2017 Annual Report
The Williams Companies, Inc.
We make energy happen.®
Financial Highlights
Dollars in millions, except per-share amounts
2017
2016
2015
2014
2013
Revenues1
$8,031
$7,499
$7,360
$7,637
$6,860
Income (loss) from continuing operations 2
2,509
(350)
(1,314)
2,335
679
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations2
2,174
(424)
(571)
2,110
441
Diluted earnings (loss) per common share:
Income (loss) from continuing operations2
2.62
(0.57)
(0.76)
2.91
0.64
Total assets at December 313
46,352
46,835
49,020
50,455
27,065
Commercial paper and long-term debt
due within one year at December 314
501
878
675
802
226
Long-term debt at December 313
20,434
22,624
23,812
20,780
11,276
Stockholders’ equity at December 313 5
Cash dividends declared per common share
9,656
1.200
4,643
1.680
6,148
2.450
8,777
1.958
4,864
1.438
1 Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian construction
management services.
2 Income (loss) from continuing operations:
•
For 2017 includes a $1.923 billion benefit for income taxes resulting from Tax Reform rate change, a $1.095 billion pre-tax gain on the sale
of our Geismar Interest, partially offset by $1.248 billion of pre-tax impairments of certain assets, and $776 million of pre-tax regulatory
charges resulting from Tax Reform;
•
For 2016 includes an $873 million impairment of certain assets and a $430 million impairment of certain equity-method investments;
• For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment of goodwill;
• For 2014 includes $2.5 billion pre-tax gain recognized as a result of remeasuring to fair value the equity-method investment we held before
we acquired a controlling interest in ACMP, $246 million of insurance recoveries related to the 2013 Geismar Incident, and $154 million
of cash received related to a contingency settlement. 2014 also includes $78 million of pre-tax equity losses from Bluegrass Pipeline and
Moss Lake related primarily to the underlying write-off of previously capitalized project development costs and $76 million of pre-tax
acquisition, merger, and transition expenses related to our acquisition of ACMP;
•
For 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign operations that are no
longer considered permanently reinvested.
3 The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMP in third quarter as well as
$1.9 billion of related debt issuances and $2.8 billion of debt issuances at WPZ. Additionally, we issued $3.4 billion of equity.
4 The increase in 2014 reflects borrowings under WPZ’s commercial paper program, which was initiated in 2013.
5 The increase in 2017 includes our issuance of common stock as part of our Financial Repositioning.
Front Cover: The 2017 “Big 5” expansion projects (clockwise from top: Virginia Southside II,
New York Bay, Dalton, Hillabee and Gulf Trace) increased the Transco pipeline’s design capacity
by nearly 25 percent.
Back Cover: Construction on Williams’ Atlantic Sunrise project in Pennsylvania — one of the largest
pipeline projects in the company’s history.
Forward-Looking Statements: Any statements included in this 2017 Annual Report that are not
historical facts, including, without limitation, statements regarding future market trends and results
of operations are forward-looking statements within the meaning of applicable securities law. Such
statements are subject to numerous risks and uncertainties beyond our control and our actual
results may differ materially from our forward-looking statements. Additional information concerning
factors that may influence our results can be found in the Form 10-K under the heading “Part I, Item
1A. Risk Factors.”
Table of Contents
1 Shareholder Letter
3 Directors and Officers
5 Form 10-K
“Our focus on safety, reliability, transparency and
consistency will continue in 2018 as the work done in
2017 truly sets the stage for another successful year.”
President and Chief Executive Officer
Alan S. Armstrong
Dear Fellow Stockholders,
I’d like to say how pleased I am with
the organization’s strong execution
in 2017. Our teams worked extremely
hard to keep our promises to our
stakeholders, including you, our
valued shareholders. I am proud of
our employees for their successful
efforts that resulted in the timely and
safe delivery of our projects, including
Transco’s ‘Big 5’ projects (Gulf Trace,
Hillabee Phase 1, Dalton, New York
Bay and Virginia Southside II) that
were all placed into service in 2017.
Combined, these five projects add
more than 2.8 billion cubic feet per
day (Bcf/d) of firm transportation
capacity to the Transco pipeline
system, contributing to the increase
of Transco’s design capacity by
approximately 25 percent. In 2018,
we look forward to a full year of
revenue from the ‘Big 5’ as well
as contributions from our Atlantic
Sunrise project later this year and
the associated growth in Northeast
gathering volumes. We also expect
in 2018 to have twice as much fully-
contracted capacity on Transco as
we did in 2010, making Transco both
the largest and fastest growing major
natural gas pipeline in the U.S.
Our successful execution in 2017
is reflected in our financial results
where we exceeded the midpoint
of our guidance range for all key
performance metrics. I would also
note that our full-year 2017 results
reflect growth in year-over-year
operating income. And that’s despite
$3 billion in asset sales and the
impact of multiple hurricanes. The
asset-sales effort exceeded the
market’s expectation and dramatically
reduced our commodity exposure.
And speaking of the market,
Williams’ stock price performance
out-performed all of its domestic
C-Corp peers for the full-year 2017.
In 2017, Williams benefited from the
addition of seven very experienced
directors that were added in the last
half of 2016. The Board’s decisive
leadership and focus on positioning
the company to deliver long-term
sustainable shareholder value and
growth were on display throughout
2017. Williams was a leader in
our sector in the demonstration of
financial discipline. Williams carried
out our financial repositioning in
January of 2017 in a way that enabled
the company to fund an attractive
slate of large-scale expansion
projects, strengthened distribution
coverage, enhanced our credit profile,
improved our cost of capital and
underpinned our growth outlook. As a
result of a full year of executing on the
key aspects of our plan, we reduced
Williams consolidated debt by $2.5
billion. The quarterly dividend paid
in March 2018 represented a 13.33
percent increase over the quarterly
dividend paid in March 2017.
Our 2017 results also reflect the
exceptional leadership and expertise
that we have added to our Executive
Officer Team. Chief Financial Officer,
John Chandler has a proven track
record of financial leadership and
delivering shareholder value. I
appreciate the theme our Investor
Relations team has introduced
for 2018 under John’s leadership:
“Strong, Stable, Conservative and
Growing.” Chief Operating Officer,
Micheal Dunn is helping us better
optimize operations and advance the
execution of our major projects all
with a primary focus on safe, reliable
service for our customers. We also
brought on a new General Counsel,
T. Lane Wilson, whose experience in
the federal courts has been invaluable
as we have steered through the
labyrinth of federal court proceedings
related to groups who oppose
the installation of critical natural
gas infrastructure.
Finally, we brought on a new head
of Corporate Strategic Development,
Chad Zamarin, who has brought the
energy and determination needed
to drive our teams through complex
project and business development
matters as we execute on a very
robust and focused strategy.
2017 Annual Report
The Williams Companies, Inc.
1
This new team has come together to
energize this great organization as
we collectively take on the challenges
of building out the nation’s critical
natural gas infrastructure. I consider it
a great honor to be able to work with
these outstanding leaders.
Our focus on safety, reliability,
execution and efficiency will continue
in 2018 as the work done in 2017 truly
sets the stage for another successful
year. Since the first of the year, we set
one- and three-day delivery records
on Transco, started construction
on the Gulf Connector’s 0.5 Bcf/d
Gulf Coast LNG delivery expansion,
reached several key milestones
on the 1.7 Bcf/d Atlantic Sunrise
project, and placed additional major
gathering expansions into service in
both Susquehanna, Pennsylvania and
Wamsutter, Wyoming.
On behalf of the Board of Directors
and our employees across the United
States, thank you for your continued
trust in Williams.
Sincerely,
Alan S. Armstrong
President and Chief Executive Officer
April 11, 2018
2
The Williams Companies, Inc.
2017 Annual Report
BOARD COMMITTEES
Audit Committee
Stephen I. Chazen
Kathleen B. Cooper
Michael A. Creel
Peter A. Ragauss (Chair)
William H. Spence
Compensation & Management
Development Committee
Stephen W. Bergstrom
Charles I. Cogut
Scott D. Sheffield
Murray D. Smith
Janice D. Stoney (Chair)
Nominating & Governance
Committee
Stephen W. Bergstrom
Stephen I. Chazen
Charles I. Cogut
Kathleen B. Cooper (Chair)
Peter A. Ragauss
Environmental, Health
& Safety Committee
Michael A. Creel
Scott D. Sheffield
Murray D. Smith (Chair)
William H. Spence
Janice D. Stoney
D I R E C T O R S A N D O F F I C E R S
DIRECTORS
HONORARY DIRECTOR
JOSEPH H. WILLIAMS
Charleston, South Carolina
Chairman and Chief Executive
Officer for Williams from 1979 -94.
Elected to the board in 1969.
SENIOR OFFICERS
ALAN S. ARMSTRONG
President and Chief
Executive Officer
MICHEAL G. DUNN
Executive Vice President
and Chief Operating Officer
WALTER J. BENNETT
Senior Vice President,
West
JOHN D. CHANDLER
Senior Vice President and
Chief Financial Officer
FRANK J. FERAZZI
Senior Vice President,
Atlantic - Gulf
JOHN E. POARCH
Senior Vice President,
Engineering Services
JAMES E. SCHEEL
Senior Vice President,
Northeast Gathering & Processing
T. LANE WILSON
Senior Vice President
and General Counsel
CHAD J. ZAMARIN
Senior Vice President,
Corporate Strategic Development
ALAN S. ARMSTRONG
Tulsa, Oklahoma
President and Chief
Executive Officer, Williams.
Director since 2011.
STEPHEN W. BERGSTROM
Houston, Texas
Former President and
Chief Executive Officer,
American Midstream Partners GP, LLC.
Chairman; Director since 2016.
STEPHEN I. CHAZEN
Houston, Texas
President, Chief Executive
Officer and Chairman,
TPG Pace Energy Holdings Corp.
Director since 2016.
CHARLES I. COGUT
New York, New York
Retired Partner, Simpson
Thacher & Bartlett LLP.
Director since 2016.
KATHLEEN B. COOPER
Dallas, Texas
President, Cooper
Strategies International LLC.
Director since 2006.
MICHAEL A. CREEL
The Woodlands, Texas
Former Chief Executive Officer,
Enterprise Products Partners L.P.
Director since 2016.
PETER A. RAGAUSS
Houston, Texas
Former Senior Vice President
and Chief Financial Officer,
Baker Hughes Incorporated.
Director since 2016.
SCOTT D. SHEFFIELD
Irving, Texas
Chairman and Former Chief
Executive Officer,
Pioneer Natural Resources Company.
Director since 2016.
MURRAY D. SMITH
Calgary, Alberta, Canada
President, Murray Smith
and Associates; former Minister
of Energy for Alberta, Canada.
Director since 2012.
WILLIAM H. SPENCE
Allentown, Pennsylvania
Chairman, President and Chief
Executive Officer, PPL Corporation.
Director since 2016.
JANICE D. STONEY
Phoenix, Arizona
Former Executive Vice President,
US West Communications.
Director since 1999.
(Not standing for re-election)
This information is presented as of March 20, 2018.
2017 Annual Report
The Williams Companies, Inc.
3
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 2017
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-4174
The Williams Companies, Inc.
(Exact Name of Registrant as Specified in Its Charter)
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
One Williams Center, Tulsa, Oklahoma
(Address of Principal Executive Offices)
73-0569878
(IRS Employer
Identification No.)
74172
(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
Common Stock, $1.00 par value
Name of Each Exchange on Which Registered
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
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
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
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
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an
emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company”
in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
(Do not check if a smaller
reporting company)
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or
revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
No
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common
equity was last sold as of the last business day of the registrant’s most recently completed second quarter was approximately $24,993,673,967.
The number of shares outstanding of the registrant’s common stock outstanding at February 19, 2018 was 827,327,336.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on May 10, 2018, are incorporated
into Part III, as specifically set forth in Part III.
(This page intentionally left blank)
THE WILLIAMS COMPANIES, INC.
FORM 10-K
TABLE OF CONTENTS
PART I
Item 1.
Business ..........................................................................................................................................................
Website Access to Reports and Other Information .........................................................................................
General............................................................................................................................................................
Financial Information About Segments ..........................................................................................................
Business Segments..........................................................................................................................................
Williams Partners............................................................................................................................................
Additional Business Segment Information .....................................................................................................
Regulatory Matters .........................................................................................................................................
Environmental Matters ...................................................................................................................................
Competition ....................................................................................................................................................
Employees.......................................................................................................................................................
Financial Information about Geographic Areas..............................................................................................
Item 1A. Risk Factors ....................................................................................................................................................
Item 1B. Unresolved Staff Comments ...........................................................................................................................
Properties ........................................................................................................................................................
Item 2.
Item 3.
Legal Proceedings...........................................................................................................................................
Item 4. Mine Safety Disclosures .................................................................................................................................
Executive Officers of the Registrant...............................................................................................................
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.........................................................................................................................................................
Selected Financial Data ..................................................................................................................................
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations .........................
Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................................
Item 8.
Financial Statements and Supplementary Data ..............................................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.........................
Item 9.
Item 9A. Controls and Procedures .................................................................................................................................
Item 9B. Other Information ...........................................................................................................................................
PART III
Item 10. Directors, Executive Officers and Corporate Governance .............................................................................
Item 11. Executive Compensation ................................................................................................................................
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ......
Item 13. Certain Relationships and Related Transactions, and Director Independence ...............................................
Item 14. Principal Accountant Fees and Services .........................................................................................................
PART IV
Item 15. Exhibits and Financial Statement Schedules ..................................................................................................
Item 16. Form 10-K Summary ......................................................................................................................................
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1
The following is a listing of certain abbreviations, acronyms and other industry terminology that may be used
DEFINITIONS
throughout this Annual Report.
Measurements:
Barrel: One barrel of petroleum products that equals 42 U.S. gallons
Bcf : One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree
Fahrenheit
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mbbls/d: One thousand barrels per day
Mdth/d: One thousand dekatherms per day
MMcf/d: One million cubic feet per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Tbtu: One trillion British thermal units
Consolidated Entities:
Cardinal: Cardinal Gas Services, L.L.C.
Constitution: Constitution Pipeline Company, LLC
Gulfstar One: Gulfstar One LLC
Jackalope: Jackalope Gas Gathering Services, L.L.C.
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
WPZ: Williams Partners L.P.
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of
December 31, 2017, we account for as an equity-method investment, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Caiman II: Caiman Energy II, LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
UEOM: Utica East Ohio Midstream LLC
2
Government and Regulatory:
EPA: Environmental Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
GAAP: Generally accepted accounting principles
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
ACMP: Access Midstream Partners, L.P. prior to its merger with Pre-Merger WPZ
Energy Transfer: Energy Transfer Equity, L.P.
ETC: Energy Transfer Corp LP
ETC Merger: Merger wherein Williams would have been merged into ETC
Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products,
such as ethane, propane, and butane
IDR: Incentive distribution right
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
Merger Agreement: Merger Agreement and Plan of Merger of Williams with Energy Transfer and certain of its
affiliates
MVC: Minimum volume commitment
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are
used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation
Pre-merger WPZ: Williams Partners L.P. prior to its merger with ACMP
PDH facility: Propane dehydrogenation facility
RGP Splitter: Refinery grade propylene splitter
Throughput: The volume of product transported or passing through a pipeline, plant, terminal, or other facility
The statements in this Annual Report that are not historical information, including statements concerning plans and
objectives of management for future operations, economic performance or related assumptions, are forward-looking
statements. Forward-looking statements may 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 and other words and terms of similar meaning. Although
we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance
that such expectations or assumptions will be achieved. Additional information regarding forward-looking statements
and important factors that could cause actual results to differ materially from those in the forward-looking statements
are described under Part I, Item 1A in this Annual Report.
3
PART I
Item 1. Business
In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates,
all of our subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” We also sometimes refer to
Williams as the “Company.”
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, proxy
statements and other documents electronically with the SEC under the Exchange Act. You may read and copy any
materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549.
You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
You may also obtain such reports from the SEC’s Internet website at www.sec.gov.
Our Internet website is http://investor.williams.com/. We make available, free of charge, through the Investors tab
of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-
K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon
as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate
Governance Guidelines, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of
Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our
corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700,
Tulsa, Oklahoma 74172.
GENERAL
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource
plays to markets for natural gas and NGLs. Our operations are located principally in the United States.
As of December 31, 2017, our interstate gas pipelines and midstream interests were largely held through our
significant investment in WPZ. We own the general partner interest and a 74 percent limited partner interest in WPZ.
We were founded in 1908, originally incorporated under the laws of the state of Nevada in 1949 and reincorporated
under the laws of the state of Delaware in 1987. Williams’ headquarters are located in Tulsa, Oklahoma, with other
major offices in Salt Lake City, Utah; Houston, Texas; Pittsburgh, Pennsylvania; and the Four Corners Area. Our
telephone number is 918-573-2000.
FINANCIAL INFORMATION ABOUT SEGMENTS
See Part II, “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial
Statements — Note 18 – Segment Disclosures.”
BUSINESS SEGMENTS
Substantially all our operations are conducted through our subsidiaries. Our activities in 2017 were operated through
the following reporting segments as presented in the accompanying financial statements and management’s discussion
and analysis.
• Williams Partners — comprised of our consolidated master limited partnership, WPZ, which includes gas
pipeline and midstream businesses. The gas pipeline business includes interstate natural gas pipelines and
pipeline joint project investments. The midstream business provides natural gas gathering, treating, processing
and compression services; NGL production, fractionation, storage, marketing and transportation; deepwater
production handling and crude oil transportation services; an olefin production business (see Note 2 –
4
Acquisitions and Divestitures of Notes to Consolidated Financial Statements), and is comprised of several
wholly owned and partially owned subsidiaries and joint project investments.
This reporting segment also included our former Canadian midstream operations comprised of an oil sands
offgas processing plant near Fort McMurray, Alberta, an NGL/olefin fractionation facility, and the Boreal
Pipeline, which were sold in September 2016 (see Note 2 – Acquisitions and Divestitures of Notes to
Consolidated Financial Statements).
• Other — comprised of business activities that are not operating segments, as well as corporate operations.
Other also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included
a liquids extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a
propane dehydrogenation facility which was under development. In September 2016, the Canadian assets
were sold (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).
Detailed discussion of each of our reporting segments follows. For a discussion of our ongoing expansion projects,
see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Williams Partners
Gas Pipeline Business
Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. Our gas pipeline
business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent
equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is
developing a pipeline project (see Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements).
Transco and Northwest Pipeline own and operate a combined total of approximately 13,600 miles of pipelines with a
total annual throughput of approximately 4,533 TBtu of natural gas and peak-day delivery capacity of approximately
18.8 MMdth of natural gas.
Transco
Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile natural gas pipeline
system, which is regulated by the FERC, extending from Texas, Louisiana, Mississippi and the 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.
Pipeline system and customers
At December 31, 2017, Transco’s system, which extends from Texas to New York, had a system-wide delivery
capacity totaling approximately 15.0 MMdth of natural gas per day. During 2017, Transco completed five fully-
contracted expansions, which added more than 2.8 MMdth of firm transportation capacity per day to the existing
pipeline system. Transco’s system includes 50 compressor stations, four underground storage fields, and an LNG
storage facility. Compression facilities at sea level-rated capacity total approximately 2.1 million horsepower.
Transco’s major natural gas transportation customers are public utilities and municipalities that provide service
to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public
utilities, municipalities, intrastate pipelines, direct industrial users, electric power generators, and natural gas
marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various
expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers interruptible
transportation services under shorter-term agreements.
Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline
system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG
storage facility that it owns and operates. 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, 2017, Transco’s customers had stored in its facilities approximately 141
5
Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent equity-method
investment 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.
Northwest Pipeline
Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline
system, which is regulated by the FERC, 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, either directly or indirectly through
interconnections with other pipelines.
Pipeline system and customers
At December 31, 2017, Northwest Pipeline’s system, having long-term firm transportation and storage
redelivery agreements with aggregate capacity reservations of approximately 3.8 MMdth/d, was composed of
approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations
having a combined sea level-rated capacity of approximately 472,000 horsepower.
Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local natural gas
distribution companies, municipal utilities, direct industrial users, electric power generators, and natural gas
marketers and producers. Northwest Pipeline’s firm transportation and storage contracts are generally long-term
contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business.
Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.
Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington
and contracts with a third party for natural gas storage services 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 natural 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 customers.
Gulfstream
Gulfstream is a 745-mile interstate natural gas pipeline system extending from the Mobile Bay area in Alabama
to markets in Florida, which has a capacity to transport 1.3 Bcf/d. Williams Partners owns, through a subsidiary, a 50
percent equity-method investment in Gulfstream. Williams Partners shares operating responsibilities for Gulfstream
with the other 50 percent owner.
Midstream Business
Williams Partners’ midstream business, one of the nation’s largest natural gas gatherers and processors, has primary
service areas concentrated in major producing basins in Arkansas, Colorado, New Mexico, Oklahoma, Texas, Wyoming,
the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio. The primary businesses are:
(1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; (3) crude oil
transportation; and (4) olefins production (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial
Statements). These fall within the middle of the process of taking raw natural gas and crude oil from the producing
fields to the consumer.
Key variables for this business will continue to be:
• Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;
• Prices impacting commodity-based activities;
6
• 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 service areas.
Gathering, Processing, and Treating
Williams Partners’ 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. Williams Partners’ treating
facilities remove water vapor, carbon dioxide, and other contaminants and collect condensate, but do not extract NGLs.
Williams Partners’ is 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.
Our gas processing services generate revenues primarily from the following 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. A portion of our fee-based processing revenues includes a share of the margins on the NGLs
produced. For the year ended December 31, 2017, 70 percent of our NGL production volumes were under
fee-based contracts.
• Noncash commodity-based: We also process gas under two types of commodity-based contracts, keep-whole
and percent-of-liquids, where we receive consideration for our services in the form of NGLs. Under these
contracts, we retain some or all of the extracted NGLs as compensation for our services. For a keep-whole
arrangement we replace the Btu content of the retained NGLs that were extracted during processing with
natural gas purchases, also known as shrink replacement gas. For a percent-of-liquids arrangement, we deliver
to customers an agreed-upon percentage of the extracted NGLs and retain the remainder. NGLs we retain in
connection with these types of processing agreements are referred to as our equity NGL production. Under
keep-whole agreements, we have commodity price exposure on the difference between NGL and natural gas
prices. For the year ended December 31, 2017, 30 percent of our NGL production volumes were under noncash
commodity-based 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. Some contracts have price
escalators which annually increase our gathering rates. In addition, certain contracts include fee redetermination or cost
of service mechanisms 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, commodity
price fluctuations, compression and other expenses. Certain of our gas gathering agreements include MVCs. If the
minimum annual or semi-annual volume commitment is not met, these customers are obligated to pay a fee equal to
7
the applicable fee for each Mcf by which the applicable customer’s minimum annual or semi-annual volume commitment
exceeds the actual volume gathered. The revenue associated with such shortfall fees is generally recognized in the
fourth quarter of each year.
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. Williams Partners’ gas gathering and processing customers are generally natural
gas producers who have proved and/or producing natural gas fields in the areas surrounding its infrastructure. During
2017, Williams Partners’ facilities gathered and processed gas and crude oil for approximately 260 customers. Williams
Partners’ top ten customers accounted for approximately 75 percent of our gathering and processing fee revenues and
NGL margins from our noncash commodity-based agreements.
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 shifted away from the more
expensive crude-based feedstocks.
Geographically, the midstream natural gas assets are positioned to maximize commercial and operational synergies
with our other assets. For example, most of the offshore gathering and processing assets attach and process or condition
natural gas supplies delivered to the Transco pipeline. Our San Juan basin, southwest Wyoming, and Piceance systems
are capable of delivering residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party
interstate systems. Our gathering systems in Pennsylvania delivers residue gas volumes into Transco’s pipeline in
addition to third-party interstate systems.
8
The following table summarizes our significant consolidated natural gas gathering assets:
Natural Gas Gathering Assets
Location
Pipeline
Miles
Inlet
Capacity
(Bcf/d)
Ownership
Interest
Supply Basins/Shale
Formations
Northeast
Ohio Valley Midstream...........
Susquehanna Supply Hub .......
Cardinal (1) .............................
Flint.........................................
Marcellus South (2) ................
Atlantic-Gulf
Canyon Chief, including
Ohio, West Virginia, &
Pennsylvania
Pennsylvania & New York
Ohio
Ohio
Pennsylvania
Blind Faith and Gulfstar
extensions............................ Deepwater Gulf of Mexico
Other Eastern Gulf ..................
Seahawk .................................. Deepwater Gulf of Mexico
Perdido Norte.......................... Deepwater Gulf of Mexico
Other Western Gulf.................
Offshore shelf and other
Offshore shelf and other
West
Four Corners ...........................
Wamsutter ...............................
Southwest Wyoming ...............
Piceance ..................................
Niobrara ..................................
Barnett Shale...........................
Eagle Ford Shale.....................
Haynesville Shale ...................
Permian ...................................
Colorado & New Mexico
Wyoming
Wyoming
Colorado
Wyoming
Texas
Texas
Louisiana
Texas
216
436
353
75
41
156
46
115
105
105
3,742
2,084
1,614
352
224
858
1,225
626
365
0.8
3.2
1.0
0.4
0.1
0.5
0.2
0.4
0.3
0.5
1.8
0.7
0.5
1.8
0.2
0.8
0.6
1.8
0.1
100%
100%
66%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
(3)
(4)
100%
100%
100%
100%
Mid-Continent......................... Oklahoma, Texas, & Kansas
2,248
0.9
100%
Appalachian
Appalachian
Appalachian
Appalachian
Appalachian
Eastern Gulf of Mexico
Eastern Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
San Juan
Wamsutter
Southwest Wyoming
Piceance
Powder River
Barnett Shale
Eagle Ford Shale
Haynesville Shale
Permian
Miss-Lime, Granite
Wash, Colony Wash,
Arkoma
__________
(1) Statistics reflect 100 percent of the assets from our 66 percent ownership of Cardinal gathering system.
(2) Statistics reflect 100 percent of the Beaver Creek assets in the consolidated Marcellus South gathering system.
(3) Includes our 60 percent ownership of a gathering system in the Ryan Gulch area with 140 miles of pipeline and
0.2 Bcf/d of inlet capacity, and our 67 percent ownership of a gathering system at Allen Point with 8 miles of
pipeline and 0.1 Bcf/d of inlet capacity. We operate both systems. We own and operate 100 percent of the balance
of the Piceance gathering assets.
(4) Statistics reflect 100 percent of the assets from our 50 percent ownership of the Jackalope gathering system.
9
The following table summarizes our significant consolidated natural gas processing facilities:
Location
Northeast
Fort Beeler ............................. Marshall County, WV
Oak Grove.............................. Marshall County, WV
Atlantic-Gulf
Markham ................................
Mobile Bay.............................
Markham, TX
Coden, AL
West
Echo Springs, WY
Echo Springs ..........................
Opal, WY
Opal........................................
Bucking Horse (1)..................
Converse County, WY
Willow Creek ......................... Rio Blanco County, CO
Parachute................................
Ignacio....................................
Kutz........................................
Garfield County, CO
Ignacio, CO
Bloomfield, NM
Natural Gas Processing Facilities
Inlet
Capacity
(Bcf/d)
NGL
Production
Capacity
(Mbbls/d)
Ownership
Interest
0.5
0.2
0.5
0.7
0.7
1.1
0.1
0.5
1.1
0.5
0.2
62
25
45
30
58
47
7
30
6
29
12
100%
100%
100%
100%
100%
100%
50%
100%
100%
100%
100%
Supply Basins
Appalachian
Appalachian
Western Gulf of Mexico
Eastern Gulf of Mexico
Wamsutter
Southwest Wyoming
Powder River
Piceance
Piceance
San Juan
San Juan
__________
(1) Statistics reflect 100 percent of the assets from our 50 percent ownership of Bucking Horse gas processing facility.
In addition, we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and
Louisiana which bring natural gas to specifications allowable by major interstate pipelines.
We also own and operate fractionation facilities at Moundsville, de-ethanization and condensate facilities at our
Oak Grove processing plant, a condensate stabilization facility near our Oak Grove plant, and an ethane transportation
pipeline. Our three condensate stabilizers are capable of handling 17 Mbbls/d of field condensate. NGLs are extracted
from the natural gas stream in our cryogenic processing plants. Our Oak Grove de-ethanizer is capable of handling up
to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane. The remaining
mixed NGL stream from the de-ethanizer is then transported and fractionated at our Moundsville facilities, which are
capable of handling more than 43 Mbbls/d 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.
Our gathering business in the Northeast also provides multiple takeaway options to its customers. Ohio Valley
Midstream makes customer deliveries with interconnections to two pipelines. Susquehanna Supply Hub makes
deliveries for its customers with interconnections to Transco, as well as five other pipelines, while our Cardinal system
utilizes interconnections with Blue Racer Midstream, LLC (Blue Racer), and UEOM. In addition, our NGL processing
business utilizes connections with multiple pipelines, as well as truck and rail transportation to local and regional
markets.
Crude Oil Transportation and Production Handling Assets
In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production
platforms serving the deepwater in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-
based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale
arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Our
offshore floating production platforms provide centralized services to deepwater producers such as compression,
separation, production handling, water removal, and pipeline landings. Revenue sources have historically included a
combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the
resident production at our Devils Tower facility are recognized on a units-of-production basis. Fixed fees associated
with the resident production at our Gulfstar One facility are recognized as the guaranteed capacity is made available.
10
The following tables summarize our significant crude oil transportation pipelines and production handling
platforms:
Crude Oil Pipelines
Pipeline
Miles
Capacity
(Mbbls/d)
Ownership
Interest
Supply Basins
Mountaineer, including Blind Faith and Gulfstar
extensions ....................................................................
BANJO ...................................................................
Alpine .....................................................................
Perdido Norte..........................................................
155
57
96
74
150
90
85
150
100%
100%
100%
100%
Eastern Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Western Gulf of Mexico
Production Handling Platforms
Devils Tower...........................................................
Gulfstar I FPS (1)....................................................
Gas Inlet
Capacity
(MMcf/d)
210
172
Crude/NGL
Handling
Capacity
(Mbbls/d)
60
80
Ownership
Interest
100%
51%
Supply Basins
Eastern Gulf of Mexico
Eastern Gulf of Mexico
__________
(1) Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.
Canadian Operations
Williams Partners completed the sale of its Canadian operations in September 2016. This business included an
oil sands offgas processing plant located near Fort McMurray, Alberta, and an NGL/olefin fractionation facility located
at Redwater, Alberta, which is near Edmonton, Alberta, and the Boreal Pipeline which transported NGLs and associated
olefins from the Fort McMurray plant to the Redwater fractionation facility. This business allowed us to extract,
fractionate, treat, store, terminal and sell the ethane/ethylene, propane, propylene, normal butane (butane), iso-butane,
alky feedstock, and condensate recovered from a third-party oil sands bitumen upgrader.
Operating statistics
The following table summarizes our significant operating statistics:
Volumes:
Canadian propylene sales (millions of pounds) ..............................................................
Canadian NGL sales (millions of gallons) ......................................................................
87
141
161
284
2016
2015
Gulf Olefins
In mid-2017, Williams Partners completed the sale of its 88.5 percent undivided interest and operatorship of an
olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter in the Gulf region. The
olefins business also operated an ethylene storage hub at Mont Belvieu using leased third-party underground storage
caverns.
Our refinery grade propylene splitter had production capacity of approximately 500 million pounds per year of
propylene. At the propylene splitter, we purchased refinery grade propylene and fractionated it into polymer grade
propylene and propane; as a result, the asset was exposed to the price spread between those commodities.
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
11
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, the
majority of sales are based on supply contracts of one year or less in duration.
In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer
customers for resale.
Prior to the sale of our olefin operations, we marketed olefin products to a wide range of users in the energy and
petrochemical industries.
Other NGL & Petchem Operations
We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These
assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d
and we own approximately 20 million barrels of NGL storage capacity.
We own 283 miles of pipeline systems in Louisiana and Texas that provide feedstock transportation from
fractionation and storage facilities to various third-party crackers. These systems include the Bayou ethane pipeline,
which provides ethane transportation from Mont Belvieu, Texas; certain ethane and propane systems in Louisiana; and
a pipeline that has the capacity to transport 12 Mbbls/d of ethane from Discovery’s Paradis fractionator.
We own 114 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.
WPZ Operating Areas
WPZ organizes these businesses into the following operating areas:
Northeast G&P is comprised of natural gas gathering and processing, compression, and NGL fractionation
businesses in the Marcellus and Utica Shale regions in Pennsylvania, West Virginia, New York, and Ohio, as well as a
66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, a 69 percent
equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia
Midstream Services, LLC, which owns an approximate average 66 percent interest in multiple gas gathering systems
in the Marcellus Shale.
Atlantic-Gulf is comprised of an interstate natural gas pipeline, Transco, and significant natural gas gathering and
processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent
interest in Gulfstar One (a consolidated entity) which is a proprietary floating production system, and various
petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in
Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is developing a pipeline project (see
Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements), and a 60 percent equity-method
investment in Discovery.
West is comprised of an interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing,
and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central
Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-
Continent region which includes the Anadarko, Arkoma, Delaware, and Permian basins. West also includes an NGL
and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near
Conway, Kansas, as well as our previously owned 50 percent equity-method investment in the Delaware basin gas
gathering system in the Permian basin, and a 50 percent equity-method investment in OPPL.
NGL & Petchem Services is comprised of previously owned operations, including an 88.5 percent undivided
interest in an olefins production facility in Geismar, Louisiana, which was sold in July 2017 (see Note 2 – Acquisitions
and Divestitures of Notes to Consolidated Financial Statements), and a refinery grade propylene splitter in the Gulf
12
region, which was sold in June 2017. This operating area also included an oil sands offgas processing plant near Fort
McMurray, Alberta, and an NGL/olefin fractionation facility, which were sold in September 2016.
Certain Equity-Method Investments
Discovery
We own a 60 percent 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 a 614-mile offshore natural gas gathering and transportation system in the Gulf of Mexico.
Discovery’s mainline has a gathering inlet capacity of 600 MMcf/d, while the Keathley Canyon Connector, a deepwater
lateral pipeline in the central deepwater Gulf of Mexico has a gathering inlet capacity of 400 MMcf/d. Discovery’s
assets also include a crude oil production handling platform with a crude oil/NGL handling capacity of 10 Mbbls/d and
natural gas processing capacity of 75 MMcf/d.
Laurel Mountain
We own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 2,053-mile gathering system that
we operate in western Pennsylvania with the capacity to gather 0.7 Bcf/d of natural gas. 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 interest in Caiman II, which owns a 50 percent interest in Blue Racer, a joint project to own,
operate, develop and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale.
Blue Racer’s assets include 721 miles of gathering pipelines, and the Natrium complex in Marshall County, West
Virginia, with a cryogenic processing capacity of 400 MMcf/d and fractionation capacity of approximately 120,000
Bbls/d. Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of
400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne.
Utica East Ohio Midstream
We own a 62 percent interest in UEOM, which includes infrastructure for the gathering, processing, and fractionation
of natural gas and NGLs in the Utica Shale play in eastern Ohio. We operate a natural gas gathering pipeline, while
our partner operates inlet compression, two processing plants with a total capacity of 800 MMcf/d, 41 Mbbls/d of
condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility, approximately 950,000 barrels of NGL
storage capacity and other ancillary assets, including loading and terminal facilities. These assets earn a fixed fee that
escalates annually within a specified range.
Appalachia Midstream Investments
Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 66
percent interest in the Bradford Supply Hub gathering system and own an approximate average 68 percent interest in
the Marcellus South gathering system, together which consist of approximately 987 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 Investments operates the assets under long-term, 100 percent fixed-fee gathering agreements
that include significant acreage dedications and cost of service mechanisms.
During the first quarter of 2017, we exchanged all of our 50 percent interest in the Delaware basin gas gathering
system for an increased interest in the Bradford Supply Hub natural gas gathering system that is part of the Appalachia
Midstream Investments and $155 million in cash. Following this exchange, we have an approximate average 66 percent
interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method
due to the significant participatory rights of our partners such that we do not exercise control. (See Note 5 – Investing
Activities of Notes to Consolidated Financial Statements.)
13
Aux Sable
We also own a 15 percent 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 132 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.
Delaware basin gas gathering system
We previously owned a non-operated 50 percent interest in the Delaware basin gas gathering system in the Permian
basin, which was sold in February 2017. The system was comprised of more than 450 miles of gathering pipeline,
located in west Texas.
Overland Pass Pipeline
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 and the Bakken
Shale in the Williston basin in North Dakota. Our equity NGL volumes from two of our three Wyoming plants and our
Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement.
Operating Statistics
The following table summarizes our significant operating statistics for Williams Partners’ domestic midstream
business:
Volumes: (1)
2017
2016
2015
Gathering (Bcf/d) .........................................................................................
Plant inlet natural gas (Bcf/d) ......................................................................
NGL production (Mbbls/d) (2) ....................................................................
NGL equity sales (Mbbls/d) (2) ...................................................................
Crude oil transportation (Mbbls/d) (2).........................................................
Geismar ethylene sales (millions of pounds) ...............................................
8.15
3.05
148
39
134
566
8.25
3.50
151
46
113
1,638
8.34
3.52
131
31
126
1,066
__________
(1) Excludes volumes associated with equity-method investments.
(2) Annual average Mbbls/d.
Additional Business Segment Information
Our ongoing business segments are presented as continuing operations in the accompanying financial statements
and Notes to Consolidated Financial Statements included in Part II.
We perform certain management, legal, financial, tax, consultation, information technology, administrative and
other services for our subsidiaries.
Our principal sources of cash are from dividends, distributions, and advances from our subsidiaries, investments,
payments by subsidiaries for services rendered, and, if needed, external financings, and net proceeds from asset sales.
The terms of certain subsidiaries’ borrowing arrangements may limit the transfer of funds to us under certain conditions.
We believe that we have adequate sources and availability of raw materials and commodities for existing and
anticipated business needs. Our interstate pipeline systems are all regulated in various ways resulting in the financial
return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each
of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion
opportunities also necessitating periodic capital outlays.
14
Revenues by service within our Williams Partners segment that exceeded 10 percent of consolidated revenue
include:
2017
Service:
Total
(Millions)
Regulated natural gas transportation and storage .......................................................................................... $
Gathering, processing, and production handling ...........................................................................................
2,148
2,715
2016
Service:
Regulated natural gas transportation and storage .......................................................................................... $
Gathering, processing, and production handling ...........................................................................................
2,001
2,729
2015
Service:
Regulated natural gas transportation and storage .......................................................................................... $
Gathering, processing and production handling ............................................................................................
1,938
2,804
We have one customer, Chesapeake Energy Corporation, and its affiliates, that accounts for 10 percent of our total
revenue in 2017. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to
Consolidated Financial Statements for additional details.)
FERC
REGULATORY MATTERS
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, our rates and charges for the
transportation of natural gas in interstate commerce, accounting, and the extension, enlargement, or abandonment of
our 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,
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Grand Isle, Ewing Bank, and Green Canyon (deepwater) areas to an onshore processing facility and downstream
interconnect points with major interstate pipelines. In addition, Williams Partners owns a 50 percent equity-method
investment in and is the operator of OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC
pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.
We also own an ethane pipeline in West Virginia and Pennsylvania (Williams Ohio Valley Pipeline LLC) and an ethane
pipeline in Texas and Louisiana (Williams Bayou Ethane Pipeline) each of which provides interstate service subject to
FERC jurisdiction under the Interstate Commerce Act.
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, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011 (Pipeline Safety
Act), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016, which regulate safety
requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities.
The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA)
administers federal pipeline safety laws.
Federal pipeline safety laws authorize PHMSA 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. PHMSA 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, PHMSA performs pipeline safety inspections and has the authority to initiate
enforcement actions.
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.
States are largely preempted by federal law from regulating pipeline safety for interstate pipelines but most are
certified by PHMSA 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 PHMSA 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 for both gas and liquid pipeline systems. On June 22, 2016, the Protecting Our
Infrastructure of Pipelines and Enhancing Safety Act of 2016 was enacted, further strengthening PHMSA’s safety
authority.
Pipeline Integrity Regulations
We have an enterprise-wide Gas 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 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. Ongoing periodic reassessments and initial
assessments of any new high-consequence areas have been completed. We estimate that the cost to be incurred in 2018
associated with this program to be approximately $99 million. 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.
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We have an enterprise-wide 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 in the event of pipeline failure. The integrity management program includes a baseline assessment
plan along with periodic reassessments expected 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 2018 associated
with this program will be approximately $4 million. 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 laws and regulations in the various states in which we
operate. For example, the Texas Railroad Commission has the authority to regulate the terms of service for our intrastate
natural gas gathering business in Texas. Although the applicable state regulations vary widely, they generally require
that pipeline rates and practices be reasonable and nondiscriminatory, and may include provisions covering marketing,
pricing, pollution, environment, and human health and safety. Some states, such as New York, have specific regulations
pertaining to the design, construction, and operations of gathering lines within such state.
Intrastate Liquids Pipelines in the Gulf Coast
Our intrastate liquids pipelines in the Gulf Coast are regulated by the Louisiana Department of Environmental
Quality, the Texas Railroad Commission, and various other state and federal agencies. These pipelines are also subject
to the liquid pipeline safety and integrity regulations discussed above since both Louisiana and Texas have adopted the
integrity management regulations defined in PHMSA.
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 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.”
See Part II, Item 8. Financial Statements and Supplementary Data — Note 17 – Contingent Liabilities and
Commitments of 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 regulatory proceedings, 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,” and
“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."
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;
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• 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 current 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 that could exceed our expectations,”
and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations —
Environmental” and “Environmental Matters” in Part II, Item 8. Financial Statements and Supplementary Data —
Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.
Gas Pipeline Business
COMPETITION
The market for supplying natural gas is highly competitive and new pipelines, storage facilities, and other related
services are expanding to service the growing demand for natural gas. Additionally, pipeline capacity in many growing
natural gas supply basins is constrained causing competition to increase among pipeline companies as they strive to
connect those basins to major natural gas demand centers.
In our business, we compete with major intrastate and interstate natural gas pipelines. In the last few years, local
distribution companies have also started entering into the long haul transportation business through joint venture
pipelines. The principle elements of competition in the interstate natural gas pipeline business are based on rates,
reliability, quality of customer service, diversity of supply, and proximity to customers and market hubs.
Significant entrance barriers to build new pipelines exist, including federal and growing state regulations and public
opposition against new pipeline builds, and these factors will continue to impact potential competition for the foreseeable
future. However, we believe the position of our existing infrastructure, established strategic long-term contracts, and
the fact that our pipelines have numerous receipt and delivery points along our systems provide us a competitive
advantage, especially along the eastern seaboard and northwestern United States.
Midstream Business
Competition for natural gas gathering, processing, treating, transporting, and storing natural gas continues to
increase as production from shales and other resource areas continues to grow. Our midstream services compete with
similar facilities that are in the same proximity as our assets.
We face competition from major and independent natural gas midstream providers, private equity firms, and major
integrated oil and natural gas companies that gather, transport, process, fractionate, store, and market natural gas and
NGLs, as well as some larger exploration and production companies that are choosing to develop midstream services
to handle their own natural gas.
Our gathering and processing agreements are generally long-term agreements that may include acreage dedication.
We primarily face competition to the extent these agreements approach renewal and new volume opportunities arise.
Competition for natural gas volumes is primarily based on reputation, commercial terms (products retained or fees
charged), array of services provided, efficiency and reliability of services, location of gathering facilities, available
capacity, downstream interconnects, and latent capacity. We believe our significant presence in traditional prolific
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supply basins, our solid positions in growing shale plays, and our ability to offer integrated packages of services position
us well against our competition.
For additional information regarding competition for our services or otherwise affecting our business, please refer
to “Risk Factors - The 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
the markets we serve,” “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 dividends, and our ability to grow.”
At February 1, 2018, we had approximately 5,425 full-time employees.
EMPLOYEES
FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS
See Part II, Item 8. Financial Statements and Supplementary Data — Note 18 – Segment Disclosures of Notes to
Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers
attributable to the United States and all foreign countries. Also see Part II, Item 8. Financial Statements and
Supplementary Data — Note 18 – Segment Disclosures of Notes to Consolidated Financial Statements for information
relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.
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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
The reports, filings, and other public announcements of Williams may contain or incorporate by reference
statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements”
within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act) and Section 21E of the
Securities Exchange Act of 1934, as amended (Exchange Act). 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:
• Expected levels of cash distributions by WPZ with respect to limited partner interests;
• Levels of dividends to Williams stockholders;
• Future credit ratings of Williams, WPZ, and their affiliates;
• Amounts and nature of future capital expenditures;
• Expansion and growth of our business and operations;
• Expected in-service dates for capital projects;
• Financial condition and liquidity;
• Business strategy;
• Cash flow from operations or results of operations;
• Seasonality of certain business components;
• Natural gas and natural gas liquids prices, supply, and demand;
• 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. 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:
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• Whether WPZ will produce sufficient cash flows to provide expected levels of cash distributions;
• Whether we are able to pay current and expected levels of dividends;
• Whether WPZ elects to pay expected levels of cash distributions and we elect to pay expected levels of
dividends;
• Whether we will be able to effectively execute our financing plan;
• Availability of supplies, including lower than anticipated volumes from third parties served by our midstream
business, and market demand;
• Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;
•
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 timely execute our capital projects and other
investment opportunities in accordance with our forecasted capital expenditures budget;
• Our ability to successfully expand our facilities and operations;
• Development and rate of adoption of alternative energy sources;
• The impact of operational and developmental hazards and unforeseen interruptions, and the availability of
adequate insurance coverage;
• The impact of existing and future laws (including, but not limited to, the Tax Cuts and Job Acts of 2017),
regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain
necessary permits and approvals and achieve favorable rate proceeding outcomes;
• Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
• Changes in maintenance and construction costs;
• Changes in the current geopolitical situation;
• Our exposure to the credit risk of our customers and counterparties;
• Risks related to financing, including restrictions stemming from debt agreements, future changes in credit
ratings as determined by nationally recognized credit rating agencies, 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 and physical damage to
our facilities;
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• Acts of terrorism, including cybersecurity threats, and related disruptions;
• Additional risks described in our filings with the Securities and Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained
in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We
disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions
to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our
intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also
cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such
factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors,
in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-
looking statements. These factors are described in the following section.
RISK FACTORS
You should carefully consider the following risk factors in addition to the other information in this report. Each
of these factors could adversely affect our business, prospects, financial condition, results of operations, cash flows,
and, in some cases our reputation. The occurrence of any of such risks could also adversely affect the value of an
investment in our securities.
Risks Related to Our Business
The 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 the markets
we serve.
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 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. Localized low natural gas prices in one or more of our existing supply basins, whether caused by
a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the
supply of natural gas made available to us. 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, as well as technological advances and renewable sources of 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,
results of operations, and cash flows.
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Prices for natural gas, NGLs, oil, and other commodities, are volatile and this volatility has and could continue to
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 natural gas, NGLs, 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 has and could continue to 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 has
and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.
The markets for natural gas, NGLs, 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, 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;
• The credit of participants in the markets where products are bought and sold.
We are exposed to the credit risk of our customers and counterparties, including Chesapeake Energy Corporation
and its affiliates, and our credit risk management will not be able to completely eliminate 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 cannot completely 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. In a low
commodity price environment certain of our customers could be negatively impacted, causing them significant economic
stress including, in some cases, to file for bankruptcy protection or to renegotiate contracts. To the extent one or more
of our key customers commences bankruptcy proceedings, our contracts with the customers may be subject to rejection
under applicable provisions of the United States Bankruptcy Code, or may be renegotiated. Further, during any such
bankruptcy proceeding, prior to assumption, rejection or renegotiation of such contracts, the bankruptcy court may
temporarily authorize the payment of value for our services less than contractually required, which could have a material
adverse effect on our business, financial condition, results of operations, and cash flows. For example, Chesapeake
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Energy Corporation and its affiliates, which accounted for approximately 10 percent of our 2017 consolidated revenues,
have experienced significant, negative financial results due to sustained low commodity prices. If we fail to adequately
assess the creditworthiness of existing or future customers and counterparties or otherwise do not take or are unable to
take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness, and
any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts
receivable. 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, financial condition, results of operations,
and cash flows.
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, or fractionation or storage facilities as well as the
expansion of existing facilities. In the current environment, we may face political opposition by landowners,
environmental activists, and others resulting in the delay and/or denial of required governmental permits. Additional
risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials,
and other required inputs in a timely manner such that projects are completed, on time or at all, 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;
• Acquisitions and capital projects may require substantial new capital, including 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 financial condition, results of operations,
including the possible impairment of our assets, or cash flows.
We may face opposition to the construction and operation of our pipelines and facilities from various groups.
We may face opposition to the construction and operation of our pipelines and facilities from environmental groups,
landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized
protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving
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our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business.
In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the
environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated
by our operations, or which causes us to make significant expenditures not covered by insurance, could adversely affect
our financial condition and results of operations.
Holders of our common stock may not receive dividends in the amount expected or any dividends.
We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends.
The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some
of which are beyond our control, including:
• The amount of cash that WPZ and our other subsidiaries 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;
• The cost of acquisitions, if any.
A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence,
reputational damage, and a decrease in the value of our stock price.
Our cash flow is heavily dependent on the earnings and distributions of WPZ.
Our partnership interest in WPZ is our largest cash-generating asset. Therefore, we are indirectly exposed to all
of the risks to which WPZ is subject, as our cash flow is heavily dependent upon the ability of WPZ to make distributions
to its partners. A significant decline in WPZ’s earnings and/or distributions would have a corresponding negative impact
on us.
One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P.
As such, this subsidiary’s operations may involve a greater risk of liability than ordinary business operations.
One of our subsidiaries acts as the general partner of WPZ, a publicly traded limited partnership. This subsidiary
may be deemed to have undertaken contractual obligations with respect to WPZ as the general partner and to the limited
partners of WPZ. Activities, determined to involve such obligations to other persons or entities typically involve a
higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability,
particularly when a conflict of interest is found to exist. Our control of the general partner of WPZ may increase the
possibility of claims of breach of such duties, including claims brought due to conflicts of interest (including conflicts
of interest that may arise between WPZ, on the one hand, and its general partner and that general partner’s affiliates,
including us, on the other hand). Any liability resulting from such claims could be material.
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.
Any current or future competitor that delivers natural gas, NGLs, or other commodities into the areas that we operate
could offer transportation services that are more desirable to shippers than those we provide because of price, location,
facilities or other factors. 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. Failure to successfully
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compete against current and future competitors could have a material adverse effect on our business, results of operations,
financial condition, and cash flows.
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. As of December 31, 2017, our investments in
the Partially Owned Entities accounted for approximately 7 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, or 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.
We will 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 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;
• We may be forced to offer rights of participation to other joint venture participants in the area of mutual interest;
• We have limited ability to influence or control certain day to day activities affecting the operations.
In addition, 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 of which is outside our control. Similarly, if we fail to make a
required capital contribution under the applicable governing provisions of a joint venture arrangement, we could be
deemed to be in default under the joint venture agreement. Joint venture partners may be in a position to take actions
contrary to 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.
The risks described above or the failure to continue joint ventures, or to resolve disagreements with joint venture
partners could adversely affect our ability to conduct our operations that are the subject of any joint venture, which
could in turn negatively affect our financial condition and results of operations.
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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 dividends, 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 dividends 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 sources, such as electricity,
renewable resources, coal, fuel oils, or nuclear energy;
• Natural gas and NGL 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 negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and
could also 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;
• 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.
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.
Some of our businesses 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.
If a supplier on which one of our businesses depends were to fail to timely supply required goods and services, such
business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at
all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such
risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a
material adverse effect on our financial condition, results of operation, and cash flows.
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Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability
to conduct our business.
Certain of our accounting and information technology services 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 others as service providers could have a material
adverse effect on our business, financial condition, results of operations, and cash flows.
An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity-
method investments, could reduce our earnings.
GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances
occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result
in impairments of our assets including our goodwill, property, plant, and equipment, intangible assets, and/or equity
method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise
exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be
required to take an immediate noncash charge to earnings.
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, 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, crude oil, or other products;
• 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;
• Security risks, including cybersecurity;
• 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.
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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. The occurrence of any risks not fully covered by our insurance could
have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability
to repay our debt.
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.
Our business could be negatively impacted by acts of terrorism and security threats, including cybersecurity threats,
and related disruptions.
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.
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 condition, results of operations, and cash flows.
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 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
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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, financial
condition, results of operations, and cash flows.
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 terms. 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, financial condition, results of operations,
and cash flows.
Our business could be negatively impacted as a result of stockholder activism.
In recent years, stockholder activism, including threatened or actual proxy contests, has been directed against
numerous public companies, including ours. During the latter part of fiscal year 2016, we were the target of a proxy
contest from a stockholder activist, which resulted in our incurring significant costs. If stockholder activists were to
again take or threaten to take actions against the Company or seek to involve themselves in the governance, strategic
direction or operations of the Company, we could incur significant costs as well as the distraction of management,
which could have an adverse effect on our business or financial results. In addition, actions of activist stockholders
may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other
factors that do not necessarily reflect the underlying fundamentals and prospects of our business.
Litigation pertaining to the ETC Merger, including litigation related to Energy Transfer Equity, L.P.’s (ETE’s)
termination of and failure to close the ETC Merger, may negatively impact our business and operations.
We have incurred and may continue to incur additional costs in connection with the prosecution, defense or
settlement of the currently pending and any future litigation relating to the ETC Merger or ETE’s termination of and
failure to close the ETC Merger. We cannot predict the outcome of this litigation. Such litigation may also create a
distraction for our management team and board of directors and require time and attention. In addition, any litigation
relating to the ETC Merger or ETE’s termination of and failure to close the ETC Merger could, among other things,
adversely affect our financial condition and results of operations.
Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement
benefit plans are affected by factors beyond our control.
We have defined benefit pension plans covering substantially all of our U.S. employees and other postretirement
benefit plans covering certain eligible participants. The timing and amount of our funding requirements under the
defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan
benefits, as well as factors outside of our control, such as asset returns, interest rates, and changes in pension laws.
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Changes to these and other factors that can significantly increase our funding requirements could have a significant
adverse effect on our financial condition and results of operations.
Failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.
Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, or
unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a
lengthy time period associated with skill development, including with the workforce needs associated with projects
and ongoing operations. Failure to hire and adequately obtain replacement employees, including the ability to transfer
significant internal historical knowledge and expertise to the new employees, or the future availability and cost of
contract labor may adversely affect our ability to manage and operate the businesses. If we are unable to successfully
attract and retain an appropriately qualified workforce, results of operations could be negatively impacted.
If there is a determination that the spin-off of WPX Energy, Inc. (WPX) stock to our stockholders is taxable for U.S.
federal income tax purposes because the facts, representations or undertakings underlying a U.S. Internal Revenue
Service (IRS) private letter ruling or a tax opinion are incorrect or for any other reason, then we and our stockholders
could incur significant income tax liabilities.
In connection with our original separation plan that called for an initial public offering (IPO) of stock of WPX and
a subsequent spin-off of our remaining shares of WPX to our stockholders, we obtained a private letter ruling from the
IRS and an opinion of our outside tax advisor, to the effect that the distribution by us of WPX shares to our stockholders,
and any related restructuring transaction undertaken by us, would not result in recognition for U.S. federal income tax
purposes, of income, gain or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the U.S.
Internal Revenue Code of 1986, as amended (Code), except for cash payments made to our stockholders in lieu of
fractional shares of WPX common stock. In addition, we received an opinion from our outside tax advisor to the effect
that the spin-off pursuant to our revised separation plan which was ultimately consummated on December 31, 2011,
which did not involve an IPO of WPX shares, would not result in the recognition, for federal income tax purposes, of
income, gain, or loss to us or our stockholders under section 355 and section 368(a)(1)(D) of the Code, except for cash
payments made to our stockholders in lieu of fractional shares of WPX. The private letter ruling and opinion have relied
on or will rely on certain facts, representations, and undertakings from us and WPX regarding the past and future
conduct of the companies’ respective businesses and other matters. If any of these facts, representations, or undertakings
are, or become, incorrect or are not otherwise satisfied, including as a result of certain significant changes in the stock
ownership of us or WPX after the spin-off, or if the IRS disagrees with any such facts and representations upon audit,
we and our stockholders may not be able to rely on the private letter ruling or the opinion of our tax advisor and could
be subject to significant income tax liabilities.
The WPX spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws
and legal dividend requirements that we did not assume in our agreements with WPX.
The spin-off is subject to review under various state and federal fraudulent conveyance laws. A court could deem
the spin-off or certain internal restructuring transactions undertaken by us in connection with the separation to be a
fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or
obligations incurred with the actual intent to hinder, delay, or defraud current or future creditors or transfers made or
obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor
insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions
or impose substantial liabilities upon us, which could adversely affect our financial condition and our results of
operations. Whether a transaction is a fraudulent conveyance or transfer will vary depending upon the jurisdiction
whose law is being applied. Under the separation and distribution agreement between us and WPX, from and after the
spin-off, each of WPX and we are responsible for the debts, liabilities, and other obligations related to the business or
businesses which each owns and operates. Although we do not expect to be liable for any such obligations not expressly
assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the
allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to WPX,
particularly if WPX were to refuse or were unable to pay or perform the subject allocated obligations.
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Risks Related to Financing Our Business
Downgrades of our credit ratings, which are determined outside of our control by independent third parties, impact
our liquidity, access to capital, and our costs of doing business.
Downgrades of our credit ratings 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
continue to be limited by the downgrading 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. As
of the date of the filing of this report, we have been assigned below investment-grade credit ratings by each of the three
credit ratings agencies.
Our ability to obtain credit in the future could be affected by WPZ’s credit ratings.
A substantial portion of our operations are conducted through, and our cash flows are substantially derived from,
distributions paid to us by WPZ. Due to our relationship with WPZ, our ability to obtain credit will be affected by
WPZ’s credit ratings. If WPZ were to experience a deterioration in its credit standing or financial condition, our access
to capital, and our ratings could be adversely affected. Any future downgrading of a WPZ credit rating could also result
in a downgrading of our credit rating. A downgrading of a WPZ credit rating could limit our ability to obtain financing
in the future upon favorable terms, if at all.
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 manner described above.
Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating
flexibility.
Our total outstanding long-term debt (including current portion) as of December 31, 2017, was $20.9 billion.
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,
the ability of our subsidiaries to incur additional debt, and our, and our material subsidiaries’, ability to enter into certain
affiliate transactions and certain restrictive agreements. 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.
Our debt service obligations and the covenants described above could have important consequences. For example,
they could:
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• 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 corporate 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 payments of
dividends, general corporate purposes, or other purposes;
• Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we
operate, 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.
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 Note 13
– Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.
Increases in interest rates could adversely impact our share price, our ability to issue equity or incur debt for
acquisitions or other purposes, and our ability to make cash dividends 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 share price will be impacted by the level of our dividends and implied dividend yield. The dividend 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
shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue
equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels.
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.
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Risks Related to Regulations
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;
• 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.
The operation of our businesses might also be adversely affected by regulatory proceedings, 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 material
and may not be covered fully or at all by insurance.
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In addition, existing regulations, including those pertaining to financial assurances to be provided by our businesses
in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise
enforced in a manner which differs from prior regulatory action. New laws and regulations, including those pertaining
to oil and gas hedging and cash collateral requirements, might also 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 or
revised 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, our compliance costs could increase, and our results of operations could be adversely affected.
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 our 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
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, 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 or denials 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 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 operate and maintain our
facilities, install new emission controls on our facilities, or 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.
We expect that certain aspects of Tax Cuts and Jobs Act signed into law on December 22, 2017 (Tax Reform),
including regulatory liabilities relating to reduced corporate federal income tax rates, could adversely impact our
financial condition and our future financial results.
35
Certain of the rates we charge to our customers are subject to the rate-making policies of the FERC. These policies
permit us to include in our cost-of-service an income tax allowance that includes a deferred income tax component.
The recently enacted Tax Reform makes significant changes to the U.S. federal income tax rules applicable to both
individuals and entities, including among other things, a reduction in corporate federal income tax rates. Although we
expect the decreased federal income tax rates will require us to return amounts to certain customers for this item through
future rates and have recognized a regulatory liability, the details of any regulatory implementation guidance remain
uncertain.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2. Properties
Please read “Business” for a description of the location and general character of our principal physical properties.
We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is 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.
On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the
facility temporarily inoperable (Geismar Incident). 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 June 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 February 21, 2017, we received notice from the Environmental Enforcement Section of the United States
Department of Justice (DOJ) regarding certain alleged violations of the Clean Air Act at our Moundsville facility as
set forth in a Notice of Noncompliance issued by the EPA on January 14, 2016. The notice includes an offer to avoid
further legal action on the alleged violations by paying $2 million. In discussion with the DOJ and the EPA, the EPA
has indicated its belief that additional similar violations have occurred at our Oak Grove facility and has expressed
interest in pursuing a global settlement. On January 19, 2018, we received an offer from the DOJ to globally settle the
government’s claim for civil penalties associated with the alleged violations at both the Moundsville and the Oak Grove
facilities for $1.955 million. We are currently evaluating the penalty assessment and the proposed global settlement
offer and will respond to the agencies.
On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental
Protection Division (GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated
rules arising from a permit issued by GADNR for construction of the Dalton Project. Pursuant to the Consent Order,
we paid a fine of $168,750 and agreed to perform a Corrective Action Order to remedy the alleged violations.
On January 19, 2018, we received notice from the PHMSA regarding certain alleged violations of PHMSA
regulations in connection with a fire and release of liquid ethane that occurred at our Houston Meter Station located
near Houston, Washington County, PA on December 24, 2014. The Notice of Probable Violation and Proposed Civil
Penalty issued by PHMSA alleges failure to timely notify the National Response Center of a release of a hazardous
36
liquid resulting in a fire or explosion and failure to verify that the facility was constructed, inspected, tested, and
calibrated in accordance with comprehensive written specifications or standards and proposes a total civil penalty of
$174,100. We are currently evaluating the penalty assessment and will respond to the agency.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in
Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under
Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.
Other Litigation
The additional information called for by this Item is provided in Note 17 – Contingent Liabilities and Commitments
of Notes to Consolidated Financial Statements included under Part II, Item 8 Financial Statements of this report, which
information is incorporated by reference into this Item.
Item 4. Mine Safety Disclosures
Not applicable.
37
Executive Officers of the Registrant
The name, age, period of service, and title of each of our executive officers as of February 22, 2018, are listed
below. Williams Partners L.P. merged with ACMP in February 2015 (the ACMP Merger). ACMP was the surviving
entity in the ACMP Merger and changed its name to Williams Partners L.P. References in the biographical information
below to (a) “Pre-merger WPZ” will mean Williams Partners L.P. prior to the ACMP Merger and (b) “ACMP/WPZ”
will refer to both ACMP prior to and after the ACMP Merger, when it changed its name to Williams Partners L.P.
Alan S. Armstrong
Director, Chief Executive Officer, and President
Age: 55
Position held since January 2011.
Mr. Armstrong has served as our Chief Executive Officer and President and
a director of Williams since January 2011. Mr. Armstrong has served as a
director of the general partner of ACMP/WPZ since 2012, as Chief Executive
Officer of ACMP/WPZ since December 31, 2014, and as Chairman of the
Board of ACMP/WPZ since February 2, 2015. Mr. Armstrong also served
as Chairman of the Board and Chief Executive Officer of the general partner
of Pre-merger WPZ from 2011 until the ACMP Merger, as Senior Vice
President - Midstream of Pre-merger WPZ from 2010 to 2011, and a director
and Chief Operating Officer of Pre-merger WPZ from 2005 to 2010. From
2002 to 2011, Mr. Armstrong served as Williams’ Senior Vice President -
Midstream and acted as president of our midstream business. From 1999 to
2002, Mr. Armstrong was Vice President, Gathering and Processing in our
midstream business and from 1998 to 1999 was Vice President, Commercial
Development. Mr. Armstrong has served as a director of BOK Financial
Corporation, a financial services company, since 2013.
Walter J. Bennett
Senior Vice President - West
Age: 48
Position held since January 2015.
Mr. Bennett has served as our Senior Vice President - West since January
2015. Mr. Bennett has served as Senior Vice President - West of the general
partner of ACMP/WPZ since December 2013 and as Senior Vice President -
West of the general partner of Pre-merger WPZ from January 2015 until the
ACMP Merger. Mr. Bennett previously served as a director of the general
partner of ACMP/WPZ from February 2017 through November 2017. Mr.
Bennett was formerly Chief Operating Officer of Chesapeake Midstream
Development and served as Senior Vice President - Operations at Boardwalk
Pipeline Partners.
38
John D. Chandler
Senior Vice President and Chief Financial Officer
Age: 48
Position held since September 2017.
Mr. Chandler has served as our Senior Vice President and Chief Financial
Officer since September 2017, and as a director of the general partner of
ACMP/WPZ since November 2017. Mr. Chandler most recently served as
Senior Vice President and Chief Financial Officer of Magellan GP, LLC, the
general partner of Magellan Midstream Partners, LP from 2009 until his
retirement in March 2014. From 2003 until 2009, he served as Senior Vice
President and Chief Financial Officer for the general partner of Magellan
Midstream Holdings, L.P. From 1992 until 2002, Mr. Chandler held various
accounting and finance roles within Williams and MAPCO Inc., prior to its
acquisition by Williams. Mr. Chandler has served as a director of Matrix
Service Company since June 2017.
Micheal G. Dunn
Executive Vice President and Chief Operating Officer
Age: 52
Position held since February 2017.
Mr. Dunn has served as our Executive Vice President and Chief Operating
Officer and as a director of the general partner of ACMP/WPZ since February
2017. Previously, Mr. Dunn served as President of Questar Pipeline and as
Executive Vice President of Questar Corporation from 2015 through 2017.
Prior to that, Mr. Dunn served as President and Chief Executive Officer of
PacifiCorp Energy from 2010 through 2015, a subsidiary of Berkshire
Hathaway Energy. Earlier, Mr. Dunn was president of Kern River Gas
Transmission Company, a Berkshire Hathaway Energy interstate natural gas
pipeline subsidiary. He joined Kern River in 1990, having served in various
leadership roles in the areas of operations, construction, engineering and
information technology before being named President of Kern River in 2007.
Mr. Dunn began his career with Williams as an operations engineer and spent
14 years with the company in a variety of technical and leadership roles.
Frank J. Ferazzi
Senior Vice President - Atlantic Gulf
Age: 61
Position held since June 2017
Mr. Ferazzi has served as our Senior Vice President - Atlantic-Gulf since June
2017. Previously, Mr. Ferazzi served as VP & GM Eastern Interstates from
November 2014 through June 2017, and previously as VP & GM Transco
from January 2013 through January 2015. Prior to that, Mr. Ferazzi served
as VP Commercial Operations - Gas Pipeline from May 2010 through
December 2012.
39
John E. Poarch
Senior Vice President - Engineering Services
Age: 52
Position held since November 2017.
Mr. Poarch has served as our Senior Vice President - Engineering Services
since November 2017. Previously, he served as VP Commercial West OA
from March 2017 through November 2017, and before that, as VP
Commercial & Business Development from January 2015 through March
2017. Previously, Mr. Poarch was the general manager for Access
Midstream’s Eagle Ford operations.
James E. Scheel
Senior Vice President - Northeast G&P
Age: 53
Position held since January 2014.
Mr. Scheel has served as our Senior Vice President - Northeast G&P since
January 2014. Mr. Scheel served as a director of ACMP/WPZ from the ACMP
Merger until November 2017. Mr. Scheel served as a director of the Pre-
merger WPZ general partner from 2012 until the ACMP Merger. Mr. Scheel
served as a director of the Pre-merger ACMP general partner from December
2012 to February 2014. Previously, Mr. Scheel served as Senior Vice President
- Corporate Strategic Development of Williams and the Pre-merger WPZ
general partner from February 2012 to January 2014. Mr. Scheel served as
Vice President of Business Development of Williams’ midstream business
from January 2011 to February 2012.
Ted T. Timmermans
Vice President, Controller, and Chief Accounting Officer
Age: 61
Position held since July 2005.
Mr. Timmermans has served as our Vice President, Controller, and Chief
Accounting Officer since July 2005. Mr. Timmermans has served in the same
roles for the general partner of ACMP/WPZ since the ACMP Merger. Mr.
Timmermans served as Chief Accounting Officer of WMZ from 2008 until
its merger with Pre-Merger WPZ in 2010. Previously, Mr. Timmermans
served as our Assistant Controller from 1998 to 2005.
T. Lane Wilson
Senior Vice President, General Counsel and Chief Compliance Officer
Age: 51
Position held since April 2017.
Mr. Wilson has served as Senior Vice President, General Counsel and Chief
Compliance Officer since April 2017. Prior to joining Williams, Mr. Wilson
served as a United States Magistrate Judge for the Northern District of
Oklahoma from 2009 until he joined Williams in April 2017. Mr. Wilson
previously served as a shareholder and member of the board of directors of
the Hall Estill law firm from 1994 through 2008.
40
Chad J. Zamarin
Senior Vice President - Corporate Strategic Development
Age: 41
Position held since June 2017.
Mr. Zamarin has served as our Senior Vice President - Corporate Strategic
Development since June 2017. Mr. Zamarin has served as a director of the
general partner of ACMP/WPZ since November 2017. Previously, he served
as President, Pipeline and Midstream at Cheniere Energy from 2014 through
2017. Prior to joining Cheniere, Mr. Zamarin served as the Chief Operating
Officer at NiSource Midstream, LLC and NiSource Energy Ventures, LLC,
as well as the President of Pennant Midstream, LLC, a joint venture with
Hilcorp Energy.
41
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business
on February 19, 2018, we had approximately 6,979 holders of record of our common stock. The high and low sales
price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past
two years are as follows:
High
Low
Dividend
2017
First Quarter .......................................................................................... $
Second Quarter .....................................................................................
Third Quarter ........................................................................................
Fourth Quarter ......................................................................................
2016
First Quarter .......................................................................................... $
Second Quarter .....................................................................................
Third Quarter ........................................................................................
Fourth Quarter ......................................................................................
$
$
32.69
31.25
32.18
30.72
26.68
23.89
31.43
32.21
$
$
27.68
27.65
28.76
26.82
10.22
14.60
19.68
27.35
0.30
0.30
0.30
0.30
0.64
0.64
0.20
0.20
Some of our subsidiaries’ borrowing arrangements may limit the transfer of funds to us. These terms have not
impeded, nor are they expected to impede, our ability to pay dividends. On February 21, 2018, our board of directors
approved a regular quarterly dividend of $0.34 per share payable on March 26, 2018.
Performance Graph
Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming
reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index and the Bloomberg
Americas Pipelines Index for the period of five fiscal years commencing January 1, 2013. The Bloomberg
Americas Pipelines Index is composed of Enbridge Inc., Kinder Morgan, Inc., TransCanada Corporation, ONEOK,
Inc., Pembina Pipeline Corporation, Cheniere Energy, Inc., Targa Resources Corp., Inter Pipeline Ltd., Keyera Corp.,
AltaGas Ltd., Plains GP Holdings, L.P., and Williams. The graph below assumes an investment of $100 at the beginning
of the period.
The Williams Companies, Inc................
S&P 500 Index .......................................
Bloomberg Americas Pipelines Index....
2012
100.0
100.0
100.0
2014
149.1
150.5
130.0
2015
90.6
152.5
71.5
2016
119.1
170.8
105.0
2017
121.5
208.1
104.7
2013
122.8
132.4
111.0
42
Item 6. Selected Financial Data
The following financial data at December 31, 2017 and 2016, and for each of the three years in the period ended
December 31, 2017, should be read in conjunction with the other financial information included in Part II, Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial
Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting
records.
Revenues (1)............................................................................. $ 8,031
Income (loss) from continuing operations (2)..........................
2,509
Amounts attributable to The Williams Companies, Inc.:
(Millions, except per-share amounts)
$ 7,637
$ 7,360
$ 7,499
2,335
(1,314)
(350)
$ 6,860
679
Income (loss) from continuing operations (2)...................
Diluted earnings (loss) per common share:
2,174
(424)
(571)
2,110
441
2017
2016
2015
2014
2013
Income (loss) from continuing operations (2) ...........
Total assets at December 31 (3) ...............................................
Commercial paper and long-term debt due within one year at
December 31 (4) ...................................................................
Long-term debt at December 31 (3) .........................................
Stockholders’ equity at December 31 (3) (5) ...........................
Cash dividends declared per common share ............................
_________
(1) Revenues for 2014 increased reflecting the consolidation of ACMP beginning in third quarter and new Canadian
802
20,780
8,777
1.958
878
22,624
4,643
1.680
501
20,434
9,656
1.200
675
23,812
6,148
2.450
226
11,276
4,864
1.438
(.57)
46,835
(.76)
49,020
2.91
50,455
.64
27,065
2.62
46,352
construction management services.
(2)
Income (loss) from continuing operations:
• For 2017 includes a $1.923 billion benefit for income taxes resulting from Tax Reform rate change, a $1.095
billion pre-tax gain on the sale of our Geismar Interest, partially offset by $1.248 billion of pre-tax impairments
of certain assets, and $776 million of pre-tax regulatory charges resulting from Tax Reform;
• For 2016 includes an $873 million impairment of certain assets and a $430 million impairment of certain
equity-method investments;
• For 2015 includes a $1.4 billion impairment of certain equity-method investments and a $1.1 billion impairment
of goodwill;
• For 2014 includes $2.5 billion pre-tax gain recognized as a result of remeasuring to fair value the equity-
method investment we held before we acquired a controlling interest in ACMP, $246 million of insurance
recoveries related to the 2013 Geismar Incident, and $154 million of cash received related to a contingency
settlement. 2014 also includes $78 million of pre-tax equity losses from Bluegrass Pipeline and Moss Lake
related primarily to the underlying write-off of previously capitalized project development costs and $76
million of pre-tax acquisition, merger, and transition expenses related to our acquisition of ACMP;
• For 2013 includes $99 million of deferred income tax expense incurred on undistributed earnings of our foreign
operations that are no longer considered permanently reinvested.
(3) The increases in 2014 reflect assets acquired and debt assumed primarily related to our acquisition of ACMP in
third quarter as well as $1.9 billion of related debt issuances and $2.8 billion of debt issuances at WPZ. Additionally,
we issued $3.4 billion of equity.
(4) The increase in 2014 reflects borrowings under WPZ’s commercial paper program, which was initiated in 2013.
(5) The increase in 2017 includes our issuance of common stock as part of our Financial Repositioning.
43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource
plays to growing markets for natural gas and NGLs. Our operations are located principally in the United States. We
have one reportable segment, Williams Partners. All remaining business activities are included in Other.
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, which includes gas pipeline and
midstream businesses. The gas pipeline businesses include interstate natural gas pipelines and pipeline joint project
investments; and the midstream businesses provide natural gas gathering, treating, and processing services; NGL
production, fractionation, storage, marketing, and transportation; deepwater production handling and crude oil
transportation services; and are comprised of several wholly owned and partially owned subsidiaries and joint project
investments. As of December 31, 2017, we own 74 percent of the interests in WPZ.
Williams Partners’ gas pipeline businesses consist primarily of Transco and Northwest Pipeline. The gas pipeline
business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent
equity-method investment in Gulfstream and a 41 percent interest in Constitution (a consolidated entity), which is
developing a pipeline project. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial Statements.)
As of December 31, 2017, Transco and Northwest Pipeline owned and operated a combined total of approximately
13,600 miles of pipelines with a total annual throughput of approximately 4,533 Tbtu of natural gas and peak-day
delivery capacity of approximately 18.8 MMdth of natural gas.
Williams Partners’ midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and
processing; (2) NGL fractionation, storage, and transportation; (3) crude oil production handling and transportation;
and (4) olefins production. (See Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
The primary service areas are concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New
Mexico, Wyoming, the Gulf of Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio, which include
the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and
NGL fractionation and transportation assets, including a 62 percent equity-method investment in UEOM, a 69 percent
equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, a 60 percent equity-
method investment in Discovery, a 50 percent equity-method investment in OPPL, and Appalachia Midstream Services,
LLC, which owns an approximate average 66 percent equity-method investment interest in multiple gas gathering
systems in the Marcellus Shale (Appalachia Midstream Investments), as well as our previously owned 50 percent
equity-method investment in the Delaware basin gas gathering system (DBJV) in the Mid-Continent region (see
Note 5 – Investing Activities of Notes to Consolidated Financial Statements).
The midstream businesses previously included Canadian midstream operations, which were comprised of an oil
sands offgas processing plant near Fort McMurray, Alberta and an NGL/olefin fractionation facility at Redwater, Alberta.
In September 2016, these Canadian operations were sold.
Williams Partners’ ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission
and midstream infrastructures where our assets can be fully utilized and drive low per-unit costs. We focus on consistently
attracting new business by providing highly reliable service to our customers and investing in growing markets and
areas of increasing natural gas demand.
Williams Partners’ interstate transmission and related storage activities are subject to regulation by the FERC and
as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion
or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are
established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have
44
limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity
reservation charges in transportation rates.
Other
Other is comprised of business activities that are not operating segments, as well as corporate operations. Other
also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids
extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane
dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold.
Financial Repositioning
In January 2017, we entered into agreements with WPZ, wherein we permanently waived the general partner’s
IDRs and converted our 2 percent general partner interest in WPZ to a noneconomic interest in exchange for 289 million
newly issued WPZ common units. Pursuant to this agreement, we also purchased approximately 277 thousand WPZ
common units for $10 million. Additionally, we purchased approximately 59 million common units of WPZ at a price
of $36.08586 per unit in a private placement transaction, funded with proceeds from our equity offering (see Note 14
– Stockholders’ Equity of Notes to Consolidated Financial Statements). According to the terms of this agreement,
concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional consideration totaling
$56 million to WPZ for these units. Subsequent to these transactions and as of December 31, 2017, we own a 74 percent
limited partner interest in WPZ.
Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition
and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated
financial statements and notes thereto included in Part II, Item 8 of this report.
Dividends
In December 2017, we paid a regular quarterly dividend of $0.30 per share. On February 21, 2018, our board of
directors approved a regular quarterly dividend of $0.34 per share payable on March 26, 2018.
Overview
Net income (loss) attributable to The Williams Companies, Inc., for the year ended December 31, 2017, changed
favorably by $2.598 billion compared to the year ended December 31, 2016, reflecting a $1.949 billion improvement
in the provision (benefit) for income taxes primarily due to Tax Reform, the absence of $430 million of impairments
of equity-method investments incurred in 2016, a $219 million increase in Other investing income (loss) – net primarily
associated with the disposition of certain equity-method investments in 2017, a $204 million increase in operating
income and reduced interest expense, partially offset by a $261 million increase in net income attributable to
noncontrolling interests primarily due to increased income at WPZ. The increase in operating income reflects a gain
of $1.095 billion from the sale of our Geismar Interest, increased service revenue from expansion projects, and lower
costs and expenses, partially offset by a $674 million regulatory charge resulting from Tax Reform, a $375 million
increase in impairments of certain assets, and a $184 million decrease in product margins primarily due to the loss of
olefins volumes as a result of the sale of our Gulf Olefins and Canadian operations.
Tax Reform
In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate
income tax rate from 35 percent to 21 percent (Tax Reform). As a result, we have remeasured our existing deferred
income tax assets and liabilities, to reflect the expected future realization of existing temporary differences at the lower
income tax rate. This resulted in the recognition of a net income tax provision benefit of $1.923 billion for the year
ended December 31, 2017. Certain adjustments within the provision benefit are considered provisional and are
potentially subject to change in the future. (See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated
Financial Statements.)
45
Transco and Northwest Pipeline have recognized regulatory liabilities to reflect the probable return to customers
through future rates of the future decrease in income taxes payable associated with Tax Reform. These liabilities
represent an obligation to return amounts directly to our customers. The regulatory liabilities were recorded in December
2017 through regulatory charges to operating income totaling $674 million. (See Note 1 – General, Description of
Business, Basis of Presentation, and Summary of Significant Accounting Policies of Notes to Consolidated Financial
Statements.) The timing and actual amount of such return will be subject to future negotiations regarding this matter
and many other elements of cost-of-service rate proceedings, including other costs of providing service.
Revenue Recognition
As a result of the adoption of Accounting Standards Update 2014-09, Revenues from Contracts with Customers
(ASC 606), we expect that our 2018 revenues will increase in situations where we receive noncash consideration, which
exists primarily in certain of our gas processing contracts where we receive commodities as full or partial consideration
for services provided. This increase in revenues will be offset by a similar increase in costs and expenses when the
commodities received are subsequently sold. Based on commodities received during 2017 as consideration for services
and market prices during 2017, we estimate the impact to revenues and costs would have been approximately $350
million.
Additionally, we expect future revenues will be impacted by application of the new accounting standard to certain
contracts for which we received prepayments for services and have recorded deferred revenue (contract liabilities).
For these contracts, which underwent modifications in periods prior to January 1, 2018, the modification is treated as
a termination of the existing contract and the creation of a new contract. The new accounting guidance requires that
the transaction price, including any remaining deferred revenue from the old contract, be allocated to the performance
obligations over the term of the new contract. As a result, we will recognize the deferred revenue over longer periods
than application of revenue recognition under accounting guidance prior to January 1, 2018. The application of ASC
606 to prior periods related to these contracts would have resulted in lower revenues in 2016 and 2017. Revenues will
also be lower in 2018 and 2019 than what would have been recorded under the previous guidance, offset by increased
revenues in later reporting periods given the longer period of recognition.
We are adopting ASC 606 utilizing the modified retrospective transition approach, effective January 1, 2018, by
recognizing the cumulative effect of initially applying ASC 606 for periods prior to January 1, 2018, which we expect
to result in a decrease of approximately $255 million, net of tax, to the opening balance of Total equity in the Consolidated
Balance Sheet. This adjustment is primarily associated with the impact to the timing of deferred revenue (contract
liabilities) for certain contracts as noted above.
Pension Deferred Vested Benefit Early Payout Program
In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment
risk, cash funding volatility, and administrative costs. In December 2017, the lump-sum payments were made and the
annuity payments were commenced in relation to this program. As a result of these lump-sum payments, as well as
lump-sum benefit payments made throughout 2017, settlement accounting was required. We settled $261 million in
liabilities and recognized a pre-tax, non-cash settlement charge of $71 million. (See Note 9 – Employee Benefit Plans
of Notes to Consolidated Financial Statements.)
Expansion Project Completions
Virginia Southside II
In December 2017, the Virginia Southside II expansion project to the Transco system was placed into service. The
project expanded Transco’s existing natural gas transmission system together with greenfield facilities to provide
incremental firm transportation capacity from our Station 210 in New Jersey and our Station 165 in Virginia to a new
lateral extending from our Brunswick Lateral in Virginia. The project increased capacity by 250 Mdth/d.
46
New York Bay Expansion
In October 2017, the New York Bay expansion to the Transco system was placed into service. The project expanded
Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station
195 in Pennsylvania to the Rockaway Delivery Lateral transfer point and the Narrows meter station in New York. The
project increased capacity by 115 Mdth/d.
Dalton
In August 2017, the Dalton expansion to the Transco system was placed into service. This project expanded
Transco’s existing natural gas transmission system together with greenfield facilities to provide incremental firm
transportation capacity from our Station 210 in New Jersey to markets in northwest Georgia. On April 1, 2017, we
began providing firm transportation service through the mainline portion of the project on an interim basis and we
placed the full project into service in August 2017. The project increased capacity by 448 Mdth/d.
Hillabee
In July 2017, Phase I of the Hillabee Expansion Project was placed into service. The project involves an expansion
of Transco’s existing natural gas transmission system from our Station 85 in west central Alabama to a new
interconnection with the Sabal Trail pipeline in Alabama. The project will be constructed in phases, and all of the
project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. We placed a portion of
Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased capacity
by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together they are expected
to increase capacity by 1,025 Mdth/d.
In March 2016, WPZ entered into an agreement with the member-sponsors of Sabal Trail to resolve several matters.
In accordance with the agreement, the member-sponsors paid us an aggregate amount of $240 million in three equal
installments as certain milestones of the project were met. The first $80 million payment was received in March 2016,
the second installment was received in September 2016 and the third installment was received in July 2017. WPZ
expects to recognize income associated with these receipts over the term of the capacity lease agreement.
In August 2017, the Court of Appeals for the District of Columbia Circuit granted an appeal of the FERC certificate
order for the Southeast Market Pipelines projects (a group of related projects, including the Hillabee Expansion Project)
filed by certain non-governmental organizations. In doing so, the court (i) remanded the matter to the FERC for
preparation of an Environmental Impact Statement (EIS) that conforms with the court’s opinion regarding quantifying
certain greenhouse gas emissions, and (ii) vacated the FERC’s certificate order for the projects, which would be effective
following the court’s mandate (by court order, the mandate will not issue until after disposition of all petitions for
rehearing). We, along with other intervenors, and the FERC filed petitions for rehearing with the court to overturn the
remedy that would involve vacating the FERC certificate order, but on January 31, 2018 the court denied the petitions.
In compliance with the court’s directive, on February 5, 2018, the FERC issued a Final Supplemental EIS for the
projects, reaffirming that while the projects would result in temporary and permanent impacts on the environment,
those impacts would not be significant. On February 6, 2018, we, along with other intervenors, and the FERC filed
motions with the court to stay the issuance of the mandate in order to give the FERC time to re-issue the authorizations
for the projects. The filing of the motions automatically stays the effectiveness of the court’s mandate. If the court’s
mandate is issued prior to the FERC re-issuing the authorizations for the projects, we believe that the FERC will take
the necessary steps (which may include issuing temporary certificate authority) to avoid any lapse in federal authorization
for the projects.
Geismar olefins facility monetization
In July 2017, WPZ completed the sale of its Geismar Interest for $2.084 billion in cash. WPZ received a final
working capital adjustment of $12 million in October 2017. Additionally, WPZ entered into a long-term supply and
transportation agreement with the purchaser to provide feedstock to the plant via its Bayou Ethane pipeline system,
which is expected to provide a long-term, fee-based revenue stream. (See Note 2 – Acquisitions and Divestitures of
Notes to Consolidated Financial Statements.)
47
Following this sale, the cash proceeds were used to repay WPZ’s $850 million term loan. WPZ has also been using
these proceeds to fund a portion of the capital and investment expenditures that are a part of its growth portfolio.
Acquisition of additional interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in
two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash.
Following this exchange, WPZ has an approximate average 66 percent interest in the Appalachia Midstream Investments.
WPZ also sold all of its interest in Ranch Westex JV LLC for $45 million. These transactions resulted in a total gain
of $269 million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations within the
Williams Partners segment. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
Commodity Prices
NGL per-unit margins were approximately 62 percent higher in 2017 compared to 2016 due to a 42 percent increase
in per-unit non-ethane prices. The per-unit margin increase also reflects the absence of our former Canadian operations
which had lower per-unit non-ethane margins in the prior year compared to our domestic operations. These favorable
impacts were partially offset by an approximate 26 percent increase in per-unit natural gas feedstock prices.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party
transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the
processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at
our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating
value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with
no obligation to replace the lost heating value.
The following graph illustrates the NGL production and sales volumes, as well as the margin differential between
ethane and non-ethane products and the relative mix of those products.
48
The potential impact of commodity prices on our business is further discussed in the following Company Outlook.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the
vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting
the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural
gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship,
operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver
safe and reliable service to our customers and an attractive return to our shareholders.
Our business plan for 2018 includes a continued focus on growing our fee-based businesses, executing growth
projects and accomplishing cost discipline initiatives to ensure operations support our strategy. We anticipate operating
results will increase through organic business growth driven primarily by Transco expansion projects and continued
growth in the Northeast region. WPZ intends to fund planned growth capital with retained cash flow and debt, and
based on currently forecasted projects, does not expect to access public equity markets for the next several years.
Our growth capital and investment expenditures in 2018 are expected to be approximately $2.7 billion.
Approximately $1.7 billion of our growth capital funding needs include Transco expansions and other interstate pipeline
growth projects, most of which are fully contracted with firm transportation agreements. The remaining growth capital
spending in 2018 primarily reflects investment in gathering and processing systems in the Northeast region limited
primarily to known new producer volumes, including volumes that support Transco expansion projects including our
Atlantic Sunrise project. In addition to growth capital and investment expenditures, we also remain committed to
projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or
contractual commitments.
49
As a result of our significant continued capital and investment expenditures on Transco expansions and fee-based
gathering and processing projects, fee-based businesses are a significant component of our portfolio and serve to reduce
the influence of commodity price fluctuations on our operating results and cash flows. We expect to benefit as continued
growth in demand for low-cost natural gas is driven by increases in LNG exports, industrial demand and power
generation. For 2018, current forward market prices indicate oil prices are expected to be higher compared to 2017,
while natural gas and NGL prices are expected to be lower or comparable with 2017. We continue to address certain
pricing risks through the utilization of commodity hedging strategies. However, some of our customers may continue
to curtail or delay drilling plans until there is a more sustained recovery in prices, which may negatively impact our
gathering and processing volumes. The credit profiles of certain of our producer customers have been, and may continue
to be, challenged as a result of lower energy commodity prices. Unfavorable changes in energy commodity prices or
the credit profile of our producer customers may also result in noncash impairments of our assets.
In 2018, our operating results are expected to include increases from our regulated Transco fee-based business,
primarily related to projects recently placed in-service or expected to be placed in-service in 2018 including the Atlantic
Sunrise project. For our non-regulated businesses, we anticipate increases in fee-based revenue in the Northeast region,
partially offset by lower fee-based revenue in the West region. As previously discussed, under the new accounting
guidance for revenue recognition, deferred revenue under certain contracts will be recognized over longer periods than
under the prior guidance, resulting in a decrease in revenue for the West region. We expect overall gathering and
processing volumes to grow in 2018 and increase thereafter to meet the growing demand for natural gas and natural
gas products. We also anticipate lower general and administrative expenses due to the full year impact of prior year
cost reduction initiatives.
Potential risks and obstacles that could impact the execution of our plan include:
• Certain aspects of Tax Reform, including regulatory liabilities relating to reduced corporate federal income
tax rates, could adversely impact the rates we can charge on our regulated pipelines;
• Opposition to infrastructure projects, including the risk of delay or denial in permits and approvals needed for
our projects;
• Unexpected significant increases in capital expenditures or delays in capital project execution;
• Counterparty credit and performance risk, including that of Chesapeake Energy Corporation and its affiliates;
• Lower than anticipated demand for natural gas and natural gas products which could result in lower than
expected volumes, energy commodity prices and margins;
• General economic, financial markets, or further industry downturn, including increased interest rates;
• Physical damages to facilities, including damage to offshore facilities by named windstorms;
• Lower than expected distributions from WPZ;
•
Production issues impacting offshore gathering volumes;
• Other risks set forth under Part I, Item 1A. Risk Factors in this report.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy
infrastructure assets which continue to serve key growth markets and supply basins in the United States.
50
Expansion Projects
Williams Partners’ ongoing major expansion projects include the following:
Atlantic Sunrise
In February 2017, we received approval from the FERC to expand Transco’s existing natural gas transmission
system along with greenfield facilities to provide incremental firm transportation capacity from the northeastern
Marcellus producing area to markets along Transco’s mainline as far south as Station 85 in west central Alabama.
We placed a portion of the mainline project facilities into service in September 2017 and it increased capacity by
400 Mdth/d. We plan to place the full project into service during mid-2018, assuming timely receipt of all
remaining regulatory approvals. The full project is expected to increase capacity by 1,700 Mdth/d.
Constitution Pipeline
We currently own 41 percent of Constitution with three other parties holding 25 percent, 24 percent, and 10
percent, respectively. We are the operator of Constitution. The 126-mile Constitution pipeline is proposed to connect
our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas
Pipeline systems in New York, as well as to a local distribution company serving New York and Pennsylvania.
In December 2014, Constitution received approval from the FERC to construct and operate its proposed
pipeline, which will have an expected capacity of 650 Mdth/d. However, in April 2016, the New York State
Department of Environmental Conservation (NYSDEC) denied the necessary water quality certification under
Section 401 of the Clean Water Act for the New York portion of the pipeline. In May 2016, Constitution appealed
the NYSDEC’s denial of the Section 401 certification to the United States Court of Appeals for the Second Circuit
and in August 2017, the court issued a decision denying in part and dismissing in part Constitution’s appeal. The
court expressly declined to rule on Constitution’s argument that the delay in the NYSDEC’s decision on
Constitution’s Section 401 application constitutes a waiver of the certification requirement. The court determined
that it lacked jurisdiction to address that contention, and found that jurisdiction over the waiver issue lies exclusively
with the United States Court of Appeals for the District of Columbia Circuit. As to the denial itself, the court
determined that NYSDEC’s action was not arbitrary or capricious. Constitution filed a petition for rehearing with
the Second Circuit Court of Appeals, but in October the court denied our petition.
In October 2017, we filed a petition for declaratory order requesting the FERC to find that, by operation of
law, the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project
was waived due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable
period of time as required by the express terms of such statute. In January 2018, the FERC denied our petition,
finding that Section 401 provides that a state waives certification only when it does not act on an application within
one year from the date of the application.
The project’s sponsors remain committed to the project, and, in that regard, we are pursuing two separate and
independent paths in order to overturn the NYSDEC’s denial of the Section 401 certification. In January 2018, we
filed a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals
that upheld the merits of the NYSDEC’s denial of the Section 401 certification. And, in February 2018, we filed
a request with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification
requirement. If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of
Appeals.
We estimate that the target in-service date for the project would be approximately 10 to 12 months following
any court or FERC decision that the NYSDEC denial order was improper or that the NYSDEC waived the Section
401 certification requirement. (See Note 3 – Variable Interest Entities of Notes to Consolidated Financial
Statements.)
Garden State
In April 2016, we received approval from the FERC to expand Transco’s existing natural gas transmission
system to provide incremental firm transportation capacity from Station 210 in New Jersey to a new interconnection
51
on our Trenton Woodbury Lateral in New Jersey. The project will be constructed in phases and is expected to
increase capacity by 180 Mdth/d. We placed the initial phase of the project into service in September 2017 and
plan to place the remaining portion of the project into service during the first quarter of 2018.
Gateway
In November 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission
system to provide incremental firm transportation capacity from PennEast Pipeline Company's proposed
interconnection with Transco’s mainline south of Station 205 in New Jersey to other existing Transco meter stations
within New Jersey. We plan to place the project into service in the first quarter of 2021, assuming timely receipt
of all necessary regulatory approvals. The project is expected to increase capacity by 65 Mdth/d.
Gulf Connector
In November 2017, we received approval from the FERC allowing Transco to expand its existing natural gas
transmission system to provide incremental firm transportation capacity from Station 65 in Louisiana to delivery
points in Wharton and San Patricio Counties, Texas. The project will be constructed in two phases and we plan
to place both phases into service during the first half of 2019, assuming timely receipt of all necessary regulatory
approvals. The project is expected to increase capacity by 475 Mdth/d.
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion
Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85
in west central Alabama to a new interconnection with the Sabal Trail pipeline in Alabama. The project will be
constructed in phases, and all of the project expansion capacity will be leased to Sabal Trail. We placed a portion
of Phase I into service in June of 2017 and the remainder of Phase I into service in July of 2017. Phase I increased
capacity by 818 Mdth/d. The in-service date of Phase II is planned for the second quarter of 2020 and together
they are expected to increase capacity by 1,025 Mdth/d. See Expansion Project Completions within Overview.
Norphlet Project
In March 2016, we announced that we have reached an agreement to provide deepwater gas gathering services
to the Appomattox development in the Gulf of Mexico. The project will provide offshore gas gathering services
to our existing Transco lateral, which will provide transmission services onshore to our Mobile Bay processing
facility. We also plan to make modifications to our Main Pass 261 Platform to install an alternate delivery route
from the platform, as well as modifications to our Mobile Bay processing facility. The project is scheduled to go
into service during the second half of 2019.
North Seattle Lateral Upgrade
In May 2017, we filed an application with the FERC to expand delivery capabilities on Northwest Pipeline’s
North Seattle Lateral. The project consists of the removal and replacement of approximately 5.9 miles of 8-inch
diameter pipeline with new 20-inch diameter pipeline. We plan to place the project into service as early as the
fourth quarter of 2019. The project is expected to increase capacity by up to 159 Mdth/d.
Northeast Supply Enhancement
In March 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission
system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway
Delivery Lateral transfer point in New York. We plan to place the project into service in late 2019 or during the
first half of 2020, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase
capacity by 400 Mdth/d.
52
Ohio River Supply Hub Expansion
We agreed to expand our services to a customer to provide 660 MMcf/d of processing wet gas capacity in the
Marcellus and Upper Devonian Shale in West Virginia. Associated with this agreement, we expect to further
expand the processing capacity of our Oak Grove facility, which has the ability to increase capacity by an additional
1.8 Bcf/d. Additionally, with the same customer, we secured a gathering dedication agreement to gather dry gas
in this same region. These expansions will be supported by long-term, fee-based agreements and volumetric
commitments.
Rivervale South to Market
In August 2017, we filed an application with the FERC to expand Transco’s existing natural gas transmission
system to provide incremental firm transportation capacity from the existing Rivervale interconnection with
Tennessee Gas Pipeline on Transco’s North New Jersey Extension to other existing Transco locations within New
Jersey. We plan to place the project into service as early as the fourth quarter of 2019, assuming timely receipt of
all necessary regulatory approvals. The project is expected to increase capacity by 190 Mdth/d.
Susquehanna Supply Hub Expansion
The Susquehanna Supply Hub Expansion, which involves two new compression facilities with an additional
49,000 horsepower and 59 miles of 12 inch to 24 inch pipeline, is expected to increase gathering capacity, allowing
a certain producer to fulfill its commitment to deliver 850 Mdth/d to our Atlantic Sunrise development. We placed
a portion of this project into service in January 2018 and anticipate this expansion will be fully commissioned in
the first quarter of 2018.
Critical Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is
material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact
of these on our financial condition or results of operations.
Pension and Postretirement Obligations
We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit cost
and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions
include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase,
health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions
are reviewed annually and adjustments are made as needed. The assumptions utilized to compute cost and the benefit
obligations are shown in Note 9 – Employee Benefit Plans of Notes to Consolidated Financial Statements.
The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting
from a one-percentage-point change in the specific assumption.
Benefit Cost
Benefit Obligation
One-
Percentage-
Point
Increase
One-
Percentage-
Point
Decrease
One-
Percentage-
Point
Increase
One-
Percentage-
Point
Decrease
Pension benefits:
Discount rate ...................................................................... $
Expected long-term rate of return on plan assets................
Rate of compensation increase ...........................................
Other postretirement benefits:
Discount rate ......................................................................
Expected long-term rate of return on plan assets................
Assumed health care cost trend rate ...................................
(8) $
(12)
2
1
(2)
—
(Millions)
$
9
12
(1)
1
2
—
(118) $
—
9
(22)
—
5
140
—
(6)
27
—
(5)
53
Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based
on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rates
of return on plan assets using our expectations of capital market results, which include an analysis of historical results
as well as forward-looking projections. These capital market expectations are based on a period of at least 10 years and
take into account our investment strategy and mix of assets. We develop our expectations using input from our third-
party independent investment consultant. The forward-looking capital market projections start with current conditions
of interest rates, equity pricing, economic growth, and inflation and those are overlaid with forward looking projections
of normal inflation, growth, and interest rates to determine expected returns. The capital market return projections for
specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the
investment portfolio. The resulting rates are an estimate of future results and, thus, likely to be different than actual
results.
In 2017, the benefit plans’ assets outperformed their respective benchmarks for fixed income strategies, but
generally underperformed the respective benchmarks for equity strategies. While the 2017 investment performance
was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and
are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact
these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans was 6.45
percent in 2017. The 2017 actual return on plan assets for our pension plans was approximately 15.5 percent. The 10-
year average rate of return on pension plan assets through December 2017 was approximately 4.3 percent.
The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit
plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date
in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due.
Increases in the discount rates decrease the obligation and, generally, decrease the related cost. The discount rates for
our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans
and their respective expected benefit cash flows as described in Note 1 – General, Description of Business, Basis of
Presentation, and Summary of Significant Accounting Policies and Note 9 – Employee Benefit Plans of Notes to
Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and
market conditions that affect interest rates on long-term, high-quality debt securities as well as by the duration of our
plans’ liabilities.
The expected rate of compensation increase represents average long-term salary increases. An increase in this rate
causes the pension obligation and cost to increase.
The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost
rates and plan design. An increase in this rate causes the other postretirement benefit obligation and cost to increase.
Property, Plant, and Equipment and Other Identifiable Intangible Assets
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events
or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable.
When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable
to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a
probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes
including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying
value has occurred, we determine the amount of the impairment recognized by estimating the fair value of the assets
and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed
at the lowest level for which separately identifiable cash flows exist.
During the third quarter of 2017, we received solicitations and engaged in negotiations for the sale of certain gas
gathering assets within the Mid-Continent region. As a result of these events, we evaluated the Mid-Continent asset
group, which includes property, plant, and equipment and intangible assets, for impairment. Our evaluation considered
the likelihood of divesting certain assets within the Mid-Continent region as well as information developed from the
negotiation process that impacted our estimate of future cash flows associated with these assets. The estimated
undiscounted future cash flows were determined to be below the carrying amount for these assets. We computed the
54
estimated fair value using an income approach and incorporated market inputs based on ongoing negotiations for the
potential sale of a portion of the underlying assets. For the income approach, we utilized a discount rate of 10.2 percent,
reflecting an estimated cost of capital and risks associated with the underlying assets. As a result of this evaluation,
we recorded an impairment charge of $1.019 billion for the difference between the estimated fair value and carrying
amount of these assets.
Judgments and assumptions are inherent in estimating undiscounted future cash flows, fair values, and the
probability-weighting of possible outcomes. The use of alternate judgments and assumptions could result in a different
determination affecting the consolidated financial statements.
Equity-Method Investments
At December 31, 2017, our Consolidated Balance Sheet includes approximately $6.6 billion of investments that
are accounted for under the equity-method of accounting. We evaluate these investments for impairment when events
or changes in circumstances indicate, in our management’s judgment, that the carrying value of such investments may
have experienced an other-than-temporary decline in value. We continue to monitor our equity-method investments
for any indications that the carrying value may have experienced an other-than-temporary decline in value. When
evidence of a loss in value has occurred, we compare our estimate of the fair value of the investment to the carrying
value of the investment to determine whether an impairment has occurred. We generally estimate the fair value of our
investments using an income approach where significant judgments and assumptions include expected future cash
flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair
value of our investments.
If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-
temporary, the excess of the carrying value over the fair value is recognized in the consolidated financial statements
as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline
in value will vary by investment, but may include:
• A significant or sustained decline in the market value of an investee;
• Lower than expected cash distributions from investees;
• Significant asset impairments or operating losses recognized by investees;
• Significant delays in or lack of producer development or significant declines in producer volumes in markets
served by investees;
• Significant delays in or failure to complete significant growth projects of investees.
As of December 31, 2017, the carrying value of our equity-method investment in Discovery is $534 million. During
the fourth quarter of 2017, certain customers of Discovery terminated a significant offshore gas gathering agreement
following the shut-in of production after the associated wells ceased flowing. As a result, we evaluated this investment
for impairment and determined that no impairment was necessary.
We estimated the fair value of our investment in Discovery using an income approach that primarily considered
probability-weighted assumptions of additional commercial development, the continued operation of the business under
existing contracts, and a discount rate of 11.3 percent. Higher probabilities were generally assigned to those commercial
development opportunities that were more advanced in the discussion and contracting process, utilizing existing
infrastructure due to producer capital constraints, and/or we believe Discovery has a competitive advantage due to
geographical proximity to the prospect. The estimated fair value of our investment in Discovery exceeded its carrying
value by approximately 6 percent and thus no impairment was necessary.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and additional
development probabilities. It is reasonably possible that an impairment could be required in the future if commercial
development activities are not as successful or as timely as assumed. The use of alternate judgments and assumptions
55
could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment
charge in the consolidated financial statements.
Constitution Pipeline Capitalized Project Costs
As of December 31, 2017, Property, plant, and equipment – net in our Consolidated Balance Sheet includes
approximately $381 million of capitalized project costs for Constitution, for which we are the construction manager
and own a 41 percent consolidated interest. As a result of the events discussed in Company Outlook, we evaluated the
capitalized project costs for impairment as recently as December 31, 2017, and determined that no impairment was
necessary. Our evaluation considered probability-weighted scenarios of undiscounted future net cash flows, including
scenarios assuming construction of the pipeline, as well as a scenario where the project does not proceed. These scenarios
included our most recent estimate of total construction costs. The probability-weighted scenarios also considered our
assessment of the likelihood of success of the two separate and independent paths to obtain necessary certification, as
described in Company Outlook. It is reasonably possible that future unfavorable developments, such as a reduced
likelihood of success, increased estimates of construction costs, or further significant delays, could result in a future
impairment.
Regulatory Liabilities resulting from Tax Reform
In December 2017, Tax Reform was enacted, which, among other things, reduced the corporate income tax rate
from 35 percent to 21 percent. Rates charged to customers of our regulated natural gas pipelines are subject to the rate-
making policies of the FERC, which permit the recovery of an income tax allowance that includes a deferred income
tax component. As a result of the reduced income tax rate from Tax Reform and the collection of historical rates that
reflected historical federal income tax rates, we expect that our regulated natural gas pipelines will be required to return
amounts to certain customers through future rates and have established regulatory liabilities accordingly. These
liabilities were recorded in December 2017 through regulatory charges to operating income totaling $674 million. (See
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies of
Notes to Consolidated Financial Statements.) The timing and actual amount of such return will be subject to future
negotiations regarding this matter and many other elements of cost–of–service rate proceedings, including other costs
of providing service.
Our estimation of these regulatory liabilities incorporated the following significant judgments and assumptions
involving income taxes collected from our customers.
• We utilized current FERC guidance for the default income tax rate for non-corporate taxpayers, which is an
element of our overall effective tax rate. It is possible that the FERC will provide updated implementation
guidance in the future, including an updated default income tax rate for non-corporate taxpayers. We estimate
that a decline of one percentage point in our assumed overall effective tax rate would increase our regulatory
liabilities by approximately $42 million.
• We made assumptions regarding the allocation of WPZ taxable income between corporate and non-corporate
taxpayers. This allocation is subject to annual variation that could impact the weighted average federal tax
component of the overall income tax allowance rate.
• We made assumptions regarding the allocation of WPZ taxable income among the states in which WPZ
conducts business. This allocation is subject to annual variation that could impact the weighted average state
tax component of the overall income tax allowance rate. It is possible that certain states may change their
income tax laws and/or rates in the future in response to Tax Reform.
•
In determining the estimated liability that we currently believe is probable of return to customers through
future rates, we considered the mix of services provided by our regulated natural gas pipelines, taking into
consideration that certain of these services are provided under contractually-based rates, in lieu of recourse-
based rates. The contractually-based rates are designed to recover the cost of providing those services, with
56
no expected future rate adjustment for the term of those contracts. We estimate that a one percent change in
the relative mix of services would change the regulatory liability by approximately $8 million.
The use of alternative judgments and assumptions could result in the recognition of different regulatory liabilities
and associated charges in the consolidated financial statements.
57
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended
December 31, 2017. The results of operations by segment are discussed in further detail following this consolidated
overview discussion.
Years Ended December 31,
$ Change
from
2016*
% Change
from
2016*
2017
2016
(Millions)
$ Change
from
2015*
% Change
from
2015*
2015
Revenues:
Service revenues .......................................... $ 5,312
2,719
Product sales ................................................
8,031
Total revenues..........................................
Costs and expenses:
Product costs................................................
Operating and maintenance expenses..........
Depreciation and amortization expenses .....
Selling, general, and administrative
expenses...................................................
Impairment of goodwill ...............................
Impairment of certain assets ........................
Gain on sale of Geismar Interest .................
Regulatory charges resulting from Tax
Reform .....................................................
Insurance recoveries – Geismar Incident.....
Other (income) expense – net ......................
Total costs and expenses..........................
Operating income (loss)...................................
Equity earnings (losses)...................................
Impairment of equity-method investments......
Other investing income (loss) – net .................
Interest expense ...............................................
Other income (expense) – net ..........................
Income (loss) before income taxes ..................
Provision (benefit) for income taxes................
Net income (loss).........................................
Less: Net income (loss) attributable to
noncontrolling interests .........................
2,300
1,585
1,736
608
—
1,248
(1,095)
674
(9)
80
7,127
904
434
—
282
(1,083)
(2)
535
(1,974)
2,509
+141
+391
-575
-5
+27
+115
—
-375
+1,095
-674
+2
+62
+37
+430
+219
+96
-76
+1,949
+7
+132
+54
+75
-25
+3% $ 5,171
2,328
+17%
7,499
1,725
1,580
1,763
-33%
—%
+2%
+16%
—%
-43%
NM
723
+18
— +1,098
-664
—
873
—
NM
+29%
+44%
—
(7)
142
6,799
700
397
+9%
(430)
+100%
NM
63
+8% (1,179)
74
NM
(375)
(25)
(350)
NM
—
-119
-102
+62
+929
+36
-135
-28
-374
—% $ 5,164
2,196
+6%
7,360
+3%
+5%
-1%
+2%
+100%
NM
—%
1,779
1,655
1,738
741
1,098
209
—
—%
-94%
NM
—
(126)
40
7,134
226
335
+19%
+68% (1,359)
27
+133%
-13% (1,044)
102
-27%
(1,713)
(399)
(1,314)
-94%
335
-261
NM
74
-817
NM
(743)
Net income (loss) attributable to The
Williams Companies, Inc......................... $ 2,174
$
(424)
$
(571)
_______
* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change
in signs, a zero-value denominator, or a percentage change greater than 200.
2017 vs. 2016
Service revenues increased due to higher transportation fee revenues at Transco and in the eastern Gulf reflecting
expansion projects placed in-service in 2016 and 2017; partially offset by a decrease in gathering, processing, and
fractionation revenue including lower rates, primarily in the Barnett Shale region associated with the restructuring of
58
contracts in the fourth quarter of 2016; lower volumes in the western regions, driven by natural declines and extreme
weather conditions in the Rocky Mountains in 2017; and the sale of our former Canadian and Gulf Olefins operations.
Product sales increased primarily due to higher marketing revenues reflecting significantly higher prices and
volumes. Revenues from the sale of our equity NGLs increased primarily due to higher non-ethane NGL prices, partially
offset by lower volumes. These increases were partially offset by lower olefin production sales due to lower volumes
resulting from the sale of our former Gulf Olefins and Canadian operations.
The increase in Product costs is primarily due to the same factors that increased marketing sales, partially offset
by lower olefin feedstock purchases associated with the sale of our Gulf Olefins and Canadian operations.
Operating and maintenance expenses increased primarily due to higher pipeline integrity testing and general
maintenance at Transco and a settlement charge from a pension early payout program (see Note 9 – Employee Benefit
Plans of Notes to Consolidated Financial Statements), partially offset by the absence of costs associated with our former
Canadian and Gulf Olefins operations and lower labor-related costs resulting from our workforce reductions that
occurred late in first-quarter 2016, and ongoing cost containment efforts.
Depreciation and amortization expenses decreased primarily due to the absence of our former Canadian and Gulf
Olefins operations, partially offset by new assets placed in-service.
Selling, general, and administrative expenses (SG&A) decreased primarily due to the absence of certain project
development costs associated with the Canadian PDH facility that were expensed in 2016, lower labor-related costs
resulting from our workforce reductions that occurred late in first-quarter 2016, ongoing cost containment efforts, lower
strategic development costs, and the absence of costs associated with our former Canadian and Gulf Coast operations.
These decreases were partially offset by higher severance and organizational realignment costs in 2017 (see Note 6 –
Other Income and Expenses of Notes to Consolidated Financial Statements) and a settlement charge from a pension
early payout program.
The unfavorable change in Impairment of certain assets reflects 2017 impairments of certain gathering operations
in the Mid-Continent and Marcellus South regions, certain NGL pipeline assets, and an olefins pipeline project in the
Gulf coast region. These 2017 impairments are partially offset by the absence of 2016 impairments of our former
Canadian operations and certain Mid-Continent assets (see Note 16 – Fair Value Measurements, Guarantees, and
Concentration of Credit Risk of Notes to Consolidated Financial Statements).
The Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017.
(See Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Regulatory charges resulting from Tax Reform relates to the recognition of regulatory liabilities for the probable
return to customers through future rates of the future decrease in income taxes payable associated with Tax Reform.
(See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes the absence of the
2016 loss on the sale of our Canadian operations, gains from certain contract settlements and terminations in 2017, a
gain on the sale of our RGP Splitter in 2017, and the absence of an unfavorable change in foreign currency exchange
associated with our former Canadian operations. These favorable changes are partially offset by additional expense
associated with an annual revision to the ARO liability, accrual of additional expenses in 2017 related to the Geismar
Incident, as well as the absence of a gain in first-quarter 2016 associated with the sale of unused pipe.
Operating income (loss) changed favorably primarily due to the Gain on sale of Geismar Interest, the absence of
the 2016 impairments of certain Mid-Continent assets and our former Canadian operations, higher service revenues
primarily from expansion projects placed in-service in 2016 and 2017, the absence of expensed Canadian PDH facility
project development costs in 2016, as well as ongoing cost containment efforts, including workforce reductions in first-
quarter 2016. Operating income (loss) also improved due to the absence of a 2016 loss on the sale of our Canadian
operations, the absence of an operating loss associated with our former Canadian operations, gains from certain contract
settlements and the sale of our RGP Splitter. These favorable changes were partially offset by 2017 impairments of
59
certain gathering operations in the Mid-Continent and Marcellus South regions, regulatory charges resulting from Tax
Reform, and certain NGL pipeline assets, as well as the absence of operating income associated with our former Gulf
Olefins operations, and a settlement charge from a pension early payout program.
The favorable change in Equity earnings (losses) is due to an increase in ownership of our Appalachia Midstream
Investments and improved results at Aux Sable due to favorable pricing and higher volumes, partially offset by lower
UEOM results driven by lower processing volumes from the Utica gathering system and lower Discovery results due
to lower volumes.
The decrease in Impairment of equity-method investments reflects the absence of 2016 impairment charges
associated with our Appalachia Midstream Investments, DBJV, Laurel Mountain, and Ranch Westex equity-method
investments. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to
Consolidated Financial Statements.)
Other investing income (loss) – net reflects the gain on disposition of our investments in DBJV and Ranch Westex
JV LLC in 2017, partially offset by the absence of interest income received in 2016 associated with a receivable related
to the sale of certain former Venezuelan assets and the absence of a 2016 gain on the sale of an equity-method investment
interest in a gathering system that was part of our Appalachia Midstream Investments. (See Note 5 – Investing Activities
of Notes to Consolidated Financial Statements).
Interest expense decreased primarily due to lower Interest incurred primarily attributable to debt retirements in
2017 and lower borrowings on our credit facilities in 2017. (See Note 13 – Debt, Banking Arrangements, and Leases
of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to charges reducing
regulatory assets related to deferred taxes on equity funds used during construction (AFUDC) resulting from Tax Reform
and a settlement charge from a pension early payout program, partially offset by a net gain on early debt retirements
in 2017, and other favorable changes related to AFUDC. (See Note 5 – Other Income and Expenses of Notes to
Consolidated Financial Statements.)
Provision (benefit) for income taxes changed favorably primarily due to a reduction in the federal statutory rate
from 35 percent to 21 percent with the enactment of Tax Reform. The remeasurement of our existing deferred tax assets
and liabilities at the reduced rate resulted in the recognition of a net income tax provision benefit of $1.923 billion.
Adjustments within this provision benefit are considered provisional and are potentially subject to change in the future.
See Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of
the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the impact
of decreased income allocated to us driven by the permanent waiver of IDRs and higher operating results at WPZ,
partially offset by a decrease in the ownership of the noncontrolling interests. Both the permanent waiver of IDRs and
the change in ownership are associated with the first-quarter 2017 Financial Repositioning (see Note 1 – General,
Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements). In addition, improved
results in our Gulfstar operations also contributed to the increase in Net income (loss) attributable to noncontrolling
interests, partially offset by lower results for our Cardinal gathering system.
2016 vs. 2015
Service revenues increased slightly primarily due to expansion projects placed in service in 2015 and 2016, partially
offset by a decrease in gathering, processing, and fractionation revenue primarily due to lower volumes in the Barnett
Shale and Anadarko basin.
Product sales increased primarily due to higher olefin sales reflecting increased volumes at our former Geismar
plant as a result of the plant operating at higher production levels in 2016, partially offset by a decrease from our other
olefin operations associated with lower volumes and per-unit sales prices. Product sales also reflect higher marketing
revenues associated with higher NGL and propylene prices and natural gas and crude oil volumes, partially offset by
lower NGL volumes, and crude oil prices.
60
The decrease in Product costs includes lower olefin feedstock purchases and lower costs associated with other
product sales, partially offset by higher marketing purchases primarily due to the same factors that increased marketing
sales. The decline in olefin feedstock purchases is primarily associated with lower per-unit feedstock costs and volumes
at our other olefin operations, partially offset by an increase in olefin feedstock purchases at our former Geismar plant
reflecting increased volumes resulting from higher production levels in 2016.
Operating and maintenance expenses decreased primarily due to lower labor-related and outside service costs
resulting from our first-quarter 2016 workforce reductions and cost containment efforts and lower costs associated with
general maintenance activities in the Marcellus Shale, as well as the absence of ACMP transition-related costs recognized
in 2015. These decreases are partially offset by $16 million of severance and related costs recognized in 2016 and
higher pipeline testing and general maintenance costs at Transco.
Depreciation and amortization expenses increased primarily due to depreciation on new assets placed in service,
including Transco pipeline projects, partially offset by lower depreciation related to Canadian operations sold in 2016.
SG&A decreased primarily due to lower merger and transition costs associated with the ACMP merger and lower
labor-related costs resulting from our first-quarter 2016 workforce reductions and cost containment efforts. These
decreases were partially offset by certain project development costs associated with the Canadian PDH facility that we
began expensing in 2016, as well as $26 million of severance and related costs recognized in 2016 and $17 million of
higher costs associated with our evaluation of strategic alternatives.
Impairment of goodwill decreased due to the absence of a 2015 impairment charge associated with certain goodwill.
(See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated
Financial Statements.)
Impairment of certain assets reflects 2016 impairments of our Canadian operations and certain Mid-Continent
assets, and other assets. Impairments recognized in 2015 relate primarily to previously capitalized development costs
and surplus equipment write-downs. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit
Risk of Notes to Consolidated Financial Statements.)
Insurance recoveries – Geismar Incident changed unfavorably reflecting the receipt of $126 million of insurance
proceeds in the second quarter of 2015, as compared to the receipt of $7 million of proceeds in the fourth quarter of
2016.
The unfavorable change in Other (income) expense – net within Operating income (loss) includes a loss on the
sale of our Canadian operations that were sold in September 2016, project development costs at Constitution as we
discontinued capitalization of these costs in April 2016, and an unfavorable change in foreign currency exchange that
primarily relates to losses incurred on foreign currency transactions and the remeasurement of the U.S. dollar-
denominated current assets and liabilities within our former Canadian operations, partially offset by a $10 million gain
on the sale of idle pipe in 2016.
Operating income (loss) changed favorably primarily due to the absence of a goodwill impairment in 2015, higher
olefin margins related to the Geismar plant operating at higher production levels in 2016, lower costs related to the
merger and integration of ACMP, and lower costs and expenses primarily associated with cost containment efforts.
These favorable changes are partially offset by impairments and loss on sale of certain assets in 2016, a decrease in
insurance proceeds received, expensed Canadian PDH facility project development costs, and higher depreciation
expenses related to new projects placed in service.
Equity earnings (losses) changed favorably primarily due to a $30 million increase at Discovery driven by the
completion of the Keathley Canyon Connector in the first quarter of 2015. Additionally, OPPL, Laurel Mountain, and
DBJV improved $16 million, $11 million, and $10 million, respectively.
Impairment of equity-method investments reflects 2016 impairment charges associated with our Appalachia
Midstream Investments, DBJV, Laurel Mountain, and Ranch Westex equity-method investments, while the 2015
impairment charges relate to our equity-method investments in Appalachia Midstream Investments, DBJV, UEOM,
and Laurel Mountain. (See Note 5 – Investing Activities of Notes to Consolidated Financial Statements.)
61
Other investing income (loss) – net changed favorably due to a 2016 gain on the sale of an equity-method investment
interest in a gathering system that was part of our Appalachia Midstream Investments and higher interest income
associated with a receivable related to the sale of certain former Venezuela assets. (See Note 5 – Investing Activities
of Notes to Consolidated Financial Statements.)
Interest expense increased due to higher Interest incurred of $99 million primarily attributable to new debt issuances
in 2016 and 2015 and lower Interest capitalized of $36 million primarily related to construction projects that have been
placed into service, partially offset by lower interest due to 2015 and 2016 debt retirements. (See Note 13 – Debt,
Banking Arrangements, and Leases of Notes to Consolidated Financial Statements.)
Other income (expense) – net below Operating income (loss) changed unfavorably primarily due to a decrease in
AFUDC due to decreased spending on Constitution and the absence of a $14 million gain on early debt retirement in
2015.
Provision (benefit) for income taxes changed unfavorably primarily due to a decrease in pre-tax loss in 2016. See
Note 7 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the
effective tax rates compared to the federal statutory rate for both years.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher
operating results at WPZ, the impact of decreased income allocated to the WPZ general partner driven by the impact
of reduced incentive distributions from WPZ, and the absence of the accelerated amortization of a beneficial conversion
feature from the first quarter of 2015. These changes are partially offset by a favorable change primarily related to our
partners’ share of Constitution project development costs in 2016.
Year-Over-Year Operating Results – Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 18 – Segment Disclosures of
Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss).
Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company
performance. In addition, management believes that this measure provides investors an enhanced perspective of the
operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a
measure of performance prepared in accordance with GAAP.
Williams Partners
Years Ended December 31,
2017
2016
(Millions)
2015
Service revenues............................................................................ $
Product sales..................................................................................
Segment revenues..........................................................................
$
5,292
2,718
8,010
$
5,173
2,318
7,491
Product costs..................................................................................
Other segment costs and expenses ................................................
Net insurance recoveries – Geismar Incident ................................
Gain on sale of Geismar Interest ...................................................
Impairment of certain assets..........................................................
Regulatory charges resulting from Tax Reform ............................
Proportional Modified EBITDA of equity-method investments...
Williams Partners Modified EBITDA........................................... $
NGL margin................................................................................... $
Olefin margin.................................................................................
(2,300)
(2,124)
9
1,095
(1,156)
(713)
795
3,616
203
126
$
$
(1,728)
(2,203)
7
—
(457)
—
754
3,864
169
337
$
$
5,135
2,196
7,331
(1,779)
(2,229)
126
—
(145)
—
699
4,003
159
226
62
2017 vs. 2016
Modified EBITDA decreased primarily due to $713 million of regulatory charges associated with the impact of
Tax Reform for Transco and Northwest Pipeline, impairments of certain gathering operations in 2017 and lower olefin
margins due to the sale of our Gulf Olefins operations early in the third quarter of 2017 and $35 million of expense in
2017 related to a settlement charge from a pension early payout program (see Note 9 – Employee Benefit Plans of
Notes to Consolidated Financial Statements). These decreases are partially offset by the $1.095 billion gain on the sale
of our Geismar Interest in third-quarter 2017, the absence of impairments of our former Canadian operations and certain
gathering assets in the Mid-Continent region in 2016, the absence of a loss on the sale of our former Canadian operations
in third-quarter 2016, higher service revenues, lower segment costs and expenses, and higher Proportional Modified
EBITDA of equity-method investments.
Service revenues increased primarily due to:
• Transco’s natural gas transportation fee revenues increased $135 million primarily due to a $150 million
increase associated with expansion projects placed in-service in 2016 and 2017, partially offset by lower
volume-based transportation services revenues;
• Higher eastern Gulf Coast region revenue of $103 million associated primarily with higher volumes, including
the impact of new volumes at Gulfstar One related to the Gunflint expansion placed in-service in the third
quarter of 2016, the absence of the temporary shut-down and subsequent ramp-up of Gulfstar One in the
second and third quarters of 2016 to tie-in Gunflint and the absence of producers’ operational issues in the
Tubular Bells field during the first quarter of 2016. This increase is partially offset by lower volumes as a
result of a temporary increase in 2016 due to disrupted operations of a competitor;
• A $39 million increase related to the amortization of deferred revenue associated with the up-front cash payment
received in conjunction with the fourth quarter 2016 Barnett Shale contract restructuring;
• A $15 million increase in Transco’s storage revenue primarily reflecting the absence of an accrual for potential
refunds associated with a ruling received in certain rate case litigation in 2016;
•
In the Northeast region, a slight increase reflecting a $38 million increase in gathering fee revenue at
Susquehanna Supply Hub driven by 11 percent higher gathered volumes reflecting increased customer
production and a $23 million increase in fee revenue at Ohio Valley Midstream reflecting the absence of shut-
in volumes from the first half of 2016, as well as new production coming online. The increases were
substantially offset by a $56 million decrease in the Utica gathering system primarily due to 14 percent lower
gathered volumes driven by natural declines in the wet gas areas which are partially offset by higher volumes
from new development in the dry gas areas;
• A $79 million decrease in the West region related to net lower gathering rates in the Barnett Shale area primarily
due to the fourth quarter 2016 contract restructuring, along with lower rates recognized in the Niobrara, Eagle
Ford Shale, and Haynesville Shale regions. These rate decreases are offset by higher commodity-based fee
revenues in the Piceance area primarily due to higher per-unit NGL margins and higher rates in the Wamsutter
area as a result of renegotiated rates in conjunction with infrastructure expansions. Rates recognized in the
Niobrara region represent a portion of the total contractual rate that is received, with the difference reflected
as deferred revenue;
• A $34 million decrease driven by lower volumes in the West region primarily as a result of natural declines
and more extreme weather conditions in the Rocky Mountains in the first quarter of 2017, partially offset by
higher volumes in the Haynesville Shale region as a result of increased drilling in certain areas;
• A $36 million decrease due to the absence of revenue generated by our former Canadian operations that were
sold in September 2016;
63
• A $15 million decrease in western Gulf Coast region fee revenues due to lower volumes primarily associated
with producer maintenance.
Product sales increased primarily due to:
• A $735 million increase in marketing revenues primarily due to significantly higher prices across all products
and higher NGL volumes (substantially offset in marketing purchases);
• A $32 million increase in revenues from our equity NGLs including a $102 million increase driven primarily
by higher non-ethane prices, partially offset by a $36 million decrease due to the absence of NGL production
revenues associated with our former Canadian operations and a $34 million decrease primarily related to lower
non-ethane volumes at our domestic plants driven by the absence of temporary volumes in 2016 related to
disrupted operations of a competitor, severe winter conditions in the first quarter of 2017, and natural declines;
• A $12 million increase in system management gas sales from Transco. System management gas sales are offset
in Product costs and, therefore, have no impact on Modified EBITDA;
• A $380 million decrease in olefin sales primarily due to a $343 million decrease reflecting the absence of
third- and fourth-quarter sales of our Gulf Olefins operations, a $29 million decrease due to the sale of the
Canadian operations in 2016, and a $16 million decrease at our Geismar plant in the first half of 2017 primarily
due to lower volumes associated with the electrical outage in second-quarter 2017, as well as planned
maintenance downtime in first-quarter 2017. These items were partially offset by $8 million higher sales at
the RGP Splitter in the first half 2017 primarily due to higher propylene prices.
Product costs increased primarily due to:
• A $725 million increase in marketing purchases primarily due to the same factors that increased marketing
sales (more than offset in marketing revenues). The increase in marketing costs does not reflect the
intercompany costs associated with certain gathering and processing services performed by an affiliate;
• A $12 million increase in system management gas costs (offset in Product sales);
• A $166 million decrease in olefin feedstock purchases primarily due to the absence of $163 million in feedstock
purchases in the second half of 2017 reflecting the sale of the Gulf Olefins operations, as well as the absence
of $9 million in costs associated with our former Canadian operations, partially offset by $6 million higher
feedstock costs in the first half of 2017.
•
A $2 million decrease in costs from our equity NGLs including a $35 million increase driven primarily by
higher gas prices, partially offset by a $24 million decrease due to the absence of NGL production revenues
associated with our former Canadian operations and a $13 million decrease primarily related to lower volumes
at our domestic plants driven by severe winter conditions in the first quarter of 2017, and the absence of
temporary volumes in 2016 related to disrupted operations of a competitor and natural declines.
The favorable change in Other segment costs and expenses includes a decrease in labor-related expenses primarily
due to our first quarter 2016 workforce reduction and ongoing cost containment efforts; the absence of $117 million
of operating and other expenses associated with our Gulf Olefins and Canadian operations; and the absence of a $34
million loss on the sale of our former Canadian operations. Additional favorable changes in Other segment costs and
expenses include a $27 million net gain associated with early debt retirement; a $15 million gain related to favorable
contract settlements and terminations; a favorable change in equity AFUDC, primarily associated with an increase in
Transco’s capital spending, which is partially offset by a decrease in capital spending at Constitution; and a $12 million
gain on the sale of the RGP Splitter. These decreases are partially offset by $35 million of expense in 2017 related to
a settlement charge from a pension early payout program (see Note 9 – Employee Benefit Plans of Notes to Consolidated
Financial Statements), higher various maintenance expenses, an increase in pipeline integrity testing on Transco, and
higher Geismar selling expenses and repairs related to a Geismar electrical outage.
64
Gain on sale of Geismar Interest reflects the gain recognized on the sale of our Geismar Interest in July 2017. (See
Note 2 - Acquisitions and Divestitures of Notes to Consolidated Financial Statements.)
Impairment of certain assets increased primarily due to a $1.032 billion impairment of certain gathering operations
primarily in the Mid-Continent region and a $115 million impairment of certain gathering operations in the Marcellus
South region, partially offset by the absence of a $341 million impairment of our former Canadian operations and a
$100 million impairment of certain Mid-Continent gathering assets and impairments or write-downs of other certain
assets that may no longer be in use or are surplus in nature during 2016. (See Note 16 - Fair Value Measurements,
Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements.)
Regulatory charges resulting from Tax Reform reflects $713 million of regulatory charges associated with the
impact of Tax Reform at Transco and Northwest Pipeline with $674 million presented as Regulatory charges resulting
from Tax Reform and $39 million included within Other income (expense) – net below Operating income (loss) in the
Consolidated Statement of Operations.
The increase in Proportional Modified EBITDA of equity-method investments includes a $100 million increase at
Appalachia Midstream Investments reflecting our increased ownership acquired late in the first quarter of 2017, higher
gathering volumes reflecting the absence of shut-in volumes from 2016 and increased customer production, and a $20
million increase at Aux Sable due to increased customer production. These increases are partially offset by a $34
million decrease at UEOM reflecting lower processing volumes from the wet gas areas of the Utica gathering system,
the divestiture of our interests in DBJV and Ranch Westex JV LLC late in the first quarter of 2017, a $12 million
decrease from Discovery primarily attributable to lower fee revenue driven by production issues at certain wells and
higher turbine maintenance expenses.
2016 vs. 2015
Modified EBITDA decreased primarily due to higher impairments, lower insurance recoveries associated with the
Geismar Incident, and loss on sale associated with our Canadian operations. These decreases were partially offset by
higher olefin margins related to the Geismar plant operating at higher production levels in 2016, lower segment costs
and expenses, and higher earnings related to our equity-method investments, including the completion of the Keathley
Canyon Connector at Discovery in the first quarter of 2015. Additionally, higher marketing margins, higher service
revenues related to projects placed in service, and higher NGL margins improved Modified EBITDA.
The increase in Service revenues is primarily due to a $79 million increase in Transco’s natural gas transportation
fee revenues primarily associated with expansion projects placed in service in 2015 and 2016 and a $31 million
transportation and fractionation revenue increase associated with Williams’ Horizon liquids extraction plant in Canada.
The Canadian operations were sold in late September 2016. These increases were partially offset by a decrease in
gathering, processing, and fractionation revenue primarily due to lower volumes primarily in the Barnett Shale and
Anadarko basin and a $15 million decrease in Transco’s storage revenue related to potential refunds associated with a
ruling received in certain rate case litigation in 2016.
Product sales increased primarily due to:
• A $94 million increase in olefin sales comprised of a $170 million increase from the Geismar plant that returned
to service in late March 2015, partially offset by a $76 million decrease from our other former olefin operations.
The increase at Geismar includes $153 million associated with increased volumes as a result of the plant
operating at higher production levels in 2016 than when production resumed in March 2015 following the
Geismar Incident and $17 million primarily associated with higher ethylene per-unit sales prices. The decrease
in other olefin sales includes a $14 million reduction due to the absence of our former Canadian operations
in the fourth quarter of 2016, as well as lower volumes and lower per-unit sales prices within our other olefin
operations;
• A $70 million increase in marketing revenues primarily due to higher NGL and propylene prices and natural
gas and crude oil volumes, partially offset by lower NGL volumes and crude oil prices (partially offset in
marketing purchases);
65
• A $6 million increase in revenues from our equity NGLs due to a $10 million increase associated with higher
volumes, partially offset by a $4 million decrease associated with lower NGL prices;
• A $39 million decrease in system management gas sales from Transco. System management gas sales are
offset in Product costs and, therefore, have no impact on Modified EBITDA.
The decrease in Product costs includes:
• A $39 million decrease in system management gas costs (offset in Product sales);
• A $17 million decrease in olefin feedstock purchases is primarily comprised of $78 million in lower purchases
at our former other olefins operations, partially offset by $61 million of higher purchases due primarily to
increased volumes at the Geismar plant resulting from higher productions levels. The lower costs at our former
other olefin operations are comprised of $54 million in lower per-unit feedstock costs and $24 million in
primarily lower propylene volumes;
• A $4 million decrease in natural gas purchases associated with the production of equity NGLs reflecting a
decrease of $13 million due to lower natural gas prices, partially offset by a $9 million increase associated
with higher volumes;
• Lower costs associated with various other products, primarily condensate;
• A $22 million increase in marketing purchases primarily due to the same factors that increased marketing sales
(more than offset in marketing revenues). The increase in marketing costs does not reflect the intercompany
costs associated with certain gathering and processing services performed by an affiliate.
The decrease in Other segment costs and expenses is primarily due to lower operating costs and general and
administrative expenses reflecting decreases in primarily labor-related and outside services costs resulting from our
first-quarter 2016 workforce reductions and ongoing cost containment efforts and lower costs associated with general
maintenance activities in the Marcellus Shale, as well as $43 million of lower ACMP Merger and transition-related
expenses. Other items partially offsetting these decreases are as follows:
•
•
$37 million increase for severance and related costs associated with workforce reductions incurred in the first
quarter of 2016 and the organizational realignment in the fourth quarter of 2016;
$34 million increase related to the 2016 loss on sale of our Canadian operations;
• $28 million higher project development costs at Constitution as we discontinued capitalization of development
costs related to this project beginning in April 2016;
•
•
•
$22 million higher contract services for pipeline testing and general maintenance at Transco;
$20 million unfavorable change in foreign currency exchange that primarily relates to losses incurred on
foreign currency transactions and the remeasurement of the U.S. dollar-denominated current assets and
liabilities within our former Canadian operations;
$19 million unfavorable change in AFUDC associated with a decrease in spending on Constitution;
• The absence of a $14 million gain recognized in second-quarter 2015 resulting from the early retirement of
certain debt.
Net insurance recoveries – Geismar Incident decreased reflecting $7 million of insurance proceeds received in
2016 compared to $126 million received in 2015.
66
Impairment of certain assets increased primarily due to 2016 impairments of $341 million associated with our
Canadian operations and $63 million associated with certain Mid-Continent gathering assets as well as impairments
or write-downs of other certain assets that may no longer be in use or are surplus in nature, partially offset by the
absence of 2015 impairments of $94 million associated with previously capitalized project development costs for a gas
processing plant and $20 million associated with certain surplus equipment within our Ohio Valley Midstream business.
(See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated
Financial Statements.)
The increase in Proportional Modified EBITDA of equity-method investments is primarily due to a $30 million
increase from Discovery primarily associated with higher fee revenues attributable to the completion of the Keathley
Canyon Connector in the first quarter of 2015. Additionally, Caiman II contributed a $20 million increase resulting
from higher volumes due to assets placed into service in 2015, OPPL contributed a $16 million increase primarily due
to higher transportation volumes and lower expenses, and UEOM contributed an $11 million increase primarily
associated with an increase in our ownership percentage. These increases were partially offset by a $29 million decrease
from Appalachia Midstream Investments primarily due to lower fee revenues driven by lower rates, partially offset by
lower impairments and higher volumes.
Other
Years Ended December 31,
2017
2016
(Millions)
2015
Other Modified EBITDA..................................................................... $
(150) $
(542) $
(112)
2017 vs. 2016
The favorable change in Modified EBITDA is primarily due to:
• The absence of the $406 million 2016 impairment of our Canadian operations, partially offset by the $23
million impairment of an olefins pipeline project in the Gulf Coast region in the second quarter of 2017 and
the $68 million impairment of a certain NGL pipeline asset in the third quarter of 2017 (see Note 16 – Fair
Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial
Statements);
• The absence of $61 million of certain project development costs associated with the Canadian PDH facility
that we expensed in 2016;
• A $31 million favorable change in the loss on the sale of our Canadian operations in September 2016;
• The absence of $32 million of transportation and fractionation fees incurred in 2016 related to the Redwater
fractionation facility, which was included in the sale of our Canadian operations in September 2016;
• A $38 million decrease in costs related to our evaluation of strategic alternatives;
• A $29 million increase in income associated with an increase in a regulatory asset primarily driven by our
increased ownership in WPZ.
These favorable changes are partially offset by:
• A $63 million charge reducing regulatory assets related to deferred taxes on AFUDC resulting from Tax Reform
(see Note 6 – Other Income and Expenses of Notes to Consolidated Financial Statements);
• A $35 million settlement charge expense related to the program to pay out certain deferred vested pension
benefits of employees associated with former operations. (See Note 9 – Employee Benefit Plans of Notes to
Consolidated Financial Statements);
67
• A reduction in revenues associated with an NGL pipeline near the Houston Ship Channel region;
• The absence of a $10 million gain on the sale of unused pipe in 2016.
2016 vs. 2015
The unfavorable change in Modified EBITDA is primarily due to:
• The impairment and loss on sale of our Canadian operations totaling $438 million in 2016;
• An increase of $61 million of certain project development costs associated with the Canadian PDH facility
that we began expensing in 2016;
• A $17 million increase in costs related to our evaluation of strategic alternatives.
These unfavorable changes are partially offset by:
• A $10 million gain on the sale of unused pipe in 2016;
• A $31 million decrease in ACMP merger and transition related costs;
• The absence of a $64 million write-off of previously capitalized project development costs for an olefins
pipeline project in 2015.
68
Management’s Discussion and Analysis of Financial Condition and Liquidity
Overview
In 2017, we exceeded our target for asset sales, significantly improved our balance sheet to provide ample available
liquidity, and continued to focus on growth in our businesses by identifying, contracting, permitting, and constructing
attractive expansion projects. Examples of this activity included:
• Sale of our Geismar Interest (see Note 2 – Acquisitions and Divestitures of Notes to Consolidated Financial
Statements).
• Repayment of WPZ’s $850 million variable interest rate term loan that was due December 2018, and early
retirement of WPZ’s $750 million of 6.125 percent senior unsecured notes that were due in 2022;
• Repayment of WPZ’s $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023 with proceeds
from the issuance of WPZ’s $1.45 billion of 3.75 percent senior unsecured notes due in 2027;
• Extension to 2021 for the maturity dates of our long-term credit facility and WPZ’s long-term credit facility;
• Expansion of WPZ’s interstate natural gas pipeline system through completion of 2017 strategic projects (Gulf
Trace, Hillabee Phase 1, Dalton, New York Bay, and Virginia Southside II) to meet the demand of growth
markets.
Outlook
Fee-based businesses are a significant component of our portfolio and serve to reduce the influence of commodity
price fluctuations on our cash flows. We expect to benefit as continued growth in demand for low-cost natural gas is
driven by increases in LNG exports, industrial demand, and power generation.
As previously discussed in Company Outlook, our consolidated growth capital and investment expenditures in
2018 are expected to be approximately $2.7 billion. Approximately $1.7 billion of our growth capital funding needs
include Transco expansions and other interstate pipeline growth projects, most of which are fully contracted with firm
transportation agreements. The remaining growth capital spending in 2018 primarily reflects investment in gathering
and processing systems in the Northeast region limited primarily to known new producer volumes, including volumes
that support Transco expansion projects including our Atlantic Sunrise project. In addition to growth capital and
investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations,
as well as projects that meet legal, regulatory, and/or contractual commitments. WPZ intends to fund their planned
2018 growth capital with retained cash flow and debt. We retain the flexibility to adjust planned levels of growth capital
and investment expenditures in response to changes in economic conditions or business opportunities.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have
sufficient liquidity to manage our businesses in 2018. WPZ expects to be self-funding and maintain separate bank
accounts and credit facilities, including its commercial paper program. Our potential material internal and external
sources and uses of consolidated liquidity for 2018 are as follows:
69
Applicable To:
WPZ
WMB
Sources:
Uses:
Cash and cash equivalents on hand ..........................................................................
Cash generated from operations ...............................................................................
Distributions from investment in WPZ.....................................................................
Distributions from equity-method investees.............................................................
Utilization of credit facilities and/or commercial paper program ............................
Cash proceeds from issuance of debt and/or equity securities .................................
Proceeds from asset monetizations...........................................................................
Working capital requirements...................................................................................
Capital and investment expenditures ........................................................................
Investment in WPZ ...................................................................................................
Quarterly distributions to unitholders.......................................................................
Quarterly dividends to shareholders .........................................................................
Debt service payments, including payments of long-term debt ...............................
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed
in Company Outlook.
As of December 31, 2017, we had a working capital deficit of $467 million. Our available liquidity is as follows:
Available Liquidity
December 31, 2017
WPZ
WMB
Total
Cash and cash equivalents .........................................................................................................
Capacity available under our $1.5 billion credit facility (1) ......................................................
$ 881
(Millions)
18
$
1,230
Capacity available to WPZ under its $3.5 billion credit facility, less amounts outstanding
under its $3 billion commercial paper program (2) ...............................................................
3,500
$4,381
$1,248
$ 899
1,230
3,500
$5,629
__________
(1) The highest amount outstanding under our credit facility during 2017 was $805 million. At December 31, 2017,
we were in compliance with the financial covenants associated with this credit facility. See Note 13 – Debt, Banking
Arrangements, and Leases of Notes to Consolidated Financial Statements for additional information on our credit
facility. Borrowing capacity available under this facility as of February 20, 2018, was $1.5 billion.
(2) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity
of WPZ’s credit facility inclusive of any outstanding amounts under its commercial paper program. As of
December 31, 2017, no Commercial paper was outstanding under WPZ’s commercial paper program. The highest
amount outstanding under WPZ’s commercial paper program and credit facility during 2017 was $178 million. At
December 31, 2017, WPZ was in compliance with the financial covenants associated with this credit facility. See
Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements for additional
information on WPZ’s credit facility and WPZ’s commercial paper program. Borrowing capacity available under
WPZ’s $3.5 billion credit facility as of February 20, 2018, was $3.5 billion.
As described in Note 13 – Debt, Banking Arrangements, and Leases of Notes to Consolidated Financial Statements,
we have determined that we have net assets that are technically considered restricted in accordance with Rule 4-08(e)
of Regulation S-X of the Securities and Exchange Commission in excess of 25 percent of our consolidated net assets.
We do not expect this determination will impact our ability to pay dividends or meet future obligations as the terms of
WPZ’s partnership agreement require it to make quarterly distributions of all available cash, as defined, to its unitholders.
70
Dividends
As part of the Financial Repositioning, we increased our regular quarterly cash dividend by 50 percent from the
previous quarterly dividend of $0.20 per share paid in December 2016, to $0.30 per share for the dividends paid in
each quarter of 2017.
Registrations
In September 2016, WPZ filed a registration statement for its distribution reinvestment program.
In May 2015, we filed a shelf registration statement, as a well-known seasoned issuer.
In February 2015, WPZ filed a shelf registration statement, as a well-known seasoned issuer, registering common
units representing limited partner interests and debt securities. Also in February 2015, WPZ filed a shelf registration
statement for the offer and sale from time to time of common units representing limited partner interests in WPZ having
an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time
in transactions at prices which are market prices prevailing at the time of sale, prices related to market price, or at
negotiated prices. Such sales are to be made pursuant to an equity distribution agreement between WPZ and certain
banks who may act as sales agents or purchase for their own accounts as principals. During 2016 and 2015, WPZ
received net proceeds of approximately $115 million and approximately $59 million, respectively, from equity issued
under this registration; there was no activity during 2017.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require
distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in
part, by reserves appropriate for operating their respective businesses. (See Note 5 – Investing Activities of Notes to
Consolidated Financial Statements for our more significant equity-method investees.)
Credit Ratings
Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings
are as follows:
WMB:
WPZ:
Rating Agency
S&P Global Ratings
Moody’s Investors Service
Fitch Ratings
S&P Global Ratings
Moody’s Investors Service
Fitch Ratings
Outlook
Stable
Positive
Stable
Stable
Positive
Positive
Senior Unsecured
Debt Rating
BB+
Ba2
BB+
Corporate
Credit Rating
BB+
N/A
N/A
BBB
Baa3
BBB-
BBB
N/A
N/A
During March 2017, S&P Global Ratings upgraded its rating for both WMB and WPZ. These credit ratings are
included for informational purposes and are not recommendations to buy, sell, or hold our or WPZ’s securities, and
each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating
agencies will continue to assign us or WPZ the ratings shown above even if we or WPZ meet or exceed their current
criteria. A downgrade of our credit ratings or the credit ratings of WPZ might increase our future cost of borrowing and
would require us to provide additional collateral to third parties, negatively impacting our available liquidity.
71
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented
(see Notes to Consolidated Financial Statements for the Notes referenced in the table):
Cash Flow
Category
Years Ended December 31,
2017
2016
2015
(Millions)
Sources of cash and cash equivalents:
Operating activities – net .......................................................... Operating
Proceeds from equity offerings.................................................
Financing
Proceeds from sale of businesses, net of cash divested (see
$
$
2,556
2,131
$
3,680
123
Note 2)...................................................................................
Proceeds from long-term debt (see Note 13)............................
Proceeds from our credit-facility borrowings...........................
Distributions from unconsolidated affiliates in excess of
cumulative earnings ..............................................................
Contributions in aid of construction .........................................
Proceeds from dispositions of equity-method investments
(see Note 5) ...........................................................................
Contributions from noncontrolling interests.............................
Proceeds from WPZ’s credit-facility borrowings .....................
Special distribution from Gulfstream (see Note 5)...................
Uses of cash and cash equivalents:
Payments of long-term debt (see Note 13) ...............................
Capital expenditures .................................................................
Payments on our credit-facility borrowings .............................
Dividends paid ..........................................................................
Dividends and distributions paid to noncontrolling interests ...
Purchases of and contributions to equity-method investments.
Payments of WPZ’s commercial paper – net............................
Payments on WPZ’s credit-facility borrowings........................
Contribution to Gulfstream for repayment of debt (see
Note 5)...................................................................................
Purchases of businesses, net of cash acquired ..........................
Investing
Financing
Financing
Investing
Investing
Investing
Financing
Financing
Financing
Financing
Investing
Financing
Financing
Financing
Investing
Financing
Financing
Financing
Investing
2,067
1,698
1,635
529
426
200
17
—
—
(3,785)
(2,399)
(2,140)
(992)
(822)
(132)
(93)
—
—
—
1,020
998
2,280
472
218
34
29
3,250
—
(375)
(2,051)
(2,155)
(1,261)
(940)
(177)
(409)
(4,560)
(148)
—
2,708
86
—
3,842
2,097
404
87
—
111
3,832
396
(1,533)
(3,167)
(1,817)
(1,836)
(942)
(595)
(306)
(3,162)
(248)
(112)
Other sources / (uses) – net ..........................................................
Increase (decrease) in cash and cash equivalents.........................
Financing
and Investing
(167)
729
$
$
42
70
$
15
(140)
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the
exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Net
(gain) loss on disposition of equity-method investments, Impairment of goodwill, Impairment of equity-method
investments, Impairment of and net (gain) loss on sale of assets and businesses, Gain on sale of Geismar Interest, and
Regulatory charges resulting from Tax Reform.
Our Net cash provided (used) by operating activities in 2017 decreased from 2016 primarily due to the absence in
2017 of receipts from 2016 contract restructurings, partially offset by higher operating income in 2017.
Our Net cash provided (used) by operating activities in 2016 increased from 2015 primarily due to the impact of
net favorable changes in operating working capital and receipts from contract restructurings.
72
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 3 – Variable Interest Entities,
Note 10 – Property, Plant, and Equipment, Note 13 – Debt, Banking Arrangements, and Leases, Note 16 – Fair Value
Measurements, Guarantees, and Concentration of Credit Risk, and Note 17 – Contingent Liabilities and Commitments
of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible
fulfillment of them will prevent us from meeting our liquidity needs.
Contractual Obligations
The table below summarizes the maturity dates of our contractual obligations at December 31, 2017:
2018
2019 - 2020
2021 - 2022
Thereafter
Total
(Millions)
Long-term debt: (1)
Principal ............................................................... $
Interest ..................................................................
Operating leases .......................................................
Purchase obligations (2) ...........................................
Other obligations (3)(4) ...........................................
Total .......................................................... $
502
1,049
44
1,171
1
2,767
$
$
2,156
1,995
74
914
2
5,141
$
$
3,146
1,743
62
632
1
5,584
$
$
15,277
7,795
137
277
1
23,487
$
$
21,081
12,582
317
2,994
5
36,979
______________
(1) Includes the borrowings outstanding under credit facilities, but does not include any related variable-rate interest
payments.
(2) Includes approximately $348 million in open property, plant, and equipment purchase orders. Includes an estimated
$314 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at
December 31, 2017 prices. This obligation is part of an overall exchange agreement whereby volumes we transport
on OPPL are sold at a third-party fractionator near Conway, Kansas, and we are subsequently obligated to purchase
ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or sold at comparable prices in
the Mont Belvieu market. Includes an estimated $454 million long-term ethane purchase obligation with index-
based pricing terms that primarily supplies third parties at their plants and is valued in this table at a price calculated
using December 31, 2017 prices. Any excess purchased volumes may be sold at comparable market prices. Includes
an estimated $765 million long-term mixed NGLs purchase obligation with index-based pricing terms that is
reflected in this table at December 31, 2017 prices. Includes an estimated $278 million long-term ethane purchase
obligation with index-based pricing terms that primarily supplies a third party for consumption at their plant and
is reflected in this table at a price calculated using December 31, 2017 prices. Any excess purchased volumes may
be sold at comparable market prices. In addition, we have not included certain natural gas life-of-lease contracts
for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders,
for the acquisition or construction of property, plant, and equipment or expected contributions to our jointly owned
investments. (See Company Outlook — Expansion Projects.)
(3) Does not include estimated contributions to our pension and other postretirement benefit plans. We made
contributions to our pension and other postretirement benefit plans of $90 million in 2017 and $72 million in 2016.
In 2018, we expect to contribute approximately $91 million to these plans (see Note 9 – Employee Benefit Plans
of Notes to Consolidated Financial Statements). Tax-qualified pension plans are required to meet minimum
contribution requirements. In the past, we have contributed amounts to our tax-qualified pension plans in excess
of the minimum required contribution. These excess amounts can be used to offset future minimum contribution
requirements. During 2017, we contributed $80 million to our tax-qualified pension plans. In addition to these
contributions, a portion of the excess contributions was used to meet the minimum contribution requirements.
During 2018, we expect to contribute approximately $80 million to our tax-qualified pension plans and use excess
amounts to satisfy minimum contribution requirements, if needed. Additionally, estimated future minimum funding
requirements may vary significantly from historical requirements if actual results differ significantly from estimated
results for assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant
assumptions or by changes to current legislation and regulations.
73
(4) We have not included income tax liabilities in the table above. See Note 7 – Provision (Benefit) for Income Taxes
of Notes to Consolidated Financial Statements for a discussion of income taxes, including our contingent tax
liability reserves.
Effects of Inflation
Our operations have historically not been materially affected by inflation. Approximately 43 percent of our gross
property, plant, and equipment is comprised of our interstate natural gas pipeline assets. They are subject to regulation,
which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current
FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to
replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability
to recover such increased costs. For our gathering and processing assets, operating costs are influenced to a greater
extent by both competition for specialized services and specific price changes in crude oil and natural gas and related
commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to
the market perceptions concerning the supply and demand balance in the near future, as well as general economic
conditions. However, our exposure to certain of these price changes is reduced through the fee-based nature of certain
of our services and the use of hedging instruments.
Environmental
We are a participant in certain environmental activities in various stages including assessment studies, cleanup
operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 17 – Contingent
Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a
coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly
and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current
estimates of the most likely costs of such activities are approximately $38 million, all of which are included in Accrued
liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31,
2017. We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling
approximately $7 million through future natural gas transmission rates. The remainder of these costs will be funded
from operations. During 2017, we paid approximately $6 million for cleanup and/or remediation and monitoring
activities. We expect to pay approximately $10 million in 2018 for these activities. Estimates of the most likely costs
of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with
other similar cleanup operations. At December 31, 2017, certain assessment studies were still in process for which the
ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend
on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated
by the EPA or other governmental authorities, and other factors.
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, air quality standards for one hour nitrogen dioxide
emissions, and volatile organic compound and methane new source performance standards impacting design and
operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding
National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We
are monitoring the rule's implementation as the reduction will trigger additional federal and state regulatory actions
that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations
and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both
new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be
required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations
and the need for further specific regulatory guidance.
Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs
and the costs associated with compliance with environmental standards to be recoverable through rates.
74
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily
comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under the
credit facilities and any issuances under WPZ’s commercial paper program could be at a variable interest rate and could
expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by
the expected lives of our operating assets. (See Note 13 – Debt, Banking Arrangements, and Leases of Notes to
Consolidated Financial Statements.)
The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of
December 31, 2017 and 2016. The fair value of our publicly traded long-term debt is valued using indicative year-end
traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar
terms and credit ratings.
2018
2019
2020
2021
2022
Thereafter (1)
Total
(Millions)
Fair Value
December 31,
2017
Long-term debt, including
current portion:
Fixed rate .......................
$
502
$
33
$ 2,123
$
873
$ 2,003
$
15,131
$ 20,665
$
22,735
Weighted-average
interest rate ................
5.1%
5.1%
5.1%
5.1%
5.2%
5.7%
Variable rate (2)..............
$
— $
— $
— $
270
$
— $
— $
270
$
270
2017
2018
2019
2020
2021
Thereafter (1)
Total
(Millions)
Fair Value
December 31,
2016
Long-term debt, including
current portion:
Fixed rate .......................
$
785
$
500
Weighted-average
interest rate ................
Variable rate (3)..............
Commercial paper:
Variable rate (4)..............
$
$
5.2%
5.2%
— $
850
$
$
32
$ 2,121
5.2%
5.2%
— $
775
$
$
5.2%
— $
5.6%
— $
1,625
871
$
17,475
$ 21,784
$
22,465
93
$
— $
— $
— $
— $
— $
93
$
$
1,625
93
__________________
(1) Includes unamortized discount / premium and debt issuance costs.
(2) The weighted-average interest rate for our $270 million credit facility borrowing at December 31, 2017 was
3.16 percent.
(3) The weighted-average interest rates for WPZ’s $850 million term loan and our $775 million credit facility borrowing
at December 31, 2016 were 2.50 percent and 2.51 percent, respectively.
(4) The weighted-average interest rate was 1.06 percent at December 31, 2016.
Commodity Price Risk
We are exposed to the impact of fluctuations in the market price of NGLs and natural gas, as well as other market
factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection
with our owned energy-related assets, our long-term energy-related contracts, and limited proprietary trading activities.
Our management of the risks associated with these market fluctuations includes maintaining sufficient liquidity, as well
as using various derivatives and nonderivative energy-related contracts. The fair value of derivative contracts is subject
75
to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in
which the contracts are transacted, and changes in interest rates. At December 31, 2017 and 2016, our derivative activity
was not material. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to
Consolidated Financial Statements.)
76
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Stockholders and the Board of Directors of
The Williams Companies, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. (the “Company”) as
of December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive income (loss),
changes in equity and cash flows for each of the three years in the period ended December 31, 2017, and the related
notes and financial statement schedules listed in the index at Item 15(a) (collectively referred to as the “consolidated
financial statements”). In our opinion, based on our audits and the reports of other auditors, the consolidated financial
statements present fairly, in all material respects, the consolidated financial position of the Company at December 31,
2017 and 2016, and the consolidated results of its operations and its cash flows for each of the three years in the period
ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
We did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (“Gulfstream”), a limited liability
corporation in which the Company has a 50 percent interest. In the consolidated financial statements, the Company’s
investment in Gulfstream was $244 million and $261 million as of December 31, 2017 and 2016, respectively, and the
Company’s equity earnings in the net income of Gulfstream were $75 million in 2017, $69 million in 2016 and $65
million in 2015. Gulfstream’s financial statements were audited by other auditors whose reports have been furnished
to us, and our opinion, insofar as it relates to the amounts included for Gulfstream, is based solely on the reports of the
other auditors.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017, 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 22, 2018 expressed an unqualified opinion
thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to
express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting
firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with
the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission
and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated
financial statements. We believe that our audits and the reports of other auditors provide a reasonable basis for our
opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 1962.
Tulsa, Oklahoma
February 22, 2018
77
Report of Independent Registered Public Accounting Firm
To the Management Committee and Members of Gulfstream Natural Gas System, L.L.C.:
Opinion on the Financial Statements
We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C. (the “Company”) as of December 31,
2017, and the related statements of operations, comprehensive income, cash flows, and members’ equity for the year
then ended, including the related notes (collectively referred to as the “financial statements;” not presented herein). In
our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as
of December 31, 2017, and the results of its operations and its cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with
the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of
the Securities and Exchange Commission and the PCAOB.
We conducted our audit of these financial statements in accordance with the standards of the PCAOB and in accordance
with auditing standards generally accepted in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement,
whether due to error or fraud.
Our audit included performing procedures to assess the risks of material misstatement of the financial statements,
whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also
included evaluating the accounting principles used and significant estimates made by management, as well as evaluating
the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our
opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 22, 2018
We have served as the Company’s auditor since 2018.
78
Report of Independent Registered Public Accounting Firm
To the Members of Gulfstream Natural Gas System, L.L.C.
We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C. (the "Company") as of December 31,
2016, and the related statement of operations, comprehensive income, cash flows, and members’ equity for each of the
two years in the period ended December 31, 2016. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States) and in accordance with auditing standards generally accepted in the United States of America. Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audits included consideration of internal control over financial reporting
as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing
an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no
such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream
Natural Gas System, L.L.C. as of December 31, 2016, and the results of its operations and its cash flows for each of
the two years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in
the United States of America.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 22, 2017
79
The Williams Companies, Inc.
Consolidated Statement of Operations
Years Ended December 31,
2017
2016
2015
(Millions, except per-share amounts)
Revenues:
Service revenues ...................................................................................
Product sales .........................................................................................
Total revenues .................................................................................
$
$
5,312
2,719
8,031
Costs and expenses:
Product costs ........................................................................................
Operating and maintenance expenses ...................................................
Depreciation and amortization expenses ..............................................
Selling, general, and administrative expenses ......................................
Impairment of goodwill (Note 16) .......................................................
Impairment of certain assets (Note 16) ................................................
Gain on sale of Geismar Interest (Note 2) ............................................
Regulatory charges resulting from Tax Reform (Note 1) .....................
Insurance recoveries – Geismar Incident ..............................................
Other (income) expense – net ...............................................................
Total costs and expenses ..................................................................
Operating income (loss) ..........................................................................
Equity earnings (losses) ..........................................................................
Impairment of equity-method investments (Note 16) .............................
Other investing income (loss) – net ........................................................
Interest incurred ......................................................................................
Interest capitalized ..................................................................................
Other income (expense) – net .................................................................
Income (loss) before income taxes .........................................................
Provision (benefit) for income taxes .......................................................
Net income (loss) .................................................................................
Less: Net income (loss) attributable to noncontrolling interests .....
Net income (loss) attributable to The Williams Companies, Inc. .........
Basic earnings (loss) per common share:
Net income (loss) ............................................................................
Weighted-average shares (thousands) .............................................
Diluted earnings (loss) per common share:
Net income (loss) ............................................................................
Weighted-average shares (thousands) .............................................
$
$
$
See accompanying notes.
2,300
1,585
1,736
608
—
1,248
(1,095)
674
(9)
80
7,127
904
434
—
282
(1,116)
33
(2)
535
(1,974)
2,509
335
2,174
2.63
826,177
2.62
828,518
$
$
$
$
5,171
2,328
7,499
1,725
1,580
1,763
723
—
873
—
—
(7)
142
6,799
700
397
(430)
63
(1,217)
38
74
(375)
(25)
(350)
74
(424) $
5,164
2,196
7,360
1,779
1,655
1,738
741
1,098
209
—
—
(126)
40
7,134
226
335
(1,359)
27
(1,118)
74
102
(1,713)
(399)
(1,314)
(743)
(571)
(.57) $
750,673
(.76)
749,271
(.57) $
750,673
(.76)
749,271
80
The Williams Companies, Inc.
Consolidated Statement of Comprehensive Income (Loss)
Years Ended December 31,
2017
2016
2015
(Millions)
Net income (loss) .......................................................................................................
$
2,509
$
(350) $ (1,314)
Other comprehensive income (loss):
Cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $2,
($1), and $0 in 2017, 2016, and 2015, respectively ........................................
Reclassifications into earnings of net derivative instruments (gain) loss, net of
taxes of ($1) in 2017, and $1 in 2016 and 2015 .............................................
Foreign currency translation activities:
Foreign currency translation adjustments, net of taxes of $0, ($37), and $31 in
2017, 2016, and 2015, respectively ................................................................
Reclassification into earnings upon sale of foreign entities, net of taxes of
($36) in 2016 ..................................................................................................
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included in net periodic benefit
cost (credit), net of taxes of $2, $2, and $3 in 2017, 2016, and 2015,
respectively ....................................................................................................
Net actuarial gain (loss) arising during the year, net of taxes of ($15), $8, and
($5) in 2017, 2016 and 2015, respectively .....................................................
Amortization of actuarial (gain) loss and net actuarial loss from settlements
included in net periodic benefit cost (credit), net of taxes of ($37), ($12),
and ($18) in 2017, 2016, and 2015, respectively (Note 9) ............................
Other comprehensive income (loss) ..........................................................................
Comprehensive income (loss) ...................................................................................
Less: Comprehensive income (loss) attributable to noncontrolling interests ..........
(9)
6
1
—
(3)
44
61
100
2,609
334
4
(2)
50
119
(4)
(15)
20
172
(178)
143
Comprehensive income (loss) attributable to The Williams Companies, Inc. ...........
$
2,275
$
(321) $
See accompanying notes.
6
(6)
(204)
—
(3)
8
28
(171)
(1,485)
(813)
(672)
81
The Williams Companies, Inc.
Consolidated Balance Sheet
December 31,
2017
2016
(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents.........................................................................................
Trade accounts and other receivables (net of allowance of $9 at December 31,
2017 and $6 at December 31, 2016)......................................................................
Inventories.................................................................................................................
Other current assets and deferred charges.................................................................
Total current assets ...............................................................................................
Investments..................................................................................................................
Property, plant, and equipment – net ...........................................................................
Intangible assets – net of accumulated amortization...................................................
Regulatory assets, deferred charges, and other............................................................
Total assets ...........................................................................................................
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ......................................................................................................
Accrued liabilities .....................................................................................................
Commercial paper .....................................................................................................
Long-term debt due within one year .........................................................................
Total current liabilities..........................................................................................
Long-term debt ............................................................................................................
Deferred income tax liabilities ....................................................................................
Regulatory liabilities, deferred income, and other ......................................................
Contingent liabilities and commitments (Note 17)
Equity:
Stockholders’ equity:
Common stock (960 million shares authorized at $1 par value; 861 million
shares issued at December 31, 2017 and 785 million shares issued at
December 31, 2016)..........................................................................................
Capital in excess of par value...............................................................................
Retained deficit ....................................................................................................
Accumulated other comprehensive income (loss) ...............................................
Treasury stock, at cost (35 million shares of common stock) ..............................
Total stockholders’ equity................................................................................
Noncontrolling interests in consolidated subsidiaries...............................................
Total equity...........................................................................................................
Total liabilities and equity ...............................................................................
See accompanying notes.
82
$
$
$
$
899
$
976
113
191
2,179
6,552
28,211
8,791
619
46,352
978
1,167
—
501
2,646
20,434
3,147
3,950
$
$
170
938
138
216
1,462
6,701
28,428
9,663
581
46,835
623
1,448
93
785
2,949
22,624
4,238
2,978
861
18,508
(8,434)
(238)
(1,041)
9,656
6,519
16,175
46,352
$
785
14,887
(9,649)
(339)
(1,041)
4,643
9,403
14,046
46,835
The Williams Companies, Inc.
Consolidated Statement of Changes in Equity
The Williams Companies, Inc., Stockholders
Common
Stock
Capital in
Excess of
Par Value
Retained
Deficit
Accumulated
Other
Comprehensive
Income (Loss)
Treasury
Stock
Total
Stockholders’
Equity
Noncontrolling
Interests
Total
Equity
(Millions)
$
(341)
(1,041)
$
8,777
$
11,395
$
20,172
Balance – December 31, 2014 .............................. $
782
$
14,925
$
(5,548)
$
Net income (loss)....................................................
Other comprehensive income (loss) .......................
Cash dividends – common stock (Note 14)............
Dividends and distributions to noncontrolling
interests ................................................................
Stock-based compensation and related common
stock issuances, net of tax....................................
Sales of limited partner units of Williams Partners
L.P. .......................................................................
Changes in ownership of consolidated
subsidiaries, net....................................................
Contributions from noncontrolling interests ..........
Other .......................................................................
Net increase (decrease) in equity............................
—
—
—
—
2
—
—
—
—
2
Balance – December 31, 2015 ..............................
784
Net income (loss)....................................................
Other comprehensive income (loss) .......................
Cash dividends – common stock (Note 14)............
Dividends and distributions to noncontrolling
interests ................................................................
Stock-based compensation and related common
stock issuances, net of tax....................................
Sales of limited partner units of Williams Partners
L.P. .......................................................................
Changes in ownership of consolidated
subsidiaries, net....................................................
Contributions from noncontrolling interests ..........
Other .......................................................................
Net increase (decrease) in equity............................
—
—
—
—
1
—
—
—
—
1
—
—
—
—
28
—
(160)
—
14
(118)
14,807
—
—
—
—
56
—
12
—
12
80
Balance – December 31, 2016 ..............................
785
14,887
Net income (loss)....................................................
Other comprehensive income (loss) .......................
Issuance of common stock (Note 14) .....................
Cash dividends – common stock (Note 14)............
Dividends and distributions to noncontrolling
interests ................................................................
Stock-based compensation and related common
stock issuances, net of tax....................................
Adoption of ASU 2016-09 (Note 1) .......................
Sales of limited partner units of Williams Partners
L.P. .......................................................................
Changes in ownership of consolidated
subsidiaries, net....................................................
Contributions from noncontrolling interests ..........
Other .......................................................................
Net increase (decrease) in equity............................
—
—
75
—
—
1
—
—
—
—
—
76
—
—
2,043
—
—
73
1
—
1,497
—
7
3,621
(571)
—
(1,836)
—
—
—
—
—
(5)
(2,412)
(7,960)
(424)
—
(1,261)
—
—
—
—
—
(4)
(1,689)
(9,649)
2,174
—
—
(992)
—
—
36
—
—
—
(3)
1,215
—
(101)
—
—
—
—
—
—
—
(101)
(442)
—
103
—
—
—
—
—
—
—
103
(339)
—
101
—
—
—
—
—
—
—
—
—
101
—
—
—
—
—
—
—
—
—
—
(1,041)
—
—
—
—
—
—
—
—
—
—
(1,041)
—
—
—
—
—
—
—
—
—
—
—
—
Balance – December 31, 2017 .............................. $
861
$
18,508
$
(8,434)
$
(238)
$
(1,041)
$
See accompanying notes.
83
(571)
(101)
(1,836)
—
30
—
(160)
—
9
(2,629)
6,148
(424)
103
(1,261)
—
57
—
12
—
8
(1,505)
4,643
2,174
101
2,118
(992)
—
74
37
—
1,497
—
4
5,013
9,656
$
(743)
(70)
—
(942)
—
59
254
111
13
(1,318)
10,077
74
69
—
(1,314)
(171)
(1,836)
(942)
30
59
94
111
22
(3,947)
16,225
(350)
172
(1,261)
(940)
(940)
—
114
(18)
29
(2)
(674)
9,403
335
(1)
—
—
(883)
—
—
61
(2,407)
17
(6)
(2,884)
57
114
(6)
29
6
(2,179)
14,046
2,509
100
2,118
(992)
(883)
74
37
61
(910)
17
(2)
2,129
6,519
$
16,175
The Williams Companies, Inc.
Consolidated Statement of Cash Flows
Years Ended December 31,
2016
2017
2015
OPERATING ACTIVITIES:
Net income (loss) ....................................................................................................
Adjustments to reconcile to net cash provided (used) by operating activities:
$
2,509
$
(350) $
(1,314)
(Millions)
Depreciation and amortization ...........................................................................
Provision (benefit) for deferred income taxes ....................................................
Net (gain) loss on disposition of equity-method investments ............................
Impairment of goodwill .....................................................................................
Impairment of equity-method investments .........................................................
Impairment of and net (gain) loss on sale of assets and businesses ...................
Gain on sale of Geismar Interest (Note 2) ..........................................................
Amortization of stock-based awards ..................................................................
Regulatory charges resulting from Tax Reform (Note 1) ...................................
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable ......................................................................
Inventories ....................................................................................................
Other current assets and deferred charges .....................................................
Accounts payable ..........................................................................................
Accrued liabilities .........................................................................................
Other, including changes in noncurrent assets and liabilities .............................
Net cash provided (used) by operating activities ..........................................
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net ............................................
Proceeds from long-term debt .................................................................................
Payments of long-term debt ....................................................................................
Proceeds from issuance of common stock ..............................................................
Proceeds from sale of limited partner units of consolidated partnership.................
Dividends paid ........................................................................................................
Dividends and distributions paid to noncontrolling interests ..................................
Contributions from noncontrolling interests ...........................................................
Payments for debt issuance costs ............................................................................
Special distribution from Gulfstream ......................................................................
Contribution to Gulfstream for repayment of debt ..................................................
Other – net ..............................................................................................................
Net cash provided (used) by financing activities ..........................................
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1) ....................................................................................
Dispositions – net ..............................................................................................
Contributions in aid of construction ........................................................................
Proceeds from sale of businesses, net of cash divested ...........................................
Proceeds from dispositions of equity-method investments .....................................
Purchases of businesses, net of cash acquired .........................................................
Purchases of and contributions to equity-method investments................................
Distributions from unconsolidated affiliates in excess of cumulative earnings.......
Other – net ..............................................................................................................
Net cash provided (used) by investing activities ...........................................
Increase (decrease) in cash and cash equivalents ......................................................
Cash and cash equivalents at beginning of year ........................................................
Cash and cash equivalents at end of year ..................................................................
_________
(1) Increases to property, plant, and equipment .........................................................
Changes in related accounts payable and accrued liabilities ................................
Capital expenditures .............................................................................................
$
$
$
1,736
(2,012)
(269)
—
—
1,249
(1,095)
78
776
(88)
8
(21)
118
(92)
(341)
2,556
(93)
3,333
(5,925)
2,131
—
(992)
(822)
17
(17)
—
—
(92)
(2,460)
(2,399)
(41)
426
2,067
200
—
(132)
529
(17)
633
729
170
899
$
1,763
(26)
(27)
—
430
918
—
73
—
82
(25)
(4)
35
512
299
3,680
(409)
6,528
(7,091)
9
114
(1,261)
(940)
29
(9)
—
(148)
(16)
(3,194)
(2,051)
30
218
1,020
34
—
(177)
472
38
(416)
70
100
170
$
1,738
(337)
—
1,098
1,359
215
—
82
—
39
105
4
(88)
54
(247)
2,708
(306)
9,772
(6,516)
27
59
(1,836)
(942)
111
(35)
396
(248)
(31)
451
(3,167)
3
87
—
—
(112)
(595)
404
81
(3,299)
(140)
240
100
(2,662) $
263
(2,399) $
(1,912) $
(139)
(2,051) $
(3,024)
(143)
(3,167)
See accompanying notes.
84
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies
General
Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like
terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise,
references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as
equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees
by name, we are referring exclusively to their businesses and operations.
Financial Repositioning
In January 2017, we entered into agreements with Williams Partners L.P. (WPZ), wherein we permanently waived
the general partner’s incentive distribution rights (IDRs) and converted our 2 percent general partner interest in WPZ
to a noneconomic interest in exchange for 289 million newly issued WPZ common units. Pursuant to this agreement,
we also purchased approximately 277 thousand WPZ common units for $10 million. Additionally, we purchased
approximately 59 million common units of WPZ at a price of $36.08586 per unit in a private placement transaction,
funded with proceeds from our equity offering (see Note 14 – Stockholders' Equity). According to the terms of this
agreement, concurrent with WPZ’s quarterly distributions in February 2017 and May 2017, we paid additional
consideration totaling $56 million to WPZ for these units. Subsequent to these transactions and as of December 31,
2017, we own a 74 percent limited partner interest in WPZ.
Termination of WPZ Merger Agreement
On May 12, 2015, we entered into an agreement for a unit-for-stock transaction whereby we would have acquired
all of the publicly held outstanding common units of WPZ in exchange for shares of our common stock (WPZ Merger
Agreement).
On September 28, 2015, we entered into a Termination Agreement and Release (Termination Agreement),
terminating the WPZ Merger Agreement. Under the terms of the Termination Agreement, we were required to pay a
$428 million termination fee to WPZ, at which time we owned approximately 60 percent, including the interests of the
general partner and IDRs. Such termination fee settled through a reduction of quarterly incentive distributions we were
entitled to receive from WPZ (such reduction not to exceed $209 million per quarter). The distributions from WPZ in
November 2015, February 2016, and May 2016 were reduced by $209 million, $209 million, and $10 million,
respectively, related to this termination fee.
ACMP Merger
On February 2, 2015, Williams Partners L.P. merged with and into Access Midstream Partners, L.P. (ACMP Merger).
For the purpose of these financial statements and notes, WPZ refers to the renamed merged partnership, while Pre-
merger Access Midstream Partners, L.P. (ACMP) and Pre-merger Williams Partners L.P. (Pre-merger WPZ) refer to
the separate partnerships prior to the consummation of the ACMP Merger and subsequent name change. The net assets
of Pre-merger WPZ and ACMP were combined at our historical basis. Our basis in ACMP reflected our business
combination accounting resulting from acquiring control of ACMP on July 1, 2014.
Description of Business
We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our
operations are located principally in the United States. We have one reportable segment, Williams Partners. All remaining
business activities are included in Other.
85
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Williams Partners
Williams Partners consists of our consolidated master limited partnership, WPZ, and primarily includes gas pipeline
and midstream businesses.
WPZ’s gas pipeline businesses primarily consist of two interstate natural gas pipelines, which are Transcontinental
Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (Northwest Pipeline), and several joint venture
investments in interstate and intrastate natural gas pipeline systems, including a 50 percent equity-method investment
in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 41 percent interest in Constitution Pipeline Company,
LLC (Constitution) (a consolidated entity), which is developing a pipeline project (see Note 3 – Variable Interest
Entities).
WPZ’s midstream businesses primarily consist of (1) natural gas gathering, treating, compression, and processing;
(2) natural gas liquid (NGL) fractionation, storage, and transportation; (3) crude oil production handling and
transportation; and (4) olefins production (see Note 2 – Acquisitions and Divestitures). The primary service areas are
concentrated in major producing basins in Colorado, Texas, Oklahoma, Kansas, New Mexico, Wyoming, the Gulf of
Mexico, Louisiana, Pennsylvania, West Virginia, New York, and Ohio, which include the Barnett, Eagle Ford,
Haynesville, Marcellus, Niobrara, and Utica shale plays as well as the Mid-Continent region.
The midstream businesses include equity-method investments in natural gas gathering and processing assets and
NGL fractionation and transportation assets, including a 62 percent equity-method investment in Utica East Ohio
Midstream, LLC (UEOM), a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel
Mountain), a 58 percent equity-method investment in Caiman Energy II, LLC (Caiman II), a 60 percent equity-method
investment in Discovery Producer Services, LLC (Discovery), a 50 percent equity-method investment in Overland Pass
Pipeline, LLC (OPPL), and Appalachia Midstream Services, LLC, which owns equity-method investments with an
approximate average 66 percent interest in multiple gathering systems in the Marcellus Shale (Appalachia Midstream
Investments), as well as our previously owned 50 percent equity-method investment in the Delaware basin gas gathering
system (DBJV) in the Mid-Continent region (see Note 5 – Investing Activities).
The midstream businesses also included our Canadian midstream operations, which were comprised of an oil sands
offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility at Redwater, Alberta.
In September 2016, we completed the sale of our Canadian operations. (See Note 2 – Acquisitions and Divestitures.)
Other
Other is comprised of business activities that are not operating segments, as well as corporate operations. Other
also includes certain domestic olefins pipeline assets as well as certain Canadian assets, which included a liquids
extraction plant located near Fort McMurray, Alberta, that began operations in March 2016, and a propane
dehydrogenation facility which was under development. In September 2016, the Canadian assets were sold. (See Note
2 – Acquisitions and Divestitures.)
Basis of Presentation
Consolidated master limited partnership
As of December 31, 2017, we owned approximately 74 percent of the interests in WPZ, a variable interest entity
(VIE) (see Note 3 – Variable Interest Entities).
Pursuant to WPZ’s distribution reinvestment program, 1,606,448 common units were issued to the public during
2017 associated with reinvested distributions of $61 million. These common unit issuances, the Financial Repositioning,
WPZ’s quarterly distribution of additional paid-in-kind Class B units to us, and other equity issuances by WPZ had the
combined net impact of decreasing Noncontrolling interests in consolidated subsidiaries by $2.407 billion, and
increasing Capital in excess of par value by $1.497 billion and Deferred income tax liabilities by $910 million in the
Consolidated Balance Sheet.
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Notes to Consolidated Financial Statements – (Continued)
WPZ is self-funding and maintains separate lines of bank credit and cash management accounts and also has a
commercial paper program. (See Note 13 – Debt, Banking Arrangements, and Leases.) Cash distributions from WPZ
to all partners, including us, are governed by WPZ’s partnership agreement.
Discontinued operations
Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our
continuing operations.
Significant risks and uncertainties
We may monetize assets that are not core to our strategy which could result in impairments of certain equity-
method investments, property, plant, and equipment, and intangible assets. Such impairments could potentially be
caused by indications of fair value implied through the monetization process or, in the case of asset dispositions that
are part of a broader asset group, the impact of the loss of future estimated cash flows.
Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the accounts of all entities that we control and our proportionate
interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate
whether we control an entity. Key areas of that evaluation include:
• Determining whether an entity is a VIE;
• Determining whether we are 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 we and our related
parties have over those activities through our variable interests;
•
Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating
whether we are a VIE’s primary beneficiary;
• 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 we do not have the
power to control such entities.
We apply the equity method of accounting to investments over which we exercise significant influence but do not
control.
Equity-method investment basis differences
Differences between the cost of our equity-method investments and our underlying equity in the net assets of
investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in the
Consolidated Statement of Operations includes our allocable share of net income (loss) of investees adjusted for any
depreciation and amortization, as applicable, associated with basis differences.
Use of estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United
States requires us to make estimates and assumptions that affect the amounts reported in the consolidated financial
statements and accompanying notes. Actual results could differ from those estimates.
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Notes to Consolidated Financial Statements – (Continued)
Significant estimates and assumptions include:
•
Impairment assessments of investments, property, plant, and equipment, goodwill, and other identifiable
intangible assets;
• Litigation-related contingencies;
• Environmental remediation obligations;
• Realization of deferred income tax assets;
• Depreciation and/or amortization of equity-method investment basis differences;
• Asset retirement obligations;
• Pension and postretirement valuation variables;
• Measurement of regulatory liabilities;
• Measurement of deferred income tax assets and liabilities.
These estimates are discussed further throughout these notes.
Regulatory accounting
Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates,
which are established by the FERC, are designed to recover the costs of providing the regulated services, and their
competitive environment makes it probable that such rates can be charged and collected. Therefore, we have determined
that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” to account
for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way
in which their rates are established. Accounting for these operations that are regulated can differ from the accounting
requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during
construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process
of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of
construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of
debt funds related to construction activities, while a component for equity is prohibited. The components of our
regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset
retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, pension and other
postretirement benefits, and rate allowances for deferred income taxes at a historically higher federal income tax rate.
In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate
income tax rate from 35 percent to 21 percent (Tax Reform) (see Note 7 – Provision (Benefit) for Income Taxes). In
accordance with ASC 980-740-25-2, Transco and Northwest Pipeline have recognized regulatory liabilities to reflect
the probable return to customers through future rates of the future decrease in income taxes payable associated with
Tax Reform. These liabilities represent an obligation to return amounts directly to our customers. While a majority of
our customers have entered into tariff rates based on our cost-of-service proceedings and related rate base therein,
certain other contracts with customers reflect contractually-based rates that are designed to recover the cost of providing
those services, including an allowance for income taxes, with no expected future rate adjustment for the term of those
contracts. This relative mix of contracts for services was considered in determining the probable amount to be returned
to customers through future rates. The regulatory liabilities were recorded in December 2017 through regulatory charges
to operating income totaling $674 million. The timing and actual amount of such return will be subject to future
negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs
of providing service.
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Notes to Consolidated Financial Statements – (Continued)
Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity earnings (losses)
in the Consolidated Statement of Operations have been reduced by $11 million related to our proportionate share of
the associated regulatory charges.
Our regulatory assets associated with the effects of deferred taxes on equity funds used during construction were
also impacted by Tax Reform and were reduced by $102 million in December 2017 through a charge to Other income
(expense) – net below Operating income (loss) in the Consolidated Statement of Operations (see Note 6 – Other Income
and Expenses). This amount, along with the previously described charges for establishing the regulatory liabilities
resulting from Tax Reform, is reported within Regulatory charges resulting from Tax Reform within the Consolidated
Statement of Cash Flows.
Our current and noncurrent regulatory asset and liability balances for the years ended December 31, 2017 and
2016 are as follows:
December 31,
2017
2016
Current assets reported within Other current assets and deferred charges ........................... $
Noncurrent assets reported within Regulatory assets, deferred charges, and other ..............
Total regulated assets ...................................................................................................... $
$
(Millions)
102
376
478
$
Current liabilities reported within Accrued liabilities............................................................ $
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other ....
Total regulated liabilities................................................................................................. $
18
1,250
1,268
$
$
91
387
478
11
498
509
Cash and cash equivalents
Cash and cash equivalents in the Consolidated Balance Sheet includes amounts primarily invested in funds with
high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have
maturity dates of three months or less when acquired.
Accounts receivable
Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We
estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our
customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received
by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time
full payment is received or collectability is assured. Past due accounts are generally written off against the allowance
for doubtful accounts only after all collection attempts have been exhausted.
Inventories
Inventories in the Consolidated Balance Sheet primarily consist of natural gas liquids, olefins, natural gas in
underground storage, and materials and supplies and are stated at the lower of cost or net realizable value. The cost of
inventories is primarily determined using the average-cost method.
Property, plant, and equipment
Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates,
assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.
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Notes to Consolidated Financial Statements – (Continued)
As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at
FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over
estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.
Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are
credited or charged to accumulated depreciation. Other gains or losses are recorded in Other (income) expense – net
included in Operating income (loss) in the Consolidated Statement of Operations.
Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and
replacements are capitalized as property, plant, and equipment.
We record a liability and increase the basis in the underlying asset for the present value of each expected future
asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or
constructed. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that
is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We
measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount
is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included
in Operating and maintenance expenses in the Consolidated Statement of Operations, except for regulated entities, for
which the liability is offset by a regulatory asset. The regulatory asset is amortized commensurate with our collection
of those costs in rates.
Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party
would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred
to as a market-risk premium.
Goodwill
Goodwill included within Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet
represents the excess of the consideration, plus the fair value of any noncontrolling interest or any previously held
equity interest, over the fair value of the net assets acquired. It is not subject to amortization but is evaluated annually
as of October 1 for impairment or more frequently if impairment indicators are present that would indicate it is more
likely than not that the fair value of the reporting unit is less than its carrying amount. Generally, the evaluation of
goodwill for impairment involves a two-step quantitative test, although under certain circumstances an initial qualitative
evaluation may be sufficient to conclude goodwill is not impaired. If a quantitative assessment is performed, we compare
our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of
the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its
related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill,
an impairment loss is recognized in the amount of the excess. Judgments and assumptions are inherent in our estimate
of fair value. Effective October 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 “Intangibles
- Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” (ASU 2017-04), which removed
the computation of the implied fair value of goodwill from the measurement process.
Other intangible assets
Our identifiable intangible assets included within Intangible assets – net of accumulated amortization in the
Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation contractual customer
relationships. Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute
to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any
changes prospectively through amortization over the revised remaining useful life.
Impairment of property, plant, and equipment, other identifiable intangible assets, and investments
We evaluate our property, plant, and equipment and other identifiable intangible assets for impairment when events
or changes in circumstances indicate, in our judgment, that the carrying value of such assets may not be recoverable.
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Notes to Consolidated Financial Statements – (Continued)
When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable
to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a
probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes
including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying
value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating
the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.
This evaluation is performed at the lowest level for which separately identifiable cash flows exist.
For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value
to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets
are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date
of sale, is recalculated when related events or circumstances change.
We evaluate our investments for impairment when events or changes in circumstances indicate, in our judgment,
that the carrying value of such investments may have experienced an other-than-temporary decline in value. When
evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value
of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying
value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair
value is recognized in the consolidated financial statements as an impairment charge.
Judgments and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or
investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets
considered for disposal.
Deferred income
We record a liability for deferred income related to cash received from customers in advance of providing our
services. Such amounts are generally recognized in revenue upon satisfying our performance obligations, primarily
providing services based on units of production or over remaining contractual service periods ranging from 1 to 25
years. Deferred income is reflected within Accrued liabilities and Regulatory liabilities, deferred income, and other
on the Consolidated Balance Sheet. (See Note 12 – Accrued Liabilities.)
WPZ received an aggregate amount of $240 million in three equal installments as certain milestones of Transco’s
Hillabee Expansion Project were met related to an agreement to resolve several matters in relation to the project. (See
Note 12 – Accrued Liabilities.) During the third quarter of 2017, WPZ received the final installment and placed the
project into service. As a result of placing the project into service, WPZ reclassified the refundable deposits to deferred
income and expects to recognize income associated with these receipts over the term of an underlying contract.
During 2016, we received cash proceeds totaling $820 million associated with restructuring certain gas gathering
contracts in the Barnett Shale and Mid-Continent regions. The proceeds were recorded as deferred income and are
being amortized into income.
In October 2016, we received $104 million of newly constructed assets as part of a noncash investing transaction
with a customer for which we provide production handling and other services. The transaction was recorded in Property,
plant, and equipment – net and deferred income in the Consolidated Balance Sheet and is being amortized based on
units of production through 2024. Due to the noncash nature of this transaction, it is not presented within the Consolidated
Statement of Cash Flows.
Contingent liabilities
We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss
is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our
assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers,
or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when
realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information
become known or circumstances change that affect the previous assumptions or estimates.
Cash flows from revolving credit facilities and commercial paper program
Proceeds and payments related to borrowings under our credit facilities are reflected in the financing activities in
the Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our
commercial paper program are reflected in the financing activities in the Consolidated Statement of Cash Flows on a
net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See
Note 13 – Debt, Banking Arrangements, and Leases.)
Treasury stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is
recorded as Treasury stock in the Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares
are credited or charged to Capital in excess of par value in the Consolidated Balance Sheet using the average-cost
method.
Derivative instruments and hedging activities
We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily
of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities.
We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has
been elected, in Other current assets and deferred charges; Regulatory assets, deferred charges, and other; Accrued
liabilities; or Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet. We determine the
current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report
these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties
on a gross basis. (See Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.)
The accounting for the changes in fair value of a commodity derivative can be summarized as follows:
Derivative Treatment
Accounting Method
Normal purchases and normal sales exception
Accrual accounting
Designated in a qualifying hedging relationship
Hedge accounting
All other derivatives
Mark-to-market accounting
We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and
sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is
not reflected on the balance sheet after the initial election of the exception.
We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for
designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation.
We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships
at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected
to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk
being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative
ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged
forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the
fair value of the derivative are recognized currently in Product sales or Product costs in the Consolidated Statement
of Operations.
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the
derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in the Consolidated Balance Sheet
and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the
derivative’s change in fair value is recognized currently in Product sales or Product costs in the Consolidated Statement
of Operations. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be
highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable
of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects
earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will
not occur, any gain or loss deferred in AOCI is recognized in Product sales or Product costs in the Consolidated
Statement of Operations at that time. The change in likelihood of a forecasted transaction is a judgmental decision that
includes qualitative assessments made by us.
For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected
the normal purchases and normal sales exception, we report changes in fair value currently in Product sales or Product
costs in the Consolidated Statement of Operations.
Certain gains and losses on derivative instruments included in the Consolidated Statement of Operations are netted
together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded
on a net basis include unrealized gains and losses on all derivatives that are not designated as hedges and for which we
have not elected the normal purchases and normal sales exception.
Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL
processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell
arrangement, are recorded on a gross basis.
Revenue recognition
Revenues
As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the
issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities
considering our and other third-party regulatory proceedings, advice of counsel, and other risks.
Service revenues
Revenues from our interstate natural gas pipeline businesses include services pursuant to long-term firm
transportation and storage agreements. These agreements provide for a reservation charge based on the volume of
contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our
FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the
volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible
transportation services and storage injection and withdrawal services, are recognized when natural gas is delivered
at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility.
Certain revenues from our midstream operations include those derived from natural gas gathering, processing,
treating, and compression services and are performed under volumetric-based fee contracts. These revenues are
recorded when services have been performed.
Certain of our gas gathering and processing agreements have minimum volume commitments. If a customer
under such an agreement fails to meet its minimum volume commitment for a specified period, generally measured
on an annual basis, it is obligated to pay a contractually determined fee based upon the shortfall between actual
production volumes and the minimum volume commitment for that period. The revenue associated with minimum
volume commitments is recognized in the period that the actual shortfall is determined and is no longer subject to
future reduction or offset, which is generally at the end of the annual period or fourth quarter.
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Crude oil gathering and transportation revenues and offshore production handling fees are recognized when
the services have been performed. Certain offshore production handling contracts contain fixed payment terms
that result in the deferral of revenues until such services have been performed or such capacity has been made
available.
Storage revenues from our midstream operations associated with prepaid contracted storage capacity contracts
are recognized on a straight-line basis over the life of the contract as services are provided.
Product sales
In the course of providing transportation services to customers of our interstate natural gas pipeline businesses,
we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers.
The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms
provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation
and exchange imbalances.
We market NGLs, crude oil, and natural gas that we purchase from our producer customers as part of the
overall service provided to producers. Revenues from marketing activities are recognized when the products have
been sold and delivered.
Under our keep-whole and percent-of-liquids processing contracts, we retain the rights to all or a portion of
the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are
sold and delivered.
Our former domestic olefins business produced olefins from purchased or produced feedstock and we
recognized revenues when the olefins were sold and delivered.
Our Canadian businesses that were sold in September 2016 had processing and fractionation operations where
we retained certain NGLs and olefins from an upgrader’s offgas stream and we recognized revenues when the
fractionated products were sold and delivered.
Interest capitalized
We capitalize interest during construction on major projects with construction periods of at least 3 months and a
total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC
exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below
Operating income (loss) in the Consolidated Statement of Operations. The rates used by regulated companies are
calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest
rate on debt.
Employee stock-based awards
We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are
recognized when they occur. (See Note 15 – Equity-Based Compensation.)
Pension and other postretirement benefits
The funded status of each of the pension and other postretirement benefit plans is recognized separately in the
Consolidated Balance Sheet as either an asset or liability. The funded status is the difference between the fair value of
plan assets and the plan’s benefit obligation. The plans’ benefit obligations and net periodic benefit costs (credits) are
actuarially determined and impacted by various assumptions and estimates. (See Note 9 – Employee Benefit Plans.)
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The discount rates are determined separately for each of our pension and other postretirement benefit plans based
on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised
of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan.
The expected long-term rates of return on plan assets are determined by combining a review of the historical returns
within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital market
projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.
Unrecognized actuarial gains and losses and unrecognized prior service costs and credits are deferred and recorded
in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of
net periodic benefit cost (credit). Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the
benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining
future years of service, which is approximately 13 years for our pension plans and approximately 7 years for our other
postretirement benefit plans.
The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-
related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of
plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected
and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more
than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related
value of plan assets for our other postretirement benefit plans is equal to the unadjusted fair value of plan assets at the
beginning of the year.
Income taxes
We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in
our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required.
Deferred income taxes are computed using the liability method and are provided on all temporary differences between
the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to
determine the levels, if any, of valuation allowances associated with deferred tax assets.
Earnings (loss) per common share
Basic earnings (loss) per common share in the Consolidated Statement of Operations is based on the sum of the
weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per
common share in the Consolidated Statement of Operations includes any dilutive effect of stock options, nonvested
restricted stock units, and convertible debt, unless otherwise noted. Diluted earnings (loss) per common share are
calculated using the treasury-stock method.
Foreign currency translation
Certain of our foreign subsidiaries that used the Canadian dollar as their functional currency were sold in 2016.
The assets and liabilities of such foreign subsidiaries were translated at the spot rate in effect at the applicable reporting
date, and the combined statements of operations were translated into the U.S. dollar at the average exchange rates in
effect during the applicable period. The resulting cumulative translation adjustment was recorded as a separate
component of AOCI in the Consolidated Balance Sheet.
Transactions denominated in currencies other than the functional currency were recorded based on exchange rates
at the time such transactions arose. Subsequent changes in exchange rates when the transactions were settled resulted
in transaction gains and losses which were reflected in Other (income) expense – net within Costs and expenses in the
Consolidated Statement of Operations. Substantially all of our Canadian operations were sold in September 2016.
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Accounting standards issued and adopted
Effective January 1, 2017, we adopted ASU 2016-09, “Compensation - Stock Compensation (Topic 718):
Improvements to Employee Share-Based Payment Accounting” (ASU 2016-09). ASU 2016-09 changed the accounting
for income taxes such that all excess tax benefits and all tax deficiencies are now recognized as a discrete item in the
provision for income taxes in the financial reporting period they occur and the recognition of tax benefits is no longer
delayed until the tax benefit is realized through a reduction in income taxes payable. These changes were applied
prospectively beginning in 2017. We recorded a cumulative-effect adjustment as of January 1, 2017, decreasing Retained
deficit by $37 million in the Consolidated Balance Sheet to recognize tax benefits that were not previously recognized.
ASU 2016-09 requires entities to classify excess tax benefits as an operating activity on the statement of cash flows.
We applied this part of the guidance prospectively beginning in 2017; therefore, the cash flows for prior periods were
not adjusted. In recognizing compensation cost from share-based payments, ASU 2016-09 allows entities to make an
accounting policy election to either recognize forfeitures when they occur or estimate the number of forfeitures expected
to occur. We are recognizing forfeitures when they occur and as a result of the change in our accounting policy, we
increased our Retained deficit for an insignificant cumulative-effect adjustment as of January 1, 2017. ASU 2016-09
requires entities to classify as a financing activity, on the statement of cash flows, cash paid by an employer to a taxing
authority when directly withholding shares from an employee’s award to satisfy the employer’s statutory tax withholding
obligation. This guidance was applied retrospectively.
Effective October 1, 2017, we early adopted ASU 2017-04 “Intangibles - Goodwill and Other (Topic 350):
Simplifying the Test for Goodwill Impairment.” ASU 2017-04 modified the concept of goodwill impairment to represent
the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of
goodwill. Under ASU 2017-04, entities are no longer required to determine the implied fair value of goodwill by
assigning the fair value of a reporting unit to its individual assets and liabilities as if that reporting unit had been acquired
in a business combination. Our Williams Partners reportable segment has $47 million of goodwill included in Intangible
assets – net of accumulated amortization in the Consolidated Balance Sheet (see Note 11 – Goodwill and Other Intangible
Assets).
Accounting standards issued but not yet adopted
In February 2018, the Financial Accounting Standards Board (FASB) issued ASU 2018-02 “Income Statement -
Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other
Comprehensive Income” (ASU 2018-02). As a result of Tax Reform lowering the federal income tax rate, the tax effects
of items within accumulated other comprehensive income may not reflect the appropriate tax rate. ASU 2018-02 allows
for the reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects
resulting from Tax Reform. ASU 2018-02 is effective for interim and annual periods beginning after December 15,
2018. Early adoption is permitted. ASU 2018-02 should be applied either in the period of adoption or retrospectively
to each period (or periods) in which the effect of the change in the federal corporate income tax rate as a result of Tax
Reform is recognized. We plan to early adopt ASU 2018-02 during the first quarter of 2018 and do not believe the
adoption will have a significant impact on our consolidated financial statements.
In August 2017, the FASB issued ASU 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements
to Accounting for Hedging Activities” (ASU 2017-12). ASU 2017-12 applies to entities that elect hedge accounting in
accordance with Accounting Standards Codification (ASC) 815. The ASU affects both the designation and measurement
guidance for hedging relationships and the presentation of hedging results. ASU 2017-12 is effective for interim and
annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2017-12 will be applied using
a modified retrospective approach for cash flow and net investment hedges existing at the date of adoption and
prospectively for the presentation and disclosure guidance. During the first quarter of 2018, we early adopted ASU
2017-12. The adoption did not have a significant impact on our consolidated financial statements.
In March 2017, the FASB issued ASU 2017-07 “Compensation - Retirement Benefits (Topic 715): Improving the
Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost” (ASU 2017-07). ASU 2017-07
requires employers to report the service cost component of net benefit cost in the same line item or items as other
96
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
compensation costs arising from employee services. The other components of net benefit cost must be presented in the
income statement separately from the service cost component and outside a subtotal of income from operations, if one
is presented. Only the service cost component is now eligible for capitalization when applicable. ASU 2017-07 is
effective beginning January 1, 2018. The presentation aspect of ASU 2017-07 must be applied retrospectively and the
capitalization requirement prospectively. Upon adoption, we will present the elements of net periodic benefit costs in
the Consolidated Statement of Operations in accordance with ASU 2017-07. We do not expect the change in the costs
eligible to be capitalized to have a material effect on our consolidated financial statements.
In August 2016, the FASB issued ASU 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain
Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow
classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity
method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning
after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not
expect ASU 2016-15 to have a material impact on our consolidated financial statements.
In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement
of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most
financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans,
and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will
result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13
is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The standard
requires varying transition methods for the different categories of amendments. Although we do not expect ASU 2016-13
to have a significant impact, it will impact our trade receivables as the related allowance for credit losses will be
recognized earlier under the expected loss model.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes
a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach
to lease classification similar to current lease accounting, and causes lessees to recognize leases on the balance sheet
as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset,
with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the
amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01
“Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU
2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the
arrangements are or contain a lease. ASU 2018-01 permits an entity to elect a transition practical expedient to not apply
ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not
previously assessed under the previous lease guidance in ASC Topic 840 “Leases.” ASU 2016-02 is effective for interim
and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 currently requires
a modified retrospective transition for financing or operating leases existing at or entered into after the beginning of
the earliest comparative period presented in the financial statements.
In January 2018, the FASB proposed an accounting standard update titled “Leases (Topic 842): Targeted
Improvements,” which is an update to ASU 2016-02 allowing entities an additional transition method to the existing
requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect
adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial
statements for periods prior to adoption. We expect to adopt ASU 2016-02 effective January 1, 2019. We are in the
process of reviewing contracts to identify leases based on the modified definition of a lease, implementing a financial
lease accounting system, and evaluating internal control changes to support management in the accounting for and
disclosure of leasing activities. While we are still in the process of completing our implementation evaluation of ASU
2016-02, we currently believe the most significant changes relate to the recognition of a lease liability and offsetting
right-of-use asset in our consolidated balance sheet for operating leases. We are also evaluating ASU 2016-02’s currently
available and proposed practical expedients on adoption.
97
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with
Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the
transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled
to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August
2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective
Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning
after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption
is permitted for annual periods beginning after December 15, 2016. We are adopting ASC 606 utilizing the modified
retrospective transition approach, effective January 1, 2018, by recognizing the cumulative effect of initially applying
ASC 606 for periods prior to January 1, 2018, which we expect to result in a decrease of approximately $255 million,
net of tax, to the opening balance of Total equity in the Consolidated Balance Sheet.
We are in the final stages of evaluating the impact ASC 606 will have on our financial statements. For each revenue
contract type, we have conducted a formal contract review process to evaluate the impact of ASC 606. We have
substantially completed our evaluation. During the fourth quarter, we concluded on certain technical matters, including
the evaluation of significant financing components, tiered pricing structures, and minimum volume commitments, and
certain contracts for which we received prepayments for services. The adjustment to Total equity upon adoption of ASC
606 is primarily comprised of the impact to the timing of recognition of deferred revenue (contract liabilities) associated
with certain contracts which underwent modifications in periods prior to January 1, 2018. Under the provisions of ASC
606, when a contract modification does not increase both the scope and price of the contract, and the remaining goods
and services are distinct from the goods and services transferred prior to the modification, the modification is treated
as a termination of the existing contract and the creation of a new contract. The new contract requires that the transaction
price, including any remaining deferred revenue from the old contract, be allocated to the performance obligations over
the term of the new contract. The contract modifications adjustments are partially offset by the impact of changes to
the timing of recognizing revenue which is subject to the constraint on estimates of variable consideration of certain
contracts. The constraint of variable consideration will result in the acceleration of revenue recognition and
corresponding de-recognition of deferred revenue for certain contracts (as compared to the previous revenue recognition
model) as a result of our assessment that it is probable such recognition would not result in a significant revenue reversal
in the future. Additionally, under ASC 606, our revenues will increase in situations where we receive noncash
consideration, which exists primarily in certain of our gas processing contracts where we receive commodities as full
or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and
expenses when the commodities received are subsequently sold. Based on commodities received during 2017 as
consideration for services and market prices during 2017, the increase in revenues and costs would have been
approximately $350 million. Financial systems and internal controls necessary for adoption were implemented effective
January 1, 2018.
Note 2 – Acquisitions and Divestitures
Eagle Ford Gathering System
In May 2015, WPZ acquired a gathering system comprised of approximately 140 miles of pipeline and a sour gas
compression facility in the Eagle Ford Shale for $112 million. The acquisition was accounted for as a business
combination, and the allocation of the acquisition-date fair value of the major classes of assets acquired includes $80
million of Property, plant, and equipment – net and $32 million of Intangible assets – net of accumulated amortization
in the Consolidated Balance Sheet. Changes to the preliminary allocation disclosed in the second quarter of 2015 reflect
an increase of $20 million in Property, plant, and equipment – net, and a decrease of $20 million in Intangible assets
– net of accumulated amortization.
Sale of Geismar Interest
In July 2017, WPZ completed the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our
88.5 percent undivided interest in the Geismar, Louisiana, olefins plant (Geismar Interest) for total consideration of
$2.084 billion in cash. We received a final working capital adjustment of $12 million in October 2017. Upon closing
98
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
of the sale, WPZ entered into a long-term supply and transportation agreement with the purchaser to provide feedstock
to the plant via its Bayou Ethane pipeline system. The assets and liabilities of the Geismar olefins plant were designated
as held for sale within the Williams Partners segment during the first quarter of 2017. As a result of this sale, we recorded
a gain of $1.095 billion in the third quarter of 2017. Following this sale, the cash proceeds were used to repay WPZ’s
$850 million term loan. Proceeds have also been funding a portion of the capital and investment expenditures that are
a part of WPZ’s growth portfolio.
The following table presents the results of operations for the Geismar Interest, excluding the gain noted above:
Years Ended December 31,
2017
2016
Income (loss) before income taxes of the Geismar Interest................................................... $
Income (loss) before income taxes of the Geismar Interest attributable to The Williams
Companies, Inc. ..........................................................................................................................
(Millions)
26
$
19
141
85
Sale of Canadian Operations
In September 2016, we completed the sale of subsidiaries conducting Canadian operations, including subsidiaries
of WPZ, (such subsidiaries, the Canadian disposal group). Consideration received totaled $1.020 billion, net of $31
million of cash divested and subject to customary working capital adjustments. In connection with the sale, we waived
$150 million of incentive distributions otherwise payable by WPZ to us in the fourth quarter of 2016 in recognition of
certain affiliate contracts wherein WPZ’s Canadian operations provided services to certain of our other businesses. The
proceeds were primarily used to reduce borrowings on credit facilities.
During the second quarter of 2016, we designated these operations as held for sale. As a result, we measured the
fair value of the disposal group as of June 30, 2016, resulting in an impairment charge of $747 million, reflected in
Impairment of certain assets in the Consolidated Statement of Operations. (See Note 16 – Fair Value Measurements,
Guarantees, and Concentration of Credit Risk.) During the second half of 2016 we recorded an additional loss of $66
million upon completion of the sale, primarily reflecting revisions to the sales price and estimated contingent
consideration and including a $15 million benefit related to transactions to hedge our foreign currency exchange risk
on the Canadian proceeds, reflected in Other (income) expense – net within Costs and expenses in the Consolidated
Statement of Operations. The total loss consists of a loss of $34 million at Williams Partners and $32 million at Other.
The following table presents the results of operations for the Canadian disposal group, excluding the impairment
and loss noted above:
Income (loss) before income taxes of Canadian disposal group............................................ $
Income (loss) before income taxes of Canadian disposal group attributable to The Williams
Companies, Inc. ..........................................................................................................................
(Millions)
— $
—
(98)
(95)
Years Ended December 31,
2017
2016
Note 3 – Variable Interest Entities
WPZ
We own a 74 percent interest in WPZ, a master limited partnership that is a VIE due to the limited partners’ lack
of substantive voting rights, such as either participating rights or kick-out rights that can be exercised with a simple
majority of the vote of the limited partners. We are the primary beneficiary of WPZ because we have the power, through
our general partner interest, to direct the activities that most significantly impact WPZ’s economic performance.
99
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table presents amounts included in our Consolidated Balance Sheet that are for the use or obligation
of WPZ and/or its subsidiaries, and which comprise a significant portion of our consolidated assets and liabilities:
December 31,
2017
2016
(Millions)
Classification
Assets (liabilities):
Cash and cash equivalents.............................. $
Trade accounts and other receivables – net ....
Inventories .....................................................
Other current assets ........................................
Investments ....................................................
Property, plant, and equipment – net..............
Intangible assets – net ....................................
Regulatory assets, deferred charges, and
other noncurrent assets .................................
Accounts payable ...........................................
Accrued liabilities including current asset
retirement obligations ..................................
Commercial paper ..........................................
Long-term debt due within one year ..............
881
972
113
176
6,552
27,912
8,790
507
(957)
(857)
—
(501)
$
145 Cash and cash equivalents
925
Trade accounts and other receivables
Inventories
138
205 Other current assets and deferred
charges
Investments
6,701
28,021 Property, plant, and equipment – net
9,662
Intangible assets – net of accumulated
amortization
467 Regulatory assets, deferred charges,
and other
(589) Accounts payable
(1,122) Accrued liabilities
(93) Commercial paper
(785) Long-term debt due within one year
Long-term debt ..............................................
(15,996)
(17,685) Long-term debt
Deferred income tax liabilities .......................
Noncurrent asset retirement obligations.........
(16)
(944)
Long-term deferred income ...........................
(1,119)
Regulatory liabilities and other ......................
(1,690)
(20) Deferred income tax liabilities
(798) Regulatory liabilities, deferred income,
and other
(1,048) Regulatory liabilities, deferred income,
and other
(812) Regulatory liabilities, deferred income,
and other
The assets and liabilities presented in the table above also include the consolidated interests of the following
individual VIEs within WPZ:
Gulfstar One
WPZ owns a 51 percent interest in Gulfstar One LLC (Gulfstar One), a subsidiary that, due to certain risk-sharing
provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar
FPS, and associated pipelines which provide production handling and gathering services in the eastern deepwater Gulf
of Mexico. WPZ is the primary beneficiary because it has the power to direct the activities that most significantly
impact Gulfstar One’s economic performance.
Constitution
WPZ owns a 41 percent interest in Constitution, a subsidiary that, due to shipper fixed-payment commitments
under its long-term firm transportation contracts, is a VIE. WPZ is the primary beneficiary because it has the power to
direct the activities that most significantly impact Constitution’s economic performance. WPZ, as operator of
100
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Constitution, is responsible for constructing the proposed pipeline connecting its gathering system in Susquehanna
County, Pennsylvania, to the Iroquois Gas Transmission and the Tennessee Gas Pipeline systems. The total remaining
cost of the project is estimated to be approximately $740 million, which would be funded with capital contributions
from WPZ and the other equity partners on a proportional basis.
In December 2014, Constitution received approval from the Federal Energy Regulatory Commission (FERC) to
construct and operate its proposed pipeline. However, in April 2016, the New York State Department of Environmental
Conservation (NYSDEC) denied the necessary water quality certification under Section 401 of the Clean Water Act
for the New York portion of the pipeline. In May 2016, Constitution appealed the NYSDEC’s denial of the Section 401
certification to the United States Court of Appeals for the Second Circuit, and in August 2017 the court issued a decision
denying in part and dismissing in part Constitution’s appeal. The court expressly declined to rule on Constitution’s
argument that the delay in the NYSDEC’s decision on Constitution’s Section 401 application constitutes a waiver of
the certification requirement. The court determined that it lacked jurisdiction to address that contention, and found that
jurisdiction over the waiver issue lies exclusively with the United States Court of Appeals for the District of Columbia
Circuit. As to the denial itself, the court determined that NYSDEC’s action was not arbitrary or capricious. Constitution
filed a petition for rehearing with the Second Circuit Court of Appeals, but in October the court denied our petition.
In October 2017, WPZ filed a petition for declaratory order requesting the FERC to find that, by operation of law,
the Section 401 certification requirement for the New York State portion of Constitution’s pipeline project was waived
due to the failure by the NYSDEC to act on Constitution’s Section 401 application within a reasonable period of time
as required by the express terms of such statute. In January 2018, the FERC denied WPZ’s petition, finding that Section
401 provides that a state waives certification only when it does not act on an application within one year from the date
of the application.
The project’s sponsors remain committed to the project, and, in that regard, we are pursuing two separate and
independent paths in order to overturn the NYSDEC’s denial of the Section 401 certification. In January 2018, we filed
a petition with the United States Supreme Court to review the decision of the Second Circuit Court of Appeals that
upheld the merits of the NYSDEC’s denial of the Section 401 certification. And, in February 2018, we filed a request
with the FERC for rehearing of its finding that the NYSDEC did not waive the Section 401 certification requirement.
If the FERC denies such request, we will file a petition for review with the D.C. Circuit Court of Appeals.
We estimate that the target in-service date for the project would be approximately 10 to 12 months following any
court or FERC decision that the NYSDEC denial order was improper or that the NYSDEC waived the Section 401
certification requirement. An unfavorable resolution could result in the impairment of a significant portion of the
capitalized project costs, which total $381 million on a consolidated basis at December 31, 2017, and are included
within Property, plant, and equipment – net in the Consolidated Balance Sheet. Beginning in April 2016, we discontinued
capitalization of development costs related to this project. It is also possible that we could incur certain supplier-related
costs in the event of a prolonged delay or termination of the project.
Cardinal
WPZ owns a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal), a subsidiary that provides gathering
services for the Utica Shale region and is a VIE due to certain risks shared with customers. WPZ is the primary beneficiary
because it has the power to direct the activities that most significantly impact Cardinal’s economic performance. Future
expansion activity is expected to be funded with capital contributions from WPZ and the other equity partner on a
proportional basis.
Jackalope
WPZ owns a 50 percent interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope), a subsidiary that provides
gathering and processing services for the Powder River basin and is a VIE due to certain risks shared with customers.
WPZ is the primary beneficiary because it has the power to direct the activities that most significantly impact Jackalope’s
economic performance. Future expansion activity is expected to be funded with capital contributions from WPZ and
the other equity partner on a proportional basis.
101
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 4 – Related Party Transactions
Transactions with Equity-Method Investees
We have purchases from our equity-method investees included in Product costs in the Consolidated Statement of
Operations of $226 million, $180 million, and $187 million for the years ended 2017, 2016, and 2015, respectively.
We have $20 million and $19 million included in Accounts payable in the Consolidated Balance Sheet with our equity-
method investees at December 31, 2017 and 2016, respectively.
WPZ has operating agreements with certain equity-method investees. These operating agreements typically provide
for reimbursement or payment to WPZ for certain direct operational payroll and employee benefit costs, materials,
supplies, and other charges and also for management services. We supplied a portion of these services, primarily those
related to employees since WPZ does not have any employees, to certain equity-method investees. The total charges
to equity-method investees for these fees are $67 million, $66 million, and $64 million for the years ended 2017, 2016,
and 2015, respectively.
Board of Directors
A former member of our Board of Directors, who was elected in 2013 and resigned during 2016, is also the current
chairman, president, and chief executive officer of an energy services company that is a customer of ours. We recorded
$144 million and $111 million in Service revenues in the Consolidated Statement of Operations from this company for
transportation and storage of natural gas for the years ended December 31, 2016 and 2015, respectively.
Note 5 – Investing Activities
Impairment of equity-method investments
The following table presents other-than-temporary impairment charges related to certain equity-method
investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk):
Williams Partners
Appalachia Midstream Investments...............................................................................
DBJV..............................................................................................................................
Laurel Mountain.............................................................................................................
UEOM............................................................................................................................
Ranch Westex.................................................................................................................
Other ..............................................................................................................................
Years Ended December 31,
2016
2015
(Millions)
$
$
294
59
50
—
24
3
430
$
$
562
503
45
241
—
8
1,359
Acquisition of Additional Interests in Appalachia Midstream Investments
During the first quarter of 2017, WPZ exchanged all of its 50 percent interest in DBJV for an increased interest in
two natural gas gathering systems that are part of the Appalachia Midstream Investments and $155 million in cash.
This transaction was recorded based on our estimate of the fair value of the interests received as we have more insight
to this value as we operate the underlying assets. Following this exchange, WPZ has an approximate average 66 percent
interest in the Appalachia Midstream Investments. We continue to account for this investment under the equity-method
due to the significant participatory rights of our partners such that we do not exercise control. WPZ also sold all of its
interest in Ranch Westex JV LLC (Ranch Westex) for $45 million. These transactions resulted in a total gain of $269
million reflected in Other investing income (loss) – net in the Consolidated Statement of Operations.
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The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The fair value of the increased interests in the Appalachia Midstream Investments received as consideration was
estimated to be $1.1 billion using an income approach based on expected cash flows and an appropriate discount rate
(a Level 3 measurement within the fair value hierarchy). The determination of estimated future cash flows involved
significant assumptions regarding gathering volumes, rates, and related capital spending. A 9.5 percent discount rate
was utilized and reflected our estimate of the cost of capital as impacted by market conditions and risks associated with
the underlying business.
Acquisition of Additional Interest in UEOM
In June 2015, WPZ acquired an approximate 13 percent additional interest in its equity-method investment, UEOM,
for $357 million. Following the acquisition WPZ owns approximately 62 percent of UEOM. However, WPZ continues
to account for this as an equity-method investment because WPZ does not control UEOM due to the significant
participatory rights of its partner. In connection with the acquisition of the additional interest, we agreed to waive
approximately $2 million of our WPZ IDR payments each quarter through 2017. See Note 1 – General, Description of
Business, Basis of Presentation, and Summary of Significant Accounting Policies for discussion of agreement with
WPZ wherein we permanently waived IDR payment obligations from WPZ.
Equity earnings (losses)
Equity earnings (losses) in 2015 includes a loss of $19 million associated with WPZ’s share of underlying property
impairments at certain of the Appalachia Midstream Investments.
Other investing income (loss) – net
In 2016, we recognized a $27 million gain from the sale of an equity-method investment interest in a gathering
system that was part of the Appalachia Midstream Investments.
Other investing income (loss) – net also includes $36 million and $27 million of interest income for 2016 and 2015,
respectively, associated with a receivable related to the sale of certain former Venezuela assets. Due to changes in
circumstances that led to late payments and increased uncertainty regarding the recovery of the receivable, we began
accounting for the receivable under a cost recovery model in first quarter 2015. Subsequently, we received payments
greater than the remaining carrying amount of the receivable, which resulted in the recognition of interest income.
Investments
Ownership
Interest at
December 31,
2017
Equity-method investments:
Appalachia Midstream Investments .................................................................
UEOM ..............................................................................................................
Discovery .........................................................................................................
Caiman II ..........................................................................................................
OPPL ................................................................................................................
Laurel Mountain ...............................................................................................
Gulfstream ........................................................................................................
DBJV ................................................................................................................
Other .................................................................................................................
(1)
62%
60%
58%
50%
69%
50%
—
Various
December 31,
2017
2016
(Millions)
$
$
3,104
1,383
534
429
422
309
244
—
127
6,552
$
$
2,062
1,448
572
426
430
324
261
988
190
6,701
___________
(1) Includes equity-method investments in multiple gathering systems in the Marcellus Shale with an approximate
average 66 percent interest.
103
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
We have differences between the carrying value of our equity-method investments and the underlying equity in
the net assets of the investees of $1.8 billion at December 31, 2017 and $1.9 billion at December 31, 2016. For 2017
these differences primarily relate to our investments in Appalachia Midstream Investments and UEOM resulting from
property, plant, and equipment, as well as customer-based intangible assets and goodwill. For 2016, the difference also
includes DBJV.
Purchases of and contributions to equity-method investments
We generally fund our portion of significant expansion or development projects of these investees through additional
capital contributions. These transactions increased the carrying value of our investments and included:
Appalachia Midstream Investments ................................................................ $
DBJV ...............................................................................................................
Caiman II .........................................................................................................
Discovery.........................................................................................................
UEOM .............................................................................................................
Other ................................................................................................................
$
Dividends and distributions
Years Ended December 31,
2017
2016
(Millions)
2015
70
32
24
1
—
5
132
$
$
28
105
22
—
—
22
177
$
$
93
57
—
35
357
53
595
The organizational documents of entities in which we have an equity-method interest generally require distribution
of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our
investments and included:
2017
Years Ended December 31,
2016
(Millions)
2015
Appalachia Midstream Investments ................................................................ $
Discovery.........................................................................................................
Gulfstream .......................................................................................................
UEOM .............................................................................................................
OPPL ...............................................................................................................
Caiman II .........................................................................................................
DBJV ...............................................................................................................
Laurel Mountain ..............................................................................................
Other ................................................................................................................
$
270
127
92
80
68
49
39
32
27
784
$
$
211
141
100
92
69
40
39
28
22
742
$
$
219
116
88
42
45
33
33
31
26
633
In addition, on September 24, 2015, WPZ received a special distribution of $396 million from Gulfstream reflecting
its proportional share of the proceeds from new debt issued by Gulfstream. The new debt was issued to refinance
Gulfstream’s debt maturities. Subsequently, WPZ contributed $248 million and $148 million to Gulfstream for its
proportional share of amounts necessary to fund debt maturities of $500 million due on November 1, 2015, and $300
million due on June 1, 2016, respectively.
104
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Summarized Financial Position and Results of Operations of All Equity-Method Investments
December 31,
2017
2016
(Millions)
Assets (liabilities):
Current assets..................................................................................................................... $
Noncurrent assets...............................................................................................................
Current liabilities ...............................................................................................................
Noncurrent liabilities .........................................................................................................
$
447
9,181
(295)
(1,538)
508
9,695
(412)
(1,484)
Years Ended December 31,
2017
2016
(Millions)
2015
Gross revenue .................................................................................................. $
Operating income ............................................................................................
Net income.......................................................................................................
$
1,961
871
806
$
1,883
799
726
1,707
690
611
Note 6 – Other Income and Expenses
The following table presents certain gains or losses reflected in Other (income) expense – net within Costs and
expenses in the Consolidated Statement of Operations:
Williams Partners
Loss on sale of Canadian operations (Note 2)................................................ $
Amortization of regulatory assets associated with asset retirement
obligations...................................................................................................
Accrual of regulatory liability related to overcollection of certain
employee expenses .....................................................................................
Project development costs related to Constitution (Note 3)...........................
Gains on contract settlements and terminations .............................................
Gain on sale of Refinery Grade Propylene Splitter........................................
Net foreign currency exchange (gains) losses (1) ..........................................
Gain on asset retirement .................................................................................
Other
Loss on sale of Canadian operations (Note 2)................................................
Gain on sale of unused pipe ...........................................................................
Years Ended December 31,
2017
2016
2015
(Millions)
4
$
34
$
33
22
16
(15)
(12)
—
—
1
—
33
25
28
—
—
10
(11)
32
(10)
—
33
20
—
—
—
(10)
—
—
—
________________
(1) Primarily relates to gains and losses incurred on foreign currency transactions and the remeasurement of U.S.
dollar-denominated current assets and liabilities within our former Canadian operations (see Note 2 – Acquisitions
and Divestitures).
105
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
ACMP Acquisition, Merger, and Transition
Certain ACMP acquisition, merger, and transition costs included in the Consolidated Statement of Operations are
as follows:
•
•
Selling, general, and administrative expenses includes $26 million in 2015 primarily related to professional
advisory fees within the Williams Partners segment.
Selling, general, and administrative expenses includes $32 million in 2015 of general corporate expenses
associated with integration and realignment of resources within the Other segment.
• Operating and maintenance expenses includes $12 million in 2015 primarily related to employee transition
costs within the Williams Partners segment.
Additional Items
Certain additional items included in the Consolidated Statement of Operations are as follows:
•
•
•
•
•
•
Service revenues includes $66 million, $58 million, and $239 million recognized in the fourth quarter of 2017,
2016, and 2015, respectively, from minimum volume commitment fees in the Barnett Shale and Mid-Continent
regions within the Williams Partners segment.
Service revenues for the year ended December 31, 2016, includes $173 million associated with the amortization
of deferred income related to the restructuring of certain gas gathering contracts in the Barnett Shale and Mid-
Continent regions within the Williams Partners segment.
Service revenues were reduced by $15 million for the year ended December 31, 2016, related to potential
refunds associated with a ruling received in certain rate case litigation within the Williams Partners segment.
Selling, general, and administrative expenses includes $9 million and $47 million for the years ended
December 31, 2017 and 2016, respectively, of costs associated with our evaluation of strategic alternatives
within the Other segment. Selling, general, and administrative expenses also includes $61 million for the year
ended December 31, 2016, of project development costs related to a proposed propane dehydrogenation facility
in Alberta, Canada within the Other segment. Beginning in the first quarter of 2016, these costs did not qualify
for capitalization.
Selling, general, and administrative expenses and Operating and maintenance expenses includes $22 million
in severance and other related costs for the year ended December 31, 2017, for the Williams Partners segment.
The year ended December 31, 2016, included $42 million in severance and other related costs associated with
an approximate 10 percent reduction in workforce in the first quarter of 2016, primarily within the Williams
Partners segment.
Selling, general, and administrative expenses and Operating and maintenance expenses includes $35 million
of settlement charge expense in 2017 related to the program to pay out certain deferred vested pension benefits
within the Williams Partners segment (see Note 9 – Employee Benefit Plans).
• Other income (expense) – net below Operating income (loss) includes $71 million, $66 million, and $77
million for equity AFUDC for the years ended December 31, 2017, 2016, and 2015, respectively. Other income
(expense) – net below Operating income (loss) also includes $52 million, $23 million and $18 million for the
years ended December 31, 2017, 2016 and 2015, respectively, of income associated with regulatory assets
related to the effects of deferred taxes on equity funds used during construction.
106
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
• Other income (expense) – net below Operating income (loss) includes a $102 million charge for the year ended
December 31, 2017, for regulatory assets associated with the effects of deferred taxes on equity funds used
during construction as a result of Tax Reform comprised of $39 million within the Williams Partners segment
and $63 million within the Other segment (see Note 1 – General, Description of Business, Basis of Presentation,
and Summary of Significant Accounting Policies).
• Other income (expense) – net below Operating income (loss) includes $35 million of settlement charge expense
in 2017 related to the program to pay out certain deferred vested pension benefits (see Note 9 – Employee
Benefit Plans).
• Other income (expense) – net below Operating income (loss) for the year ended December 31, 2017, includes
a net gain of $30 million associated with the February 23, 2017, early retirement of $750 million of 6.125
percent senior unsecured notes that were due in 2022 and a net loss of $3 million associated with the July 3,
2017, early retirement of of $1.4 billion of 4.875 percent senior unsecured notes that were due in 2023. The
net gain for the February 23, 2017, early retirement within the Other segment reflects $53 million of
unamortized premium, partially offset by $23 million in premiums paid. The net loss for the July 3, 2017,
early retirement within the Other segment reflects $51 million of unamortized premium, offset by $54 million
in premiums paid (see Note 13 – Debt, Banking Arrangements, and Leases).
Note 7 – Provision (Benefit) for Income Taxes
The Provision (benefit) for income taxes includes:
Years Ended December 31,
2017
2016
(Millions)
2015
$
— $
15
23
—
38
(2,004)
(8)
—
(2,012)
(1,974) $
2
(1)
1
(6)
61
(81)
(26)
(25) $
—
(7)
(55)
(62)
(317)
(25)
5
(337)
(399)
Current:
Federal........................................................................................................ $
State............................................................................................................
Foreign .......................................................................................................
Deferred:
Federal........................................................................................................
State............................................................................................................
Foreign .......................................................................................................
Provision (benefit) for income taxes............................................................... $
107
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are
as follows:
Provision (benefit) at statutory rate ...................................................... $
Increases (decreases) in taxes resulting from:
Impact of nontaxable noncontrolling interests..................................
Federal Tax Reform rate change .......................................................
State income taxes (net of federal benefit)........................................
State deferred income tax rate change ..............................................
Foreign operations – net (including tax effect of Canadian Sale).....
Translation adjustment of certain unrecognized tax benefits............
Other – net.........................................................................................
Provision (benefit) for income taxes..................................................... $
Years Ended December 31,
2017
2016
(Millions)
2015
187
$
(131) $
(600)
(117)
(1,932)
(17)
26
(127)
—
6
(1,974) $
(22)
—
3
43
78
(1)
5
(25) $
263
—
(21)
—
8
(71)
22
(399)
Income (loss) before income taxes includes $7 million and $885 million of foreign loss in 2017 and 2016,
respectively, and $20 million of foreign income in 2015.
Foreign operations – net (including tax effect of Canadian Sale) increased in 2016 due to a valuation allowance
associated with impairments and losses on the sale of our Canadian operations (see Note 2 – Acquisitions and
Divestitures) and the reversal of anticipatory foreign tax credits, partially offset by the tax effect of the impairments
associated with our Canadian disposition.
On December 22, 2017, Tax Reform was enacted. Most of the provisions of Tax Reform are not effective until
after January 1, 2018. However, the deferred tax impact of reducing the U.S. corporate tax rate from 35 percent to 21
percent is recognized in the period of enactment. This remeasurement resulted in a reduction of our deferred tax liabilities
of approximately $1.9 billion, with a corresponding net adjustment to Provision (benefit) for income taxes. Under the
guidance provided by Securities and Exchange Commission Staff Accounting Bulletin No. 118, Income Tax Accounting
Implications of the Tax Cuts and Jobs Act, we are recording provisional adjustments related to the impact of Tax Reform,
including items such as direct expensing of assets placed into service after September 27, 2017. We anticipate that
additional guidance from the Internal Revenue Service (IRS) will be released to guide us in determining what assets
are eligible for direct expensing in 2017. We are also recording provisional adjustments for valuation allowances
associated with State losses and credits (see following table), since, at this time, we cannot assess the impact that the
interest expense disallowance will have on our estimated future taxable income. We are not reducing our Minimum tax
credit (see following table) for sequestration until we receive further guidance on that matter.
The Translation adjustment of certain unrecognized tax benefits in 2016 and 2015 reflects the impact of changes
in foreign currency exchange rates on the remeasurement of a foreign currency denominated unrecognized tax benefit,
including associated penalties and interest.
The 2015 federal and state income tax provisions include the tax effect of a $2.7 billion impairment loss associated
with certain goodwill, equity-method investments, and other assets. (See Note 16 – Fair Value Measurements,
Guarantees, and Concentration of Credit Risk.)
During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges
regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions
and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various
filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we
record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual
is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision
(benefit) for income taxes.
108
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Significant components of Deferred income tax liabilities and Deferred income tax assets are as follows:
Deferred income tax liabilities:
Investments........................................................................................................................ $
Other ..................................................................................................................................
Total deferred income tax liabilities ............................................................................
Deferred income tax assets:
Accrued liabilities..............................................................................................................
Minimum tax credit ...........................................................................................................
Foreign tax credit...............................................................................................................
Federal loss carryovers ......................................................................................................
State losses and credits ......................................................................................................
Other ..................................................................................................................................
Total deferred income tax assets..................................................................................
Less valuation allowance...................................................................................................
Net deferred income tax assets ....................................................................................
Overall net deferred income tax liabilities ............................................................................ $
December 31,
2017
2016
(Millions)
3,565
19
3,584
53
155
140
—
283
30
661
224
437
3,147
$
$
5,300
29
5,329
145
139
140
651
313
37
1,425
334
1,091
4,238
As of December 31, 2017, Overall net deferred income tax liabilities reflects the 21 percent federal rate change
as established by Tax Reform. We consider all amounts recorded related to Tax Reform to be reasonable estimates. The
amounts recorded are provisional as our interpretation, assessment, and presentation of the impact of the tax law change
may be further clarified with additional guidance from regulatory, tax, and accounting authorities. Should additional
guidance be provided by these authorities or other sources, we will review the provisional amounts and adjust as
appropriate.
The valuation allowance at December 31, 2017 and 2016 serves to reduce the available deferred income tax assets
to an amount that will, more likely than not, be realized. We consider all available positive and negative evidence,
including projected future taxable income and management’s estimate of future reversals of existing taxable temporary
differences, and have determined that a portion of our deferred income tax assets related to State losses and credits
may not be realized. The change in Valuation allowance is partially due to this evaluation. The amounts presented in
the table above are, with respect to state items, before any federal benefit. The change from prior year for the State
losses and credits is primarily due to increases in losses and credits generated in the current and prior years less losses
and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions.
These attributes generally expire between 2018 and 2037 with some carryovers having indefinite carryforward periods.
The Valuation allowance change from prior year is primarily due to releasing a $127 million valuation allowance on
a deferred tax asset associated with a capital loss carryover. Under Tax Reform, the federal Minimum tax credit of $155
million will be refunded/utilized no later than 2021. Foreign tax credit carryforwards of $140 million are expected to
be utilized prior to their expiration between 2024 and 2027.
Federal deferred income tax assets related to our net operating loss carryovers and charitable contribution carryovers
at the end of 2017 are fully offset by our unrecognized tax positions in the table below.
Cash payments for income taxes (net of refunds) were $28 million and $5 million in 2017 and 2016, respectively.
Cash refunds for income taxes (net of payments and discontinued operations) were $136 million in 2015.
As of December 31, 2017, we had approximately $50 million of unrecognized tax benefits. If recognized, income
tax expense would be reduced by $50 million and $49 million for 2017 and 2016, respectively, including the effect of
these changes on other tax attributes, with state income tax amounts included net of federal tax effect. A reconciliation
of the beginning and ending amount of unrecognized tax benefits is as follows:
109
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
2017
2016
Balance at beginning of period ............................................................................................. $
Reductions for tax positions of prior years ...........................................................................
Changes due to currency translation .....................................................................................
Balance at end of period........................................................................................................ $
$
(Millions)
50
—
—
50
$
55
(4)
(1)
50
We recognize related interest and penalties as a component of Provision (benefit) for income taxes. Total interest
and penalties recognized as part of income tax provision were benefits of $400 thousand and $22 million for 2017 and
2015, respectively, and expenses of $300 thousand for 2016. Approximately $2 million and $3 million of interest and
penalties primarily relating to uncertain tax positions have been accrued as of December 31, 2017 and 2016, respectively.
During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with
domestic or international matters to have a material impact on our unrecognized tax benefit position.
Consolidated U.S. Federal income tax returns are open to IRS examination for years after 2010. As of December 31,
2017, examinations of tax returns for 2011 through 2013 are currently in process. We do not expect material changes
in our financial position resulting from these examinations. The statute of limitations for most states expires one year
after expiration of the IRS statute. Generally, tax returns for our previously owned Canadian entities are open to audit
for tax years after 2012. Tax years 2013 and 2014 are currently under examination. We have indemnified the purchaser
for any adjustments to Canadian tax returns for periods prior to the sale of our Canadian operations in September 2016.
On September 13, 2013, the IRS issued final regulations providing guidance on the treatment of amounts paid to
acquire, produce, or improve tangible property. On August 18, 2014, the IRS issued final regulations providing guidance
on the dispositions of such property. The implementation date for these regulations was January 1, 2014. The IRS is
expected to issue additional procedural guidance regarding how the requirements may be implemented for the gas
transmission and distribution industry. Pending the issuance of this additional procedural guidance from the IRS, we
cannot at this time estimate the impact of implementing the regulations for our gas transmission business, although we
anticipate that it will result in an immaterial balance-sheet-only impact.
Note 8 – Earnings (Loss) Per Common Share
Net income (loss) attributable to The Williams Companies, Inc. available to
common stockholders for basic and diluted earnings (loss) per common
share ............................................................................................................. $
Basic weighted-average shares........................................................................
Effect of dilutive securities:
Nonvested restricted stock units...................................................................
Stock options ................................................................................................
Diluted weighted-average shares (1) ...............................................................
Earnings (loss) per common share:
Years Ended December 31,
2017
2016
2015
(Dollars in millions, except per-share
amounts; shares in thousands)
2,174
826,177
$
(424) $
750,673
(571)
749,271
1,704
637
828,518
—
—
750,673
—
—
749,271
Basic ............................................................................................................. $
Diluted .......................................................................................................... $
2.63
2.62
$
$
(.57) $
(.57) $
(.76)
(.76)
________________
(1) For the years ended December 31, 2016 and December 31, 2015, 0.6 million and 1.7 million weighted-average
nonvested restricted stock units, and 0.5 million and 1.5 million weighted-average stock options have been excluded
from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to
our loss from continuing operations attributable to The Williams Companies, Inc.
110
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 9 – Employee Benefit Plans
We have noncontributory defined benefit pension plans in which all eligible employees participate. Currently,
eligible employees earn benefits primarily based on a cash balance formula. Various other formulas, as defined in the
plan documents, are utilized to calculate the retirement benefits for plan participants not covered by the cash balance
formula. At the time of retirement, participants may elect, to the extent they are eligible for the various options, to
receive annuity payments, a lump-sum payment, or a combination of annuity and lump-sum payments. In addition to
our pension plans, we currently provide subsidized retiree medical and life insurance benefits (other postretirement
benefits) to certain eligible participants. Generally, employees hired after December 31, 1991, are not eligible for the
subsidized retiree medical benefits, except for participants that were employees or retirees of Transco Energy Company
on December 31, 1995, and other miscellaneous defined participant groups. Subsidized retiree medical benefits for
eligible participants age 65 and older are paid through contributions to health reimbursement accounts. Subsidized
retiree medical benefits for eligible participants under age 65 are provided through a self-insured medical plan sponsored
by us. The self-insured retiree medical plan provides for retiree contributions and contains other cost-sharing features
such as deductibles, co-payments, and co-insurance. The accounting for these plans anticipates estimated future
increases to our contribution levels to the health reimbursement accounts for participants age 65 and older, as well as
future cost-sharing that is consistent with our expressed intent to increase the retiree contribution level generally in line
with health care cost increases for participants under age 65.
In September 2017, we initiated a program to pay out certain deferred vested pension benefits to reduce investment
risk, cash funding volatility, and administrative costs. In December 2017, the lump-sum payments were made and the
annuity payments were commenced in relation to this program. As a result of these lump-sum payments, as well as
lump-sum benefit payments made throughout 2017, settlement accounting was required. We settled $261 million in
liabilities of our pension plans and recognized a pre-tax, non-cash settlement charge of $71 million, of which $35
million is reported in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of
Operations (see Note 6 – Other Income and Expenses). These amounts are included within the subsequent tables of
changes in benefit obligations and plan assets, net periodic benefit cost (credit), and other changes in plan assets and
benefit obligations recognized in other comprehensive income (loss) before taxes.
111
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Funded Status
The following table presents the changes in benefit obligations and plan assets for pension benefits and other
postretirement benefits for the years indicated:
Pension Benefits
Other
Postretirement
Benefits
2017
2016
2017
2016
(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year.................................. $
Service cost ............................................................................
Interest cost ............................................................................
Plan participants’ contributions..............................................
Benefits paid...........................................................................
Actuarial loss (gain) ...............................................................
Settlements .............................................................................
Net increase (decrease) in benefit obligation......................
Benefit obligation at end of year ............................................
Change in plan assets:
Fair value of plan assets at beginning of year ........................
Actual return on plan assets ...................................................
Employer contributions ..........................................................
Plan participants’ contributions..............................................
Benefits paid...........................................................................
Settlements .............................................................................
Net increase (decrease) in fair value of plan assets ............
Fair value of plan assets at end of year ..................................
Funded status — overfunded (underfunded) ............................. $
Accumulated benefit obligation................................................. $
$
1,466
50
59
—
(35)
40
(261)
(147)
1,319
1,254
184
85
—
(35)
(261)
(27)
1,227
(92) $
$
1,294
$
1,464
54
62
—
(130)
20
(4)
2
1,466
1,241
82
65
—
(130)
(4)
13
1,254
(212) $
1,440
197
1
8
3
(14)
11
—
9
206
208
25
5
3
(14)
—
19
227
21
$
$
202
1
8
2
(15)
(1)
—
(5)
197
201
13
7
2
(15)
—
7
208
11
The overfunded (underfunded) status of our pension plans and other postretirement benefit plans presented in the
previous table are recognized in the Consolidated Balance Sheet within the following accounts:
December 31,
2017
2016
(Millions)
Underfunded pension plans:
Current liabilities............................................................................................................ $
Noncurrent liabilities......................................................................................................
(2) $
(90)
(2)
(210)
Overfunded (underfunded) other postretirement benefit plans:
Current liabilities............................................................................................................
Noncurrent assets (liabilities).........................................................................................
(6)
27
(7)
18
The plan assets within our other postretirement benefit plans are intended to be used for the payment of benefits
for certain groups of participants. The Current liabilities for the other postretirement benefit plans represent the current
portion of benefits expected to be payable in the subsequent year for the groups of participants whose benefits are not
expected to be paid from plan assets.
112
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The pension plans’ benefit obligation Actuarial loss (gain) of $40 million in 2017 is primarily due to the impact
of a decrease in the discount rates utilized to calculate the benefit obligation. The pension plans’ benefit obligation
Actuarial loss (gain) of $20 million in 2016 is primarily due to the impact of a decrease in the discount rates utilized
to calculate the benefit obligation.
The 2017 benefit obligation Actuarial loss (gain) of $11 million for our other postretirement benefit plans is
primarily due to a decrease in the discount rate used to calculate the benefit obligation.
At December 31, 2017 and 2016, all of our pension plans had a projected benefit obligation and accumulated
benefit obligation in excess of plan assets.
Pre-tax amounts not yet recognized in Net periodic benefit cost (credit) at December 31 are as follows:
Pension Benefits
Other
Postretirement
Benefits
2017
2016
2017
2016
(Millions)
Amounts included in Accumulated other comprehensive
income (loss):
Prior service credit.............................................................. $
Net actuarial loss.................................................................
— $
— $
(375)
(535)
— $
(21)
5
(18)
Amounts included in regulatory liabilities associated with
Transco and Northwest Pipeline:
Prior service credit..............................................................
Net actuarial gain................................................................
N/A
N/A
N/A $
N/A
$
2
14
10
8
In addition to the regulatory liabilities included in the previous table, differences in the amount of actuarially
determined Net periodic benefit cost (credit) for our other postretirement benefit plans and the other postretirement
benefit costs recovered in rates for Transco and Northwest Pipeline are deferred as a regulatory asset or liability. We
have regulatory liabilities of $108 million at December 31, 2017 and $94 million at December 31, 2016, related to these
deferrals. Additionally, Transco recognizes a regulatory liability for rate collections in excess of its amount funded to
the tax-qualified pension plans. At December 31, 2017 and 2016, these regulatory liabilities were $33 million and $21
million, respectively. These pension and other postretirement plans amounts will be reflected in future rates based on
the rate structures of these gas pipelines.
Net Periodic Benefit Cost (Credit)
Net periodic benefit cost (credit) for the years ended December 31 consist of the following:
Pension Benefits
2017
2016
2015
Other
Postretirement Benefits
2016
2017
2015
(Millions)
Components of net periodic benefit cost (credit):
Service cost ................................................................ $
Interest cost ................................................................
Expected return on plan assets ...................................
Amortization of prior service credit ...........................
Amortization of net actuarial loss ..............................
Net actuarial loss from settlements ............................
Reclassification to regulatory liability .......................
Net periodic benefit cost (credit) ................................... $
50
59
(82)
—
27
71
—
125
$
$
54
62
(85)
—
30
2
—
63
$
$
59
58
(75)
—
42
2
—
86
$
$
$
1
8
(11)
(13)
—
—
3
(12) $
$
1
8
(12)
(15)
—
—
4
(14) $
2
9
(12)
(17)
2
—
3
(13)
113
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Items Recognized in Other Comprehensive Income (Loss) and Regulatory Assets and Liabilities
Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes
for the years ended December 31 consist of the following:
Pension Benefits
Other
Postretirement Benefits
2017
2016
2015
2017
2016
2015
(Millions)
Other changes in plan assets and benefit obligations
recognized in Other comprehensive income (loss):
Net actuarial gain (loss) ............................................. $
Amortization of prior service credit...........................
Amortization of net actuarial loss ..............................
Net actuarial loss from settlements ............................
62
—
27
71
$
(23) $
—
30
2
5
—
42
2
$
(3) $ — $
(5)
—
—
(6)
—
—
8
(6)
2
—
Other changes in plan assets and benefit obligations
recognized in Other comprehensive income (loss)........ $ 160
$
9
$
49
$
(8) $
(6) $
4
Other changes in plan assets and benefit obligations for our other postretirement benefit plans associated with
Transco and Northwest Pipeline are recognized in regulatory assets and liabilities. Amounts recognized in regulatory
assets and liabilities for the years ended December 31 consist of the following:
Other changes in plan assets and benefit obligations recognized in
regulatory (assets) and liabilities:
Net actuarial gain (loss)..........................................................................
Amortization of prior service credit .......................................................
$
$
6
(8)
$
2
(9)
10
(11)
Pre-tax amounts expected to be amortized in Net periodic benefit cost (credit) in 2018 are as follows:
2017
2016
2015
(Millions)
Amounts included in Accumulated other comprehensive income (loss):
Prior service credit..................................................................................................... $
Net actuarial loss .......................................................................................................
Amounts included in regulatory liabilities associated with Transco and Northwest
Pipeline:
Prior service credit.....................................................................................................
Net actuarial loss .......................................................................................................
Key Assumptions
Pension
Benefits
Other
Postretirement
Benefits
(Millions)
— $
23
N/A $
N/A
(1)
—
(2)
—
The weighted-average assumptions utilized to determine benefit obligations as of December 31 are as follows:
Discount rate ..............................................................................
Rate of compensation increase...................................................
3.66%
4.93
4.17%
4.87
3.71%
N/A
4.27%
N/A
Pension Benefits
Other
Postretirement
Benefits
2017
2016
2017
2016
114
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The weighted-average assumptions utilized to determine Net periodic benefit cost (credit) for the years ended
December 31 are as follows:
Discount rate...................................
Expected long-term rate of return
on plan assets ..............................
Rate of compensation increase .......
Pension Benefits
Other
Postretirement Benefits
2017
2016
2015
2017
2016
2015
4.17%
4.37%
3.96%
4.27%
4.50%
4.12%
6.45
4.87
6.85
4.88
6.38
4.62
5.53
N/A
6.11
N/A
5.70
N/A
The mortality assumptions used to determine the benefit obligations for our pension and other postretirement
benefit plans reflect generational projection mortality tables.
The assumed health care cost trend rate for 2018 is 8.0 percent. This rate decreases to 4.5 percent by 2026. A one-
percentage-point change in assumed health care cost trend rates would have the following effects:
Effect on total of service and interest cost components................................................ $
Effect on other postretirement benefit obligation .........................................................
(Millions)
— $
5
—
(5)
Point increase
Point decrease
Plan Assets
Plan assets for our pension and other postretirement benefit plans consist primarily of equity and fixed income
securities including mutual funds and commingled investment funds invested in equity and fixed income securities.
The plans’ investment policy provides for a strategy in accordance with the Employee Retirement Income Security Act
(ERISA), which governs the investment of the assets in a diversified portfolio. The plans follow a policy of diversifying
the investments across various asset classes and investment managers. Additionally, the investment returns on
approximately 37 percent of the other postretirement benefit plan assets are subject to income tax; therefore, certain
investments are managed in a tax efficient manner.
The investment policy for the pension plans includes a general target asset allocation at December 31, 2017, of 46
percent equity securities and 54 percent fixed income securities. The target allocation includes the investments in equity
and fixed income mutual funds and commingled investment funds. The investment policy allows for a broad range of
asset allocations that permit the plans to de-risk in response to changes in the plans’ funded status.
Equity securities may include U.S. equities and non-U.S. equities. Investment in Williams’ securities or an entity
in which Williams has a majority ownership is prohibited except where these securities may be owned in a commingled
investment fund in which the plans’ trusts invest. No more than 5 percent of the total stock portfolio valued at market
may be invested in the common stock of any one corporation.
Fixed income securities may consist of U.S. as well as international instruments, including emerging markets. The
fixed income strategies may invest in government, corporate, asset-backed securities, and mortgage-backed obligations.
The weighted-average credit rating of the fixed income strategies must be at least “investment grade” including ratings
by Moody’s and/or Standard & Poor’s. No more than 5 percent of the total fixed income portfolio may be invested in
the fixed income securities of any one issuer with the exception of bond index funds and U.S. government guaranteed
and agency securities.
The following securities and transactions are not authorized: unregistered securities, commodities or commodity
contracts, short sales or margin transactions, or other leveraging strategies. Investment strategies using direct
investments in derivative securities require approval and, historically, have not been used; however, these instruments
may be used in mutual funds and commingled investment funds held by the plans’ trusts. Additionally, real estate equity,
115
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
natural resource property, venture capital, leveraged buyouts, and other high-return, high-risk investments are generally
restricted.
There are no significant concentrations of risk within the plans’ investment securities because of the diversity of
the types of investments, diversity of the various industries, and the diversity of the fund managers and investment
strategies. Generally, the investments held in the plans are publicly traded, therefore, minimizing liquidity risk in the
portfolio.
The fair values of our pension plan assets at December 31, 2017 and 2016 by asset class are as follows:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2017
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(Millions)
Total
Pension assets:
Cash management fund ............................................... $
Equity securities:
U.S. large cap...........................................................
U.S. small cap..........................................................
Fixed income securities (1):
U.S. Treasury securities...........................................
Government and municipal bonds...........................
Mortgage and asset-backed securities .....................
Corporate bonds.......................................................
Insurance company investment contracts and other....
$
Commingled investment funds measured at net asset
value practical expedient (2):
Equities — U.S. large cap .......................................
Equities — International small cap .........................
Equities — International emerging markets............
Equities — International developed markets ..........
Fixed income — U.S. long duration........................
Fixed income — Corporate bonds...........................
Total assets at fair value at December 31, 2017...
17
$
— $
— $
62
54
103
—
—
—
—
236
$
—
—
—
15
47
158
5
225
$
—
—
—
—
—
—
—
—
$
17
62
54
103
15
47
158
5
461
265
26
41
110
205
119
1,227
116
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2016
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(Millions)
Total
Pension assets:
Cash management fund ............................................... $
Equity securities:
U.S. large cap...........................................................
U.S. small cap..........................................................
Fixed income securities (1):
U.S. Treasury securities...........................................
Government and municipal bonds...........................
Mortgage and asset-backed securities .....................
Corporate bonds.......................................................
Insurance company investment contracts and other....
$
Commingled investment funds measured at net asset
value practical expedient (2):
Equities — U.S. large cap .......................................
Equities — International small cap .........................
Equities — International emerging markets............
Equities — International developed markets ..........
Fixed income — U.S. long duration........................
Fixed income — Corporate bonds...........................
Total assets at fair value at December 31, 2016...
14
$
— $
— $
87
77
68
—
—
—
—
246
$
—
—
—
10
80
148
5
243
$
—
—
—
—
—
—
—
—
$
14
87
77
68
10
80
148
5
489
369
27
50
149
88
82
1,254
117
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The fair values of our other postretirement benefits plan assets at December 31, 2017 and 2016 by asset class are
as follows:
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2017
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(Millions)
Total
Other postretirement benefit assets:
Cash management funds ............................................. $
Equity securities:
U.S. large cap...........................................................
U.S. small cap..........................................................
International developed markets large cap growth..
Fixed income securities (1):
U.S. Treasury securities...........................................
Government and municipal bonds...........................
Mortgage and asset-backed securities .....................
Corporate bonds.......................................................
Mutual fund — Municipal bonds................................
$
Commingled investment funds measured at net asset
value practical expedient (2):
Equities — U.S. large cap .......................................
Equities — International small cap .........................
Equities — International emerging markets............
Equities — International developed markets ..........
Fixed income — U.S. long duration........................
Fixed income — Corporate bonds...........................
Total assets at fair value at December 31, 2017...
11
$
— $
— $
25
14
—
12
—
—
—
43
105
$
—
—
6
—
2
5
19
—
32
$
—
—
—
—
—
—
—
—
—
$
11
25
14
6
12
2
5
19
43
137
31
3
5
13
24
14
227
118
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
2016
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(Millions)
Total
Other postretirement benefit assets:
Cash management funds............................................... $
Equity securities:
U.S. large cap............................................................
U.S. small cap ...........................................................
International developed markets large cap growth ...
Fixed income securities (1):
U.S. Treasury securities ............................................
Government and municipal bonds ............................
Mortgage and asset-backed securities ......................
Corporate bonds........................................................
Mutual fund — Municipal bonds .................................
$
Commingled investment funds measured at net asset
value practical expedient (2):
Equities — U.S. large cap.........................................
Equities — International small cap...........................
Equities — International emerging markets .............
Equities — International developed markets............
Fixed income — U.S. long duration.........................
Fixed income — Corporate bonds............................
Total assets at fair value at December 31, 2016....
11
$
— $
— $
24
15
—
7
—
—
—
42
99
$
—
—
5
—
1
8
15
—
29
$
—
—
—
—
—
—
—
—
—
$
11
24
15
5
7
1
8
15
42
128
38
3
5
16
9
9
208
____________
(1) The weighted-average credit quality rating of the fixed income security portfolio is investment grade with a
weighted-average duration of approximately 12 years for 2017 and 8 years for 2016.
(2) The stated intents of the funds vary based on each commingled fund’s investment objective. These objectives
generally include strategies to replicate or outperform various market indices. Certain standard withdrawal
restrictions generally apply, which may include redemption notification period restrictions ranging from 10 to 30
days. Additionally, the fund managers retain the right to restrict withdrawals from and/or purchases into the funds
so as not to disadvantage other investors in the funds. Generally, the funds also reserve the right to make all or a
portion of the redemption in-kind rather than in cash or a combination of cash and in-kind.
The fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is
significant to the fair value measurement of an asset.
Shares of the cash management funds and mutual funds are valued at fair value based on published market prices
as of the close of business on the last business day of the year, which represents the net asset values of the shares held.
The fair values of equity securities traded on U.S. exchanges are derived from quoted market prices as of the close
of business on the last business day of the year. The fair values of equity securities traded on foreign exchanges are
also derived from quoted market prices as of the close of business on an active foreign exchange on the last business
119
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
day of the year. However, the valuation requires translation of the foreign currency to U.S. dollars and this translation
is considered an observable input to the valuation.
The fair values of all commingled investment funds are determined based on the net asset values per unit of each
of the funds. The net asset values per unit represent the aggregate values of the funds’ assets at fair value less liabilities,
divided by the number of units outstanding.
The fair values of fixed income securities, except U.S. Treasury securities, are determined using pricing models.
These pricing models incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes,
and issuer spreads for similar securities to determine fair value. The U.S. Treasury securities are valued at fair value
based on closing prices on the last business day of the year reported in the active market in which the security is traded.
There have been no significant changes in the preceding valuation methodologies used at December 31, 2017 and
2016. Additionally, there were no transfers or reclassifications of investments between Level 1 and Level 2 from
December 2016 to December 2017. If transfers between levels had occurred, the transfers would have been recognized
as of the end of the period.
Plan Benefit Payments and Employer Contributions
Following are the expected benefits to be paid by the plans. These estimates are based on the same assumptions
previously discussed and reflect future service as appropriate. The actuarial assumptions are based on long-term
expectations and include, but are not limited to, assumptions as to average expected retirement age and form of benefit
payment. Actual benefit payments could differ significantly from expected benefit payments if near-term participant
behaviors differ significantly from the actuarial assumptions.
2018........................................................................................................................... $
2019...........................................................................................................................
2020...........................................................................................................................
2021...........................................................................................................................
2022...........................................................................................................................
2023-2027 .................................................................................................................
Pension
Benefits
Other
Postretirement
Benefits
$
(Millions)
91
90
92
96
96
486
13
13
14
13
13
60
In 2018, we expect to contribute approximately $80 million to our tax-qualified pension plans and approximately
$5 million to our nonqualified pension plans, for a total of approximately $85 million, and approximately $6 million
to our other postretirement benefit plans.
Defined Contribution Plans
We also maintain defined contribution plans for the benefit of substantially all of our employees. Generally, plan
participants may contribute a portion of their compensation on a pre-tax and after-tax basis in accordance with the
plans’ guidelines. We match employees’ contributions up to certain limits. Our matching contributions charged to
expense were $34 million in 2017, $36 million in 2016, and $39 million in 2015.
120
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 10 – Property, Plant, and Equipment
The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the
Consolidated Balance Sheet for the years ended:
Nonregulated:
Estimated
Useful Life (1)
(Years)
Depreciation
Rates (1)
(%)
December 31,
2017
2016
(Millions)
Natural gas gathering and processing facilities (2)
Construction in progress......................................... Not applicable
Other (2) .................................................................
5 - 40
2 - 45
Regulated:
Natural gas transmission facilities..........................
Construction in progress......................................... Not applicable Not applicable
Other.......................................................................
Total property, plant, and equipment, at cost .............
Accumulated depreciation and amortization .............
Property, plant, and equipment — net .......................
1.35 - 33.33
1.20 - 6.97
5 - 45
$
$
$
18,440
566
2,776
19,523
412
3,092
14,460
1,637
1,634
39,513
(11,302)
28,211
$
12,692
1,603
1,590
38,912
(10,484)
28,428
__________
(1) Estimated useful life and depreciation rates are presented as of December 31, 2017. Depreciation rates and estimated
useful lives for regulated assets are prescribed by the FERC.
(2) The 2016 presentation has been changed to reflect $890 million of right-of-way assets previously presented in
Natural gas gathering and processing facilities, now in Other.
Depreciation and amortization expense for Property, plant, and equipment – net was $1.389 billion, $1.407 billion,
and $1.382 billion in 2017, 2016, and 2015, respectively.
Regulated Property, plant, and equipment – net includes approximately $626 million and $665 million at
December 31, 2017 and 2016, respectively, related to amounts in excess of the original cost of the regulated facilities
within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years
using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts
in excess of original cost of construction.
Asset Retirement Obligations
Our accrued obligations relate to underground storage caverns, offshore platforms and pipelines, fractionation and
compression facilities, gas gathering well connections and pipelines, and gas transmission pipelines and facilities. At
the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any
related surface equipment, to restore land and remove surface equipment at gas processing, fractionation, and
compression facilities, to dismantle offshore platforms and appropriately abandon offshore pipelines, to cap certain
gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain
components of gas transmission facilities from the ground.
121
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table presents the significant changes to our ARO, of which $946 million and $801 million are
included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued liabilities
at December 31, 2017 and 2016, respectively.
December 31,
2017
2016
Beginning balance ......................................................................................................... $
Liabilities incurred.........................................................................................................
Liabilities settled ...........................................................................................................
Accretion expense (1)....................................................................................................
Revisions (2)..................................................................................................................
Ending balance .............................................................................................................. $
___________
(1) The increase in accretion expense for 2017 includes an adjustment associated with obligations identified from
915
24
(8)
69
(138)
862
$
$
(Millions)
862
33
(16)
141
(22)
998
certain Transco land agreements.
(2) Several factors are considered in the annual review process, including inflation rates, current estimates for removal
cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2017 revisions
reflect changes in removal cost estimates and decreases in the estimated remaining useful life of certain assets and
discount rates used in the annual review process. The 2016 revisions reflect changes in removal cost estimates,
increases in the estimated remaining useful life of certain assets, and decreases in the inflation rate and discount
rates used in the annual review process.
The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account
dedicated to funding its ARO (ARO Trust). (See Note 16 – Fair Value Measurements, Guarantees, and Concentration
of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $36 million,
with installments to be deposited monthly.
Note 11 – Goodwill and Other Intangible Assets
Goodwill
At December 31, 2017, 2016, and 2015, our Consolidated Balance Sheet includes $47 million of goodwill in
Intangible assets – net of accumulated amortization, reported in the Williams Partners segment. Our goodwill is not
subject to amortization, but is evaluated at least annually for impairment or more frequently if impairment indicators
are present. We did not identify or recognize any impairments to goodwill in connection with our annual evaluation of
goodwill for impairment (performed as of October 1) during the years ended December 31, 2017 and 2016. During
2015, we performed an interim assessment and an annual assessment as of September 30, 2015 and October 1, 2015,
respectively, of certain goodwill within the Williams Partners segment. The estimated fair value of the reporting units
evaluated exceeded their carrying amounts, and thus no impairment was identified. We performed an additional goodwill
impairment evaluation as of December 31, 2015, of the goodwill recorded within the Williams Partners segment. As a
result of this evaluation, we recorded goodwill impairment charges totaling $1.098 billion. (See Note 16 – Fair Value
Measurements, Guarantees, and Concentration of Credit Risk.)
122
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Other Intangible Assets
The gross carrying amount and accumulated amortization of other intangible assets, included in Intangible assets
– net of accumulated amortization, at December 31 are as follows:
2017
2016
Gross
Carrying
Amount
Accumulated
Amortization
Gross
Carrying
Amount
Accumulated
Amortization
(Millions)
Contractual customer relationships......................................... $
10,027
$
(1,283) $
10,635
$
(1,019)
Other intangible assets primarily relate to gas gathering, processing, and fractionation contractual customer
relationships recognized in acquisitions including ACMP and Eagle Ford (see Note 2 – Acquisitions and Divestitures).
The decrease in the gross carrying amount of other intangible assets during 2017 is primarily related to the impairment
of certain gathering operations in the Mid-Continent and Marcellus South regions (see Note 16 – Fair Value
Measurements, Guarantees, and Concentration of Credit Risk). The write-off of accumulated amortization related to
the impaired assets is the primary reason for the difference between the change in accumulated amortization during
2017 indicated above and the amortization expense for 2017 noted below. Other intangible assets are being amortized
on a straight-line basis over an initial period of 30 years which represents a portion of the term over which the contractual
customer relationships are expected to contribute to our cash flows.
We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts
with customers. Based on the estimated future revenues during the contract periods (as estimated at the time of the
acquisition), the weighted-average period prior to the next renewal or extension of the contractual customer relationships
associated with the Eagle Ford acquisition was approximately 10 years. Although a significant portion of the expected
future cash flows associated with these contractual customer relationships are dependent on our ability to renew or
extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced
by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to
our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced
due to the significant capital investment required.
The amortization expense related to other intangible assets was $347 million, $356 million, and $353 million in
2017, 2016, and 2015, respectively. The estimated amortization expense for each of the next five succeeding fiscal
years is approximately $337 million.
Note 12 – Accrued Liabilities
December 31,
2017
2016
Deferred income............................................................................................................ $
Interest on debt..............................................................................................................
Employee costs .............................................................................................................
Refundable deposits ......................................................................................................
Property taxes................................................................................................................
Asset retirement obligations..........................................................................................
Other, including other loss contingencies .....................................................................
$
$
(Millions)
361
267
202
—
63
53
221
1,167
$
338
310
223
160
55
61
301
1,448
Deferred income includes cash proceeds associated with restructuring certain gas gathering contracts in the Barnett
Shale and Mid-Continent regions. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary
of Significant Accounting Policies.)
123
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Refundable deposits in 2016 includes receipts related to an agreement to resolve several matters in relation to
Transco’s Hillabee Expansion Project. In accordance with the agreement, the member–sponsors of Sabal Trail paid
WPZ an aggregate amount of $240 million in three equal installments as certain milestones of the project were met.
During the third quarter of 2017 WPZ received the final installment and placed the project into service. As a result of
placing the project into service, WPZ reclassified the Refundable deposits to Accrued liabilities and Regulatory
liabilities, deferred income, and other and expects to recognize income associated with these receipts over the term of
an underlying contract.
124
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 13 – Debt, Banking Arrangements, and Leases
Long-Term Debt
Transco:
6.05% Notes due 2018 ........................................................................................ $
7.08% Debentures due 2026 ................................................................................
7.25% Debentures due 2026 ................................................................................
7.85% Notes due 2026 ........................................................................................
5.4% Notes due 2041 ..........................................................................................
4.45% Notes due 2042 ........................................................................................
Other financing obligation ...................................................................................
Northwest Pipeline:
5.95% Notes due 2017 ........................................................................................
6.05% Notes due 2018 ........................................................................................
7.125% Debentures due 2025 ..............................................................................
4% Notes due 2027 .............................................................................................
WPZ:
7.25% Notes due 2017 ........................................................................................
5.25% Notes due 2020 ........................................................................................
4.125% Notes due 2020 ......................................................................................
4% Notes due 2021 .............................................................................................
3.6% Notes due 2022 ..........................................................................................
3.35% Notes due 2022 ........................................................................................
6.125% Notes due 2022 ......................................................................................
4.5% Notes due 2023 ..........................................................................................
4.875% Notes due 2023 ......................................................................................
4.3% Notes due 2024 ..........................................................................................
4.875% Notes due 2024 ......................................................................................
3.9% Notes due 2025 ..........................................................................................
4% Notes due 2025 .............................................................................................
3.75% Notes due 2027 ........................................................................................
6.3% Notes due 2040 ..........................................................................................
5.8% Notes due 2043 ..........................................................................................
5.4% Notes due 2044 ..........................................................................................
4.9% Notes due 2045 ..........................................................................................
5.1% Notes due 2045 ..........................................................................................
Term Loan, variable interest rate, due 2018 ........................................................
WMB:
7.875% Notes due 2021 ......................................................................................
3.7% Notes due 2023 ..........................................................................................
4.55% Notes due 2024 ........................................................................................
7.5% Debentures due 2031 ..................................................................................
7.75% Notes due 2031 ........................................................................................
8.75% Notes due 2032 ........................................................................................
5.75% Notes due 2044 ........................................................................................
Various — 7.625% to 10.25% Notes and Debentures due 2019 to 2027 ............
Credit facility loans .............................................................................................
Debt issuance costs .....................................................................................................
Net unamortized debt premium (discount) .................................................................
Total long-term debt, including current portion ..........................................................
Long-term debt due within one year ...........................................................................
Long-term debt ........................................................................................................... $
125
December 31,
2017
2016
(Millions)
$
250
8
200
1,000
375
400
231
—
250
85
250
—
1,500
600
500
1,250
750
—
600
—
1,000
750
750
750
1,450
1,250
400
500
500
1,000
—
371
850
1,250
339
252
445
650
55
270
(122)
(24)
20,935
(501)
20,434
$
250
8
200
1,000
375
400
—
185
250
85
—
600
1,500
600
500
1,250
750
750
600
1,400
1,000
750
750
750
—
1,250
400
500
500
1,000
850
371
850
1,250
339
252
445
650
55
775
(119)
88
23,409
(785)
22,624
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create
liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our
ability to make certain distributions or repurchase equity.
The following table presents aggregate minimum maturities of long-term debt, excluding net unamortized debt
premium (discount) and debt issuance costs, for each of the next five years:
December 31,
2017
(Millions)
2018 .................................................................................................................................................... $
2019 ....................................................................................................................................................
2020 ....................................................................................................................................................
2021 ....................................................................................................................................................
2022 ....................................................................................................................................................
502
33
2,123
1,143
2,003
Issuances and retirements
On July 6, 2017, WPZ repaid its $850 million variable interest rate term loan that was due December 2018 using
proceeds from the sale of its Geismar Interest.
On June 5, 2017, WPZ issued $1.45 billion of 3.75 percent senior unsecured notes due 2027. WPZ used the proceeds
for general partnership purposes, primarily the July 3, 2017, repayment of $1.4 billion of 4.875 percent senior unsecured
notes that were due in 2023.
On April 3, 2017, Northwest Pipeline issued $250 million of 4.0 percent senior unsecured notes due 2027 to
investors in a private debt placement. Northwest Pipeline used the net proceeds to retire $185 million of 5.95 percent
senior unsecured notes that matured on April 15, 2017, and for general corporate purposes. As part of the issuance,
Northwest Pipeline entered into a registration rights agreement with the initial purchasers of the unsecured notes. Under
the terms of the agreement, Northwest Pipeline was obligated to file and consummate a registration statement for an
offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933,
as amended, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer.
Northwest Pipeline has filed the registration statement, which became effective in January 2018. The exchange offer
is expected to be completed in the first quarter of 2018.
On February 23, 2017, using proceeds received from the Financial Repositioning (See Note 1 – General, Description
of Business, Basis of Presentation, and Summary of Significant Accounting Policies), WPZ early retired $750 million
of 6.125 percent senior unsecured notes that were due in 2022.
WPZ retired $600 million of 7.25 percent senior unsecured notes that matured on February 1, 2017.
Northwest Pipeline retired $175 million of 7 percent senior unsecured notes that matured on June 15, 2016.
Transco retired $200 million of 6.4 percent senior unsecured notes that matured on April 15, 2016.
On January 22, 2016, Transco issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a
private debt placement. In January 2017, Transco completed an exchange of these notes for substantially identical new
notes that are registered under the Securities Act of 1933, as amended. Transco used the net proceeds to repay debt
and to fund capital expenditures.
Other financing obligation
During the construction of Transco’s Dalton expansion project, WPZ received funding from a partner for its
proportionate share of construction costs related to its undivided ownership interest in the project. Amounts received
were recorded within noncurrent liabilities and 100 percent of the costs associated with construction were capitalized
126
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
on our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, WPZ began
leasing this partner’s undivided interest in the lateral, including the associated pipeline capacity, and reclassified
approximately $237 million of funding previously received from its partner from noncurrent liabilities to debt to reflect
the financing obligation payable to its partner over an expected term of 35 years.
Credit Facilities
WMB
Long-term credit facility ..................................................................................................... $
Letters of credit under certain bilateral bank agreements ....................................................
WPZ
December 31, 2017
Available
Outstanding
(Millions)
1,500
$
270
13
—
1
Long-term credit facility (1) ................................................................................................
Letters of credit under certain bilateral bank agreements ....................................................
3,500
________________
(1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity
of our credit facility inclusive of any outstanding amounts under our commercial paper program.
WMB long-term credit facility
On February 2, 2015, we entered into the Second Amended and Restated Credit Agreement. The aggregate
commitments available remained at $1.5 billion, with up to an additional $500 million increase in aggregate
commitments available under certain circumstances. In November 2017, the maturity date of the credit facility was
extended to February 2, 2021. However, we may request an additional extension of the maturity date for a one year
period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement also allows for
swing line loans up to an aggregate amount of $50 million, subject to available capacity under the credit facility, and
the letters of credit up to $675 million.
The agreements governing the 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, merge or consolidate, sell all or substantially all of its assets, enter into
certain affiliate transactions, make certain distributions during an event of default, make investments, and
allow any material change in the nature of its business.
•
If an event of default with respect to a borrower occurs under its respective credit facility, the lenders will be
able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of
the defaulting borrower under the respective credit facility agreement and exercise other rights and remedies.
• Each time funds are borrowed under our credit facility, the borrower may choose from two methods of
calculating interest: a fluctuating base rate equal to the bank’s alternate base rate plus an applicable margin
or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. The
borrower is required to pay a commitment fee based on the unused portion of its respective credit facility. The
applicable margin and the commitment fee are determined for us by reference to a pricing schedule based on
our senior unsecured long-term debt ratings.
Significant financial covenants under the agreement require the ratio of debt to EBITDA (each as defined in the
credit agreement) 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.
We are in compliance with these financial covenants as measured at December 31, 2017.
127
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
As of February 20, 2018, there are no amounts outstanding under our long-term credit facility.
WPZ long-term credit facilities
On February 2, 2015, WPZ along with Transco, 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.
In November 2017, the maturity date of the credit facility was extended to February 2, 2021. However, the co-borrowers
may request an additional extension of the maturity date for a one year period to allow a maturity date as late as
February 2, 2022, under certain circumstances. 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. 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.
The agreement governing this 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, 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 swing line 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 one half of 1 percent, and (c) a periodic fixed rate equal to the LIBOR plus 1 percent, 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 swing line
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.
Significant financial covenants under the agreement require the ratio of debt to EBITDA, each as defined in the
credit facility, be no greater than 5.00 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
Transco and Northwest Pipeline. WPZ is in compliance with these financial covenants as measured at December 31,
2017.
As of February 20, 2018, there are no amounts outstanding under the WPZ long-term credit facility.
Commercial Paper Program
On February 2, 2015, WPZ amended and restated the commercial paper program for the ACMP Merger and to
allow a maximum outstanding amount of unsecured commercial paper notes 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. Proceeds from these notes are used for general
partnership purposes, including funding capital expenditures, working capital, and partnership distributions. At
128
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
December 31, 2017, WPZ had no Commercial paper outstanding. At December 31, 2016, WPZ had $93 million of
Commercial paper outstanding at a weighted-average interest rate of 1.06 percent, which was classified in Current
liabilities in the Consolidated Balance Sheet, as the outstanding notes had maturity dates less than three months from
the date of issuance.
Cash Payments for Interest (Net of Amounts Capitalized)
Cash payments for interest (net of amounts capitalized) were $1.110 billion in 2017, $1.152 billion in 2016, and
$1.023 billion in 2015.
Restricted Net Assets of Subsidiaries
We have considered the guidance in the Securities and Exchange Commission’s Regulation S-X related to restricted
net assets of subsidiaries. In accordance with Rule 4-08(e) of Regulation S-X, we have determined that certain net
assets of our subsidiaries are considered restricted under this guidance and exceed 25 percent of our consolidated net
assets. As of December 31, 2017, substantially all of these restricted net assets relate to the net assets of WPZ, which
are technically considered restricted under this accounting rule due to terms within WPZ’s partnership agreement that
govern the partnerships’ assets. Our interest in WPZ’s net assets that are considered to be restricted at December 31,
2017, was $16 billion.
Leases-Lessee
The future minimum annual rentals under noncancelable operating leases, are payable as follows:
December 31,
2017
(Millions)
2018 .................................................................................................................................................... $
2019 ....................................................................................................................................................
2020 ....................................................................................................................................................
2021 ....................................................................................................................................................
2022 ....................................................................................................................................................
Thereafter............................................................................................................................................
Total.................................................................................................................................................. $
43
41
33
33
29
137
316
Total rent expense was $62 million in 2017, $64 million in 2016, and $69 million in 2015 and primarily included
in Operating and maintenance expenses and Selling, general, and administrative expenses in the Consolidated Statement
of Operations.
Note 14 – Stockholders' Equity
Cash dividends declared per common share were $1.20, $1.68, and $2.45 for 2017, 2016, and 2015, respectively.
On February 21, 2018, our board of directors approved a regular quarterly dividend of $0.34 per share payable on
March 26, 2018.
In January 2017, we issued 65 million shares of common stock in a public offering at a price of $29.00 per share.
In February 2017, we issued 9.75 million shares of common stock pursuant to the full exercise of the underwriter’s
option to purchase additional shares. The net proceeds of approximately $2.1 billion were used to purchase newly
issued common units in WPZ as part of our Financial Repositioning. (See Note 1 – General, Description of Business,
Basis of Presentation, and Summary of Significant Accounting Policies.)
129
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
AOCI
The following table presents the changes in AOCI by component, net of income taxes:
Cash
Flow
Hedges
Foreign
Currency
Translation
Pension and
Other Post
Retirement
Benefits
Total
Balance at December 31, 2016 .................................. $
— $
Other comprehensive income (loss) before
reclassifications ..................................................
Amounts reclassified from accumulated other
comprehensive income (loss) .............................
Other comprehensive income (loss)...........................
Balance at December 31, 2017 .................................. $
(6)
4
(2)
(2) $
(Millions)
(2) $
(337) $
(339)
1
44
—
1
(1) $
58
102
(235) $
39
62
101
(238)
Reclassifications out of AOCI are presented in the following table by component for the year ended December 31,
2017:
Cash flow hedges:
Component
Reclassifications
(Millions)
Classification
Energy commodity contracts.......................................
$
7 Product sales and Product costs
Pension and other postretirement benefits:
Amortization of prior service cost (credit) included
in net periodic benefit cost (credit) ........................
Amortization of actuarial (gain) loss and net
actuarial loss from settlements included in net
periodic benefit cost (credit) ..................................
Total before tax..............................................................
Income tax benefit .........................................................
Net of income tax ..........................................................
(5) Note 9 – Employee Benefit Plans
98 Note 9 – Employee Benefit Plans
100
(36) Provision (benefit) for income taxes
64
Noncontrolling interest..................................................
Reclassifications during the period .................................
$
(2)
62
Net income (loss) attributable to
noncontrolling interests
Note 15 – Equity-Based Compensation
Williams’ Plan Information
On May 17, 2007, our stockholders approved The Williams Companies, Inc. 2007 Incentive Plan (the Plan) that
provides common-stock-based awards to both employees and nonmanagement directors and reserved 19 million new
shares for issuance. On May 20, 2010 and May 22, 2014, our stockholders approved amendments and restatements of
the Plan to increase by 11 million and 10 million, respectively, the number of new shares authorized for making awards
under the Plan, among other changes. The Plan permits the granting of various types of awards including, but not limited
to, restricted stock units and stock options. At December 31, 2017, 26 million shares of our common stock were reserved
for issuance pursuant to existing and future stock awards, of which 15 million shares were available for future grants.
Additionally, on May 17, 2007, our stockholders approved an Employee Stock Purchase Plan (ESPP) which
authorized up to 2 million new shares of our common stock to be available for sale under the ESPP. On May 22, 2014,
our stockholders approved an amendment and restatement of the ESPP to increase by 1.6 million the number of new
shares authorized for sale under the ESPP. Employees purchased 272 thousand shares at an average price of $25.83
130
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
per share during 2017. Approximately 1.1 million shares were available for purchase under the ESPP at December 31,
2017.
Operating and maintenance expenses and Selling, general, and administrative expenses include equity-based
compensation expense for the years ended December 31, 2017, 2016, and 2015 of $70 million, $53 million, and $56
million, respectively. Income tax benefit recognized related to the stock-based compensation expense for the years
ended December 31, 2017, 2016, and 2015 was $17 million, $20 million, and $21 million, respectively. Measured but
unrecognized stock-based compensation expense at December 31, 2017, was $61 million, comprised of $4 million
related to stock options and $57 million related to restricted stock units. These amounts are expected to be recognized
over a weighted-average period of 1.8 years.
Stock Options
The following summary reflects stock option activity and related information for the year ended December 31,
2017:
Stock Options
Weighted-
Average
Exercise
Price
Aggregate
Intrinsic
Value
(Millions)
Options
(Millions)
Outstanding at December 31, 2016 ...............................................
Granted ..........................................................................................
Exercised .......................................................................................
Cancelled .......................................................................................
Outstanding at December 31, 2017 ...............................................
Exercisable at December 31, 2017 ................................................
$
6.2
1.0
$
(0.5) $
(0.1) $
$
6.6
$
5.1
31.32
28.85
21.33
36.75
31.53
31.85
$
$
23
19
The following table summarizes additional information related to stock option activity during each of the last three
years:
Years Ended December 31,
2017
2016
(Millions)
2015
Total intrinsic value of options exercised........................................................ $
Tax benefits realized on options exercised...................................................... $
Cash received from the exercise of options..................................................... $
4
1
7
$
$
$
2
1
4
$
$
$
37
13
20
The weighted-average remaining contractual life for stock options outstanding and exercisable at December 31,
2017, was 5.0 years and 4.0 years, respectively.
The estimated fair value at date of grant of options for our common stock granted in each respective year, using
the Black-Scholes option pricing model, is as follows:
Weighted-average grant date fair value of options for our common stock
granted during the year, per share................................................................ $
6.61
$
7.90
$
7.61
Weighted-average assumptions:
Dividend yield..............................................................................................
Volatility.......................................................................................................
Risk-free interest rate...................................................................................
Expected life (years) ....................................................................................
4.2%
35.1%
2.1%
6.0
3.2%
44.7%
1.2%
6.0
4.8%
27.8%
1.8%
6.0
2017
2016
2015
131
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The 2017 expected dividend yield is based on the 2017 dividend forecast and the grant-date market price of our
stock. Our expected future volatility is determined using the historical volatility of our stock and implied volatility on
our traded options. Historical volatility is based on the blended 10-year historical volatility of our stock and certain
peer companies. The risk-free interest rate is based on the U.S. Treasury Constant Maturity rates as of the grant date.
The expected life of the option is based on historical exercise behavior and expected future experience.
Nonvested Restricted Stock Units
The following summary reflects nonvested restricted stock unit activity and related information for the year ended
December 31, 2017:
Restricted Stock Units Outstanding
Weighted-
Average
Fair Value (1)
Shares
(Millions)
Nonvested at December 31, 2016 .............................................................................
Granted......................................................................................................................
Forfeited ....................................................................................................................
Vested........................................................................................................................
Nonvested at December 31, 2017 .............................................................................
______________
(1) Performance-based restricted stock units are valued utilizing a Monte Carlo valuation method using measures of
total shareholder return. All other restricted stock units are valued at the grant-date market price. Restricted stock
units generally vest after three years.
3.9
$
$
2.0
(0.8) $
(0.9) $
$
4.2
35.19
29.47
39.21
38.30
31.02
Value of Restricted Stock Units
Weighted-average grant date fair value of restricted stock units granted
2017
2016
2015
during the year, per share............................................................................. $
29.47
Total fair value of restricted stock units vested during the year ($’s in
millions) ....................................................................................................... $
33
$
$
26.51
32
$
$
40.15
42
Performance-based restricted stock units granted under the Plan represent 31 percent of nonvested restricted stock
units outstanding at December 31, 2017. These grants may be earned at the end of the vesting period based on actual
performance against a performance target. Based on the extent to which certain financial targets are achieved, vested
shares may range from zero percent to 200 percent of the original grant amount.
WPZ’s Plan Information
During 2014, certain employees of ACMP’s general partner received equity-based compensation through ACMP’s
equity-based compensation program. These awards were converted to WPZ equity-based awards in accordance with
the terms of the ACMP Merger. No additional grants of restricted common units were awarded through WPZ’s equity-
based compensation programs, and no additional grants are expected in the future. Equity-based compensation expense
of $8 million, $20 million, and $29 million related to WPZ’s equity-based compensation program is included in
Operating and maintenance expenses and Selling, general, and administrative expenses for the years ended
December 31, 2017, 2016, and 2015, respectively. The total fair value of the restricted common units vested during
2017, 2016, and 2015 was $24 million, $34 million, and $5 million, respectively. As of December 31, 2017, there were
76 thousand nonvested units outstanding and $1 million of unrecognized compensation expense attributable to the
outstanding awards which will be recognized in 2018.
132
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities.
The carrying values of cash and cash equivalents, accounts receivable, commercial paper, and accounts payable
approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are
not presented in the following table.
Fair Value Measurements Using
Quoted
Prices In
Active
Markets for
Identical
Assets
(Level 1)
(Millions)
Significant
Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Carrying
Amount
Fair
Value
Assets (liabilities) at December 31, 2017:
Measured on a recurring basis:
ARO Trust investments ........................................... $
135
$
135
$
135
$
— $
Energy derivatives liabilities designated as
hedging instruments ............................................
Energy derivatives liabilities not designated as
hedging instruments ............................................
Additional disclosures:
(3)
(3)
(3)
(3)
Other receivables .....................................................
Long-term debt, including current portion ..............
Guarantees ...............................................................
7
(20,935)
(43)
7
(23,005)
(30)
(2)
—
7
—
—
(1)
—
—
(23,005)
(14)
96
$
96
$
96
$
— $
—
—
—
15
—
—
2
—
—
—
(24,090)
(14)
Assets (liabilities) at December 31, 2016:
Measured on a recurring basis:
ARO Trust investments ........................................... $
Energy derivatives assets designated as hedging
instruments ..........................................................
Energy derivatives assets not designated as
hedging instruments ............................................
Energy derivatives liabilities not designated as
hedging instruments ............................................
Additional disclosures:
2
1
(6)
2
1
(6)
Other receivables .....................................................
Long-term debt, including current portion ..............
Guarantees ...............................................................
15
(23,409)
(44)
15
(24,090)
(30)
133
—
—
(3)
—
—
(16)
—
—
1
(6)
—
—
(16)
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into
an external trust that is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a
portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in
an active market, is classified as available-for-sale, and is reported in Regulatory assets, deferred charges, and other
in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory
assets or liabilities.
Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter
contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis.
The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions
permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit
in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivatives
assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in
the Consolidated Balance Sheet. Energy derivatives liabilities are reported in Accrued liabilities and Regulatory
liabilities, deferred income, and other in the Consolidated Balance Sheet.
Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are
made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the years ended December 31,
2017 or 2016.
Additional fair value disclosures
Other receivables: Other receivables consist of margin deposits, which are reported in Other current assets and
deferred charges in the Consolidated Balance Sheet. The disclosed fair value of our margin deposits is considered to
approximate the carrying value generally due to the short-term nature of these items.
Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily
by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable
transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation
associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach
(see Note 13 – Debt, Banking Arrangements, and Leases).
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our
previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance
obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future
contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average
cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of
the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel
guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted
exposure is approximately $30 million at December 31, 2017. Our exposure declines systematically through the
remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated
using an income approach that considered probability-weighted scenarios of potential levels of future performance.
The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee.
134
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated
Balance Sheet.
We are required by our revolving credit agreements to indemnify lenders for certain taxes required to be withheld
from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount
of future payments under these indemnifications is based on the related borrowings and such future payments cannot
currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax
regulations and have no carrying value. We have never been called upon to perform under these indemnifications and
have no current expectation of a future claim.
Nonrecurring fair value measurements
We performed an interim assessment of the goodwill associated with our former Central and Northeast G&P
reporting units as of September 30, 2015, and the annual assessment of goodwill associated with our Northeast G&P
and West reporting units as of October 1, 2015. No impairment charges were required following these evaluations.
During the fourth quarter of 2015, we observed a significant decline in the market values of WPZ and comparable
midstream companies within the industry. This served to reduce our estimate of enterprise value and increased our
estimates of discount rates. As a result, we performed an impairment assessment as of December 31, 2015, of the
goodwill associated with these reporting units, all within the Williams Partners segment.
We estimated the fair value of each reporting unit based on an income approach utilizing discount rates specific
to the underlying businesses of each reporting unit. These discount rates considered variables unique to each business
area, including equity yields of comparable midstream businesses, expectations for future growth, and customer
performance considerations. Weighted-average discount rates utilized ranged from approximately 10 percent to 13
percent across the three reporting units.
As a result of the increases in discount rates during the fourth quarter of 2015, coupled with certain reductions in
estimated future cash flows determined during the same period, the fair values of the former Central and Northeast
G&P reporting units were determined to be below their respective carrying values. For these measurements, the book
basis of each reporting unit was reduced by the associated deferred tax liabilities. We then calculated the implied fair
value of goodwill by performing a hypothetical application of the acquisition method wherein the estimated fair value
was allocated to the underlying assets and liabilities of each reporting unit. As a result of these Level 3 measurements,
we determined that the previously recorded goodwill associated with each reporting unit was fully impaired, resulting
in a fourth-quarter 2015 noncash charge of $1,098 million, reflected in Impairment of goodwill in the Consolidated
Statement of Operations. For the West reporting unit, the estimated fair value exceeded the carrying value and no
impairment was recorded.
135
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table presents impairments of assets and investments associated with certain nonrecurring fair value
measurements within Level 3 of the fair value hierarchy.
Classification
Segment
Date of
Measurement
Fair
Value
2017
2016
2015
(Millions)
Impairments
Years Ended December 31,
Certain gathering operations (1) ..
Certain gathering operations (2) ..
Certain NGL pipeline (3).............
Certain olefins pipeline project
(4).............................................
Canadian operations (5)...............
Property, plant,
and equipment –
net and Intangible
assets - net of
accumulated
amortization
Property, plant,
and equipment –
net and Intangible
assets - net of
accumulated
amortization
Property, plant,
and equipment –
net
Property, plant,
and equipment –
net
Assets held for
sale
Williams
Partners
September 30,
2017
$ 439
$ 1,019
Williams
Partners
September 30,
2017
21
115
Other
September 30,
2017
Other
June 30, 2017
32
18
68
23
Other
June 30, 2016
206
$ 406
Canadian operations (5)...............
Assets held for
sale
Williams
Partners
June 30, 2016
924
Property, plant,
and equipment –
net
Property, plant,
and equipment –
net
Property, plant,
and equipment –
net
Property, plant,
and equipment –
net
Property, plant,
and equipment –
net
Williams
Partners
June 30, 2016
Other
December 31,
2016
Williams
Partners
December 31,
2015
Other
December 31,
2015
Williams
Partners
June 30, 2015
18
73
13
40
17
Certain gathering operations (6) ..
Certain idle assets ........................
Previously capitalized project
development costs (7) ..............
Previously capitalized project
development costs (8) ..............
Surplus equipment (9)..................
Level 3 fair value measurements
of certain assets........................
Other impairments and write-
downs (10) ...............................
Impairment of certain assets ........
341
48
8
$
94
64
20
1,225
803
178
23
70
31
$ 1,248
$ 873
$
209
136
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Classification
Segment
Date of
Measurement
Fair
Value
2017
2016
2015
Impairments
Years Ended December 31,
Equity-method investments (11)..
Investments
Equity-method investments (12)..
Investments
Other equity-method investment .
Investments
Equity-method investments (13)..
Investments
Equity-method investments (14)..
Investments
Other equity-method investment .
Investments
Impairment of equity-method
investments ..............................
Williams
Partners
Williams
Partners
Williams
Partners
Williams
Partners
Williams
Partners
Williams
Partners
December 31,
2016
$1,295
March 31,
2016
March 31,
2016
December 31,
2015
September 30,
2015
December 31,
2015
1,294
—
4,017
1,203
58
(Millions)
$ 318
109
3
$
890
461
8
$ 430
$ 1,359
______________
(1) Relates to certain gathering operations in the Mid-Continent region. During the third quarter of 2017, we received
solicitations and engaged in negotiations for the sale of certain of these assets which led to our impairment
evaluation. The estimated fair value was determined using an income approach and incorporated market inputs
based on ongoing negotiations for a potential sale of a portion of the underlying assets. For the income approach,
we utilized a discount rate of 10.2 percent, reflecting an estimated cost of capital and risks associated with the
underlying assets.
(2) Relates to certain gathering operations in the Marcellus South region resulting from an anticipated decline in
future volumes following a third-quarter 2017 shut-in by the primary producer. The estimated fair value was
determined by the income approach utilizing a discount rate of 11.1 percent, reflecting an estimated cost of capital
and risks associated with the underlying assets.
(3) Relates to an NGL pipeline near the Houston Ship Channel region which we anticipate will be underutilized for
the foreseeable future. The estimated fair value was primarily determined by using a market approach based on
our analysis of observable inputs in the principal market.
(4) Relates primarily to project development costs associated with an olefins pipeline project in the Gulf Coast region,
the likelihood of completion of which is now considered remote. The estimated fair value of the remaining pipe
and equipment considered a market approach based on our analysis of observable inputs in the principal market,
as well as an estimate of replacement cost.
(5) Relates to our Canadian operations. We designated these operations as held for sale as of June 30, 2016. As a
result, we measured the fair value of the disposal group, resulting in an impairment charge. The estimated fair
value was determined by a market approach based primarily on inputs received in the marketing process and
reflected our estimate of the potential assumed proceeds. We disposed of our Canadian operations through a sale
during the third quarter of 2016. (See Note 2 – Acquisitions and Divestitures).
(6) Relates to certain gathering assets within the Mid-Continent region. The estimated fair value was determined by
a market approach based on our analysis of observable inputs in the principal market.
137
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
(7) Relates to a gas processing plant, the completion of which is considered remote due to unfavorable impact of low
natural gas prices on customer drilling activities. The assessed fair value primarily represents the estimated salvage
value of certain equipment measured using a market approach based on our analysis of observable inputs in the
principal market.
(8) Relates to an olefins pipeline project, the completion of which is considered remote due to lack of customer
interest. The assessed fair value primarily represents the estimated fair value of unused pipeline measured using
a market approach based on our analysis of observable inputs in the principal market.
(9) Relates to certain surplus equipment. The estimated fair value was determined by a market approach based on
our analysis of observable inputs in the principal market.
(10) Reflects multiple individually insignificant impairments and write-downs of other certain assets that may no
longer be in use or are surplus in nature for which the fair value was determined to be lower than the carrying
value.
(11) Relates to Williams Partners’ previously held interest in Ranch Westex and multiple Appalachia Midstream
Investments currently held. The historical carrying value of these equity-method investments was initially recorded
based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We
estimated the fair value of these Appalachia Midstream Investments using an income approach based on expected
future cash flows and appropriate discount rates. The determination of estimated future cash flows involved
significant assumptions regarding gathering volumes, rates, and related capital spending. The discount rate utilized
for the Appalachia Midstream Investments evaluation was 10.2 percent and reflected an estimated cost of capital
as impacted by market conditions and risks associated with the underlying businesses. In addition to utilizing an
income approach, we also considered a market approach for certain Appalachia Midstream Investments and Ranch
Westex based on an agreement reached in February 2017 to exchange our interests in DBJV and Ranch Westex
for additional interests in certain Appalachia Midstream Investments and cash. (See Note 5 – Investing Activities).
(12) Relates to Williams Partners’ previously held interest in DBJV and currently held equity-method investment in
Laurel Mountain. Our carrying values in these equity-method investments had been written down to fair value
at December 31, 2015. Our first-quarter 2016 analysis reflected higher discount rates for both of these equity-
method investments, along with lower natural gas prices for Laurel Mountain. We estimated the fair value of
these equity-method investments using an income approach based on expected future cash flows and appropriate
discount rates. The determination of estimated future cash flows involved significant assumptions regarding
gathering volumes and related capital spending. Discount rates utilized ranged from 13.0 percent to 13.3 percent
and reflected increases in the estimated cost of capital, revised estimates of expected future cash flows, and risks
associated with the underlying businesses.
(13) Relates to Williams Partners’ previously held interest in DBJV, as well as equity-method investments in certain
of the Appalachia Midstream Investments, UEOM, and Laurel Mountain, all of which are currently held. We
estimated the fair value of these equity-method investments using an income approach based on expected future
cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant
assumptions regarding gathering volumes and related capital spending. Discount rates utilized ranged from 10.8
percent to 14.4 percent and reflected further fourth-quarter 2015 increases in the estimated cost of capital, revised
estimates of expected future cash flows, and risks associated with the underlying businesses.
(14) Relates to Williams Partners’ previously held interest in DBJV and certain of the Appalachia Midstream
Investments currently held. The historical carrying value of these equity-method investments was initially recorded
based on estimated fair value during the third quarter of 2014 in conjunction with the acquisition of ACMP. We
estimated the fair value of these equity-method investments using an income approach based on expected future
cash flows and appropriate discount rates. The determination of estimated future cash flows involved significant
assumptions regarding gathering volumes and related capital spending. Discount rates utilized were 11.8 percent
and 8.8 percent for DBJV and certain of the Appalachia Midstream Investments, respectively, and reflected an
estimated cost of capital as impacted by market conditions, and risks associated with the underlying businesses.
138
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Concentration of Credit Risk
Cash equivalents
Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that
are issued or guaranteed by the U.S. government.
Trade accounts and other receivables
The following table summarizes concentration of receivables, net of allowances:
December 31,
2017
2016
NGLs, natural gas, and related products and services .............................................. $
Transportation of natural gas and related products ...................................................
Other..........................................................................................................................
Total ....................................................................................................................... $
$
(Millions)
760
212
4
976
$
736
187
15
938
Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily
located in the continental United States. As a general policy, collateral is not required for receivables, but customers’
financial condition and credit worthiness are evaluated regularly. Based upon this evaluation, we may obtain collateral
to support receivables. As of December 31, 2017 and 2016, Chesapeake Energy Corporation, and its affiliates
(Chesapeake), a customer within our Williams Partners segment, accounted for $176 million and $133 million,
respectively, of the consolidated Trade accounts and other receivables balances.
Revenues
In 2017, 2016, and 2015, Chesapeake accounted for 10 percent, 14 percent, and 18 percent, respectively, of our
consolidated revenues.
Note 17 – Contingent Liabilities and Commitments
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed an individual and class actions against us, our
former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas
price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district
court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related
to this matter.
In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016,
granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the
court extended such ruling to us, entering final judgment in our favor. Farmland has appealed.
In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class
certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition
for permission to appeal the order, and the appeal is now pending.
Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range
of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and
our related indemnification obligation could result in a potential loss that may be material to our results of operations.
In connection with this indemnification, we have an accrued liability balance associated with this matter, and as a result,
have exposure to future developments in this matter.
139
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Alaska Refinery Contamination Litigation
We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole,
Alaska, from 1980 until 2004, through our wholly-owned subsidiaries, Williams Alaska Petroleum Inc. (WAPI) and
MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc.,
in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions arise from sulfolane
contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010
naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things,
contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA
settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in
our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-
site sulfolane remain pending. The State of Alaska filed its action in March 2014, seeking damages. The City of North
Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages.
Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA.
FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February
2017, the three cases were consolidated into one action in state court containing the remaining claims from the James
West case and those of the State of Alaska and North Pole. A trial encompassing all three cases was originally scheduled
to commence in May 2017, but has been continued. A new trial date has not been scheduled. Due to the ongoing
assessment of the level and extent of sulfolane contamination, the lack of an articulated cleanup level for sulfolane,
and the lack of a concrete remedial proposal and cost estimate, we are unable to estimate a range of exposure to the
State of Alaska or North Pole at this time. We currently estimate that our reasonably possible loss exposure to FHRA
could range from an insignificant amount up to $32 million, although uncertainties inherent in the litigation process,
expert evaluations, and jury dynamics might cause our exposure to exceed that amount.
Independent of the litigation matter described in the preceding paragraphs, in 2013, the Alaska Department of
Environmental Conservation indicated that it views FHRA and us as responsible parties, and that it intended to enter
a compliance order to address the environmental remediation of sulfolane and other possible contaminants including
cleanup work outside the refinery’s boundaries. To date, no compliance order has been issued. Due to the ongoing
assessment of the level and extent of sulfolane contamination, the ultimate cost of remediation and division of costs
among the potentially responsible parties, and the previously described separate litigation, we are unable to estimate a
range of exposure at this time.
Royalty Matters
Certain of our customers, including one major customer, have been named in various lawsuits alleging
underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced
and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania
based on allegations that we improperly participated with that major customer in causing the alleged royalty
underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major
customer. Due to the preliminary status of the cases, we are unable to estimate a range of potential loss at this time.
Shareholder Litigation
A purported shareholder filed a class action lawsuit in the Delaware Court of Chancery on January 15, 2016. The
putative class action complaint alleged that the individual members of our Board of Directors breached their fiduciary
duties by, among other things, agreeing to the WPZ Merger Agreement, which purportedly reduced the merger
consideration to have been received in the subsequently proposed but now terminated merger with Energy Transfer
Equity, L.P. (Energy Transfer). The plaintiff filed a motion to voluntarily dismiss, which the court granted on January 13,
2017. On September 2, 2016, the same purported shareholder filed a derivative action claiming that the members of
our Board of Directors breached their fiduciary duties by executing the WPZ Merger Agreement as a defensive measure
against Energy Transfer. On September 28, 2016, we requested the court dismiss this action, and on May 15, 2017, the
140
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
court dismissed the action. On June 6, 2017, the plaintiff filed a notice of appeal, and on December 18, 2017, the
Delaware Supreme Court affirmed the lower court’s decision.
On March 7, 2016, a purported unitholder of WPZ filed a putative class action on behalf of certain purchasers of
WPZ units in U.S. District Court in Oklahoma. The action names as defendants us, WPZ, Williams Partners GP LLC,
Alan S. Armstrong, and former Chief Financial Officer Donald R. Chappel and alleges violations of certain federal
securities laws for failure to disclose Energy Transfer’s intention to pursue a purchase of us conditioned on us not
closing the WPZ Merger Agreement when announcing the WPZ Merger Agreement. The complaint seeks, among other
things, damages and an award of costs and attorneys’ fees. The plaintiff filed an amended complaint on August 31,
2016. On October 17, 2016, we requested the court dismiss the action, and on March 8, 2017, the court dismissed the
complaint with prejudice. On April 7, 2017, the plaintiff filed a notice of appeal.
We cannot reasonably estimate a range of potential loss related to these matters at this time.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer and LE GP, LLC (the general
partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (Merger
Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series
A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors.
The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to
specifically perform their obligations under the Merger Agreement. On April 19, 2016, we filed an amended complaint
seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.
On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP,
LLC, and the other Energy Transfer affiliates that are parties to the Merger Agreement, alleging material breaches of
the Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the
Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under
the Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC)
(ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer
from terminating or otherwise avoiding its obligations under the Merger Agreement due to any failure to obtain the
Tax Opinion.
The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy
Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax
Opinion suits, alleging certain breaches of the Merger Agreement by us and seeking, among other things, a declaration
that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy
Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a
Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the
substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On
June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and
remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s
ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied
on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches
of the Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and
supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things,
payment of the $1.48 billion termination fee due to our alleged breaches of the Merger Agreement. On December 1,
2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking
payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument
with the Court of Chancery.
141
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup
operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these
sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA),
or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these
activities and solely responsible in others. 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, 2017, we have accrued liabilities totaling $38 million for these matters, as discussed below. Estimates
of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies,
or our experience with other similar cleanup operations. At December 31, 2017, certain assessment studies were still
in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs
incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup
standards mandated by the EPA or other governmental authorities, and other factors.
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, air quality standards for one hour nitrogen dioxide
emissions, and volatile organic compound and methane new source performance standards impacting design and
operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding
National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We
are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions
that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations
and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both
new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be
required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations
and the need for further specific regulatory guidance.
Continuing operations
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, 2017, we have accrued liabilities of $7 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, 2017, we have accrued liabilities totaling $8 million for these
costs.
Former operations, including operations classified as discontinued
We have potential obligations in connection with assets and businesses we no longer operate. These potential
obligations include remediation activities at the direction of federal and state environmental authorities and the
indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing
at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described
below.
• Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
• Former petroleum products and natural gas pipelines;
142
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
• Former petroleum refining facilities;
• Former exploration and production and mining operations;
• Former electricity and natural gas marketing and trading operations.
At December 31, 2017, we have accrued environmental liabilities of $23 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified
certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us.
The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers
incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of
warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other
representations that we have provided.
At December 31, 2017, other than as previously disclosed, we are not aware of any material claims against us
involving the indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to
have a material impact on our future financial position. Any claim for indemnity brought against us in the future may
have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us which are incidental to our operations,
none of which are expected to be material to our expected future annual results of operations, liquidity, and financial
position.
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all
significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all
other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses
beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial
position. These calculations have been made without consideration of any potential recovery from third parties.
Commitments
Commitments for construction and acquisition of property, plant, and equipment are approximately $348 million
at December 31, 2017.
Note 18 – Segment Disclosures
We have one reportable segment, Williams Partners. All remaining business activities are included in Other. (See
Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)
Our segment presentation of Williams Partners, which includes our consolidated master limited partnership, is
reflective of the parent-level focus by our chief operating decision-maker, considering the resource allocation and
governance provisions associated with the master limited partnership structure. This partnership maintains capital and
cash management structures that are separate from ours. It is self-funding and maintains its own lines of bank credit
and cash management accounts. These factors serve to differentiate the management of this entity as a whole.
Performance Measurement
We evaluate segment operating performance based upon Modified EBITDA (earnings before interest, taxes,
depreciation, and amortization). This measure represents the basis of our internal financial reporting and is the primary
143
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
performance measure used by our chief operating decision maker in measuring performance and allocating resources
among our reportable segments.
We define Modified EBITDA as follows:
• Net income (loss) before:
Provision (benefit) for income taxes;
Interest incurred, net of interest capitalized;
Equity earnings (losses);
Gain on remeasurement of equity-method investment;
Impairment of equity-method investments;
Other investing income (loss) – net;
Impairment of goodwill;
Depreciation and amortization expenses;
Accretion expense associated with asset retirement obligations for nonregulated operations.
• This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified
EBITDA from our equity-method investments calculated consistently with the definition described above.
The following geographic area data includes Revenues from external customers based on product shipment origin
and Long-lived assets based upon physical location:
Revenues from external customers:
2017............................................................................................
2016............................................................................................
2015............................................................................................
Long-lived assets:
2017............................................................................................
2016............................................................................................
2015............................................................................................
United States
Canada
(Millions)
Total
$
$
$
$
8,030
7,425
7,247
37,002
38,091
38,016
$
1
74
113
8,031
7,499
7,360
— $
—
1,580
37,002
38,091
39,596
Long-lived assets are comprised of property, plant, and equipment, goodwill, and other intangible assets.
144
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated
Statement of Operations and Other financial information:
Williams
Partners
Other
Eliminations
Total
(Millions)
2017
Segment revenues:
Service revenues
External ..................................................................................... $
Internal .......................................................................................
Total service revenues ...................................................................
Product sales
External .....................................................................................
Internal .......................................................................................
Total product sales ........................................................................
Total revenues .................................................................................. $
Other financial information:
Additions to long-lived assets ........................................................ $
Proportional Modified EBITDA of equity-method investments ....
2016
Segment revenues:
Service revenues
External ..................................................................................... $
Internal .......................................................................................
Total service revenues ...................................................................
Product sales
External .....................................................................................
Internal .......................................................................................
Total product sales ........................................................................
Total revenues .................................................................................. $
Other financial information:
Additions to long-lived assets ........................................................ $
Proportional Modified EBITDA of equity-method investments ....
2015
Segment revenues:
Service revenues
External ................................................................................... $
Internal ....................................................................................
Total service revenues ...................................................................
Product sales
External ...................................................................................
Internal ....................................................................................
Total product sales ........................................................................
Total revenues .................................................................................. $
Other financial information:
Additions to long-lived assets ........................................................ $
Proportional Modified EBITDA of equity-method investments ....
145
$
$
$
$
$
$
$
$
$
5,291
1
5,292
2,718
—
2,718
8,010
2,792
795
5,140
33
5,173
2,318
—
2,318
7,491
2,102
754
5,134
1
5,135
2,196
—
2,196
7,331
2,960
699
$
$
$
$
$
$
$
$
$
21
11
32
1
—
1
33
22
—
31
19
50
10
16
26
76
44
—
30
91
121
—
—
—
121
388
—
— $
(12)
(12)
—
—
—
(12) $
— $
—
— $
(52)
(52)
—
(16)
(16)
(68) $
(1) $
—
— $
(92)
(92)
—
—
—
(92) $
(12) $
—
5,312
—
5,312
2,719
—
2,719
8,031
2,814
795
5,171
—
5,171
2,328
—
2,328
7,499
2,145
754
5,164
—
5,164
2,196
—
2,196
7,360
3,336
699
The Williams Companies, Inc.
Notes to Consolidated Financial Statements – (Continued)
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the
Consolidated Statement of Operations:
Modified EBITDA by segment:
Williams Partners ............................................................................................ $
Other ................................................................................................................
Accretion expense associated with asset retirement obligations for
nonregulated operations....................................................................................
Depreciation and amortization expenses..............................................................
Impairment of goodwill........................................................................................
Equity earnings (losses) .......................................................................................
Impairment of equity-method investments ..........................................................
Other investing income (loss) – net......................................................................
Proportional Modified EBITDA of equity-method investments..........................
Interest expense ....................................................................................................
(Provision) benefit for income taxes ....................................................................
Net income (loss)............................................................................................. $
Years Ended December 31,
2017
2016
(Millions)
2015
$
3,616
(150)
3,466
$
3,864
(542)
3,322
4,003
(112)
3,891
(33)
(1,736)
—
434
—
282
(795)
(1,083)
1,974
2,509
(31)
(1,763)
—
397
(430)
63
(754)
(1,179)
25
(28)
(1,738)
(1,098)
335
(1,359)
27
(699)
(1,044)
399
(350) $ (1,314)
$
The following table reflects Total assets and Equity-method investments by reportable segments:
Total Assets
December 31,
2017
December 31,
2016
Equity-Method Investments
December 31,
December 31,
2016
2017
Williams Partners ...................................................
Other.......................................................................
Eliminations ...........................................................
Total ..................................................................
$
$
45,903
589
(140)
46,352
$
$
(Millions)
46,265
685
(115)
46,835
$
$
6,552
—
—
6,552
$
$
6,701
—
—
6,701
146
The Williams Companies Inc.
Quarterly Financial Data
(Unaudited)
Summarized quarterly financial data are as follows:
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(Millions, except per-share amounts)
2017
Revenues ........................................................................................ $
Product costs ..................................................................................
Net income (loss) ............................................................................
Amounts attributable to The Williams Companies, Inc.:
$
1,988
579
569
$
1,924
537
193
$
1,891
504
125
Net income (loss) ....................................................................
Basic earnings (loss) per common share .................................
Diluted earnings (loss) per common share ..............................
373
.45
.45
81
.10
.10
33
.04
.04
2,228
680
1,622
1,687
2.04
2.03
2016
Revenues ........................................................................................ $
Product costs ..................................................................................
Net income (loss) ............................................................................
Amounts attributable to The Williams Companies, Inc.:
$
1,660
318
(13)
$
1,736
401
(505)
$
1,905
461
131
2,198
545
37
Net income (loss) ....................................................................
Basic and diluted earnings (loss) per common share ..............
(65)
(.09)
(405)
(.54)
61
.08
(15)
(.02)
The sum of earnings (loss) per share for the four quarters may not equal the total earnings (loss) per share for the
year due to changes in the average number of common shares outstanding and rounding.
2017
Net income (loss) for fourth-quarter 2017 includes:
•
•
$1.923 billion benefit for income taxes resulting from Tax Reform rate change (see Note 7 – Provision (Benefit)
for Income Taxes of Notes to Consolidated Financial Statements);
$674 million of regulatory charges resulting from Tax Reform and $102 million of charges associated with
regulatory asset-related deferred taxes on equity funds used during construction due to Tax Reform (see Note
6 – Other Income and Expenses).
Net income (loss) for third-quarter 2017 includes includes:
•
•
$1.095 billion gain on the sale of Williams Olefins, L.L.C., a wholly owned subsidiary which owned our
interest in the Geismar, Louisiana, olefins plant (Geismar Interest) (see Note 2 – Acquisitions and Divestitures);
$1.210 billion impairment on certain assets (see Note 16 – Fair Value Measurements, Guarantees, and
Concentration of Credit Risk).
Net income (loss) for first-quarter 2017 includes a gain of $269 million associated with the disposition of certain
equity-method investments (see Note 5 – Investing Activities).
147
The Williams Companies Inc.
Quarterly Financial Data – (Continued)
(Unaudited)
2016
Net income (loss) for fourth-quarter 2016 includes:
•
•
$173 million of income associated with the amortization of deferred income related to the restructuring of
certain gas gathering contracts in the Barnett Shale and Mid-Continent regions and $58 million of related
minimum volume commitment fees (see Note 6 – Other Income and Expenses);
$318 million impairment loss on certain equity-method investments (see Note 16 – Fair Value Measurements,
Guarantees, and Concentration of Credit Risk).
Net income (loss) for second-quarter 2016 includes a $747 million impairment loss on Canadian assets (see Note
16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
Net income (loss) for first-quarter 2016 includes a $112 million impairment loss on certain equity-method
investments (see Note 16 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk).
148
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant
Statement of Comprehensive Income (Loss) (Parent)
Years Ended December 31,
2017
2016
2015
(Millions, except per-share amounts)
Equity in earnings of consolidated subsidiaries .................................................... $
Interest incurred — external .................................................................................
Interest incurred — affiliate ..................................................................................
Interest income — affiliate ...................................................................................
Other income (expense) — net .............................................................................
Income (loss) before income taxes ........................................................................
Provision (benefit) for income taxes .....................................................................
Net income (loss) .............................................................................................. $
898
(261)
(413)
—
(23)
201
(1,973)
2,174
Basic earnings (loss) per common share:
Net income (loss) .............................................................................................. $
Weighted-average shares (thousands) ...............................................................
2.63
826,177
Diluted earnings (loss) per common share:
Net income (loss) .............................................................................................. $
Weighted-average shares (thousands) ...............................................................
2.62
828,518
$
$
$
$
$
522
(268)
(568)
—
(53)
(367)
57
(424) $
232
(255)
(828)
6
(75)
(920)
(349)
(571)
(.57) $
750,673
(.76)
749,271
(.57) $
750,673
(.76)
749,271
Other comprehensive income (loss):
Equity in other comprehensive income (loss) of consolidated subsidiaries ...... $
(2) $
171
$
(204)
Other comprehensive income (loss) attributable to The Williams Companies,
Inc. .................................................................................................................
Other comprehensive income (loss) ......................................................................
102
100
1
172
Less: Other comprehensive income (loss) attributable to noncontrolling
interests ...........................................................................................................
Comprehensive income (loss) attributable to The Williams Companies, Inc........ $
(1)
2,275
$
69
(321) $
33
(171)
(70)
(672)
See accompanying notes.
149
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Balance Sheet (Parent)
ASSETS
Current assets:
Cash and cash equivalents ................................................................................. $
Other current assets and deferred charges .........................................................
Total current assets............................................................................
Investments in and advances to consolidated subsidiaries........................................
Property, plant, and equipment — net.......................................................................
Other noncurrent assets .............................................................................................
Total assets ........................................................................................ $
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable ............................................................................................... $
Other current liabilities ......................................................................................
Total current liabilities ......................................................................
Long-term debt..........................................................................................................
Notes payable — affiliates ........................................................................................
Pension, other postretirement, and other noncurrent liabilities.................................
Deferred income tax liabilities ..................................................................................
Contingent liabilities and commitments
Equity:
Common stock ...................................................................................................
Other stockholders’ equity .................................................................................
Total stockholders’ equity...........................................................................
December 31,
2017
2016
(Millions)
14
10
24
25,268
77
6
25,375
$
$
20
$
187
207
4,438
7,763
164
3,147
861
8,795
9,656
14
16
30
22,359
77
8
22,474
27
169
196
4,939
8,171
287
4,238
785
3,858
4,643
Total liabilities and stockholders’ equity........................................... $
25,375
$
22,474
See accompanying notes.
150
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Statement of Cash Flows (Parent)
Years Ended December 31,
2017
2016
2015
(Millions)
NET CASH FLOWS PROVIDED (USED) BY OPERATING ACTIVITIES.. $
(648) $
(827) $
(1,181)
FINANCING ACTIVITIES:
Proceeds from long-term debt ..............................................................................
Payments of long-term debt .................................................................................
Changes in notes payable to affiliates ..................................................................
Proceeds from issuance of common stock ...........................................................
Dividends paid .....................................................................................................
Other — net .........................................................................................................
Net cash provided (used) by financing activities ..........................................
1,635
(2,140)
(408)
2,131
(992)
(9)
217
2,280
(2,155)
9
9
(1,261)
(6)
(1,124)
INVESTING ACTIVITIES:
Capital expenditures ............................................................................................
Changes in investments in and advances to consolidated subsidiaries ................
Net cash provided (used) by investing activities ..........................................
Increase (decrease) in cash and cash equivalents ....................................................
Cash and cash equivalents at beginning of year ......................................................
Cash and cash equivalents at end of year ................................................................ $
(22)
453
431
—
14
14
$
(13)
1,966
1,953
2
12
14
$
2,097
(1,817)
2,211
27
(1,836)
(30)
652
(29)
521
492
(37)
49
12
See accompanying notes.
151
The Williams Companies, Inc.
Schedule I — Condensed Financial Information of Registrant – (Continued)
Notes to Financial Information (Parent)
Note 1. Guarantees
In addition to the guarantees disclosed in the accompanying consolidated financial statements in Item 8, we have
financially guaranteed the performance of certain consolidated subsidiaries. The duration of these guarantees varies,
and we estimate the maximum undiscounted potential future payment obligation related to these guarantees as of
December 31, 2017, is approximately $305 million.
Note 2. Cash Dividends Received
We receive dividends and distributions either directly from our subsidiaries or indirectly through dividends received
by subsidiaries and subsequent transfers of cash to us through our corporate cash management system. The total of
such receipts ultimately related to dividends and distributions for the years ended December 31, 2017, 2016, and 2015
was approximately $1.9 billion, $1.7 billion, and $1.8 billion, respectively.
152
The Williams Companies, Inc.
Schedule II — Valuation and Qualifying Accounts
Additions
Charged
(Credited)
To Costs and
Expenses
Beginning
Balance
Other
Deductions
Ending
Balance
(Millions)
2017
Deferred tax asset valuation allowance (1).................. $
2016
Deferred tax asset valuation allowance (1)..................
2015
Deferred tax asset valuation allowance (1)..................
__________
(1) Deducted from related assets.
334
$
(110) $
— $
— $
224
190
206
144
(16)
—
—
—
—
334
190
153
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our
disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act)
(Disclosure Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated,
can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the
design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be
considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls
can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been
detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that
breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by management override of the control. The design of
any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there
can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.
Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur
and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard
is that the Disclosure Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the
end of the period covered by this report. This evaluation was performed under the supervision and with the participation
of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation,
our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a
reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the fourth quarter of 2017 that have materially affected, or are reasonably
likely to materially affect, our Internal Control over Financial Reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as
defined in Rules 13a - 15(f) and 15d - 15(f) under the Securities Exchange Act of 1934). Our internal control over
financial reporting is 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.
154
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,
2017, 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, 2017, our internal control over financial reporting was effective.
Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over
financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.
155
Report of Independent Registered Public Accounting Firm
on Internal Control Over Financial Reporting
The Stockholders and the Board of Directors of
The Williams Companies, Inc.
Opinion on Internal Control Over Financial Reporting
We have audited The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2017,
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”). In our opinion, The Williams
Companies, Inc. (the “Company”) maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2017, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the consolidated balance sheet of the Company as of December 31, 2017 and 2016, and the related
consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the
three years in the period ended December 31, 2017, and the related notes and financial statement schedules listed in
the index at Item 15(a) and our report dated February 22, 2018 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’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 Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control Over Financial Reporting
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.
/s/ Ernst & Young LLP
Tulsa, Oklahoma
February 22, 2018
156
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information regarding our directors and nominees for director required by Item 401 of Regulation S-K will
be presented under the heading “Election of Directors” in our definitive proxy statement prepared for the solicitation
of proxies in connection with our Annual Meeting of Stockholders to be held May 10, 2018, which shall be filed no
later than April 30, 2018 (Proxy Statement), which information is incorporated by reference herein.
Information regarding our executive officers required by Item 401(b) of Regulation S-K is presented at the end of
Part I herein and captioned “Executive Officers of the Registrant” as permitted by General Instruction G(3) to and
Instruction 3 to Item 401(b) of Regulation S-K.
Information required by Item 405 of Regulation S-K will be included under the heading “Section 16(a) Beneficial
Ownership Reporting Compliance” in our Proxy Statement, which information is incorporated by reference herein.
Information required by paragraphs (c)(3), (d)(4) and (d)(5) of Item 407 of Regulation S-K will be included under
the heading “Questions and Answers About the Annual Meeting and Voting” and “Corporate Governance and Board
Matters” in our Proxy Statement, which information is incorporated by reference herein.
We have adopted a Code of Ethics for Senior Officers that applies to our Chief Executive Officer, Chief Financial
Officer, and Controller, or persons performing similar functions. The Code of Ethics for Senior Officers, together with
our Corporate Governance Guidelines, the charters for each of our board committees, and our Code of Business Conduct
applicable to all employees are available on our Internet website at www.williams.com. We will provide, free of charge,
a copy of our Code of Ethics or any of our other corporate documents listed above upon written request to our Corporate
Secretary at Williams, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172. We intend to disclose any amendments
to or waivers of the Code of Ethics on behalf of our Chief Executive Officer, Chief Financial Officer, Controller, and
persons performing similar functions on the corporate governance section of our Internet website at www.williams.com,
promptly following the date of any such amendment or waiver.
Item 11. Executive Compensation
The information required by Item 402 and paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K regarding
executive compensation will be presented under the headings “Compensation Discussion and Analysis,” “Executive
Compensation and Other Information,” “Compensation of Directors,” “Compensation and Management Development
Committee Report on Executive Compensation,” and “Compensation and Management Development Committee
Interlocks and Insider Participation” in our Proxy Statement, which information is incorporated by reference herein.
Notwithstanding the foregoing, the information provided under the heading “Compensation and Management
Development Committee Report on Executive Compensation” in our Proxy Statement is furnished and shall not be
deemed to be filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, is not subject to
the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act of 1933,
as amended.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information regarding securities authorized for issuance under equity compensation plans required by
Item 201(d) of Regulation S-K and the security ownership of certain beneficial owners and management required by
Item 403 of Regulation S-K will be presented under the headings “Equity Compensation Stock Plans” and “Security
157
Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated
by reference herein.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information regarding certain relationships and related transactions required by Item 404 and Item 407(a) of
Regulation S-K will be presented under the heading “Corporate Governance and Board Matters” in our Proxy Statement,
which information is incorporated by reference herein.
Item 14. Principal Accountant Fees and Services
The information regarding our principal accounting fees and services required by Item 9(e) of Schedule 14A will
be presented under the heading “Principal Accountant Fees and Services” in our Proxy Statement, which information
is incorporated by reference herein.
158
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) 1 and 2.
Covered by report of independent auditors:
Consolidated statement of operations for each year in the three-year period ended December 31, 2017 ..
Consolidated statement of comprehensive income (loss) for each year in the three-year period ended
December 31, 2017 ..................................................................................................................................
Consolidated balance sheet at December 31, 2017 and 2016 .....................................................................
Consolidated statement of changes in equity for each year in the three-year period ended December 31,
2017..........................................................................................................................................................
Consolidated statement of cash flows for each year in the three-year period ended December 31, 2017 ..
Notes to consolidated financial statements .....................................................................................................
Schedule for each year in the three-year period ended December 31, 2017:
I — Condensed financial information of registrant..................................................................................
II — Valuation and qualifying accounts ....................................................................................................
Not covered by report of independent auditors:
Quarterly financial data (unaudited) ...............................................................................................................
Page
80
81
82
83
84
85
149
153
147
All other schedules have been omitted since the required information is not present or is not present in amounts
sufficient to require submission of the schedule, or because the information required is included in the financial
statements and notes thereto.
(a) 3 and (b). The exhibits listed below are filed as part of this annual report.
Exhibit
No.
2.1+
2.2
2.3+
INDEX TO EXHIBITS
Description
__ Agreement and Plan of Merger dated as of May 12, 2015, by and among The Williams Companies,
Inc., SCMS LLC, Williams Partners, L.P., and WPZ GP LLC (filed on May 13, 2015 as Exhibit 2.1
to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
— Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The
Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy
Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as
Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174)
and incorporated herein by reference).
— Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams
Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity,
L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to
The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
159
Exhibit
No.
2.4
2.5
2.6+
2.7
3.1
Description
— Share Purchase Agreement by and between The Williams Companies International Holdings B.V.
and Inter Pipeline Ltd. and The Williams Companies, Inc., dated August 8, 2016 (filed on August 12,
2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (file No.
001-04174) and incorporated herein by reference).
— Share Purchase Agreement by and between Williams Energy Canada LP and Inter Pipeline Ltd. and
Williams Partners L.P., dated August 8, 2016 (filed on August 12, 2016 as Exhibit 2.2 to The Williams
Companies, Inc.’s current report on Form 8-K (file No. 001-04174) and incorporated herein by
reference).
— Interest Swap and Purchase Agreement by and among Western Gas Partners, LP, WGR Operating,
LP, Delaware Basin JV Gathering LLC, Williams Partners L.P., Williams Midstream Gas Services
LLC, and Appalachia Midstream Services, L.L.C., dated February 9, 2017 (filed on February 10,
2017 as Exhibit 2.1 to The Williams Companies Inc.’s current report on Form 8-K (File No.
001-04174) and incorporated herein by reference).
__ Membership Interest Purchase Agreement, dated as of April 13, 2017, among Williams Field Services
Group, LLC, Williams Partners L.P., Williams Olefins, L.L.C., NOVA Chemicals Inc., and NOVA
Chemicals Corporation (filed on August 3, 2017 as Exhibit 2.2 to Williams Partners L.P.’s quarterly
report on Form 10-Q (File No. 001-34831) and incorporated herein by reference).
— Amended and Restated Certificate of Incorporation, (filed on May 26, 2010 as Exhibit 3.(i)1 to The
Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein
by reference).
3.2
— By-Laws (filed on January 20, 2017, as Exhibit 3.1 to The Williams Companies Inc.’s current report
on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.1
4.2
4.3
4.4
4.5
— Senior Indenture, dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company,
N.A. (formerly The First National Bank of Chicago), as Trustee (filed on February 25, 1997 as
Exhibit 4.5.1 to MAPCO Inc.’s Amendment No. l to registration statement on Form S-3 (File No.
333-20837) and incorporated herein by reference).
— Supplemental Indenture No. 1, dated March 5, 1997, between MAPCO Inc. and Bank One Trust
Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 4, 1998
as Exhibit 4(o) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December
31, 1997 (File No. 001-05254) and incorporated herein by reference).
— Supplemental Indenture No. 2, dated March 5, 1997, between MAPCO Inc. and Bank One Trust
Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 4, 1998
as Exhibit 4(p) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December
31, 1997 (File No. 001-05254) and incorporated herein by reference).
— Supplemental Indenture No. 3, dated March 31, 1998, among MAPCO Inc., Williams Holdings of
Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago),
as Trustee (filed on March 30, 1999 as Exhibit 4(J) to Williams Holdings of Delaware, Inc.’s annual
report on Form 10-K for the fiscal year ended December 31, 1998 (File No. 000-20555) and
incorporated herein by reference).
— Fourth Supplemental Indenture, dated as of July 31, 1999, among Williams Holdings of Delaware,
Inc., The Williams Companies, Inc. and Bank One Trust Company, N.A. (formerly The First National
Bank of Chicago), as Trustee (filed on March 28, 2000 as Exhibit 4(q) to The Williams Companies,
Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
160
Exhibit
No.
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
Description
— Fifth Supplemental Indenture, dated as of February 1, 2010, between The Williams Companies, Inc.
and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.3
to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
— Fifth Supplemental Indenture between The Williams Companies, Inc. and Bank One Trust Company,
N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001 as Exhibit 4(k) to The
Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated
herein by reference).
— Seventh Supplemental Indenture, dated March 19, 2002, between The Williams Companies, Inc. as
Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002 as
Exhibit 4.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174)
and incorporated herein by reference).
— Eleventh Supplemental Indenture, dated as of February 1, 2010, between The Williams Companies,
Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.1
to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
— Indenture, dated as of May 28, 2003, by and between The Williams Companies, Inc. and JPMorgan
Chase Bank, as Trustee (filed on August 12, 2003 as Exhibit 4.2 to The Williams Companies, Inc.’s
quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
— Indenture, dated as of March 5, 2009, among The Williams Companies, Inc. and The Bank of New
York Mellon Trust Company, N.A., as Trustee (filed on March 11, 2009 as Exhibit 4.1 to The Williams
Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by
reference).
— First Supplemental Indenture, dated as of February 1, 2010, between The Williams Companies, Inc.
and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010 as Exhibit 4.2
to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
— Indenture, dated December 18, 2012, between The Williams Companies, Inc. and The Bank of New
York Mellon Trust Company, N.A. as trustee (filed on December 20, 2012 as Exhibit 4.1 to The
Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
— First Supplemental Indenture, dated December 18, 2012, between The Williams Companies, Inc.
and The Bank of New York Mellon Trust Company, N.A. as trustee (filed on December 20, 2012
as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174)
and incorporated herein by reference).
— Second Supplemental Indenture, dated as of June 24, 2014, between The Williams Companies, Inc.
and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 24, 2014 as
Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174)
and incorporated herein by reference).
— 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 The Williams Companies,
Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
— 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).
161
Exhibit
No.
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
Description
— 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 Williams
Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by
reference).
— 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 Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and
incorporated herein by reference).
— 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 November 18, 2011 as
Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and
incorporated herein by reference).
— 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 Williams Partners L.P.’s current report
on Form 8-K (File No. 001-32599) and incorporated herein by reference).
— Fourth Supplemental Indenture, dated as of November 15, 2013, between Williams Partners L.P.
and The Bank of New York Mellon Trust Company, N .A., as trustee (filed on November 18, 2013
as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and
incorporated herein by reference).
— 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
to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein
by reference).
— Sixth Supplemental Indenture, dated as of June 27, 2014, between Williams Partners L.P. and The
Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 27, 2014 as Exhibit 4.1
to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein
by reference).
— 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).
— Eighth Supplemental Indenture, dated as of March 3, 2015, between Williams Partners L.P. and The
Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 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).
__ Ninth Supplemental Indenture, dated as of June 5, 2017, between Williams Partners L.P. and The
Bank of New York Mellon Trust Company, N.A., as trustee. (filed on June 5, 2017 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).
— 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).
162
Exhibit
No.
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
Description
— 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).
— Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and
Chemical Bank, Trustee (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s registration
statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
— 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).
__ Indenture, dated as of April 3, 2017, between Northwest Pipeline LLC and The Bank of New York
Mellon Trust Company, N.A., as trustee (filed on April 3, 2017 as Exhibit 4.1 to Northwest Pipeline’s
current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
— 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 Corporation’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein
by reference).
— 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 Corporation’s current report on Form 8-K (File No. 001-07584) and
incorporated herein by reference).
— 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).
— 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).
— Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC
and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016 as
Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174)
and incorporated herein by reference).
10.1*§ — The Williams Companies Amended and Restated Retirement Restoration Plan effective as of
December 1, 2017.
10.2§ — Form of Director and Officer Indemnification Agreement (filed on September 24, 2008 as Exhibit
10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and
incorporated herein by reference).
10.3§ — Form of 2013 Nonqualified Stock Option Agreement among Williams and certain employees and
officers (filed on February 27, 2013 as Exhibit 10.6 to The Williams Companies, Inc.’s annual report
on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.4§ — Form of 2013 Restricted Stock Unit Agreement among Williams and certain nonmanagement
directors (filed on February 26, 2014 as Exhibit 10.11 to The Williams Companies, Inc. annual report
on Form 10-K (File No. 001-04174) and incorporated herein by reference).
163
Exhibit
No.
Description
10.5§ — Form of 2014 Performance-Based Restricted Stock Unit Agreement among Williams and certain
employees and officers (filed on February 26, 2014 as Exhibit 10.6 to The Williams Companies,
Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.6§ — Form of 2014 Restricted Stock Unit Agreement among Williams and certain employees and officers
(filed on February 26, 2014 as Exhibit 10.7 to The Williams Companies, Inc. annual report on Form
10-K (File No. 001-04174) and incorporated herein by reference).
10.7§ — Form of 2014 Nonqualified Stock Option Agreement among Williams and certain employees and
officers (filed on February 26, 2014 as Exhibit 10.8 to The Williams Companies, Inc. annual report
on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.8§ — Form of 2014 Restricted Stock Unit Agreement among Williams and certain nonmanagement
directors (filed on February 25, 2015 as Exhibit 10.12 to The Williams Companies, Inc. annual
report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.9§ — Form of October 2014 Leveraged Performance Unit Award Agreement among Williams and certain
officers (filed on February 25, 2015 as Exhibit 10.13 to The Williams Companies, Inc. annual report
on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.10§ — Form of Leveraged Performance Unit Award Agreement dated January 1, 2015 between Williams
and Walter Bennett (filed on February 25, 2015 as Exhibit 10.14 to The Williams Companies, Inc.
annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.11§ — Form of 2015 Performance-Based Restricted Stock Unit Agreement among Williams and certain
employees and officers (filed on February 25, 2015 as Exhibit 10.15 to The Williams Companies,
Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.12§ — Form of 2015 Time-Based Restricted Stock Unit Agreement among Williams and certain employees
and officers (filed on February 25, 2015 as Exhibit 10.16 to The Williams Companies, Inc. annual
report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.13§ — Form of 2015 Nonqualified Stock Option Agreement among Williams and certain employees and
officers (filed on February 25, 2015 as Exhibit 10.17 to The Williams Companies, Inc. annual report
on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.14§ — Form of 2015 Non-Equity Incentive Award Agreement among The Williams Companies Inc. and
certain employees and officers (filed on October 29, 2015 as Exhibit 10.3 to The Williams
Companies, Inc. quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by
reference).
10.15§ — Form of 2016 Performance-Based Restricted Stock Unit Agreement among Williams and certain
employees and officers (filed on February 22, 2017 as Exhibit 10.18 to The Williams Companies,
Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.16§
— Form of 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain employees
and officers (filed on February 22, 2017 as Exhibit 10.19 to The Williams Companies, Inc.’s annual
report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.17§ — Form of 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain employees
and officers vesting February 22, 2019 (filed on February 22, 2017 as Exhibit 10.20 to The Williams
Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by
reference).
10.18§
— Form of 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain non-
management directors (filed on February 22, 2017 as Exhibit 10.21 to The Williams Companies,
Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
164
Exhibit
No.
Description
10.19§ — Form of 2016 Nonqualified Stock Option Agreement among Williams and certain employees and
officers (filed on February 22, 2017 as Exhibit 10.22 to The Williams Companies, Inc.’s annual
report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.20§ — Form of 2017 Time-Based Restricted Stock Unit Agreement among Williams and certain employees
and officers (filed on February 22, 2017 as Exhibit 10.23 to The Williams Companies, Inc.’s annual
report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.21§ — Form of 2017 Time-Based Restricted Stock Unit Agreement among Williams and certain non-
management directors (filed on February 22, 2017 as Exhibit 10.24 to The Williams Companies,
Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.22§ — Form of 2017 Nonqualified Stock Option Agreement among Williams and certain employees and
officers (filed on February 22, 2017 as Exhibit 10.25 to The Williams Companies, Inc.’s annual
report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.23§
__ Form of 2017 Performance-Based Restricted Stock Unit Agreement among Williams and certain
employees and officers (filed on May 4, 2017 as Exhibit 10.10 to The Williams Companies, Inc.’s
quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.24§ — The Williams Companies, Inc. 1996 Stock Plan for Nonemployee Directors (filed on March 27,
1996 as Exhibit B to The Williams Companies, Inc.’s Definitive Proxy Statement (File No.
002-27038) and incorporated herein by reference).
10.25§ — The Williams Companies, Inc. 2002 Incentive Plan as amended and restated effective as of
January 23, 2004 (filed on August 5, 2004 as Exhibit 10.1 to The Williams Companies, Inc.’s
quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.26§ — Amendment No. 1 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25,
2009 as Exhibit 10.11 to The Williams Companies, Inc.’s annual report on Form 10-K (File
No. 001-04174) and incorporated herein by reference).
10.27§ — Amendment No. 2 to The Williams Companies, Inc. 2002 Incentive Plan (filed on February 25,
2009 as Exhibit 10.12 to The Williams Companies, Inc.’s annual report on Form 10-K (File
No. 001-04174) and incorporated herein by reference).
10.28§ — Amended and Restated Change-in-Control Severance Agreement between the Company and certain
executive officers (Tier I Executives) (filed on February 27, 2013 as Exhibit 10.14 to The Williams
Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by
reference).
10.29§ — Amended and Restated Change-in-Control Severance Agreement between the Company and certain
executive officers (Tier II Executives) (filed on February 28, 2012, as Exhibit 10.14 to The Williams
Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by
reference).
10.30§ — The Williams Companies, Inc. Executive Severance Pay Plan, dated November 14, 2012 (filed July
20, 2016, as Exhibit 10.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No.
001-04174) and incorporated herein by reference).
10.31§ — First Amendment to The Williams Companies Inc. Executive Severance Pay Plan (filed July 20,
2016, as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No.
001-04174) and incorporated herein by reference).
165
Exhibit
No.
Description
10.32 — Separation and Distribution Agreement dated as of December 30, 2011, between The Williams
Companies, Inc. and WPX Energy, Inc. (Filed on February 28, 2012 as Exhibit 10.19 to The Williams
Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by
reference).
10.33 — Tax Sharing Agreement, dated as of December 30, 2011, between The Williams Companies, Inc.
and WPX Energy, Inc. (filed on January 6, 2012 as Exhibit 10.3 to The Williams Companies, Inc.’s
current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.34§ — Letter Agreement, dated January 27, 2014, with James E. Scheel, Senior Vice President - Northeast
G&P, regarding Relocation from Pennsylvania Benefits (filed on May 1, 2014 as Exhibit 10.2 to
The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and
incorporated herein by reference).
10.35§ — The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective July 14, 2016
(filed on February 22, 2017 as Exhibit 10.38 to The Williams Companies, Inc.’s annual report on
Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.36 — Termination Agreement and Release, dated as of September 29, 2015, by and among The Williams
Companies, Inc., SCMS LLC, Williams Partners L.P. and WPZ GP LLC (filed on September 28,
2015 as Exhibit 10.1 to Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174)
and incorporated herein by reference).
10.37 — Second Amended and Restated Credit Agreement dated as of February 2, 2015, between The
Williams Companies, Inc., the lenders named therein, and Citibank, N.A. as Administrative Agent
(filed on February 3, 2015 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form
8-K (File 001-04174) and incorporated herein by reference).
10.38
__ Amendment No. 1 and Extension Agreement, dated as of November 17, 2017, by and among The
Williams Companies, Inc., the lenders party thereto and Citibank, N.A. (filed on November 22,
2017 as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No.
001-04174) and incorporated herein by reference).
10.39 — 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).
10.40 — Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of December 18,
2015, between Williams Partners L.P., Northwest Pipeline LLC, Transcontinental Gas Pipe Line
Company, LLC, as co-borrowers, the lenders named therein, and Citibank, N.A. as Administrative
Agent (filed on December 23, 2015 as Exhibit 10.1 to The Williams Companies, Inc.’s current report
on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.41
__ Amendment No. 2 and Extension Agreement, dated as of November 17, 2017, by and among
Williams Partners L.P., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company
LLC, the lenders party thereto and Citibank, N.A. (filed on November 22, 2017 as Exhibit 10.2 to
The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
10.42 — 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).
166
Exhibit
No.
Description
10.43 — Common Unit Issuance Agreement, dated January 9, 2017 (filed on January 10, 2017, as Exhibit 2
to Schedule 13D/A (File No. 005-86017) by The Williams Companies, Inc. relating to the common
units representing limited partner interests of Williams Partners L.P. and incorporated herein by
reference.)
10.44 — Common Unit Purchase Agreement, dated January 9, 2017 (filed on January 10, 2017, as Exhibit 3
to Schedule 13D/A (File No. 005-86017) by The Williams Companies, Inc. relating to the common
units representing limited partner interests of Williams Partners L.P. and incorporated herein by
reference.)
10.45
12*
14
__ Separation Agreement and General Release entered into by and among Robert S. Purgason and The
William Companies, Inc., dated March 21, 2017 (filed on March 24, 2017, as Exhibit 10.1 to The
Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated
herein by reference).
— Computation of Ratio of Earnings to Combined Fixed Charges.
— Code of Ethics for Senior Officers (filed on March 15, 2004 as Exhibit 14 to The Williams
Companies, Inc.’s annual report on Form 10-K and incorporated herein by reference).
21*
— Subsidiaries of the registrant.
23.1* — Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
23.2*
Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP.
23.3* — Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP.
31.1* — Certification of the Chief Executive Officer pursuant to Rules 13a-l 4(a) and 15d-14(a) promulgated
under the Securities Exchange Act of 1934, as amended, and Item 601(b)(3 l) of Regulation S-K,
as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* — Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and l 5d-l 4(a) promulgated
under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K,
as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**
— Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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
§ Management contract or compensatory plan or arrangement
+ Pursuant to item 601(6)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any
omitted exhibit or schedule to the SEC upon request.
167
Item 16. Form 10-K Summary
Not applicable.
168
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.
SIGNATURES
THE WILLIAMS COMPANIES, INC.
(Registrant)
By:
/s/ TED T. TIMMERMANS
Ted T. Timmermans
Vice President, Controller and
Chief Accounting Officer
Date: February 22, 2018
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
President, Chief Executive Officer and Director
February 22, 2018
Alan S. Armstrong
(Principal Executive Officer)
/s/ JOHN D. CHANDLER
Senior Vice President and Chief Financial Officer
February 22, 2018
John D. Chandler
(Principal Financial Officer)
/s/ TED T. TIMMERMANS
Ted T. Timmermans
Vice President, Controller and Chief Accounting
Officer
(Principal Accounting Officer)
February 22, 2018
/s/ STEPHEN W. BERGSTROM
Chairman of the Board
February 22, 2018
Stephen W. Bergstrom
/s/ STEPHEN I. CHAZEN
Stephen I. Chazen
/s/ CHARLES I. COGUT
Charles I. Cogut
Director
Director
February 22, 2018
February 22, 2018
/s/ KATHLEEN B. COOPER
Director
February 22, 2018
Kathleen B. Cooper
/s/ MICHAEL A. CREEL
Michael A. Creel
/s/ PETER A. RAGAUSS
Peter A. Ragauss
/s/ SCOTT D. SHEFFIELD
Scott D. Sheffield
/s/ MURRAY D. SMITH
Murray D. Smith
Director
Director
Director
Director
169
February 22, 2018
February 22, 2018
February 22, 2018
February 22, 2018
Signature
/s/ WILLIAM H. SPENCE
William H. Spence
/s/ JANICE D. STONEY
Janice D. Stoney
Title
Director
Director
Date
February 22, 2018
February 22, 2018
170
Corporate Data
ANNUAL MEETING
AUDITORS
Stockholders are invited to our annual
meeting at 2 p.m. Central Time
on May 10, 2018, in the presentation
theater, Williams Resource Center,
One Williams Center, Tulsa, Okla.
Ernst & Young LLP
1700 One Williams Center
Tulsa, OK 74172-0117
CERTIFICATIONS
We submitted the certification of
Alan S. Armstrong, our Chief Executive
Officer and President, to the New
York Stock Exchange pursuant to
NYSE Section 303A.12(a) on
June 1, 2017.
We also filed with the Securities and
Exchange Commission on February
22, 2018, as Exhibits 31.1 and 31.2 to
our Annual Report on Form 10-K for
the year ended December 31, 2017,
the certificates of our Chief Executive
Officer and Chief Financial Officer
as required by Section 302 of the
Sarbanes-Oxley Act of 2002.
EQUAL OPPORTUNITY
The company is an Equal Employment
Opportunity (EEO) employer and does
not discriminate in any employer/
employee relations based on race,
color, religion, sex, sexual orientation,
national origin, age, disability or
veteran’s status.
CORPORATE RESPONSIBILITY
To learn about Williams’ corporate
responsibility, go to www.williams.com.
INTERNET
Company information is available
at www.williams.com.
INQUIRIES
To request additional materials, call
800-600-3782 or access our website.
To contact our investor relations group,
call 800-600-3782. Please send written
inquiries to investor relations to the
headquarters address below.
CORPORATE HEADQUARTERS
One Williams Center
Tulsa, OK 74172
Phone: 918-573-2000 or
toll-free, 800-WILLIAMS
TRANSFER AGENT AND REGISTRAR
Routine shareholder correspondence:
Computershare Trust Company, N.A.
P.O. Box 505000
Louisville, KY 40233-5000
Phone: 800-884-4225
Hearing impaired: 800-952-9245
Internet: www.computershare.com
Overnight correspondence:
Computershare Trust Company, N.A.
462 South 4th Street Suite 1600
Louisville, KY 40202
Contact our transfer agent for
information on registered share
accounts, dividend payments or
to receive information about our
Direct Stock Purchase Plan.
Stockholder Information
WILLIAMS SECURITIES
Williams common stock (WMB) is listed
on the New York Stock Exchange.
The market value on February 19, 2018
was approximately $23.9 billion. On that
date, 6,979 shareholders of record held
827,327,336 shares of Williams common
stock. The company’s common stock
traded at an average daily volume of 6.4
million shares in 2017.
WMB COMMON STOCK ACTIVITY
(dividend/share)
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
2017
0.30
0.30
0.30
0.30
2016
0.64
0.64
0.20
0.20
WMB AVERAGE DAILY VOLUMES TRADED
(thousands of shares)
2013
2014
2015
2016
2017
20,000
16,000
12,000
8,000
4,000
43214321432143214321
WMB PRICE RANGES
($/share)
High
Low
2013
2014
2015
2016
2017
70
60
50
40
30
20
10
0
43214321432143214321
WMB DAILY PRICES
($/share)
2017
2016
High
Low
High
Low
1st Quarter
32.69
27.68
26.68
10.22
2nd Quarter
31.25
27.65
23.89
14.60
3rd Quarter
32.18
28.76
31.43
19.68
4th Quarter
30.72
26.82
32.21
27.35
We make energy happen.®
(800) WILLIAMS l www.williams.com
© 2018 The Williams Companies, Inc.