that are paid out upon the vesting of such units.

(3)

The amounts shown in this column represent the aggregate grant date fair value of the awards, determined in accordance with FASB ASC Topic 718. The values shown in reference to phantom unit awards are based on the closing price of the Partnership’s common units on the grant date. The value ultimately realized by the executive upon the actual vesting of the awards may or may not be equal to the grant date fair value. Unvested phantom units accrue distributions that are paid out upon the vesting of such units. Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.  

(4)

The Williams Compensation Committee approved Williams’ equity awards to Messrs. Purgason, Bennett and Seldenrust on October 25, 2014.  These awards are in the form of Williams’ restricted stock units and are not our units or part of our general partner’s LTIP.  The award focused on strengthening the alignment between management and Williams stockholders while building important retention with select leaders during a time of tremendous growth and capital investment, The award incents the growth of Williams’ TSR over a three-year period.  In order for the award to generate value for the recipient, the annualized absolute TSR over the three-year period must be at least 7%.  At the 7% annualized TSR result, the recipient would receive half of the units granted,

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regardless of the performance relative to its 2015 comparator company group.  A result below 7% annualized TSR will not generate any distribution to the award recipients  For each full percentage point the annualized absolute TSR improves above the 7% threshold, the number of units vesting will increase by a factor of the original unit award amount.  This factor amount will vary based on Williams TSR performance relative to its 2015 comparator company group.  When Williams TSR over the performance period meets or exceeds the median TSR of its comparator group of companies, the number of units earned will increase by a factor of 25% of the original unit award for each 1% above a 7% annualized rate of TSR and by 50% of the original unit award for each 1% above a 12% annualized TSR.  When Williams TSR over the performance period falls below the median TSR of its comparator group of companies, the number of units earned will increase by a factor of 10% of the original award for each 1% above a 7% annualized rate of TSR.  While the awards will vest at the end of three years, any earned units will distribute one-third three years after the award date, one-third four years after the award date, and one-third five years after the award date.  The award may not exceed five times the number of original units granted or eight times the target value of the award in dollars.

 

Outstanding Equity Awards at Fiscal Year-End 2014

The following table reflects outstanding phantom unit awards as of December 31, 2014, for each of the named executive officers in connection with their service to the Partnership.

 

 

  

Stock Awards

 

 

  

Grant Date of
Shares or Units of
Stock That Have
Not Vested

 

  

Number of Shares
or Units of Stock
That Have Not
Vested (#) (1)

 

  

Market Value of
Shares or Units of
Stock That Have
Not Vested ($)

 

J. Michael Stice

  

 

July 16, 2014

  

  

 

15,652

  

  

 

848,338

(2)

Robert S. Purgason

  

 

July 16, 2014

  

  

 

78,260

 

 

 

4,241,692

(2) 

 

 

 

October 25, 2014

 

 

 

18,746

 

 

 

842,445

(3)

David C. Shiels

  

 

July 16, 2014

  

  

 

9,392

 

 

 

509,046

(2)

John D. Seldenrust

  

 

July 16, 2014

 

  

 

62,608

 

 

 

3,393,354

(2)

 

 

 

October 25, 2014

 

 

 

14,202

 

 

 

638,238

(3)

Walter Bennett

  

 

July 16, 2014

  

  

 

46,956

 

 

 

2,545,015

(2)

 

 

 

October 25, 2014

 

 

 

11,361

 

 

 

510,563

(3)

Alan S. Armstrong

 

 

 

 

 

 

 

 

 

Donald R. Chappel

 

 

 

 

 

 

 

 

 

 

(1)

For vesting terms, see footnote 2 of the Grants of Plan-Based Awards in 2014 table.

(2)

The value shown for phantom unit awards is based on the closing price of Pre-merger ACMP’s common units on the NYSE on December 31, 2014, of $54.20 per unit.

(3)

The value shown is based on the closing price of Williams’ common units on the NYSE on December 31, 2014, of $44.94 per unit.

Stock Vested and Units Vested in 2014

 

The following table reflects phantom unit awards that vested in 2014.

 

 

 

Unit Awards

 

 Name

 

Number of Units
Acquired on Vesting
(#) (1)

 

  

Value Realized
on Vesting
($)

 

J. Michael Stice

 

 

135,770

 

 

$

8,404,945

 

Robert S. Purgason

 

 

16,979

 

 

 

1,060,155

 

David C. Shiels

 

 

14,171

 

 

 

883,289

 

John D. Seldenrust

 

 

15,479

 

 

 

975,746

 

Walter Bennett

 

 

12,330

 

 

 

784,507

 

Alan S. Armstrong

 

 

 

 

 

 

Donald R. Chappel

 

 

 

 

 

 

 

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(1)

The number of units acquired on vesting reflects the vesting of phantom unit awards granted to the applicable named executive officer in connection with his service to the Partnership. The value realized on vesting is based on the closing price of the Partnership’s common units on the vesting dates.

 

Nonqualified Deferred Compensation for 2014

Name

 

Executive
Contribution
in Last
Fiscal Year
($)

 

 

Registrant
Contributions
in Last
Fiscal Year
($)(1)

 

 

Aggregate
Earnings in

Last Fiscal
Year
($)

 

 

Aggregate
Withdrawals/
Distributions
($)

 

 

Aggregate
Balance at
Last Fiscal
Year-End
($)

 

J. Michael Stice

 

$

 

 

$

297,538

 

 

$

16,394

 

 

$

 

 

$

470,587

 

Robert S. Purgason

 

 

 

 

 

147,213

 

 

 

5,608

 

 

 

 

 

 

249,614

 

David C. Shiels.

 

 

 

 

 

120,715

 

 

 

5,200

 

 

 

 

 

 

180,230

 

John D. Seldenrust

 

 

 

 

 

91,864

 

 

 

7,830

 

 

 

 

 

 

163,924

 

Walter Bennett

 

 

 

 

 

76,354

 

 

 

2,508

 

 

 

 

 

 

117,928

 

(1)

Partnership matching contributions are included as compensation in the All Other Compensation column of the Summary Compensation Table.

The named executive officers were permitted to participate in the general partner’s Match Restoration Plan (the “MRP”), a nonqualified deferred compensation plan.  

 

Potential Payments Upon Termination or Change of Control

Employment Agreements.  As discussed under “Compensation Discussion and Analysis” above, each of the named executive officers is or was a party to an employment agreement with our general partner, each of which became effective January 1, 2013, that govern or governed the terms and conditions of their employment, including their duties and responsibilities, compensation and benefits, and applicable severance terms.  Below is a discussion of the arrangements in effect during calendar year 2014.  

J. Michael Stice Employment Agreement. Mr. Stice's employment agreement provided for certain change of control and termination benefits in the event of a termination of Mr. Stice's employment under certain circumstances.  

Upon a termination of his employment without “cause” or for a “good reason condition” (each as defined in the employment agreement), subject to his execution of a release, Mr. Stice was entitled to receive an amount equal to (i) 200% of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination. If such termination occurred within two years after a “change of control” (as defined in the employment agreement), Mr. Stice was entitled to receive (in lieu of the severance benefits described above) an amount equal to (a) 250% of the sum of (i) his then-current annual base salary and (ii) the most recent actual annual bonus (or, if the most recent annual bonus was paid semi-annually, the two most recent semi-annual bonuses) paid to Mr. Stice during the twelve-month period preceding the change of control, plus (b) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination.

Upon a termination of Mr. Stice’s employment due to his death or incapacity, subject (in the case of his incapacity) to the execution of a release, Mr. Stice (or his estate, as applicable) was entitled to receive an amount equal to (i) 100% of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum following such termination. Upon any other termination of employment (including a termination for “cause” or due to the expiration or non-renewal of the employment term), Mr. Stice was entitled to receive only accrued but unpaid vacation through the date of termination. However, Mr. Stice was entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our general partner’s Severance Program (as defined below), which is described in more detail below under “Severance Program.”

Mr. Stice’s employment agreement contained confidentiality restrictions effective during and after his employment and non-solicitation covenants effective during employment and for one year (or six months in the case of a termination due to the expiration of the employment term) following the termination of his employment.

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As a result of Mr. Stice’s departure from our general partner effective December 31, 2014, he received a payment in 2015 consistent with the severance payment terms of the Employment Agreement.   The Williams Acquisition did not trigger the Change in Control provisions of this agreement.

Robert S. Purgason Employment Agreement. Mr. Purgason’s employment agreement with our general partner provides for certain termination benefits in the event of termination under certain specified circumstances.  

Upon a termination of employment without “cause” or for a “good reason condition” (each as defined in the applicable employment agreement), subject to the execution of a release, Mr. Purgason is entitled to receive an amount equal to (i) 100% of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination. If such termination occurs within two years after a “change of control” (as defined in the applicable employment agreement), Mr. Purgason is entitled to receive (in lieu of the severance benefits described above) an amount equal to (a) 100% of the sum of (i) his then-current annual base salary and (ii) the most recent actual annual bonus (or, if the most recent annual bonus was paid semi-annually, the two most recent semi-annual bonuses) paid to him during the twelve-month period preceding the change of control, plus (b) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination.

Upon a termination of employment due to his death or incapacity, subject (in the case of incapacity) to the execution of a release, Mr. Purgason (or his estate, as applicable) is entitled to receive an amount equal to (i) 100% (in the case of death) or 50% (in the case of incapacity), as applicable, of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum following such termination. Upon any other termination (including a termination for “cause” or due to the non-renewal of the employment term), Mr. Purgason will be entitled to receive only accrued but unpaid vacation through the date of termination. However, Mr. Purgason may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Severance Program.”

Mr. Purgason’s employment agreement also contains confidentiality restrictions effective during and after his employment and non-solicitation covenants effective during employment and for one year following the termination of his employment.

David C. Shiels Employment Agreement. Mr. Shiels’ employment agreement with our general partner provided for certain termination benefits in the event of termination under certain specified circumstances.  

Upon a termination of employment without “cause” or for a “good reason condition” (each as defined in the applicable employment agreement), subject to the execution of a release, Mr. Shiels was entitled to receive an amount equal to (i) 100% of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination. If such termination occurred within two years after a “change of control” (as defined in the applicable employment agreement), Mr. Shiels was entitled to receive (in lieu of the severance benefits described above) an amount equal to (a) 100% of the sum of (i) his then-current annual base salary and (ii) the most recent actual annual bonus (or, if the most recent annual bonus was paid semi-annually, the two most recent semi-annual bonuses) paid to him during the twelve-month period preceding the change of control, plus (b) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination.

Upon a termination of employment due to his death or incapacity, subject (in the case of incapacity) to the execution of a release, Mr. Shiels (or his estate, as applicable) was entitled to receive an amount equal to (i) 100% (in the case of death) or 50% (in the case of incapacity), as applicable, of his then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum following such termination. Upon any other termination (including a termination for “cause” or due to the non-renewal of the employment term), Mr. Shiels was entitled to receive only accrued but unpaid vacation through the date of termination. However, Mr. Shiels was entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Severance Program.”

Mr. Shiels’ employment agreement also contained confidentiality restrictions effective during and after his employment and non-solicitation covenants effective during employment and for one year following the termination of his employment.

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As a result of Mr. Shiels’ departure from our general partner effective December 31, 2014, he received a payment in 2015 consistent with the severance payment terms of the Employment Agreement.   The Williams Acquisition did not trigger the Change in Control provisions of this agreement.

Walter Bennett and John D. Seldenrust Employment Agreements. Mr. Bennett’s and Mr. Seldenrust’s employment agreements with our general partner provide for certain termination benefits in the event of termination under certain specified circumstances.  

Upon a termination of employment without “cause” or for a “good reason condition” (each as defined in the applicable employment agreement), subject to the execution of a release, each of Messrs. Bennett and Seldenrust are entitled to receive an amount equal to (i) 26 weeks of the executive’s then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination. If such termination occurs within two years after a “change of control” (as defined in the applicable employment agreement), each of Messrs. Bennett and Seldenrust are entitled to receive (in lieu of the severance benefits described above) an amount equal to (a) the sum of (i) 26 weeks of the executive’s then-current annual base salary and (ii) the most recent annual bonus (or, if the most recent annual bonus was paid semi-annually, the two most recent semi-annual bonuses) paid to the executive during the twelve-month period preceding the change of control, plus (b) any accrued but unused vacation as of the date of termination, payable in a lump sum within thirty days following termination.

Upon a termination of employment due to the executive’s death or incapacity, subject (in the case of incapacity) to the execution of a release, each of Messrs. Bennett and Seldenrust (or their estates, as applicable) is entitled to receive an amount equal to (i) 52 weeks (in the case of death) or 26 weeks (in the case of incapacity), as applicable, of the executive’s then-current annual base salary, plus (ii) any accrued but unused vacation as of the date of termination, payable in a lump sum following such termination. Upon any other termination (including a termination for “cause” or due to the non-renewal of the employment term), each of Messrs. Bennett and Seldenrust will be entitled to receive only accrued but unpaid vacation through the date of termination. However, Messrs. Bennett and Seldenrust may be entitled to receive certain benefits and payments upon certain qualifying terminations of employment in accordance with the terms of our Severance Program, which is described in more detail below under “Severance Program.”

Each employment agreement also contains confidentiality restrictions effective during and after the executive’s employment and non-solicitation covenants effective during employment and for one year following the termination of the executive’s employment.

Severance Program.  Our general partner maintains an Employee Severance Program (the “Severance Program”), which provides certain severance payments and benefits to eligible employees, including our named executive officers, upon specified terminations of employment. Specifically, upon an involuntary termination of employment due to a job elimination, subject to the execution of a release and continued compliance with certain confidentiality obligations, each eligible employee is entitled to receive: (i) an amount in cash equal to eight weeks (or twenty-six weeks for directors and senior directors) of the participant’s base salary (the “Severance Payment”), (ii) payment or reimbursement for continued healthcare of COBRA coverage for eight weeks (or twenty-six weeks for directors and senior directors) following termination, (iii) payment for post-termination outplacement services, and (iv) full accelerated vesting of any of then-unvested awards of restricted units held by the participant (collectively, (ii) through (iv), the “Severance Benefits”).

However, employees who have entered into individual employment agreements with our general partner, including our named executive officers, are eligible to receive Severance Benefits under the Severance Program only to the extent that the applicable employment agreement does not provide the employee with the same type of severance benefits (i.e., healthcare or COBRA payment or reimbursement, outplacement benefits and/or equity award acceleration, as applicable) provided under the Severance Program. Additionally, such employees, including our named executive officers, are eligible to receive the cash Severance Payment under the Severance Program only to the extent that the cash Severance Payment under the Severance Program is greater than the cash severance payments provided under the employment agreement.

131


 

The tables below provide estimates of the compensation and benefits that would have been payable to Messrs. Stice, Shiels, Purgason, Bennett and Seldenrust under each the above described arrangements if such termination events had been triggered as of December 31, 2014.

 

J. Michael Stice - Executive
Benefits and Payments Upon Separation

 

Termination
without Cause

 

  

Change of
Control

 

  

Retirement

 

  

Incapacity of
Executive

 

  

Death of
Executive

 

Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

1,500,000

 

 

$

3,337,500

 

 

$

 

 

$

750,000

 

 

$

750,000

 

Acceleration of Equity Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Phantom Unit Awards(1)

 

 

 

 

 

848,338

 

 

 

 

 

 

 

 

 

 

Benefits and Perquisites:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accrued Vacation Pay

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

1,500,000

 

 

$

4,185,838

 

 

$

 

 

$

750,000

 

 

$

750,000

 

(1)

Amounts based on the closing price of Pre-Merger ACMP’s common units on December 31, 2014.  

 

 

Robert S. Purgason - Executive
Benefits and Payments Upon Separation

 

Termination
without Cause

 

  

Change of
Control

 

  

Retirement

 

  

Incapacity of
Executive

 

  

Death of
Executive

 

Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

450,000

 

 

$

1,108,250

 

 

$

 

 

$

225,000

 

 

$

450,000

 

Acceleration of Equity Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Phantom Unit Awards(1)

 

 

 

 

 

4,241,692

 

 

 

 

 

 

 

 

 

 

Benefits and Perquisites:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accrued Vacation Pay

 

 

3,263

 

 

 

3,263

 

 

 

3,263

 

 

 

3,263

 

 

 

3,263

 

Total

 

$

453,263

 

 

$

5,353,205

 

 

$

3,263

 

 

$

228,263

 

 

$

453,263

 

(1)

Amounts based on the closing price of Pre-Merger’s common units on December 31, 2014.

 

David C. Shiels - Executive Benefits and Payments Upon Separation

 

Termination
without Cause

 

  

Change of
Control

 

  

Retirement

 

  

Incapacity of
Executive

 

  

Death of
Executive

 

Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

415,000

 

 

$

1,022,000

 

 

$

 

 

$

207,500

 

 

$

415,000

 

Acceleration of Equity Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Phantom Unit Awards(1)

 

 

 

 

 

509,046

 

 

 

 

 

 

 

 

 

 

Benefits and Perquisites:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accrued Vacation Pay

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

415,000

 

 

$

1,531,046

 

 

$

 

 

$

207,500

 

 

$

415,000

 

 

 

(1)

Amounts based on the closing price of Pre-Merger’s common units on December 31, 2014.

 

John D. Seldenrust - Executive Benefits and Payments Upon Separation

 

Termination
without Cause

 

  

Change of
Control

 

  

Retirement

 

  

Incapacity of
Executive

 

  

Death of
Executive

 

Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

193,000

 

 

$

559,750

 

 

$

 

 

$

193,000

 

 

$

386,000

 

Acceleration of Equity Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Phantom Unit Awards(1)

 

 

 

 

 

3,393,354

 

 

 

 

 

 

 

 

 

 

Benefits and Perquisites:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accrued Vacation Pay

 

 

1,499

 

 

 

1,499

 

 

 

1,499

 

 

 

1,499

 

 

 

1,499

 

Total

 

$

194,499

 

 

$

3,954,603

 

 

$

1,499

 

 

$

194,499

 

 

$

387,499

 

 

(1)

Amounts based on the closing price of Pre-Merger’s common units on December 31, 2014.  

 

132


 

 

Walter Bennett - Executive Benefits and Payments Upon Separation

 

Termination
without Cause

 

  

Change of
Control

 

  

Retirement

 

  

Incapacity of
Executive

 

  

Death of
Executive

 

Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash Severance

 

$

167,500

 

 

$

485,750

 

 

$

 

 

$

167,500

 

 

$

335,000

 

Acceleration of Equity Compensation:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Phantom Unit Awards(1)

 

 

 

 

 

2,545,015

 

 

 

 

 

 

 

 

 

 

Benefits and Perquisites:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accrued Vacation Pay

 

 

21,917

 

 

 

21,917

 

 

 

21,917

 

 

 

21,917

 

 

 

21,917

 

Total

 

$

189,417

 

 

$

3,052,682

 

 

$

21,917

 

 

$

189,417

 

 

$

356,917

 

 

(1)

Amounts based on the closing price of Pre-Merger’s common units on December 31, 2014.  

 

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Our non-management directors receive compensation for their service on our general partner’s Board of Directors. In 2014, such compensation consisted of an annual retainer of $80,000 for each Board member, except for the Chairman of the Board of Directors who received $100,000. The independent directors also received an initial grant of the number of units having a grant date value of approximately $50,000 upon initial appointment as a director of our general partner. The independent directors also received an annual grant, effective on the first business day of January, of a number of units having a grant date value of approximately $50,000, 25 percent of which vested on the grant date and 75 percent of which were phantom units that provided for time-based vesting, but for which vesting was accelerated because of the Williams Acquisition in July 2014.  

Effective January 1, 2015, our general partner’s Board of Directors adopted a new compensation program for its non-management directors.  Under the new program, non-employee directors will receive a bi-annual compensation package consisting of the following, which amounts are paid on January 1 and July 1: (a) $75,000 cash retainer; and (b) $5,000 cash retainer for the Chair of each of the Conflicts Committee and Audit Committee. If a non-employee director’s service on the Board of Directors commenced after January 1 and prior to the final day of June, or between July 1 and December 31, the non-employee director will receive a prorated bi-annual compensation package.

In addition, each director is reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or committees.   We also reimburse non-employee directors for the costs of education programs relevant to their duties as Board members.  Each director is fully indemnified by us, pursuant to individual indemnification agreements, or our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law.

On January 2, 2014, each of Messrs. Daberko, Berry and Frederickson and Ms. Kelly was awarded 915 phantom units and all outstanding units vested on July 1, 2014.

The following table sets forth the compensation earned by the directors of our general partner in 2014:

 

Name

 

Fees
Earned or
Paid in Cash
($)

 

  

Stock Awards
($)(1)

 

  

Option
Awards
($)

 

  

All Other
Compensation
($)(2)

 

  

Total
($)

 

David A. Daberko

 

 

100,000

 

 

 

 

 

 

 

 

 

9,456

 

 

 

109,456

 

William B. Berry

 

 

40,000

 

 

 

 

 

 

 

 

 

775

 

 

 

40,775

 

Philip A. Frederickson

 

 

80,000

 

 

 

 

 

 

 

 

 

9,456

 

 

 

89,456

 

Suedeen G. Kelly

 

 

80,000

 

 

 

 

 

 

 

 

 

9,456

 

 

 

89,456

 

 

(1)

Reflects the aggregate grant date fair value of 2014 unit awards computed in accordance with FASB ASC Topic 718. All units awarded previously were vested on July 1, 2014 and no additional awards were granted in the third or fourth quarter of 2014.

(2)

The amounts shown in this column reflect distribution equivalent rights with regard to phantom unit awards that were accrued and credited to the directors in 2014.

 

133


 

H. Brent Austin and Alice M. Peterson joined the Board of Directors on February 2, 2015.  Directors who did not receive compensation are not included in the previous table. J. Michael Stice will begin receiving compensation in 2015.  

Compensation Committee Interlocks and Insider Participation

In 2014, Mesdames Robyn L. Ewing, Sarah C. Miller, and Suedeen Kelly (each of whom served as directors of our general partner until the Merger) and Messrs. Armstrong, Chappel, Cleary (who served as a director of our general partner until July 1, 2014), Daberko, Frederickson, and Woodburn (who served as a director of our general partner until July 1, 2014) served on the Compensation Committee of our general partner’s Board of Directors.  Ms. Ewing and Messrs. Armstrong and Chappel are executive officers of Williams and Mr. Armstrong is a director of Williams. Messrs. Armstrong and Chappel were appointed executive officers of our general partner on December 31, 2014, subsequent to the previously discussed dissolution of the Compensation Committee in December 2014. Each of these individuals is compensated by Williams and receive no compensation from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and Williams.

Relation of Compensation Policies and Practices to Risk Management

Our Pre-merger compensation arrangements contained a number of design elements that served to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. In combination with our risk-management practices, we do not believe that risks arising from our Pre-merger compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us. Please read “—Compensation Discussion and Analysis.” Beginning January 1, 2015, all of the officers of our general partner and employees who perform services on our behalf are employees of a subsidiary of Williams and, except to the limited extent that our Pre-merger compensation programs continue, are compensated directly by Williams.  Please read “Compensation Discussion and Analysis,” and “Certain Relationships and Related Transactions, and Director Independence” for more information about this arrangement. For an analysis of any risks arising from Williams’ compensation policies and practices, please read the proxy statement for Williams’ 2015 annual meeting of stockholders which will be available upon its filing on the SEC’s website at www.sec.gov and on Williams’ website at www.williams.com.

ITEM 12.

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

The following tables set forth the beneficial ownership of (i) our common units and other classes of equity and (ii) shares of Williams that, unless otherwise noted, as of February 13, 2015, are held by:

·

each member of our general partner’s Board of Directors;

·

each named executive officer of our general partner;

·

all directors and executive officers of our general partner as a group; and

·

each person or group of persons known by us to be a beneficial owner of 5% or more of the then outstanding common units.

The amounts and percentage of units or shares beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he or she has no economic interest. Except as indicated by footnote, the persons named in the tables below have sole voting and investment power with respect to all units or shares shown as beneficially owned by them, subject to community property laws where applicable.

134


 

Williams Partners Beneficial Ownership

Name of Beneficial Owner

 

Common Units

 

 

Percentage of 
Common Units
(1)

 

 

Class B Units

 

 

Percentage of
Class B Units

 

The Williams Companies, Inc.(2)

 

 

339,664,088

  

 

 

57.89

 

 

13,948,171

  

 

 

100

Alan S. Armstrong (3)

 

 

17,334

  

 

 

*

  

 

 

—  

  

 

 

—  

  

H. Brent Austin

 

 

8,958

  

 

 

*

  

 

 

—  

  

 

 

—  

  

Walter Bennett

 

 

8,770

 

 

 

*

  

 

 

—  

  

 

 

—  

  

Frank E. Billings

 

 

  

 

 

*

  

 

 

—  

  

 

 

—  

  

Donald R. Chappel

 

 

19,574

  

 

 

*

  

 

 

—  

  

 

 

—  

  

David A. Daberko

 

 

20,074

 

 

 

*

  

 

 

—  

  

 

 

—  

  

Philip L. Frederickson

 

 

23,577

  

 

 

*

  

 

 

—  

  

 

 

—  

  

Rory L. Miller

 

 

1,752

  

 

 

*

  

 

 

—  

  

 

 

—  

  

Alice M. Peterson

 

 

3,921

  

 

 

*

  

 

 

—  

  

 

 

—  

  

Robert S. Purgason

 

 

29,726

 

 

 

*

  

 

 

—  

  

 

 

—  

  

James E. Scheel

 

 

 

 

 

 

*

 

 

—  

 

 

 

—  

 

John D. Seldenrust

 

 

3,971

 

 

 

*

  

 

 

—  

  

 

 

—  

  

David C. Shiels

 

 

19,940

 

 

 

*

  

 

 

—  

  

 

 

—  

  

J. Michael Stice

 

 

143,664

 

 

 

*

  

 

 

—  

  

 

 

—  

  

All executive officers and directors of general partner as a group (19 persons)

 

     

285,125

  

 

 

*

  

 

 

—  

  

 

 

—  

  

 

*Less than 1%.

(1)

The percentage of beneficial ownership is based on 586,694,518 common units outstanding as of February 13, 2015.

(2)

This row includes ownership information of Williams Gas Pipeline Company, LLC, which is controlled by Williams and directly held 339,664,088 Common Units and 13,948,171 Class B Units as of February 13, 2015.

(3)

Includes 8,667 common units indirectly held by the Shelly Stone Armstrong Trust, dated June 16, 2010 and 8,667 common units indirectly held by the Alan Stuart Armstrong Trust, dated June 16, 2010.


135


 

Williams Beneficial Ownership

 

Name of Beneficial Owner

 

Shares
of Common
Stock
Owned
Directly or
Indirectly

 

 

 

Shares
Underlying
Stock
Options(1)

 

 

 

Shares
Underlying
Restricted Stock
Units(2)

 

 

 

Total

 

 

Percent
of Class(3)

 

Alan S. Armstrong

 

201,994

 

 

 

692,911

 

 

 

118,870

 

 

 

1,013,775

  

 

*

  

H. Brent Austin

 

 

 

 

—-

 

 

 

—-

 

 

 

—-

  

 

*

  

Walter Bennett

 

 

 

 

—-

 

 

 

—-

 

 

 

—-

  

 

*

 

Frank E. Billings

 

8,192

 

 

 

66,694

 

 

 

9,582

 

 

 

84,468

  

 

*

  

Donald R. Chappel

 

236,736

 

 

 

672,539

 

 

 

140,632

 

 

 

1,049,907

  

 

*

  

David A. Daberko

 

—-

 

 

 

—-

 

 

 

—-

 

 

 

—-

 

 

*

  

Philip L. Frederickson

 

—-

 

 

 

—-

 

 

 

—-

 

 

 

—-

 

 

*

  

Rory L. Miller

 

59,954

 

 

 

134,919

 

 

 

43,381

 

 

 

238,254

  

 

*

  

Alice M. Peterson

 

 

 

 

—-

 

 

 

—-

 

 

 

—-

  

 

*

  

Robert S. Purgason

 

 

 

 

—-

 

 

 

—-

 

 

 

—-

  

 

*

  

James E. Scheel

 

4,344

 

 

 

99,010

 

 

 

43,967

 

 

 

147,321

  

 

*

  

John D. Seldenrust

 

—-

 

 

 

—-

 

 

 

—-

 

 

 

—-

 

 

*

  

David C. Shiels

 

50

 

 

 

—-

 

 

 

—-

 

 

 

—-

  

 

*

  

J. Michael Stice

 

 

 

 

—-

 

 

 

—-

 

 

 

—-

  

 

*

  

All executive officers and directors of general partner as a group (19 persons)

  

 576,459

 

 

 

2,031,093

 

 

 

462,821

 

 

 

3,070,423

  

 

 

  

 

*

Less than 1%.

(1)

Amounts reflect Williams shares that may be acquired upon the exercise of stock options granted under Williams’ current or previous equity plans that are currently exercisable, will become exercisable, or would become exercisable upon the voluntary retirement of such person, within 60 days of February 13, 2015.

(2)

Amounts reflect Williams shares that would be acquired upon the vesting of restricted stock units granted under Williams current or previous equity plans that will vest or that would vest upon the voluntary retirement of such person, within 60 days of February 13, 2015. Restricted stock units have no voting or investment power.

(3)

Ownership percentage is reported based on 747,801,194 shares of Williams common stock outstanding on February 13, 2015, plus, as to the holder thereof only and no other person, the number of shares (if any) that the person has the right to acquire as of February 13, 2015, or within 60 days from that date, through the exercise of all options and other rights.

136


 

Securities authorized for issuance under equity compensation plans

The following table sets forth information with respect to the securities that may be issued under the LTIP as of December 31, 2014. For more information regarding the LTIP, which did not require approval by our unitholders, please see “Item 11. Executive Compensation—Long-Term Incentive Plan.”

 

Plan Category (3)

  

Number of Securities
to be Issued upon
Exercise of
Outstanding Options,
Warrants and Rights

 

  

Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights

 

  

Number of Securities
Remaining Available for  Future
Issuance Under Equity
Compensation Plans
(Excluding Securities Reflected
in Column(1))

 

Equity compensation plans approved by security holders

  

 

  

  

 

  

  

 

  

Equity compensation plans not approved by security holders(1)

  

 

1,306,460

(2)

  

 

N/A

  

  

 

1,160,205

 (2) 

 

(1)

The Board of Directors of our general partner adopted the LTIP in 2010.

(2)

Pursuant to the terms of the LTIP, our general partner’s Board of Directors was required, effective February 2, 2015, to adjust outstanding awards and the number of securities remaining available for issuance to reflect the Pre-merger Unit Split that occurred immediately prior to the Merger.  The units listed do not reflect the adjustment for the Pre-merger Unit Split.

(3)

Table does not include securities available for future issuance under the Pre-merger WPZ LTIP, which we assumed as a result of the Merger subsequent to December 31, 2014.  As of December 31, 2014, 686,597 Pre-merger WPZ securities were available for issuance under this plan.  The number of awards that may be issued under this plan in the future is subject to conversion to our securities by our general partner consistent with the ratio of the Merger Exchange.  No awards were outstanding under the Pre-merger WPZ LTIP as of December 31, 2014.

 

ITEM 13.

Certain Relationships and Related Transactions, and Director Independence

At February 13, 2015, an affiliate of our general partner owns 339,664,088 common units and 13,948,171 Class B units representing a combined 59 percent limited partner interest in us. Williams also owns 100 percent of our general partner, which allows it to control us. Certain officers and directors of our general partner also serve as officers and/or directors of Williams. Our general partner owns a 2.0 percent general partner interest and incentive distribution rights in us.

137


 

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made by us (Pre-Merger ACMP) to our general partner and its affiliates in connection with our ongoing operation and any liquidation of Williams Partners L.P. These distributions and payments were determined by and among affiliated entities.

Operational Stage

 

Distributions of available cash to our general partner and its affiliates

  

We generally make cash distributions 98.0 percent to our unitholders pro rata, including Williams as the holders of an aggregate 46.6 percent of common units and 2.0 percent to our general partner at December 31, 2014, assuming it makes any capital contributions necessary to maintain its 2.0 percent interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner is entitled to increasing percentages of the distributions, up to 50.0 percent of the distributions above the highest target distribution level.

 

If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.

 

Payments to our general partner and its affiliates

  

Our general partner does not receive a management fee or other compensation for the management of our partnership. We reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.

 

Beginning in 2015, our general partner will allocate expenses to us for the services performed on our behalf by our executive officers and directors, who are also employees of Williams. This allocated expense will include our allocable share of salaries, non-equity incentive plan compensation, and other employee-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams defined contribution plan and premiums for life insurance.

 

Williams affiliates charge us for costs associated with the employees that operate our assets. In addition, general and administrative services are provided to us by employees of Williams, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our operations. Williams charged us $15 million for the six months ended December 31, 2014.

 

Withdrawal or removal of our general partner

  

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

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Liquidation Stage

 

Liquidation

  

Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

 

Reimbursement of Expenses of Our General Partner

Our general partner does not receive any management fee or other compensation for its management of our business. On January 1, 2015, all persons who were employed by our general partner and providing services to Pre-merger ACMP became employees of another affiliate of Williams, including our executive officers and management directors who were not previously employees of Williams.  We will reimburse our general partner for expenses incurred on our behalf, including expenses incurred in compensating employees of an affiliate of Williams who perform services on our behalf. These expenses include all allocable expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no minimum or maximum amount that may be paid or reimbursed to our general partner for expenses incurred on our behalf.  These expenses will include our allocable share of salaries, non-equity incentive plan compensation, and other employment-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams defined contribution plan and premiums for life insurance.

Williams’ affiliates will charge us for the costs associated with the employees that operate our assets. In addition, general and administrative services are provided to us by employees of a subsidiary of Williams, and we will be charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our operations. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and will result in a reasonable allocation to us of the costs of doing business incurred by Williams. These services are provided to Transco and Northwest Pipeline pursuant to separate administrative service agreements with an affiliate of Williams.

Transactions Involving Chesapeake

In June 2012, Chesapeake sold all of its ownership interests in us and in our general partner; however, Mr. Dell’Osso, Executive Vice President and Chief Financial Officer of Chesapeake, remained on our Board of Directors through July 1, 2014.

Services Agreement

We were party to a services agreement with Chesapeake under which Chesapeake and its affiliates provided certain technology-related services and certain field communication support services through September 2014. For the year ended December 31, 2014, we paid Chesapeake and its affiliates approximately $1.1 million under the services agreement.

Gas Gathering Agreements

We are party to several gas gathering agreements with certain subsidiaries of Chesapeake under which we provide gathering and related services on our gathering systems in the Eagle Ford Shale region, Haynesville Shale region, Marcellus Shale region, Niobrara Shale region and Utica Shale region. For the year ended December 31, 2014, we received fees totaling $1.3 billion in the aggregate for providing services under these agreements.

Compression Agreements

We were party to four compression agreements with MidCon, a wholly owned indirect subsidiary of Chesapeake, pursuant to which MidCon agreed to provide compression equipment that we use to compress gas gathered on our gathering systems and provide certain related services. In return for MidCon’s provision of such equipment, we agreed to pay specified monthly rates per specified compression units, subject to an annual escalator to be applied on October 1st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1,

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2016.  These agreements were terminated on March 31, 2014 and for the three-months ending March 31, 2014, we paid MidCon fees totaling $63.4 million in the aggregate for providing compression equipment under these agreements.

Master Recoupment, Netting and Setoff Agreement

We are party to a master recoupment, netting and setoff agreement with Chesapeake and certain of its subsidiaries that provides for the netting of fees, liquidated damages and other charges between the parties to certain “covered agreements,” including our gas gathering agreements with Chesapeake with respect to the Eagle Ford, Haynesville, Niobrara, Marcellus and Utica Shale regions and our services agreement. The recoupment agreement provides for the parties’ right to recoup, net and setoff accrued and unpaid fees, reimbursements, late payment charges and interest, and liquidated damages for breach or early termination pursuant to specified obligations arising under the terms of the covered agreements and losses, damages and other amounts to the extent agreed by the parties or provided by a court order. Recoupment, netting and setoff rights are triggered by a “recoupment event,” defined as the failure to pay an accrued payment obligation or obligations exceeding $100,000 under a covered agreement. Under the agreement, if a “triggering event,” defined as bankruptcy or insolvency, occurs, the non-bankrupt/insolvent party has the right to hold funds due from it to the bankrupt/insolvent party as an offset to liquidated amounts due from the bankrupt/insolvent party to the non-bankrupt/insolvent party, pending resolution of the parties’ rights under the recoupment agreement or common law. This agreement will terminate in the event there are fewer than two “covered agreements” in effect, or earlier upon written agreement of the parties.

Transactions Involving Williams

Merger Agreement

See Note 1 – Description of Business and Basis of Presentation of our Notes to Consolidated Financial Statements for a discussion of the Merger with Williams Partners L.P.

Our general partner charged us $175 thousand for the costs associated with Williams equity-based compensation programs for certain employees from the grant date of October 25, 2014 through December 31, 2014.

Commodity Purchase Contracts

Pre-merger WPZ purchases olefins and NGLs for resale from Williams Energy Canada ULC, a subsidiary of Williams, at market prices at the time of purchase.

Operating Agreements with Equity-Method Investees

Pre-merger WPZ and Pre-Merger ACMP are parties to operating agreements with unconsolidated companies where the investment is accounted for using the equity method. These operating agreements typically provide for reimbursement or payment to the partnership for certain direct operational payroll and employee benefit costs, materials, supplies and other charges and also for management services. Williams supplies a portion of these services, primarily those related to employees since the partnership does not have any employees, to the equity method investees. Amounts are billed to the equity- method investments the partnership operates.

Summary of Other Transactions with Williams and its Affiliates

Initial Omnibus Agreement

Upon the closing of Pre-merger WPZ’s initial public offering (“IPO”) in 2005, Pre-merger WPZ entered into an omnibus agreement with Williams and its affiliates that was not the result of arm’s-length negotiations. The omnibus agreement continues to govern our relationship with Williams regarding the following matters in connection with our IPO: 

Indemnification for certain environmental liabilities and tax liabilities;

Reimbursement for certain expenditures; and

A license for the use of certain software and intellectual property.

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February 2010 Omnibus Agreement

In connection with Williams’ contribution of ownership interests in certain entities to Pre-merger WPZ in February 2010, Pre-merger WPZ entered into an omnibus agreement with Williams. Pursuant to this omnibus agreement, Williams remains obligated to indemnify Pre-merger WPZ for an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform located in Mississippi Canyon Block 773. In 2010, we also entered into a contribution agreement with Williams in connection with this transaction.  The contribution agreement continues to govern our relationship with Williams with respect to indemnification for certain tax liabilities.

Ancillary Agreements with Affiliates of Williams

These agreements provide for:

Certain rights to access and use the acquired facilities by Williams affiliates so Williams may continue to develop additional projects;

Development of future projects by the parties;

Employees of Williams to operate the acquired assets and the allocation of costs related to the operation of those assets.

Intellectual Property License

Williams and its affiliates granted a license to us for the use of certain marks, including our logo, for as long as Williams controls our general partner, at no charge.

Review, Approval or Ratification of Transactions with Related Persons

Our partnership agreement contains specific provisions that address potential conflicts of interest between our general partner and its affiliates, including Williams, on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee of the Board of Directors of our general partner, which is comprised of independent directors. The partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is: 

Approved by the Conflicts Committee;

 

Approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

 

On terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

Fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner does not seek approval from the Conflicts Committee and the Board of Directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership. See “Directors, Executive Officers and Corporate Governance — Governance — Board Committees — Conflicts Committee.”

In addition, our Code of Business Conduct and Ethics requires that all employees, including employees of affiliates of Williams who perform services for us and our general partner, avoid or disclose any activity that may interfere, or have the appearance of interfering, with their responsibilities to us and our unitholders. Conflicts of interest that cannot be

141


 

avoided must be disclosed to a supervisor who is then responsible for establishing and monitoring procedures to ensure that we are not disadvantaged.

Director Independence

Please read “Directors, Executive Officers and Corporate Governance — Governance — Director Independence” and “ — Board Committees” in Item 10 above for information about the independence of our general partner’s Board of Directors and its committees, which information is incorporated into this Item 13 by reference.

 

ITEM 14.

Principal Accountant Fees and Services

We have engaged Ernst & Young LLP (and previously PricewaterhouseCoopers LLP) as our independent registered public accounting firm. The following table summarizes the fees we have paid to both firms to audit the Partnership’s annual consolidated financial statements and for other services for each of the last two fiscal years:

 

 

2014

 

  

2013

 

 

(in thousands)

 

  

(in thousands)

 

Audit fees

$

2,553

  

  

$

1,309

  

Audit-related fees

 

  

  

 

  

Tax

 

645

  

  

 

397

  

Total

$

3,198

  

  

$

1,706

  

Audit fees are primarily for audit of the Partnership’s consolidated financial statements, reviews of the Partnership’s financial statements included in the Form 10-Qs, comfort letters and other filings.

Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice and tax planning. This category includes services relating to the preparation of unitholder annual K-1 statements.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of the Partnership’s general partner has adopted a Pre-Approval Policy with respect to services which may be performed by Ernst & Young LLP and PricewaterhouseCoopers LLP. This policy lists specific audit-related services as well as any other services that Ernst & Young LLP and PricewaterhouseCoopers LLP are authorized to perform and set out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairman, to whom such authority has been conditionally delegated, prior to engagement. During 2014, no fees for services outside the scope of audit, review, or attestation that exceed the waiver provisions of 17 CFR 210.2-01(c)(7)(i)(C) were approved by the Audit Committee.

The Audit Committee has approved the appointment of Ernst & Young LLP as independent registered public accounting firm to conduct the audit of the Partnership’s consolidated financial statements for the year ended December 31, 2014.  PricewaterhouseCoopers LLP was appointed during the first three quarters of 2014 and for the year ended December 31, 2013.

 

 

 

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PART IV

 

ITEM  15.

Exhibits and Financial Statement Schedules

(a)

The following documents are filed as part of this report:

1.

Financial Statements. Reference is made to the accompanying Index to Financial Statements.

2.

Financial Statement Schedules. Quarterly financial data (unaudited) is included in Item 8 of this report with our consolidated financial statements. No other financial statement schedules are applicable or required.

3.

Exhibits. The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K:

 

 

Exhibit No.

 

Description

2.1§

--

Agreement and Plan of Merger dated as of October 24, 2014, by and among Williams Partners L.P., Access Midstream Partners, L.P., Access Midstream Partners GP, L.L.C., Williams Partners GP LLC, and VHMS LLC (filed on October 27, 2014 as Exhibit 2.1 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.1

--

Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on February 16, 2010 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905 and incorporated herein by reference).

 

3.2

--

Amendment to Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on July 30, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.3

--

Amendment to Certificate of Limited Partnership of Access Midstream Partners, L.P. (filed on February 3, 2015 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.4*

--

Composite Certificate of Limited Partnership of Williams Partners L.P.

 

3.5

--

First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P., dated August 3, 2010 (filed on August 5, 2010 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.6

--

Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated as of December 20, 2012 (filed on July 20, 2012 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.7

--

Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of December 20, 2012 (filed on December 20, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.8

--

Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.9

--

Amendment No. 4 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.10*

--

Composite Agreement of Limited Partnership of Williams Partners L.P.

 

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Exhibit No.

 

Description

3.11

--

Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on February 16, 2010 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).

 

3.12

--

Certificate of Amendment to Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on July 20, 2012 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.13

--

Certificate of Amendment to Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 2, 2015 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.14*

--

Composite Certificate of Formation of WPZ GP LLC.

 

3.15

--

Seventh Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on February 2, 2015 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.1

--

Indenture, dated as of April 19, 2011, by and among the Partnership, Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 5, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference.

 

4.2

--

First Supplemental Indenture, dated as of January 4, 2012 among Chesapeake Midstream Partners, L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.3

--

First Supplemental Indenture, dated as of January 7, 2013, by and among the Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 19, 2013 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.4

--

Third Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of April 18, 2014 (filed on May 1, 2014 as Exhibit 4.5 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.5

--

Fourth Supplemental Indenture dated February 2, 2015, by and among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 3, 2015, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.6

--

Indenture, dated as of January 11, 2012, by and among the Chesapeake Midstream Partners, L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 11, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.7

--

First Supplemental Indenture, dated as of January 7, 2013, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.5 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 

144


 

Exhibit No.

 

Description

4.8

--

Second Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of April 18, 2014 among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee filed on May 1, 2014 as Exhibit 4.4 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.9

--

Third Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.10

--

Indenture, dated as of December 19, 2012, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.11

--

First Supplemental Indenture, dated as of December 19, 2012, among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.12

--

Second Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of January 7, 2013, by among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.9 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 

4.13

--

Third Supplemental Indenture, dated as of March 7, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 7, 2014 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.14

--

Third Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of April 18, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.3 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.15

--

Fifth Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.16

--

Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).

 

4.17

--

Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).

 

4.18

--

Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

145


 

Exhibit No.

 

Description

4.19

--

First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.2 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.20

--

Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2011 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.21

--

Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.22

--

Fourth Supplemental Indenture, dated as of November 15, 2013, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.23

--

Fifth Supplemental Indenture, dated as of March 4, 2014, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 4, 2014 as Exhibit 4.1 Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.24

--

Sixth Supplemental Indenture, dated as of June 27, 2014, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 27, 2014 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.25

--

Seventh Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.26

--

Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.27

--

First Supplemental Indenture, dated as of February 2, 2015, among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.6 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.28

--

Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.29

--

First Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.30

--

Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee (filed on September 14, 1995 as Exhibit 4.1 to Northwest Pipeline GP’s registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).

 

146


 

Exhibit No.

 

Description

4.31

--

Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File. No. 001-07414), and incorporated herein by reference).

 

4.32

--

Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).

 

4.33

--

Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K File No. 001-07414) and incorporated herein by reference).

 

4.34

--

Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein by reference).

 

4.35

--

Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

4.36

--

Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

4.37

--

Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

4.38

--

Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

10.1#

--

Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

10.2#

--

Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

10.3#

--

Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Pre-merger WPZ’s annual report on Form 10-K (File No. 001-32599) and incorporated herein by reference).

 

10.4#

--

Chesapeake Midstream Long-Term Incentive Plan (filed on July 20, 2010 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).

 

10.5#

--

First Amendment to Access Midstream Long-Term Incentive Plan, dated effective as of July 1, 2014 (filed on July 2, 2014 as Exhibit 10.01 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

147


 

Exhibit No.

 

Description

10.6#*

--

Second Amendment to Williams Partners L.P. Long-Term Incentive Plan, dated effective as of February 2, 2015.

 

10.7#

--

Access Midstream Partners GP, L.L.C. Employee Severance Program, effective as of January 1, 2013 (filed on December 27, 2012 as Exhibit 10.8 to Williams Partners L.P.’s current report on Form 8-K dated December 27, 2012 (file No. 001-34831) and incorporated herein by reference).

 

10.8#

--

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and Robert S. Purgason (filed on December 27, 2012 as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.9

--

Amended and Restated Services Agreement, dated August 3, 2013, by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating Inc., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Partners, L.P., and Chesapeake MLP Operating, L.L.C. (filed on August 5, 2010 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

 

 

10.10†

--

Compression Services Agreement, dated February 26, 2014 between EXLP Operating LLC and Access MLP Operating, L.L.C. (filed on April 30, 2014 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).  

 

 

 

10.11#*

--

Amendment to Employment Agreement, effective as of October 17, 2014 between Access Midstream Partners GP, L.L.C. and Robert S. Purgason.

 

10.12#*

--

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and John D. Seldenrust.

 

10.13#*

--

First Amendment to Employment Agreement, dated August 1, 2013, between Access Midstream Partners GP, L.L.C. and John D. Seldenrust.

 

 

 

10.14#*

--

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and Walter J. Bennett.

 

10.15#

--

Form of Restricted Phantom Unit Award Agreement (filed on July 7, 2014 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.16#*

--

WPZ GP LLC Director Compensation Policy adopted December 11, 2014.

 

10.17

 

--

Second Amended and Restated Credit Agreement, dated as of May 13, 2013, by and among Access MLP Operating, L.L.C., as the borrower, Access Midstream Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and the Issuing Lender, and the other lenders party thereto (filed on May 14, 2013 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.18

--

First Amended & Restated Credit Agreement dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Pre-merger WPZ’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).

 

10.19

--

Amendment No. 1 and Consent to First Amended & Restated Credit Agreement, dated as of December 1, 2014, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent. (filed on December 4, 2014 as exhibit 10.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

148


 

Exhibit No.

 

Description

10.20

--

Form of Commercial Paper Dealer Agreement, dated as of March 12, 2013, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on March 18, 2013 as Exhibit 10.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

10.21

--

Form of Amended and Restated Commercial Paper Dealer Agreement, dated as of February 2, 2015, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on February 3, 2015 as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.22

--

Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.23

--

Credit Agreement dated as of February 3, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on February 3, 2015 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

12*

--

Computation of Ratio of Earnings to Fixed Charges.

 

21*

--

List of subsidiaries of Williams Partners L.P.

 

23.1*

--

Consent of Ernst & Young LLP.

 

23.2*

--

Consent of PricewaterhouseCoopers, LLP.

 

24*

--

Power of attorney.

 

31.1*

--

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

 

31.2*

--

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

 

32**

--

Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.

 

101.INS*

--

XBRL Instance Document.

 

101.SCH*

--

XBRL Taxonomy Extension Schema.

 

101.CAL*

--

XBRL Taxonomy Extension Calculation Linkbase.

 

101.DEF*

--

XBRL Taxonomy Extension Definition Linkbase.

 

101.LAB*

--

XBRL Taxonomy Extension Label Linkbase.

 

101.PRE*

--

XBRL Taxonomy Extension Presentation Linkbase.

____________________________

*Filed herewith.

** Furnished herewith.

§

Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

#Management contract or compensatory plan or arrangement.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment.  Such portions have been filed separately with the Securities and Exchange Commission.

 

 

 

149


 

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

 

 

Williams Partners L.P.

By: WPZ GP LLC, its general partner

Date: February 25, 2015

 

By

 

 

/S/ Ted T. Timmermans

 

 

 

 

Ted T. Timmermans

Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer)

 

 

 

150


 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature

 

Title

 

Date

 

/s/  Alan S. Armstrong

 

Chief Executive Officer and Chairman of the Board

(Principal Executive Officer)

 

February 25, 2015

Alan S. Armstrong

 

 

 

/s/  Donald R. Chappel

 

Chief Financial Officer and Director

(Principal Financial Officer)

 

February 25, 2015

Donald R. Chappel

 

 

 

/s/  Ted T. Timmermans

 

Vice President, Controller, and Chief Accounting Officer

 

February 25, 2015

Ted T. Timmermans

 

 (Principal Accounting Officer)

 

 

 

/s/  Brent Austin*

 

Director

 

February 25, 2015

Brent Austin

 

 

 

 

 

/s/   Francis E. Billings*

 

Director

 

February 25, 2015

Francis E. Billings

 

 

 

 

 

/s/   David A. Dabarko*

 

Director

 

February 25, 2015

David A. Dabarko

 

 

 

 

 

/s/ Phillip L. Fredrickson*

 

Director

 

February 25, 2015

Phillip L. Fredrickson

 

 

 

 

 

/s/  Rory L. Miller*

 

Director

 

February 25, 2015

Rory L. Miller

 

 

 

 

 

/s/ Alice M. Peterson*

 

Director

 

February 25, 2015

Alice M. Peterson

 

 

 

 

 

/s/  Robert S. Purgason*

 

Director

 

February 25, 2015

Robert S. Purgason

 

 

 

 

 

/s/   James E. Scheel*

 

Director

 

February 25, 2015

James E. Scheel

 

 

 

 

 

/s/   J. Mike Stice*

 

Director

 

February 25, 2015

J. Mike Stice

 

 

 

 

 

*By:

/s/ William H. Gault                                                                 February 25, 2015

 

William H. Gault

 

Attorney-in-Fact

 

 

 

 


 

 

 

EXHIBIT INDEX

 

 

 

Exhibit No.

 

Description

2.1§

--

Agreement and Plan of Merger dated as of October 24, 2014, by and among Williams Partners L.P., Access Midstream Partners, L.P., Access Midstream Partners GP, L.L.C., Williams Partners GP LLC, and VHMS LLC (filed on October 27, 2014 as Exhibit 2.1 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.1

--

Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on February 16, 2010 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905 and incorporated herein by reference).

 

3.2

--

Amendment to Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P. (filed on July 30, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.3

--

Amendment to Certificate of Limited Partnership of Access Midstream Partners, L.P. (filed on February 3, 2015 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.4*

--

Composite Certificate of Limited Partnership of Williams Partners L.P.

 

3.5

--

First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P., dated August 3, 2010 (filed on August 5, 2010 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.6

--

Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated as of December 20, 2012 (filed on July 20, 2012 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.7

--

Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of December 20, 2012 (filed on December 20, 2012 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.8

--

Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.9

--

Amendment No. 4 to the First Amended and Restated Agreement of Limited Partnership of Access Midstream Partners, L.P. dated as of January 29, 2015 (filed on February 3, 2015 as Exhibit 3.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.10*

--

Composite Agreement of Limited Partnership of Williams Partners L.P.

 

3.11

--

Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on February 16, 2010 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).

 

3.12

--

Certificate of Amendment to Certificate of Formation of Chesapeake Midstream GP, L.L.C. (filed on July 20, 2012 as Exhibit 3.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

3.13

--

Certificate of Amendment to Certificate of Formation of Access Midstream Partners GP, L.L.C. (filed on February 2, 2015 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

 


 

 

 

EXHIBIT INDEX

 

 

 

Exhibit No.

 

Description

3.14*

--

Composite Certificate of Formation of WPZ GP LLC.

 

3.15

--

Seventh Amended and Restated Limited Liability Company Agreement of WPZ GP LLC (filed on February 2, 2015 as Exhibit 3.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.1

--

Indenture, dated as of April 19, 2011, by and among the Partnership, Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 5, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference.

 

4.2

--

First Supplemental Indenture, dated as of January 4, 2012 among Chesapeake Midstream Partners, L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.3

--

First Supplemental Indenture, dated as of January 7, 2013, by and among the Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 19, 2013 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.4

--

Third Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of April 18, 2014 (filed on May 1, 2014 as Exhibit 4.5 to Williams Partners L.P.’s (formerly known as Access Midstream Partners L.P.) quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.5

--

Fourth Supplemental Indenture dated February 2, 2015, by and among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 3, 2015, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.6

--

Indenture, dated as of January 11, 2012, by and among the Chesapeake Midstream Partners, L.P., CHKM Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 11, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.7

--

First Supplemental Indenture, dated as of January 7, 2013, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.5 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 

4.8

--

Second Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of April 18, 2014 among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee filed on May 1, 2014 as Exhibit 4.4 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.9

--

Third Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.10

--

Indenture, dated as of December 19, 2012, by and among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

 


 

 

 

EXHIBIT INDEX

 

 

 

Exhibit No.

 

Description

4.11

--

First Supplemental Indenture, dated as of December 19, 2012, among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on December 19, 2012 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.12

--

Second Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of January 7, 2013, by among Access Midstream Partners, L.P., ACMP Finance Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on February 21, 2014 as Exhibit 4.9 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-34831) and incorporated herein by reference).

 

4.13

--

Third Supplemental Indenture, dated as of March 7, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 7, 2014 as Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.14

--

Third Supplemental Indenture and Amendment – Subsidiary Guarantee, dated as of April 18, 2014, among the Access Midstream Partners, L.P., ACMP Finance Corp, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 1, 2014 as Exhibit 4.3 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).

 

4.15

--

Fifth Supplemental Indenture among Williams Partners L.P., ACMP Finance Corp. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.16

--

Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).

 

4.17

--

Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Pre-merger WPZ’s registration statement on Form S-3 (File No. 333-137562) and incorporated herein by reference).

 

4.18

--

Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.19

--

First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.2 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.20

--

Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2011 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.21

--

Third Supplemental Indenture (including Form of 3.35% Senior Notes due 2022), dated as of August 14, 2012, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 14, 2012 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.22

--

Fourth Supplemental Indenture, dated as of November 15, 2013, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2013 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

 


 

 

 

EXHIBIT INDEX

 

 

 

Exhibit No.

 

Description

4.23

--

Fifth Supplemental Indenture, dated as of March 4, 2014, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 4, 2014 as Exhibit 4.1 Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.24

--

Sixth Supplemental Indenture, dated as of June 27, 2014, between Pre-merger WPZ and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 27, 2014 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.25

--

Seventh Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.26

--

Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.27

--

First Supplemental Indenture, dated as of February 2, 2015, among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.6 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.28

--

Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

4.29

--

First Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015 as Exhibit 4.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

4.30

--

Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee (filed on September 14, 1995 as Exhibit 4.1 to Northwest Pipeline GP’s registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).

 

4.31

--

Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File. No. 001-07414), and incorporated herein by reference).

 

4.32

--

Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).

 

4.33

--

Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s current report on Form 8-K File No. 001-07414) and incorporated herein by reference).

 

4.34

--

Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein by reference).

 

4.35

--

Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

 


 

 

 

EXHIBIT INDEX

 

 

 

Exhibit No.

 

Description

4.36

--

Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

4.37

--

Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

4.38

--

Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).

 

10.1#

--

Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

10.2#

--

Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

10.3#

--

Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Pre-merger WPZ’s annual report on Form 10-K (File No. 001-32599) and incorporated herein by reference).

 

10.4#

--

Chesapeake Midstream Long-Term Incentive Plan (filed on July 20, 2010 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-164905) and incorporated herein by reference).

 

10.5#

--

First Amendment to Access Midstream Long-Term Incentive Plan, dated effective as of July 1, 2014 (filed on July 2, 2014 as Exhibit 10.01 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.6#*

--

Second Amendment to Williams Partners L.P. Long-Term Incentive Plan, dated effective as of February 2, 2015.

 

10.7#

--

Access Midstream Partners GP, L.L.C. Employee Severance Program, effective as of January 1, 2013 (filed on December 27, 2012 as Exhibit 10.8 to Williams Partners L.P.’s current report on Form 8-K dated December 27, 2012 (file No. 001-34831) and incorporated herein by reference).

 

10.8#

--

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and Robert S. Purgason (filed on December 27, 2012 as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.9

--

Amended and Restated Services Agreement, dated August 3, 2013, by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating Inc., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Partners, L.P., and Chesapeake MLP Operating, L.L.C. (filed on August 5, 2010 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

 

 

10.10†

--

Compression Services Agreement, dated February 26, 2014 between EXLP Operating LLC and Access MLP Operating, L.L.C. (filed on April 30, 2014 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).  

 

 

 

10.11#*

--

Amendment to Employment Agreement, effective as of October 17, 2014 between Access Midstream Partners GP, L.L.C. and Robert S. Purgason.

 

 


 

 

 

EXHIBIT INDEX

 

 

 

Exhibit No.

 

Description

10.12#*

--

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and John D. Seldenrust.

 

10.13#*

--

First Amendment to Employment Agreement, dated August 1, 2013, between Access Midstream Partners GP, L.L.C. and John D. Seldenrust.

 

 

 

10.14#*

--

Employment Agreement, effective as of January 1, 2013, between Access Midstream Partners GP, L.L.C. and Walter J. Bennett.

 

10.15#

--

Form of Restricted Phantom Unit Award Agreement (filed on July 7, 2014 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.16#*

--

WPZ GP LLC Director Compensation Policy adopted December 11, 2014.

 

10.17

 

--

Second Amended and Restated Credit Agreement, dated as of May 13, 2013, by and among Access MLP Operating, L.L.C., as the borrower, Access Midstream Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and the Issuing Lender, and the other lenders party thereto (filed on May 14, 2013 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.18

--

First Amended & Restated Credit Agreement dated as of July 31, 2013, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on July 31, 2013 as Exhibit 10 to Pre-merger WPZ’s quarterly report on Form 10-Q (File No. 001-32599) and incorporated herein by reference).

 

10.19

--

Amendment No. 1 and Consent to First Amended & Restated Credit Agreement, dated as of December 1, 2014, by and among Williams Partners L.P., Northwest Pipeline LLC and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A., as Administrative Agent. (filed on December 4, 2014 as exhibit 10.1 to Pre-merger WPZ’s report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

10.20

--

Form of Commercial Paper Dealer Agreement, dated as of March 12, 2013, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on March 18, 2013 as Exhibit 10.1 to Pre-merger WPZ’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

 

10.21

--

Form of Amended and Restated Commercial Paper Dealer Agreement, dated as of February 2, 2015, between Williams Partners L.P., as Issuer, and the Dealer party thereto (filed on February 3, 2015 as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.22

--

Second Amended and Restated Credit Agreement dated as of February 2, 2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipeline Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative Agent (filed on February 3, 2015 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

10.23

--

Credit Agreement dated as of February 3, 2015, between Williams Partners L.P., the lenders named therein, and Barclays Bank PLC as Administrative Agent (filed on February 3, 2015 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).

 

12*

--

Computation of Ratio of Earnings to Fixed Charges.

 

21*

--

List of subsidiaries of Williams Partners L.P.

 

 


 

 

 

EXHIBIT INDEX

 

 

 

Exhibit No.

 

Description

23.1*

--

Consent of Ernst & Young LLP.

 

23.2*

--

Consent of PricewaterhouseCoopers, LLP.

 

24*

--

Power of attorney.

 

31.1*

--

Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

 

31.2*

--

Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

 

32**

--

Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.

 

101.INS*

--

XBRL Instance Document.

 

101.SCH*

--

XBRL Taxonomy Extension Schema.

 

101.CAL*

--

XBRL Taxonomy Extension Calculation Linkbase.

 

101.DEF*

--

XBRL Taxonomy Extension Definition Linkbase.

 

101.LAB*

--

XBRL Taxonomy Extension Label Linkbase.

 

101.PRE*

--

XBRL Taxonomy Extension Presentation Linkbase.

 

____________________________

*Filed herewith.

** Furnished herewith.

§

Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

#Management contract or compensatory plan or arrangement.

Portions of this exhibit have been omitted pursuant to a request for confidential treatment.  Such portions have been filed separately with the Securities and Exchange Commission.